PB81-234239
Environmental and Economic Comparison of
Advanced Processes for Conversion of
Coal and Biomass into Clean Energy
Bechtel National, Inc.
San Francisco, CA
Prepared for
Industrial Environmental Research Lab
Cincinnati, OH
Aug 81
U.S. DEPARTMENT OF COMMERCE
National Technical Information Service
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NOTICE
THIS DOCUMENT HAS BEEN REPRODUCED
FROM THE BEST COPY FURNISHED US BY
THE SPONSORING AGENCY. ALTHOUGH IT
IS RECOGNIZED THAT CERTAIN PORTIONS
ARE ILLEGIBLE, IT IS BEING RELEASED
IN THE INTEREST OF MAKING AVAILABLE
AS MUCH INFORMATION AS POSSIBLE.
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
. REPORT NO.
EPA-6QO/7-81-133
2.
ORD Report
3. RECIPIENT'S ACCESSION-NO.
234239
4. TITLE AND SUBTITLE
Environmental and Economic Comparison of Advanced
Processes for Conversion of Coal and Biomass
into Clean Energy
5. REPORT DATE
August 1981
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
R. A. Stenzel, B. T. Kown, M. C. Weekes, J. D. Ruby,
B. R. Gilbert, C. M. Harper, Y. J. Yim, R. T. Milligan
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Bechtel National, Inc.
P.O. Box 3965
San Francisco, CA 94119
10. PROGRAM ELEMENT NO.
C2G1E
11. CONTRACT/GRANT NO.
68-02-2616
12. SPONSORING AGENCY NAME AND ADDRESS
Industrial Environmental Research Lab, Cinn, OH
Office of Research and Development
U.S. Environmental Protection Agency
Cincinnati, OH 45268
13. TYPE OF REPORT AND PERIOD COVERED
Final - 9/77 - 12/78
14. SPONSORING AGENCY CODE
EPA/600/12
15. SUPPLEMENTARY NOTES
Project Officer - Thomas J. Powers (513-684-4363)
16. ABSTRACT
Biomass and coal conversion into clean energy is compared on an economic and
environmental basis in three regional scenarios: (1) electric power from direct
combustion of wood versus conventional coal combustion in the South Central U.S.,
(2) synthetic pipeline gas from anaerobic digestion of wheat straw and manure
versus high-Btu gasification of coal (HYGASR) in the Midwest, and (3) synthetic
fuel oil from wood liquefaction versus coal liquefaction (H-CoalR) in the North-
east. Conceptual commercial-scale plants are described. Capital and operating
costs are presented for each of the six plants, and the biomass versus coal
economics are compared. General environmental impacts of biomass and coal
resource collection are assessed and compared in the scenario contexts. Plant
environmental emissions were estimated where possible, and relative environmental
impacts are discussed. Conclusions are given about the conversion concepts
which seem the more promising routes to clean energy, and areas needing further
study are identified.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Biomass*, Coal*, Energy*, Combustion,
Gasification, Liquefaction, Pollution,
Economic analysis
Synthetic fuels, Anaer-
obic digestion, Environ-
mental assessments, Pol-
lution control, Solid
waste, Management, HYGAS,
H-coal
13. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
401
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
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DISCLAIMER
This report has been reviewed by the Industrial Environmental Research Labora-
tory, U.S. Environmental Protection Agency, and approved for publication.
Approval does not signify that the contents necessarily reflect the views and
policies of the U.S. Environmental Protection Agency, nor does mention of trade
names or commercial products constitute endorsement or recommendation for use.
11
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FOREWORD
When energy and material resources are extracted, processed, converted, and
used, the related pollutional impacts on our environment and even on our health
often require that new and increasingly more efficient pollution control methods
be used. The Industrial Environmental Research Laboratory — Cincinnati (lERL-Ci)
assists in developing and demonstrating new and improved methodologies that will
meet these needs both efficiently and economically.
The subject of this report is an environmental and economic comparison of various
processes for converting biomass and coal into clean energy. The information
contained herein will be of interest to those involved in biomass and coal con-
version research and development programs, and to those involved in the evalua-
tion of alternative clean energy sources. Inquiries and comments regarding the
report should be directed to the Alternate Energy Sources Branch, Energy
Pollution Control Division.
David G. Stephan
Director
Industrial Environmental Research
Laboratory-Cincinnati
111
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EXECUTIVE SUMMARY
This report presents the results of three environmental and economic comparisons
of biomass and coal conversion into clean energy. The study was initiated to
help develop priorities for assessing conversion technologies capable of pro-
ducing clean energy from biomass and coal resources. Electric power, synthetic
pipeline gas (SPG), and synthetic fuel oil were chosen as representative clean
energy products which can be produced from both biomass and coal. Represen-
tative coal conversion technologies were to serve as base cases to which biomass
conversion technologies were to be compared. Three regional scenarios, each
with a biomass-coal plant pair, were selected from a number of possible candi-
dates. Conceptual designs of commercial-scale plants were compared in these
regional scenarios:
• A 50 MWe wood-fired power plant versus a 500 MWe coal-fired
power plant in the South Central U.S.
• A 7 MM SCFD (6.7 billion Btu/day) biogas plant (anaerobic
digestion of wheat straw and manure) versus a 274 MM SCFD
(250 billion Btu/day) high-Btu gasification plant (steam-
oxygen HYGASR) in the Midwest
• A 1764 BPD wood-to-oil liquefaction plant versus a 66,856 BPD
coal liquefaction plant (H-Coal^) in the Northeast
In the scenarios, biomass residue is collected locally from forestland (chipped
forest residue), from farmland (wheat straw), and from feedlots (cattle manure).
Coal is strip-mined in the first two scenarios and deep-mined in the third. As
plant feedstocks, the biomass materials have lower sulfur and ash contents, lower
heating values, and lower bulk densities (except manure) than coal.
The plant capacities chosen are representative of commercial scales being pro-
posed for biomass residue and coal conversion. The disparity in biomass-coal
plant capacities is almost inherent; hence the higher capacity coal conversion
plants have a distinct economy-of-scale advantage. The direct combustion and
the liquefaction processes for biomass conversion are similar to their coal
conversion counterparts. A biological conversion process, anaerobic digestion,
is compared with a thermal conversion process, steam-oxygen gasification. Esti-
mated plant thermal efficiencies (based on net product output) are compared
below:
Power SPG Fuel Oil
Biomass conversion 21.6% 31.9% 42.1%
Coal conversion 35.1% 69.7% 65.5%
IV
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It is apparent that these three biomass processes have relatively low conversion
efficiencies. In the wood conversion processes, the feedstock properties are a
disadvantage — low heating values (high moisture and oxygen contents) and low
bulk densities mean that more material must be handled per unit of energy con-
tent than for coal. Energy consumption and losses are high. The anaerobic
digestion process suffers from a low methane production rate and incomplete bio-
mass conversion. This process does yield a digester residue that may be a val-
uable byproduct if it can be used as an animal feed.
Improvements in conversion efficiencies are important if these particular bio-
mass processes are to be competitive with the coal processes. Worthwhile ideas
for improving feedstock properties (preprocessing of biomass) should be given
attention, as such ideas could lead to increased process conversion efficiencies.
Economic comparisons of the biomass and coal conversion concepts are presented
in Figures 1, 2, and 3 for utility and private financial methods, using the
ERDA-AGA Cost Guidelines. These figures illustrate that the biomass-derived
energy products are about 50 percent (power) to 300 percent (SPG) more expensive
to produce than the corresponding coal-derived products from much larger con-
version plants. Synthetic fuel oil from wood liquefaction is about 2.5 times
more costly than oil from the H-Coal process. In these scenarios at least, the
economic disparities result from a combination of less desirable feedstock prop-
erties, smaller biomass plant capacities, and lower process conversion effi-
ciencies. In many economic situations, both direct-fired plants would produce
electric power more cheaply than it could be produced in conventional power
plants firing any of the four synthetic fuels.
WOOD COST, S/MMBTU
1 50
0.50
1.00 1.50 2.00 2.50
COAL COST, S/MMBTU
Figure 1. Economic comparisons of wood and coal to power.
Figure 1 shows that the cost of electricity from a wood-fired plant is not
competitive with that from a large coal-fired generating station if wood
and coal prices are about the same on a $/MM Btu basis. For a high coal
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STRAW OR MANURE COST, S/MMBTU
1.00 1.50 2.00 2.50
46
STRAW AND MANURE COST, S/TON
O inP
1.50 2.0
COAL COST. S/MMBTU
Figure 2. Economic comparison of straw/manure and coal to SPG.
WOOD COST. S/MMBTU
1.00 1.50 2.00
0.50
1 50 2.00 2.50
COAL COST, S/MMBTU
Figure 3. Economic comparison of wood and coal to fuel oil.
VI
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cost/low wood cost scenario, a small wood-fired plant could be economic as
evidenced by existing power boilers burning wood wastes in many pulp and paper
mills in the Northeast.
The biomass-derived synthetic gas and oil are just not close to being competi-
tive with the coal derived synthetic fuels, as Figures 2 and 3 illustrate.
Pollution control costs will be high for the large coal conversion plants, prob-
ably 5 to 10 percent of the total plant capital costs. These large expenditures,
however, do not shift the economic advantage to biomass conversion, as the fore-
going figures show.
Environmental impacts of plant construction and operation were considered
separately from impacts of resource collection. Resources consumed by the
plants and emissions of conventional pollutants x^ere estimated for each biomass
and coal conversion plant, and then comparisons were made on a relative (energy
output) basis. None of the three biomass conversion plants appears to have an
overall environmental advantage over its coal conversion plant counterpart on
the relative comparison basis. This environmental standoff is partly due to
the extensive pollution controls used in the coal conversion plants which reduce
conventional pollutant emissions to about the same overall .levels as those from
biomass conversion. The potential for generation and release of toxic or
hazardous substances (priority pollutants) cannot be assessed adequately at
this time because much of the information has not been developed yet.
Biomass residue collection should entail considerably fewer adverse consequences
on the environment than deep-mining or strip-mining coal resources. Forest
residue or wheat straw collection activities will affect much more land area
than coal mining, but little environmental damage should occur if collection
activities are managed properly. Unlike coal, the biomass resources are renew-
able and some environmental credit is deserved for their utilization. If the
plant impacts and the collection impacts are considered together, biomass con-
version in these scenarios may be preferable from an overall environmental
impact viewpoint.
Major conclusions reached from these three biomass-coal comparisons are:
• The coal conversion plants have considerably higher thermal
efficiencies than their biomass counterparts
• The biomass residues have the advantage of low sulfur and ash
contents, but their low bulk densities and low energy contents
are distinct disadvantages with respect to coal as a plant
feedstock
• Biomass-derived electric power, SPG, and synthetic fuel oil
are more expensive to produce than the corresponding coal-
derived clean energy products from the large-scale conversion
plants
VI1
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• Pollution control costs for the coal conversion plants are
high, but have little impact on the relative economics of
coal versus biomass conversion
• The anaerobic digestion and wood liquefaction processes are not
promising routes to low cost synthetic fuels in view of the
superior HYGAS and H-Coal process economics
• In certain localities, power generation from wood may be eco-
nomically competitive with power generation from coal if the
coal:wood price ratio is high enough
• The small biomass conversion plants do not appear to have an
overall environmental advantage over their coal conversion
plant counterparts on a relative basis; however, more and better
quantitative emission data need to be developed in order to
better assess the probable impacts of both the biomass and
coal conversion technologies
• Managed properly, biomass residue collection should have less
severe environmental impacts than coal mining, even though much
more land area would be affected by residue collection
From these comparisons, it is evident that the coal conversion processes are
more likely to become major routes to clean fuels than these biomass conver-
sion processes, primarily because of better economics. Other biomass feed-
stock/conversion process/energy product scenarios could prove to be more
favorable in this type of biomass-coal comparison. A combination of three
factors is desirable:
• A relatively low-priced biomass feed material
• A process that has a relatively high conversion efficiency
• A higher-priced product than fuel oil or fuel gas
Steam and power production from low-cost residues and co-firing of wood and
fossil fuels appear to be promising ways of using biomass resources in a number
of localities in the U.S. Biomass conversion into more valuable products
(chemicals, fertilizers, animal feeds) should also be a promising area of study
Both biomass and coal conversion would have adverse environmental impacts, and
there is continuing need to better define the likely impacts of resource col-
lection, conversion, and product usage.
The coal conversion plants need to be large in order to produce competitively
priced clean energy. If the coal conversion plants could be scaled-down to
the same low capacities as their biomass plant counterparts, it is likely that
the coal-derived energy products would be more costly than the respective
biomass-derived products. In some localized -scenarios, biomass conversion
could have an economic advantage over coal conversion on a small scale.
viii
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CONTENTS
Foreword ill
Executive Summary iv
Figures xi
Tables xiii
Abbreviations xviii
Unit Conversions xix
Acknowledgment xx
1. Introduction 1
Objectives of the study 1
Groundrules and methodology 1
2. Summary and Recommendations 9
Process conversion summaries 9
Economic comparison 17
Environmental comparisons 22
Conclusions and recommendations 29
3. Scenario 1 — Wood and Coal to Power in the South Central Region 33
Regional environmental setting 33
Wood-to-power plant site description 36
Forest residue procurement 38
Wood-to-power process description 40
Wood-to-power capital and operating costs 51
Wood-to-power environmental assessment 55
Coal-to-power plant site description 68
Coal procurement 68
Coal-to-power process description 71
Coal-to-power plant costs 87
Coal-to-power environmental assessment 89
4. Scenario 2 — Straw/Manure and Coal to SPG in the Midwest Region 110
Regional environmental setting 112
Biogas plant site description 114
Wheat straw and manure procurement 117
Biogas process description (anaerobic digestion) 118
Biogas plant costs 135
Biogas environmental assessment 138
Coal gasification plant site description 158
Coal procurement 158
Coal gasification process description — steam-oxygen HYGAS 159
Coal gasification plant costs 174
Coal gasification environmental impacts 178
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5. Scenario 3 — Wood and Coal to Fuel in the Northeast Region 197
Regional environmental settings 199
Wood-to-oil plant site description 201
Forest residue procurement 205
Wood-to-oil process description 205
Wood-to-oil plant costs 223
Wood-to-oil environmental assessment 225
Coal liquefaction plant site description 245
Coal procurement 248
Coal liquefaction process description (H-coal) 249
Coal liquefaction plant costs 266
Coal liquefaction environmental assessment 270
6. Economic and Environmental Comparisons 287
Wood and coal to electric power 287
Straw/manure and coal to synthetic pipeline gas 301
Wood and coal to synthetic fuel oil 313
References 325
Appendices
A. Plant equipment lists 329
B. Biomass and coal feedstock availabilities 364
C. Cost estimation and economic evaluation methods 371
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FIGURES
Number Page
1 Economic comparisons of wood and coal to power v
2 Economic comparison of straw/manure and coal to SPG vi
3 Economic comparison of wood and coal to fuel oil vi
4 Biomass and coal scenario regions 5
5 Wood and coal to power region — Scenario 1 34
6 Wood to power plant, general arrangement 41
7 Wood chip receiving and storage section (wood to power) 42
8 Wood to power process flow diagram, combustion and steam cycle 44
9 Wood to power plant, simplified water balance 48
10 Effect of wood cost on cost of electricity with both private and
utility financing 52
11 Coal-fired power plant, general plant layout 73
12 Coal-fired power plant, simplified process flow diagram 75
13 Coal-fired power plant, simplified water balance 83
14 Effect of coal cost on cost of electricity with both private and
utility financing 90
15 Straw/manure and coal to SPG region — Scenario 2 111
16 Straw/manure to gas, general plant arrangement 120
17 Straw/manure receiving and feed preparation section 121
18 Straw/manure to gas, process flow sheet, digesters and waste
treatment 130
19 Straw/manure to gas, gas cleaning section 132
20 Straw/manure to gas, simplified plant water balance 134
21 Effect of straw/manure cost and cost of gas with both private and
utility financing 140
22 HYGAS gasification plant, simplified block flow diagram 161
23 HYGAS gasification plant, plot plan 162
24 HYGAS simplified water balance 172
25 Effect of coal cost on cost of gas with both private and
utility financing 179
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Page
Number —
198
26 Wood to fuel oil region — Scenario 3
1 no
27 Coal to fuel oil region — Scenario 3
or) 7
28 Wood to oil plant, general arrangement ^'
29 Wood chip receiving and storage section (wood to oil) 208
30 Wood to oil process flow diagram — preparation, reaction, and
product recovery
31 Wood to oil process flow diagram — syngas production and catalyst
recovery 210
32 Wood to oil plant material balance 211
33 Wood to oil plant, simplified water balance 220
34 Effect of wood cost on cost of oil with both private and utility
financing 227
35 Artist's rendering of a commercial wood to oil plant 241
36 H-Coal liquefaction plant, plot plan 250
37 H-Coal liquefaction plant, simplified block flow diagram '. 255
38 H-Coal plant, simplified water balance 261
39 Effect of coal cost on cost of oil with both private and utility
financing 269
40 Effect of feedstock cost on the cost of electricity 290
41 Effect of feedstock cost on the cost of synthetic pipeline gas (SPG) 303
42 Effect of feedstock cost on the cost of synthetic fuel oil 315
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TABLES
Number Page
1 Selected Biomass-Coal Process Comparisons 6
2 Summary of Potentially Applicable Federal Environmental
Legislation 8
3 Summary Comparison of Wood and Coal to Power Conversion
Processes 10
4 Summary Comparison of Straw/Manure and Coal to SPG Conversion
Processes 12
5 Summary Comparison of Wood and Coal to Fuel Oil Conversion
Processes 15
6 Summary of Capital and Annual Operating Costs Biomass and
Coal Conversion 17
7 Annual Inputs and Outputs Requirements Using Consistent
Load Factors 19
8 Economic Comparison Summary for Biomass and Coal Conversion
Processes (Based on $/Ton) 20
9 Economic Comparison Summary for Biomass and Coal Conversion
Processes (based on S/MM Btu) 21
10 Sample Numerical Ratings for Qualitative Assessments 24
11 Comparison of Principal Resource Requirements — Wood and Coal
to Power 25
12 Relative Environmental Impact Summary of Wood and Coal to Power 26
13 Comparison of Principal Resource Requirements — Straw/Manure
and Coal to SPG 27
14 Relative Environmental Impact Summary of Straw/Manure and Coal
to SPG 28
15 Comparison of Principal Resource Requirements — Wood and Coal
to Fuel Oil 29
16 Relative Environmental Impact Summary of Wood and Coal to
Synthetic Fuel Oil 30
17 Assumed Climatic Conditions 37
18 Assumed Average River Water Quality 39
19 Assumed Wood Fuel Properties 43
20 Wood to Power Thermal Balance Elements 50
Xlll
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Number Page_
21 Wood to Power Capital Costs 5^
22 Annual Operating and Maintenance Costs — Wood to Power 54
23 Annualized Cost of Electricity 54
24 Procurement Impact Summary — Forest Residue 57
25 Principal Resources Committed to Plant Operation 59
26 Summary of Annual Chemical Requirements — Wood to Power 60
27 Summary of Estimated Air Emissions — Wood to Power 61
28 Summary of Estimated Wastewater Emissions — Wood to Power 64
29 Solid Waste Disposal Summary — Wood to Power 65
30 Summary of Environmental Matrix — Wood to Power 69
31 Assumed Coal Fuel Properties 74
32 500 MWe Power Plant Design Bases and Assumptions 76
33 FGD System Design Parameters 79
34 Coal to Power Thermal Balance Elements 87
35 Coal to Power Capital Costs __ 88
36 Annual Operating and Maintenance Costs — Coal to Power 89
37 Procurement Impact Summary — Coal 92
38 Principal Resources Committed to Plant Operation — Coal to Power 96
39 Summary of Annual Chemicals Consumed — Coal to Power 97
40 Summary of Estimated Air Emissions — Coal to Power 99
41 Summary of Estimated Wastewater Emissions — Coal to Power 102
42 Solid Waste Disposal Summary — Coal to Power 105
43 Summary of Environmental Matrix — Coal to Power 108
44 Assumed Climatic Conditions at the Site 115
45 Assumed Average River Water Quality 116
46 Assumed Characteristics of Feedstocks 122
47 Design and Operating Criteria — Feed Preparation 123
48 Design and Operating Criteria — Digestion 124
49 Design and Operating Criteria — Gas Cleaning 125
50 Design and Operating Criteria — Effluent Treatment 126
51 Biogas Plant Thermal Balance Factors 136
52 Straw/Manure to Gas Capital Costs 137
53 Annual Operating and Maintenance Costs — Straw/Manure to Gas ^39
54 Annualized Cost of Gas Production 139
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Number Page
55 Procurement Impact Summary — Wheat Straw and Manure 144
56 Principal Resources Committed to Plant Operation 146
57 Summary of Annual Chemical Requirements — Straw and Manure to
Gas 147
58 Summary of Estimated Air Emissions — Straw and Manure to Gas 148
59 Summary of Estimated Wastewater Emissions — Straw and Manure
to Gas 151
60 Solid Waste Disposal Summary — Straw and Manure to Gas 153
61 Summary Environmental Matrix — Straw and Manure to Gas 156
62 Assumed Coal Feedstock Properties . 163
63 Coal To Pipeline Gas Design Bases and Assumptions 164
64 Summary Material Balance — IGT Steam-Oxygen HYGAS Process 166
65 HYGAS Gasification Plant — 250 MMM Btu/Day — Overall Material
Balance 167
66 Summary Energy Balance — IGT Steam-Oxygen HYGAS Process 175
67 HYGAS Capital Costs -176
68 Annual Operating and Maintenance Costs — HYGAS 177
69 Procurement Impact Summary 183
70 Principal Resources Committed to Plant Operation 185
71 Estimate of Annual HYGAS Chemical Requirements — Bechtel Estimate 185
72 Summary of Estimated Air Emissions — HYGAS 186
73 Summary of Estimated Wastewater Emissions — HYGAS 189
74 Solid Waste Disposal Summary — HYGAS 192
75 Summary Environmental Matrix — HYGAS 195
76 Assumed Climatic Conditions at the Site 202
77 Assumed River Water Quality at the Site — Average 204
78 Design Feedstock Composition 212
79 Plant Design Basis and Assumptions 213
80 Thermal Balance Elements — Wood to Oil 223
81 Wood to Oil Capital Costs 224
82 Annual Operating and Maintenance Costs — Wood to Oil 226
83 Annualized Cost of Oil Production 226
84 Procurement Impact Summary — Forest Residue 230
85 Resources Committed to Plant Operation 232
xv
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XT i. Page
Number e—
86 Summary of Annual Chemical Requirements - Wood to Oil 233
87 Summary of Estimated Air Emissions - Wood to Oil 234
88 Summary of Estimated Wastewater Emissions - Wood to Oil 237
89 Solid Waste Disposal Summary — Wood to Oil 238
90 Summary Environmental Matrix — Wood to Oil
91 Assumed Climatic Conditions at the Site
92 Assumed Average River Water Quality
93 Coal Feedstock Properties
94 Coal to Fuel Oil Design Bases and Assumptions 252
95 H-Coal Liquefaction Plant — 25,000 Tons per Day — Overall
Material Balance 25^
96 Summary Energy Balance — H-Coal Process 265
97 H-Coal Capital Costs 267
98 Annual Operating and Maintenance Costs — H Coal 268
99 Procurement Impact Summary — Coal 272
100 Principal Resources Committed to H-Coal Plant Operation 273
101 Estimated Annual Catalysts and Chemicals Makeup 274
102 Summary of Estimated Air Emissions — Coal to Oil 276
103 Summary of Estimated Wastewater Emissions — Coal to Oil 279
104 Solid Waste Disposal Summary — Coal to Oil 282
105 Summary Environmental Matrix — H-Coal 285
106 Economic Comparison of Wood and Coal to Power 288
107 Impact Summary for Site Specific Factors — Feedstock Procurement 291
108 Impact Summary for Site Factors — Wood and Coal to Power 295
109 Resources Committed to the Power Plants 298
110 Sample Numerical Ratings for Qualitative Assessments 299
111 Summary of Wood and Coal to Power Impacts 300
112 Economic Comparison of Straw/Manure and Coal to SPG 302
113 Impact Summary for Site Specific Factors — Feedstock Procurement 305
114 Impact Summary for Site Specific Factors — Straw/Manure and
Coal to Synthetic Pipeline Gas 308
115 Resources Committed to the Synthetic Gas Plants 311
116 Summary of Straw/Manure and Coal to Synthetic Gas Impacts 312
117 Economic Comparison of Wood and Coal to Synthetic Fuel Oil 314
xvi
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Number Page
118 Impact Summary for Site Specific Factors — Feedstock Procurement 317
119 Impact Summary for Site Specific Factors — Wood and Coal to Fuel
Oil 320
120 Resources Committed to Synthetic Fuel Oil Plants 323
121 Summary of Wood and Coal to Oil Impacts 324
xvi i
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ABBREVIATIONS
ac = acre
ACFM actual cubic feet per minute
API American Petroleum Institute
bbl barrels
BPD = barrels per day
BPSD barrels per stream day
BOD biochemical oxygen demand (5-day)
bhp "= brake horsepower
Btu British thermal unit
cfm = cubic feet per minute
CFD cubic feet per dav
CFY cubic feet per year
CO = carbon monoxide
C02 carbon dioxide
COS = carbonyl sulfide
CPI = corrugated plate interceptor
cu ft = cubic feet
dSCF dry standard cubic foot
ft feet
FGD flue gas desulfurization
g grams
gal gallons
gpm gallons per minute
gr grains
ha hectares
HC hydrocarbons
HHV higher heating value
hp horsepower
Hz Hertz
H2$ hydrogen sulfide
in. inches
in. Hga inches of mercury absolute
JTU Jackson turbidity units
kg kilograms
kV kilovolts
kVA kilovolt amperes
kW kilowatts
kWh kilowatt hours
Ib pounds
LHV lower heating value
LTPSD long tons per stream day
M thousand
MM million
MMM = billion
mg/1 milligrams per liter
MLVSS mixed liquor volatile suspended
solids
mph miles per hour
MPH moles per hour
MPN most probable number
HT metric tons
MVA = megavolt amperes
MW - megawatts
MWe = megawatts electrical
MWt = megawatts thermal
NPDES = National Pollutant Discharge
Elimination System
NOx nitrogen oxides
NSPS new source performance standards
pf power factor
PM particulate matter
ppmv parts per million by volume
psia pounds per square inch absolute
psig pounds per square inch gauge
RO reverse osmosis
SCA specific collection area
SCFD standard cubic feet per day
sq ft square feet
S0,( sulfur oxides
S.P. = static pressure
STPSD = short tons per stream day
TDH total dynamic head
IDS total dissolved solids
tpd tons per day
tph tons per hour
TSS total suspended solids
TTD terminal temperature difference
VS volatile solids
wg water gauge
XVI11
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UNIT CONVERSIONS TO S.I.
English Units SI Units
1 acre (ac) 4046.86 meter2
1 acre foot 1233.48 meter2
1 atmosphere (atm) 101.325 kilopascal
1 barrel (bbl) 0.15899 meter3
1 brake horsepower (bhp) 0.7457 kilowatts
1 British thermal unit (Btu) 1.05435 kilojoules
1 Btu/hr 0.29288 watts
I Btu/pound (Ib) 2.3244 joules/gram
1 Btu/lb mole 2.3244 joules/mole
1 3tu/standard cubic foot (SCF) 37.320 kilojoules/meter3
1 cubic foot (cu ft) 0.02832 meter3
1 cubic foot per hour (CFH) 7.8667 x 10~ meter3/second
1 foot 0.3048 meter
1 gallon (U.S.) 3.785 v 10" 3 meter3
1 gallon per minute 6.3089 x 10" meter /sec
1 horsepower (hp) 0.7457 kilowatts
1 inch of mercury (60 F) 3,376.85 newton/meter
1 kilowatt hour (kwh) 3600 kilojoules
1 inch of water (60 F) 248.84 newton/neter
1 pound (Ib) 0.45359 kilograms
1 Ib/cu ft 16.0135 kilograms/meter3
1 Ib/hr 0.12600 grams/second
1 Ib/million (MM) Btu 4.3021 x 10"7 kilograms/kilojoule
1 Ib mole/hr 0.12600 gram mole/second
1 mile (U.S. statute) 1609.344 meter
1 pound per sq in. absolute (psia) 6.89476 kilopascal
1 standard cubic foot per minute (SCFM) 4.7200 x 10~ meter /second
1 short ton per'day (STPD) 0.10500 kilograms/second
1 ton (short) 907.185 kilograms
1 ton (long) 1016.047 kilograms
1 ton per hour (tph) 0.25200 kilograms/sec
1 c/lb 2.2046 c/kilogram
1 c/M gallons 0.26417 c/meter3
1 $/MM Btu 9.4845 .' 10~' S/kilojoule
1 5/ton 1.1023 \ 10"3 S/kilogram
1 mill/kWh 2.773 , ICf c/kilojoule
XIX
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ACKNOWLEDGMENTS
The authors wish to acknowledge the Project Officer, Mr. Thomas J. Powers of
the Energy Systems Environmental Control Division, IERL, Cincinnati for his
continued support and guidance throughout this study. We would also like to
acknowledge the helpful comments and suggestions concerning coal conversion
by Mr. T. Kelley Janes, Branch Chief, Fuels Process Branch, IERL, Research
Triangle Park.
The authors especially wish to thank Professor William, J. Oswald and Professor
Theodore Venneulen, both of the University of California, Berkeley, for their
service as voluntary reviewers of the draft final report. Their comments and
suggestions were very useful in the preparation of this final report.
-------
SECTION 1
INTRODUCTION
OBJECTIVES OF THE STUDY
The United States has enormous quantities of both biomass and coal. A hundred
years ago, the U.S. obtained about 75 percent of its energy from wood (2.4 quads
-or about 3 percent of current energy consumed)(1). Later, coal provided the
major source of energy in the U.S. before petroleum and natural gas supplies
became abundant. Today, coal accounts for less than 19 percent of the U.S.
energy consumption, but constitutes more than 90 percent of the total national
resources of coal, petroleum, and natural gas(2). Both biomass and coal are
likely to be major energy and chemical feedstock sources in the future if eco-
nomical conversion processes can be developed. But coal, rather than biomass,
will probably predominate in the next 20 years.
Intrinsically, biomass materials are "cleaner" sources of energy than coal
because of their relatively low sulfur and ash contents. Coal conversion
processes will generally require more extensive control technology to produce
clean-energy forms and to prevent the release of pollutants in damaging quan-
tities to the environment. The environmental controls needed for the conver-
sion of coal into clean-energy forms are costly. To aid in developing priorities
on the specific conversion technologies to be assessed, it is desirable to
evaluate coal-based technologies against other technologies capable of produc-
ing similar clean-energy forms from nonfossil-based raw materials. Conversion
of renewable resources such as biomass residues is a specific alternative to
be considered.
The major objectives of this study were to provide both environmental and eco-
nomic assessments to compare the conversion of biomass and coal into clean
energy. Specific emphasis was to be placed upon the analysis of the applica-
bility of existing biomass conversion processes, the technology requirements,
the costs of pollution control, and the costs of clean energy production com-
pared to coal-based technology. Pollutant emissions and the environmental
impacts of biomass conversion were also to be evaluated.
GROUNDRULES AND METHODOLOGY
To make environmental and economic comparisons of biomass versus coal, several
factors needed unbiased consideration:
• Conversion technologies and state of development
• Type, location, and availability of resources
1
-------
a
• Forms of clean energy and plant sizes
• Environmental regulations
• Economic bases and time of plant implementation
A wholly satisfactory basis was not found. It was felt that only three biomass
coal comparisons could be covered adequately in this study. In view of this,
range of possibilities was deliberately developed for the three comparisons:
• Three different conversion technologies in different states of
development — direct combustion, gasification, liquefaction
• Three regional locations
• Three biomass types
• Three coal types
• Three clean energy products — electric power, synthetic pipeline
gas, synthetic fuel oil
This list includes three different major energy forms for which coal conversion
technologies exist and which could be used as bases for comparison with appro-
priate biomass conversion technologies. A methanol or ethanol fuel could also
have been chosen as a representative clean energy form.
Factors that proved to be difficult to normalize included plant sizes, environ-
mental regulations, and economic evaluation bases because of the differing states
of process development, the unknown future implementation periods, and the future
cost of feedstocks. Difficulties encountered in the comparisons are discussed
in subsequent sections.
A recent Battelle report, which outlined six regional scenarios, provided the
basis for preliminary selection of the biomass conversion scenarios and pro-
cesses (3). Other sources of information were also used in selecting candidate
regions, resources, and conversion processes.
On the biomass conversion side, conversion processes and economic evaluations
were limited to those in at least the conceptual design stage and for which
commercial-scale plant economic data were available to the public.
General groundrules and methodology established for selection and comparison
of the specific processes were:
• Site characteristics
— Each plant site will be favorable for the particular con-
version process; sufficient land is available; resources
are adequate; there is a demand for the product in the region
— A general description of each plant site will be given;
the sites will be hypothetical (not identified)
-------
Feedstocks
— Available quantities will be cited; resources must be suf-
ficient to support the plant over its operating life
— Seasonal variations will be considered
— A single feedstock composition will be used for the plant
conceptual design
— Feedstock collection and transport will be described
— Costs of feedstock delivered to the plant will be estimated
Plant and conversion processes
— Each plant will be of the largest practical capacity, with
due consideration to feedstock availability, conversion
equipment of commercial size, and demand for the product
in the region
— Major products will be comparable in form and of a quality
usable offsite as an energy supply
— Conversion details will be based on published information,
discussions with process developers, and engineering judgment
— The biomass-coal pairs will have the same stream or load
factors and the same plant operating lives
— Auxiliary facilities for each plant will be identified for
cost estimating purposes; however, offsite product distri-
bution systems will be excluded
— Environmental controls for each plant will be identified
and will meet applicable new source standards or will be
based on best available technology
Environmental emissions and impacts
— Principal resources committed to each plant will be esti-
mated and compared on a normalized (product output) basis
— Air, water, and solid waste pollutant emissions from each
plant will be estimated, if possible
— Implications of federal regulations (air, water, toxic
materials, hazardous waste) will be considered
-------
- - Environmental impacts of each plant will be described based
on resources committed, environmental emissions and the
general characteristics of the site; an environmental matrix
will be used to compare the impacts of each biomass-coal
pair
— Impacts of feedstock procurement will be described very
qualitatively for each conversion case and biomass-coal
procurement impacts will be compared in matrix form
• Cost estimates and economics (see Appendix C for cost informa-
tion methods)
— Capital and operating costs will be based on first quarter
1978 wage and price levels for all plants
— Pollution control costs will be discussed
— The biomass and coal conversion economics will be compared
on a utility and a private financing basis with feedstock
cost as a sensitivity parameter
— A simplified production (break-even) cost will also be
given for the biomass conversion plants
Figure 4 shows the biomass-coal regions selected for the scenarios. Table 1
summarizes the three pairs of plants selected for comparison.
The basic approach was to attempt to define reasonable commercial-scale biomass
conversion processes, estimate their costs, and estimate their major environ-
mental emissions and impacts — given the limited states of process development
in two of the three processes. The disparities in biomass and coal-plant capac-
ities are primarily the result of limitations on the biomass side. Types of
limitations generally include biomass residue availabilities, onsite storage
and handling difficulties, and, to a lesser extent, process equipment limita-
tions or complexities. It would be unreasonable to scale down the coal conver-
sion plants to match the biomass conversion plant capacities.
The HYGASR and H-Coal conversion facilities were designed and their cost esti-
mated by others (5, 6, 7), and no comments are made on their technical soundness
or cost estimations. They are used as base references for the biomass-coal
comparisons. The ERDA-AGA gas cost guidelines (8) were used for comparing the
relative economics of biomass and coal conversion on a consistent basis.
Published environmental emission data were lacking in many areas for both bio-
mass and coal conversion processes. Emission estimates in this study were
limited primarily to conventional pollutants. The emissions and impacts pres-
ented are incomplete and somewhat speculative. The objective was to estimate
and compare major impacts anticipated from construction and operation of the
hypothetical conversion facilities.
-------
Figure 4. Biomass and coal scenario regions.
-------
TABLE 1. SELECTED BIOMASS-COAL PROCESS COMPARISONS
Major Product
Electric Power
Electric Power
Uses
Local utility
supply
Regional utility
supply
Feedstock
Forest residue
Eastern bituminous,
strip-mined, 1.4%
Conversion
Wood-fired
boiler — st
turbine gen
Pulverized
fired boile
Process
earn
t± v a t o r
coal-
Plant Size
1870 TPD feed
45 MWe output
4190 TPD feed
476 MWe output
Plant Location
South Central
(Alabama,
Mississippi)
South Central
(Alabama,
US
US
Synthetic Local utility
Pipeline Gas gas supply
(SPG)
Synthetic Regional utility
Pipeline Gas gas supply
Heavy Fuel Oil Low sulfur boiler
fuel
Heavy Fuel Oil Low sulfur boiler
and Naphtha fuel, refinery
feedstocks
sulfur
Wheat straw and cattle
manure
Western subbituminous,
strip-mined, 0.5%
sulfur
Forest residue
Eastern bituminous,
deep-mined, 4.4%
sulfur
steam turbine
generator
Anaerobic
digestion and CO
removal
(upgrading)
IGT-HYGASR (steam-
oxygen) process
plus methanation
Catalytic lique-
faction (PERC)
process
HRI H-CoalK
process (fuel oil
mode)
2000 TPD feed
6.7 MMM Btu/day
product
20,472 TPD feed
250 MMM Btu/day
product
Mississippi)
Midwest (Kansas,
Nebraska)
Midwest (Kansas.,
Nebraska)
1965 TPD feed Northeast
1764 BPD product (Maine, Vermont)
oil
27,836 TPD feed
66,856 BPD
products
Northeast
(Pennsylvania,
West Virginia)
-------
Additionally, there is a general lack of environmental,.regulations or guide-
lines specifically applicable to new conversion processes for producing synthetic
fuels. Table 2 lists some of the federal legislation which may have an impact
on air, water, and solid waste emissions from these hypothetical conversion
plants. For the steam-electric generating source category, there are published
new source performance standards (NSPS) that would be applicable to the wood
and coal-to-power plants. In the electric power scenarios, unpublished "draft"
NSPS for particulate matter, sulfur oxides (SOX), and nitrogen oxides (NOX)
listed in Table 2 are assumed to apply. These unpublished draft standards
would require percentage emission reductions in addition to maximum limits.
For the other conversion scenarios, the environmental control technologies
assumed may or may not be sufficient to meet future requirements established
under the listed legislation. In subsequent sections of the report, environ-
mental uncertainties or potential problem areas are identified.
Section 2 summarizes the biomass and coal conversion scenarios, their economics
and anticipated environmental impacts, and conclusions and recommendations for
future studies.
Sections 3, 4, and 5 present the details of the three biomass-coal conversion
scenarios. In Section 6, each biomass and coal conversion pair is compared on
an economic and environmental impact basis. The appendices contain plant equip-
ment lists, a discussion of feedstock availability, and a summary of the cost
estimating and economic evaluation methods used in this study.
-------
TABLE 2. SUMMARY OF POTENTIALLY APPLICABLE
FEDERAL ENVIRONMENTAL LEGISLATION
Environmental
Emission Category
Public Law, Regulation or Guideline
General Significance or Applicability
to Biomass-Coal Conversion
Air Pollutant Emissions Clean Air Act Amendments of 1977,
(PM, SOX, NOX, CO, PL 95-190
Nonmethane Hydrocarbons)
Air Pollutant Emission "Draft" NSPS for steam-electric
Standards (PM, Opacity, generating, 40 CFR 60, Subpart D:
x' ' x' . PM <0.03 Ib/MM Btu input and
99% "reduction of uncontrolled
emissions
• Opacity <_l07a (6-minute average)
• SO <1.2 lb S09/MM Btu input and
90" reduction of uncontrolled
emissions (<0.2 Ib/MM Btu — no
reduction required)
* V^x iP • ^ lb ^T0:>/MM 3tu input
and 657, reduction of uncontrolled
emissions
Sulfur Emissions Final NSPS for petroleum refining,
40 CFR 60, Subpart J:
• Fuel gas (combustion) _^0.1 gr
H2S/dSCF
• Glaus plant tail gas <_250 ppmv
S02/dSCF (after incineration) or
<300 ppmv reduced sulfur compounds
and ^100 ppmv R2S (as S02)/dSCF
(no incineration)
Air Pollutants
Hazardous
Water Pollutant
Emissions
Water Pollutant
Emissions
Solid Wastes
Toxic Substances
The Clean Air Act of 1970,
Section 112
The Federal Water Pollution Control
Act of 1972, PL 92-500: Effluent
Guidelines and Standards for Steam-
Electric. Power Generating
(40CFR423)
The Clean Water Act of 1977,
PL 95-217
The Resource Conservation and
Recovery Act of 1976, PL 94-580
The Toxic Substances Control
Act, PL 94-469
Prevention of significant deterioration —
applicable to major new stationary
sources with potential emissions
>100 tons/yr; BAT may be required in
c~lean air areas, emission offsets may
be required in nonattainment areas
Assumed to be applicable to wood and
coal-fired power plant scenario, instead
of current NSPS's which have no require-
ments for percentage reduction of uncon-
trolled emissions
Standards for fuel gas combustion and
sulfur recovery plants with oxidation or
reduction control systems may be applied
in the future to similar units in coal
conversion facilities
Emission standards or control technology
may be established for identified hazardous
air pollutants, e.g., mercury, beryllium,
benzene
NPDES discharge permit required — sets
allowable emission rates, best available
technology (BAT) required for new sources;
no standards established yet for biomass
or coal conversion as point source categories
Requires implementation of BAT by July 1984
for existing point source categories, focuses
on control of priority pollutants (potential
toxic substances); potential future applica-
tion to biomass and coal conversion effluents
Criteria to be developed for identifying
hazardous substances for purposes of hazardous
waste management — potential impact on bio-
mass and coal conversion waste disposal
Identify and evaluate potential hazards in
chemical substances; regulate the production
use, distribution and disposal of toxic
substances
-------
SECTION 2
SUMMARY AND RECOMMENDATIONS
This section summarizes the three biomass-coal scenarios through a comparison
of the conversion processes, their economics as of first quarter 1978, and
their relative environmental impacts. Conclusions and recommendations are
presented at the end of this section.
Three scenarios were used to depict conversion of renewable (biomass) and non-
renewable (coal) resources into forms of clean energy in regional contexts —
wood and coal to power in the south central region, straw/manure and coal to
synthetic pipeline gas in the midwest, and wood and coal to (synthetic) fuel
oil in the northeast. This regionalization primarily affects the type and
characteristics of the plant feedstock materials, but the effects of regional
location on conversion processes, economics, and environmental impacts were
considered.
PROCESS CONVERSION SUMMARIES
Wood and Coal to Power
Table 3 compares major process factors of the 50 MWe wood-fired power plant
and the 500 MWe coal-fired power plant. Both are assumed to be single unit
installations. The order-of-magnitude disparity in plant capacity, by itself,
has relatively little effect on the relative process conversion efficiencies.
The principal biomass-coal process differences are in feed preparation (none
versus pulverization), in the nonreheat versus reheat steam cycle, and in
requirements for flue gas cleanup (no sulfur removal versus 90 percent sulfur
removal). The higher sulfur and ash contents of the coal (versus wood), along
with more expensive flue gas cleanup, result in the large relative difference
in solid waste generation.
The gross thermal efficiency of the wood-fired plant is about one-third lower
than that of the coal-fired plant. A significant portion of this difference
is attributable to the high moisture content of the wood (50 percent), which
results in a low boiler efficiency. It should be noted that the thermal effi-
ciency could be improved by using drier fuel and a more efficient (and costly)
steam cycle.
Straw/Manure and Coal to SPG
Table 4 compares process features of the 6.66 billion (MMM) Btu/day biogas
plant with the 250 MMM Btu/day coal gasification plant based on the IGT Steam-
Oxygen HYGAS Process (5). Feed preparation is somewhat similar. The conversion
-------
TABLE 3. SUMMARY COMPARISON OF WOOD AND COAL TO POWER
CONVERSION PROCESSES
Process
Elements
Wood-to-Power
45 MWe (net)
Coal-to-Power
476 MWe (net)
Plant Opacity (j^roGs
output)
Product Output — Electric
Power
Feedstock
Onsite Storage
Feed Preparation
Feed Input Rate
Conversion Process
50,010 kW
45,080 kW/115 kV
Forest residue -
4,565 Btu/lb,
<0.01% sulfur
56,000 tons,
30 days
None - received
as chips
78 tph
Tangentially-fired
furnace with traveling
grate, drum-type
boiler with superheater
and economizer
504,300 kW
476,000 kW/345 kV
Bituminous coal -
13,033 Btu/lb,
1.44% sulfur
264,600 tons, 60 days
dead and 3 days live
Pulverization
175 tph
Tangentially-fired,
balance draft fur-
nace, controlled cir-
culation boiler with
superheater and econo-
mizer
Steam Conditions
(at throttle)
Steam Turbine
Turbine Generator
470,000 lb/hr/1250
psia/900°F
50,000 kW, single flow,
single case condensing
60,000 kW, H?-cooled
13.8 kV, 3, 60 Hz,
0.9 pf
3.37 MM lb/hr/2411 psia/
1,000°F/1,000°F reheat
553,000 kW,' tandem
compound, 4-flow, single
reheat condensing
590 MVA, H2-cooled
22 kV, 34>, 60 Hz,
0.95 pf
(Continued)
10
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TABLE 3 (Continued)
Process
Elements
Wood-to-Power
45 MWe (net)
Coal-to-Power
476 MWe (net)
Surface Condenser
Feedwater Heating
Flue Gas Cleanup
Heat Dissipation
Solid Waste Disposal
Boiler Efficiency
Gross Thermal Efficiency
Overall Plant Thermal
Efficiency
Plant Heat Rate (net)
Plant Load Factor
Plant Operating Life
1-shell, 2-pass,
50,000 sq ft,
6°F TTD, 2 inches Hga
3 stages (1 open),
drain feed forward
Electrostatic precipitator
(ESP) 99+ % efficiency,
330 SCA
4-cell induced draft
cooling tower, 333 MM
Btu/hr, 15°F cooling
range
1,430 tons per year -
onsite landfill
70%
24.0%
21.6%
15,790 Btu/kWh
69.9% (255 days/yr)
30 years
2-shell, 2-pass,
234,000 sq ft
6°F TTD, 2.5 inches Hga
7 stages (1 open),
drain feed backward
ESP (99% efficiency,
340 SCA)+lime slurry
FGD system (90% S02
removal) + 50°F reheat
Two 8-cell induced
draft towers, 2350
MM Btu/hr, 30°F
cooling range
215,600 tons per year -
onsite landfill
89.7%
37.8%
35.1%
9,727 Btu/kWh*
69.9% (255 days/yr)
30 years
*Includes 78 MM Btu/hr natural gas for flue gas reheat; if excluded, the
above values would be 35.7% and 9,563 Btu/kWh.
11
-------
TABLE 4. SUMMARY COMPARISON OF STRAW/MANURE AND COAL
TO SPG CONVERSION PROCESSES
Process
Elements
Straw/Manure-to-SPG
7 MM SCFD (net)
Coal-to-SPG (HYGAS)
274 MM SCFD (net)
Plant Capacity
Product
Feedstocks
Onsite Storage
Feed Input Rate
Feed Preparation
Conversion Process
Raw Gas Cleanup and
Upgrading
Utility Generation
Flue Gas Cleanup
6.66 MMM Btu/day
SPG-7.01 MM SCFD at
950 Btu/SCF, 3'05 psig
Wheat straw — 8548 Btu/
Ib, 0.176% sulfur
Cattle manure — 1225
Btu/lb, 0.045% sulfur
Straw — 60,000 tons,
60 days
Manure — 15,000 tons,
15 days
Straw — 1000 tpd
Manure - 1000 tpd
Straw — grind, pulp and
slurry
Manure — pulp and slurry
Single-stage anaerobic
digestion, 10 day re-
tention (1 train)
Acid gas removal and
dehydration (1 train)
250 MMM Btu/day
SPG - 273.7 MMSCFD at
915 Btu/SCF, 1010 psig
Western subbituminous
coal - 8,800 Btu/lb,
0.51% sulfur
Coal — 1,515,000 tons,
14 days live, 60 days
dead
Coal - 20,472 tpd
Wet grind, slurry, and
preheat
Process steam - raw and
product gas heaters/
boilers
power - purchased
None required
Steam — oxygen gasification
(HYGAS) 600-1,850°F, 1200
psig (2 trains)
Gas quench, shift conversion,
acid gas removal, methana-
tion and dehydration
(2 trains)
Process steam and power -
process heat recovery and
coal-fired boilers/turbine
generators; oxygen - air
separation plants
Sulfur recovery via IFF
Stackpol process
(Continued)
12
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TABLE 3 (Continued)
Process
Elements
Wood-to-Power
45 MWe (net)
Coal-to-Power
476 MWe (net)
Surface Condenser
Feedwater Heating
Flue Gas Cleanup
Heat Dissipation
Solid Waste Disposal
Boiler Efficiency
Gross Thermal Efficiency
Overall Plant Thermal
Efficiency
Plant Heat Rate (net)
Plant Load Factor
Plant Operating Life
1-shell, 2-pass,
50,000 sq ft,
6°F TTD, 2 inches Hga
3 stages (1 open),
drain feed forward
Electrostatic precipitator
(ESP) 99+ % efficiency,
330 SCA
4-cell induced draft
cooling tower, 333 MM
Btu/hr, 15°F cooling
range
1,430 tons per year -
onsite landfill
70%
24.0%
21.6%
15,790 Btu/kWh
69.9% (255 days/yr)
30 years
2-shell, 2-pass,
234,000 sq ft
6°F TTD, 2.5 inches Hga
7 stages (1 open),
drain feed backward
ESP (99% efficiency,
340 SCA)+lime slurry
FGD system (90% S02
removal) 4- 50°F reheat
Two 8-cell induced
draft towers, 2350-
MM Btu/hr, 30°F
cooling range
215,600 tons per year -
onsite landfill
89.7%
37.8%
35.1%
9,727 Btu/kWh*
69.9% (255 days/yr)
30 years
*Includes 78 MM Btu/hr natural gas for flue gas reheat; if excluded, the
above values would be 35.7% and 9,563 Btu/kWh.
11
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TABLE 4. SUMMARY COMPARISON OF STRAW/MANURE AND COAL
TO SPG CONVERSION PROCESSES
Process
Elements
Straw/Manure-to-SPG
7 MM SCFD (net)
Coal-to-SPG (HYGAS)
274 MM SCFD (net)
Plant Capacity
Product
Feedstocks
Onsite Storage
Feed Input Rate
Feed Preparation
Conversion Process
Raw Gas Cleanup and
Upgrading
Utility Generation
Flue Gas Cleanup
6.66 MMM Btu/day
SPG-7.01 MM SCFD at
950 Btu/SCF, 305 psig
Wheat straw — 8548 Btu/
Ib, 0.176% sulfur
Cattle manure — 1225
Btu/lb, 0.045% sulfur
Straw — 60,000 tons,
60 days
Manure — 15,000 tons,
15 days
Straw — 1000 tpd
Manure — 1000 tpd
Straw — grind, pulp and
slurry
Manure — pulp and slurry
Single-stage anaerobic
digestion, 10 day re-
tention (1 train)
Acid gas removal and
dehydration (1 train)
250 MMM Btu/day
SPG - 273.7 MMSCFD at
915 Btu/SCF, 1010 psig
Western subbituminous
coal — 8,800 Btu/lb,
0.51% sulfur
Coal — 1,515,000 tons,
14 days live, 60 days
dead
Coal - 20,472 tpd
Wet grind, slurry, and
preheat
Process steam - raw and
product gas heaters/
boilers
power - purchased
None required
Steam — oxygen gasification
(HYGAS) 600-1,850°F, 1200
psig (2 trains)
Gas quench, shift conversion,
acid gas removal, methana-
tion and dehydration
(2 trains)
Process steam and power -
process heat recovery and
coal-fired boilers/turbine
generators; oxygen - air
separation plants
Sulfur recovery via IFP
Stackpol process
(Continued)
12
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TABLE 4. (Continued)
Process
Elements
Straw/Manure-to-SPG
7 MM SCFD (net)
Coal-to-SPG. (HYGAS)
274 MM SCFD (net)
Acid Gas Cleanup
Byproduct Recovery
Heat Rejection
Solid Waste Disposal
Conversion Thermal
Efficiency
Overall Thermal
Efficiency
Plant Load Factor
Plant Operating Life
Incineration
None
2-cell induced draft
cooling tower, 25 F
range
24 MM Btu/hr
604,400 tons per year
residue — returned to
farmland, other buried
onsite
33.3%
31.9*%
90% (328.5 days/yr)
20 years
Sulfur recovery via IFP
Stackpol process
Sulfur 88.9 LTPD
Ammonia 88.8 STPD
Oil 4594 BPD
Maximum air cooling
4-cell induced draft
tower,
35°F range, 359 MM Btu/hr
785,200 tons per year ash-
returned to mine, other
buried onsite
69.7%
77.6**%
90% (328.5 days/yr)
20 vears
^"Deduction for fuel equivalent of purchased electric power
**Credit for heat value of by-products
13
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processes are totally different, but both produce medium-Btu raw gas. The
biogas is upgraded by carbon dioxide removal versus the more extensive upgrad-
ing required far the gasifier raw product gas. Air pollution controls in the
HYGAS plant are considerably more extensive than in the biogas plant. Some
oil, sulfur, and ammonia, however, are recovered as salable byproducts of gas
cleanup. The biogas plant produces proportionately more solid waste for dis-
posal, partially a result of the relatively low conversion of straw and manure
solids to gas. The use of digester residue as an animal feed is being actively
investigated by process developers. Instead of being disposed of as waste,
this residue may ultimately be the major salable product of a biogas plant.
The conversion efficiency of feed energy to SPG in the biogas plant is about
one-half the conversion efficiency of the HYGAS plant. Not enough is known
about the mechanism of methane production by anaerobic digestion to predict
whether a significant improvement in conversion efficiency can be achieved. A
more optimistic estimate of straw and manure conversion to methane could have
been made. An overall thermal efficiency of 40 percent would still be poor in
comparison with the coal gasification efficiency.
Wood and Coal to Synthetic Fuel Oil
The wood and coal liquefaction processes have a large difference in plant
capacity, but this difference does not greatly affect the relative process
efficiencies. The feed preparation and liquefaction processes are similar.
Table 5 provides a process comparison. The H-Coal process has a very complex
product separation and recovery system, producing naphtha as well as heavy
fuel oil. A heavy residuum from liquefaction is gasified to produce hydrogen
(reducing) gas in the H-Coal process. Reducing gas for wood liquefaction.is.
produced by partial pyrolysis of a separate wood feed stream. Both conversion
plants have air separation plants to provide high purity oxygen. Coal lique-
faction produces enough fuel gas to generate the plants' electric power require-
ments in power boilers, whereas electric power is assumed to be purchased in the
wood liquefaction case. (Onsite power generation could be provided with a
wood-fired power boiler.) Sulfur, ammonia, and phenols are recovered as
byproducts from cleanup of various gas and aqueous streams in coal liquefac-
tion. Few or no byproducts are produced in the wood liquefaction process.
Unreacted feed solids (mainly ash) are the major process solid wastes gen-
erated in both liquefaction plants.
The thermal conversion efficiency of wood-to-oil is about 20 percent lower
than that for the H-Coal process on a simple Btu basis. If the wood fuel
equivalent (say, 15,500 Btu/kWh) of purchased electric power is used, the
wood-to-oil thermal efficiency drops by 20 percent. An improvement in thermal
efficiency would result from a significant reduction in the carbon monoxide/
hydrogen gas generation requirements.
Process Summary
For each biomass-coal pair, the coal conversion process appears to enjoy a
significantly higher overall thermal efficiency. Efficiencies of biomass con-
version processes shown here are not considered to be optimistic, and improve-
ments are likely as the processes become better developed. The relatively iow
14
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TABLE 5. SUMMARY COMPARISON OF WOOD AND COAL
TO FUEL OIL CONVERSION PROCESSES
Process
Elements
Wood-to-Fuel Oil
1764 BPD
Coal-to-Fuel Oil (H-Coal)
66,856 BPD
Plant Capacity
Products
Feedstock
11.11 MMM Btu/day
Heavy fuel oil-1764 BPD,
-31.8°API, 0.01% wt
sulfur
Forest residue1 —
4,977 Btu/lb, <0.01% wt
sulfur
417.6 MMM Btu/day
Heavy fuel oil - 51,325 BPD,
1.8°API, 0.5% wt sulfur
Naphtha - 15,531 BPD,
38.2°API, 0.02% wt sulfur
Bituminous coal — 11,900
Btu/lb, 4.45% wt sulfur
Onsite Storage
Feed Input Rate
Feed Preparation
Conversion Process
Product Recovery
120,000 tons, 60 days
1965 tpd
Grind, dry, and slurry
with hot recycle oil
Catalytic liquefaction
with CO/H2 gas, 6509F,
2500 psia — helical
coil reactor & soak
vessel (2 trains)
Reactor product flash,
solvent dilution, fil-
tration, vacuum distil-
lation and catalyst ex-
traction (2 trains)
1,756,000 tons, 3 days live,
60 days dead
27,836 tpd
Grind, dry, and slurry with
recycle oils and preheat
Catalytic liquefaction
with H2, 850QF, 3,000 psig -
ebullated reactor (6 trains)
Reactor product vapor-liquid
separation, slurry flash
and hydroclone concentration,
slurry stripping and solvent
deashing, fractionation and
naphtha stabilization (mul-
tiple trains)
Reduction Gas
Generation
Wood pyrolysis (PUROX )
scrubbing and acid gas
removal (BenfieldR)
Heavy residuum gasification
(Texaco Partial Oxidation) ,
quench, shift conversion,
acid gas removal (Selexol )
(Continued)
15
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TABLE 5. (Continued)
Process
Elements
Utility Generation
Heat Rejection
Wood-to-Fuel Oil
1764 BPD
Oxygen — air separation
plant
Steam — wood-fired boiler.
Power — purchased
Byproduct Recovery none
3-cell induced draft
cooling tower, 30 F range,
90 MM Btu/hr
Solid Waste Disposal —8,680 tons per year —
buried in onsite land-
fill
Conversion Thermal
Efficiency
Overall Thermal
Efficiency
Plant Load Factor
52.8% (HHV)
42.1%* (HHV)
91.3% (8000 hr/yr)
Plant Operating Life 20 years
Coal-to-Fuel Oil (H-Coal)
66,856 BPD
Oxygen — air separation plants
process steam and power —
process heat recovery and
process fuel gas — fired
boilers & turbogenerators
Sulfur (Glaus) - 1052.2 LTPD
Liquid ammonia
(Chevron WWT) - 180.2 STPD
Mixed phenols — 17.9 STPD
Air coolers and two 7-cell
induced draft towers (pro-
cess cooling), two 6-cell
towers (power plant cooling),
35 F range
~1,330,000 tons per year —
offsite disposal in valley
landfill
65.5% (LHV)
67.7%** (LHV)
91.3% (8000 hr/yr)
20 years
""Deduction for fuel equivalent of purchased electric power
**Credit for heat value of byproducts
16
-------
heating values of the biomass feedstocks are a distinct disadvantage with
respect to coal because more material must be handled per unit of energy
content.
ECONOMIC COMPARISON
Capital and operating costs were estimated for each conceptual plant at first
quarter 19-78 wage and price levels. Estimates for the three biomass plants
and the coal-fired power plant were based on Bechtel conceptual designs. Appen-
dix C summarizes the cost estimating methods. Cost estimates by C.F. Braun
& Co. (5) and Fluor Engineers and Constructors (6) for the HYGAS and H-Coal
plants, respectively, were escalated to first quarter 1978 dollars.
Table 6 summarizes the capital and operating costs for the six conceptual con-
version plants. The small capacities of the biomass conversion plants do result
in cost penalties relative to the coal conversion plants since some economy of
scale is lost.
TABLE 6. SUMMARY OF CAPITAL AND ANNUAL OPERATING COSTS*
BIOMASS AND COAL CONVERSION
Biomass and Coal Cases
Total
Capital
Cost
$1,000,000
Annual
Operating
Cost**
$1,000,000
476 MWe Coal-Fired Power Plant 384.0
45 MWe Wood-Fired Power Plant 54.2
250 MMM Btu/day Coal Gasification Plant 1,213.2
6.66 MMM Btu/day Biogas Plant 85.2
66,856 bbl/day Coal Liquefaction Plant 1,640.0
1,764 bbl/day Wood-to-Oil Plant 99.1
14.8
2.2
53.6
6.5
108.8
11.1
*First quarter 1978, price and wage levels
**Excluding feedstock costs
Capital investments for the power plants are about $1200/kW and $800/kW (net)
for wood and coal, respectively. Annual operating expenses, excluding feed-
stock, are about 8 mills/kWh and 5 mills/kWh, respectively. Both the capital
and operating costs for a several hundred megawatt wood-fired plant might be
closer to the 500 MWe coal-fired plant, but plants in that size range are
probably impractical at present.
For the synthetic pipeline gas plants, the capital investment per million
Btu/day of output is about $12,800 for the biogas plant and about $4850 for
17
-------
the HYGAS plant. The escalation in Braun's 1976 HYGAS estimate was about 14 per-
cent (5). Annual operating expenses, exluding feedstock, are about $2.97/MM Btu
and $0.65/MMBtu, respectively. In this instance, it appears unlikely that a
massive biogas (straw and manure) installation, even if practical, would be com-
petitive with HYGAS.
The total capital cost for the H-Coal plant was escalated from Fluor's 1975
estimate (6). This 1978 investment is about $24,500 per barrel per day (BPD)
of product or about $3930 per MM Btu/day. For wood liquefaction the invest-
ment is about $56,200/BPD or $8920 per MM Btu/day. Similarly, the annual oper-
ating expense, exluding feedstock, is about $4.90/bbl for H-Coal versus about
$18.90/bbl for wood liquefaction. On a Btu basis, the operating expense com-
parison is about $0.78/MM Btu output versus $3.00/MM Btu. The comparison with
synthetic fuel oil from coal is not very favorable.
The ERDA-AGA Gas Cost Guidelines were used to look at the conversion economics
on a more formal and consistent basis (8). Both private and utility financing
methods were used for each plant. Table 7 shows the annual plant feedstock
inputs and product outputs. Tables 8 and 9 illustrate the effect of feedstock
cost on the cost of clean energy products for the three pairs of plants.
The comparison indicates that wood-to-power at zero wood cost would be econo-
mically competitive with coal-to-power at about $25 per ton coal cost. The
28.5 mills/kWh base cost of electricity (utility financing) is not much higher
than approximately 23 to 26 mills/kWh estimated by SRI (9) and Mitre (10) for
approximately 50 MWe wood-fired plants with considerably higher thermal effi-
ciencies.* It is also apparent that the cost of electricity is quite sensitive
to wood costs, about 1.7 mills/kWh for each dollar per ton of wood. This is
about 4.5 times the increase in the cost of electricity for each dollar per
ton of coal increase for the larger coal-fired plant.
The cost of SPG from the biogas plant with either utility or private financing
is several times what might be considered a reasonable (unregulated) gas cost
today of, say, $2 to $2.50/MM Btu. Again the effect of feedstock cost on gas
cost is large for the low capacity biogas plant. The effect is less dramatic
for the large coal gasification plant. Other published estimates for SNG from
biomass tend to be on the more optimistic side, mostly in the $3 to $4/MM Btu
range (excluding feed costs) for anaerobic digestion and for gasification of
various biomass materials (9, 10, 12). In this estimate at least, it does not
appear that the biogas-derived SNG is competitive with coal-derived SNG from
the HYGAS plant. Large economies of scale in the biogas plant are probably
not possible either. If the digester residue were salable as an animal feed,
then the plant economics could be much improved.
The economic comparison of wood and coal-to-oil indicates similar disparities
in production costs and in the effects of feedstock cost on the cost of oil.**
*., A m°re recent SRI Deport shows about 38 mills/kWh for_ a 50 MWe plant (11).
** A recent SRI report (11) shows a $3.50/MM Btu oil cost (private financing
excluding feedstock) for a 5268 BPD catalytic liquefaction of wood plant°
versus about $6/MM Btu (utility) and $9/MM Btu (private) estimated here.
18
-------
TABLE 7. ANNUAL INPUTS AND OUTPUTS REQUIREMENT
USING CONSISTENT LOAD FACTORS
Load Factor
Input
Output
Wood-to-Power 255 days/yr,
69.9%
Coal-to-Power 255 days/yr,
69.9%
Wood -
477,207"tons, or
4.357 trillion Btu
at 9.13 MM Btu/ton
Coal -
1,068,720 tons or
27.857 trillion Btu
at 26.066 MM Btu/ton
Power (net)-
275.9 MM kWh
0.9416 trillion Btu
Power (net)-
2,913 MM kWh
9.942 trillion Btu
Straw/Manure 328.5 days/yr,
to-Gas 90.0%
HYGAS
328.5 days/yr,
90.0%
Straw -
328,500 tons or
4.71 trillion Btu
at 14.34 MM Btu/ton
Manure -
328,500 tons or
0.96 trillion Btu
at 2.92 MM Btu/ton
Coal -
6,725,000 tons or
118.36 trillion Btu
at 17.60 MM Btu/ton
Gas -
2.1886 trillion Btu
2,304 MMSCF
Gas -
82.125 trillion Btu
89,910 MMSCF
Wood-to-Oil
H-Coal
333.3 days/yr,
91.3%
333.3 days/yr,
91.3%
Wood -
655,000 tons or
6.52 trillion Btu
at 9.954 MM Btu/ton
Coal -
9,277,740 tons or
220.8 trillion Btu
at 23.80 MM Btu/ton
Oil (Fuel Oil) -
588,000 bbl
3.704 trillion Btu
(HHV)
Oil (Naphtha and
Fuel Oil) -
22,283,200 bbl
139.186 trillion
Btu (LEV)
19
-------
TABLE 8. ECONOMIC COMPARISON SUMMARY FOR BIOMASS AND COAL CONVERSION
PROCESSES (BASED ON $/TON)
BIOMASS CONVERSION
COAL CONVERSION
Wood-to-Power (45 MWe)
Wood Cost
$/ton
0
10
20
30
40
Power Cost, Mills/kWh
Utility
28.5
45.8
63. 1
80.4
97.7
Private
45.5
62.8
80.1
97.4
114.7
Straw/Manure-to-Gas (6.66 MMM Btu/day)
Straw
$/ton
0
5
10
15
20
25
Manure
$/ton
0
1
2
3
4
5
Gas Cost, $/MM Btu
Utility
7.68
8.58
9.48
10.38
11.28
12.19
Private
10.63
11.53
12.43
13.33
14.23
15. 13
Wood-to-Oil (1,764 BPSD)
Wood Cost
?/ton
0
10
20
30
40
Fuel Oil Cost, $/bbl
Utility
39.23
50.37
61.51
72.65
83.79
Private
51.99
63.13
74.27
85.41
96.55
Coal-to-Power (476 MWe)
Coal Cost
$/ton
0
10
20
30
40
Power Cost, Mills/kWh
Utility
19.0
22.7
26.4
30.0
33.7
Private
32.0
35.6
39.3
43.0
46.6
Coal Gasification-HYGAS (250 MMM Btu/day)
Coal Cost
$/ton
0
5
10
15
20
25
Gas Cost, $/MM Btu
Utility
2.42
2.84
3.25
3.66
4.07
4.48
Private
3.75
4. 17
4.60
5.02
5.44
5.87
Coal Liquef action -H-Coal (66,856 BPSD)
Coal Cost
$/ton
0
10
20
30
40
Fuel Oil Cost, $/bbl
Utility
13.72
17.91
22.10
26.28
30.47
Private
20.37
24.57
28.78
32.98
37. 18
20
-------
TABLE 9. ECONOMIC COMPARISON SUMMARY FOR BIOMASS AND COAL CONVERSION
PROCESSES (BASED ON $/MM BTU)
BIOMASS CONVERSION
COAL CONVERSION
Wood-to-Power (45 MWe)
Wood Cost
$/MM Btu
0
1
2
3
4
Power Cost, Mills/kWh
Utility
28.5
44.3
60.1
76.0
91.8
Private
45.5
61.3
77.2
93.0
108.8
Straw/Manure-to-Gas (6.66 MMM Btu/day)
Straw Manure
S/MM
0
0.5
1.0
1.5
2.0
2.5
Btu S/MM Btu
0
0.5
1.0
1.5
2.0
2.5
Gas Cost, S/MM Btu
Utility
7.68
8.98
10.27
11.57
12.86
14. 16
Private
10.63
11.93
13.22
14.52
15.81
17. 11
Wood-to-Oil (1,764 BPSD)
Wood Cost
S/MM Btu
0
1
2
3
4
Fuel Oil Cost, $/bbl
Utility
39.23
50.32
61.41
72.49
83.58
Private
51.99
63.08
74.17
85.26
96.35
Coal-to-Power (476 MWe)
Coal Cost
$/MM Btu
0
0.5
1.0
1.5
2.0
Power Cost, Mills/kWh
Utility
19.0
23.8
28.6
33.4
38.2
Private
32.0
36.7
41.5
46.3
51.1
Coal Gasification-HYGAS (250 MMM Btu/day)
Coal Cost
S/MM Btu
0
0.25
0.50
0.75
1.00
1.25
Gas Cost, S/MM Btu
Utility
2.42
2.79
3.15
3.51
3.87
4.24
Private
3.75
4.12
4.49
4.87
5.24
5.61
Coal Liquefaction-H-Coal (66,856 BPSD)
Coal Cost
S/MM Btu
0
0.5
1.0
1.5
2.0
Fuel Oil Cost, S/bbl
Utility
13.72
18.70
23.69
28.67
33.65
Private
20.37
25.37
30.37
35.37
40.37
21
-------
The two to three times higher cost factor could be reduced by a combination^
of: (1) improvement in wood conversion efficiency, (2) increase in plant size,
and (3) a relative price advantage of wood versus coal.
On the basis of these economic estimates, the three biomass conversion plants
do not produce clean energy products at costs competitive with current prices
of the same or similar products; neither do the coal gasification and lique-
faction plants. The product costs do not appear to be competitive with those
for large-scale coal conversion facilities, except perhaps for wood-to-power.
It is likely that the product cost,differentials could be reduced by process
improvements and more favorable comparison assumptions. For example, product
distribution costs were excluded in all cases. Distribution costs for biomass-
derived energy products used locally could be considerably lower than the costs
for distribution of coal-derived products from large conversion plants.
ENVIRONMENTAL COMPARISONS
As in the economic comparison, the effect of the disparate plant sizes makes
an environmental comparison difficult. The biomass conversion plants have
an economic disadvantage (small capacity) and an environmental advantage (small
capacity) which must be kept in mind.
Sections 3, 4, and 5 present brief descriptions of the regional settings and
hypothetical sites for both biomass and coal scenarios. These section-s sum-
marize the environmental impacts which would be expected to occur at the hypo-
thetical sites should biomass or coal scenarios be implemented. Similar sum-
maries of impacts were also presented for feedstock procurement scenarios.
In this report, pairs of biomass and coal facilities are compared with respect
to the types and magnitudes of impacts anticipated. Where possible, impacts
are described on a per unit basis (e.g., acres per kWh, mg/1 per Btu, etc.)
to permit a more direct comparison of facilities which are widely different in
size or production capacity. However, many impacts either cannot be quantified
(e.g., aesthetics) or may not be linearly proportional to the facility size
(e.g., acres of land committed); these potential problem areas in comparison
are identified as they arise in the discussions.
Biomass and coal facilities (and feedstock procurement) have been paired accord-
ing to the product of the process, with site characteristics kept about the
same within the pair. Since site factors can influence impacts and impact mag-
nitude, different processes cannot be directly compared in this study. Also,
impacts from actual implementation of a coal or biomass plant may vary since
site characteristics will probably differ from the hypothetical descriptions
given in this report. Factors such as aesthetic resources, i.e., the visual
worth or scenic value of a location, are highly site-specific. Therefore, the
range and general nature of impacts expected are indicative only of differ-
ences between similar processes which may be used to determine environmentally
preferable alternatives, potential areas for continued study, and areas where
mitigation may be profitably applied.
Construction of a conversion plant, like that of any industrial facility,
involves site preparation, building construction, transportation access,
22
-------
and utility hookups. These activities affect land use on the plant site; the
site becomes committed for use by the plant for the operating life of that plant
and, in the case of refuse disposal or mine reclamation, may be permanently
altered. These land use changes and other effects, such as water pollution from
site erosion or waste discharge, air pollution from fugitive dust and equipment
emissions, traffic congestion, an influx of people and money into the region,
and a demand on community services, are generic to all scenarios, regardless
of feedstock, product, or location. However, the significance of these impacts
does vary with type of feedstock used (wood, straw/manure, or coal), the prod-
uct (electricity, synthetic pipeline gas, or synthetic fuel oil), the location
(south central, midwest, eastern, or northeastern U.S.), and the size of the
facility.
Conversion plant operational impacts vary with the process as well as with the
feedstock, with air, water, and solid waste emissions the primary direct causes
of environmental impact. While the location and size of the plant are important,
the actual chemical composition of the wastes may be an overriding consideration
in determining the significance of the impacts.
Feedstock procurement affects the environment by the removal of a material. The
significance of the impact depends on the area affected and the amount of phys-
ical disturbance of that area.
A numerical rating system with nonweighted factors (Table 10) is used here to
compare general feedstock procurement and plant impacts for each biomass-coal
pair. Relative (to plant output) rather than absolute impacts are compared to
avoid the obvious conclusion that small biomass .plants will have less impact
than large coal plants.
Scenario 1
Conversion of forest residues or coal to electricity will result in roughly
the same rates of consumption of natural resources (Table 11), although the
wood conversion plant requires more feedstock because of the lower Btu value
of the fuel and the lower conversion efficiency. Feedstock procurement for
the coal-fired plant will have significantly more potential for impact due to
the need to remove topsoil and overburden to get at the coal (Tables 10, 12).
Impacts on air, water, soils, ecology, and aesthetics are particularly impor-
tant to this analysis. Strip mining will result in physical changes that have
both short-term and long-term impacts. Even though much more land area is
affected by residue collection, actual physical changes to the harvested areas
will be much less pronounced than if mining were to occur. Prompt reclamation
of strip-mined areas can help mitigate the impacts of physical distrubance.
While the coal-fired power plant is larger and therefore will contribute more
energy to the power grid, the overall environmental impact per MWe will be
similar in type and extent for both wood and coal (Tables 10, 12). Air and
water emissions will be roughly similar in type and relative quantity, although
considerably more sulfur dioxide per kWh output will be released by the coal-
fired plant even with 90 percent sulfur dioxide (S02) removal. The coal-fired
plant also will produce much more solid waste (more ash in coal and the SC>2
scrubber sludge). The chemical makeup of coal ash and the potential leachate
23
-------
TABLE 10. SAMPLE NUMERICAL RATINGS FOR QUALITATIVE ASSESSMENTS
Scale Environmental Qualitative Assessment
+10 Significant benefit
9
8
7
6
5 Moderate benefit
4
3
2
+1 Insignificant benefit
0 No discernible impact
-1 Insignificant adverse short-term impact
2
3 Moderate adverse short-term impact
4
5 Significant adverse short-term impact
6 Insignificant adverse long-term impact
7
8 Moderate adverse long-term impact
9
-10 Significant adverse long-term impact
24
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TABLE 11. COMPARISON OF PRINCIPAL RESOURCE REQUIREMENTS -
WOOD AND COAL TO POWER
Resource Category
Normalized Units
Wood-to-Power
45 MWe (net)
Coal-to-Power
476 MWe (net)
Land, acres /MWe
Feedstock, Ib/kWh (Btu/kWh)
Auxiliary Fuel, Btu/kWh
Power (Consumed) , kW/kW
Chemicals, Ib/kWh
Water, gal/kWh
Manpower , men/MWe
1.1
3.46 (15,790)
188
0.109
0.00046
0.82
0.67
0.77
0.734
169
0.06
0.022
0.51
0.2
(9,563)
from disposal can prevent significant adverse impacts. Overall, the wood-fired
plant may be environmentally preferable in this scenario because of the poten-
tially lower impact of feedstock procurement.
Scenario 2
The HYGAS process for conversion of coal to synthetic gas will consume fewer
natural resources per Btu of product than the straw/manure to SPG process
(Table 13), partly because of the higher Btu feedstock and higher conversion
efficiency and partly because of the economy of scale in the plant. As in
Scenario 1, feedstock procurement for HYGAS, which will involve surface mining,
will have potentially more adverse impact on air, water, soils, ecology, aes-
thetics, and land use (Tables 10, 14), although straw procurement will require
a larger commitment of acreage. Care must be exercised in the collection of
the wheat straw to avoid significant damage to soils, but otherwise there would
not be the actual physical disturbance to land that would occur in mining.
Plant air emissions of fugitive dust and hydrocarbons would be relatively lower
for the biogas plant, but nitrogen oxides emissions could be higher. Both
plants could have potential solid waste disposal problems. The biogas plant
will have much more residue to dispose of, but the potential for use as a soil
conditioner or cattle feed may offset the disadvantage of its large quantity
relative to HYGAS ash. The potential for hazardous materials in some air
emissions and solid wastes from the HYGAS process is of concern, but the over-
all extent of the plant's regional impact will be similar to that of the biomass
25
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TABLE 12. RELATIVE ENVIRONMENTAL IMPACT SUMMARY
OF WOOD AND COAL TO POWER*
Site Specific Feedstock Procurement
Factors
Wood Residue Coal
Climatology and
Meteorology 0 0
Air Quality -1 -1
Surface Water
Availability 0 -1
Surface Water
Quality -1 -6
Groundwater
Availability 0 -7
Groundwater
Quality 0 -7
Soils, Geology -7 -9
Land
Availability -1 -1
Ecology 1 -7
Aesthetic
Resources 1 -8
Historical,
Archaeological
Resources 0 -7
Community
Economy 5 5
Community
Population
and Services 0 -6
Labor
Availability 1 __[
Power
Availability 0 0
Transportation
Availability -6 -6
TOTAL -8 -62
Conversion
Plants
Wood Coal
-1 -1
-6 -6
-1 -1
-1 -1
0 0
-6 -6
-6 -8
-6 -6
-6 -6
-7 -8
-6 -6
5 5
-1 -2
-1 -1
5 10
-6 -6
-44 -43
*See Table 10 for rating scale.
26
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TABLE 13. COMPARISON OF PRINCIPAL RESOURCE REQUIREMENTS -
STRAW/MANURE AND COAL TO SPG
Resource Category,
Normalized Units
Straw/Manure-to-SPG
6.66 MMM Btu/day
Coal-to-SPG (HYGAS)
250 MMM Btu/day
Land, acres/MM Btu/hr
Feedstock, Ib/MM Btu
Auxiliary Fuel, Btu/MM Btu
Power (Consumed), kW/MM
Btu/hr
Catalysts and Chemicals,
0.5
600.4
544
19.6
0.07
163.8
134
0
Ib/MM Btu
Water, gal/MM Btu
Manpower, mh/MM Btu
5.6
42.9
0.09
0.071
11.1
0.019
conversion process (Table 14). Excluding the feedstock procurement impacts,
neither process would have a clear environmental advantage.
Scenario 3
The rate of consumption of resources per million Btu of product oil will be
greater for wood-to-oil conversion than for coal-to-oil (H-Coal) conversion
as indicated in Table 15. This again is due to the lower Btu value of the
feedstock, the lower conversion efficiency, and the smaller scale of the wood-
to-oil plant. The high waste heat load does result in a greater water consump-
tion for H-Coal. Waste disposal for the deep coal mine, and associated impacts
on water and topography, result in greater potential for adverse impact for
coal procurement than for forest residue collection (see Table 10, 16). The
difference in feedstock procurement impact is similar to that described for
Scenarios 1 and 2. Physical/chemical emissions from the plants will be roughly
similar overall, with individual pluses and minuses for both plants. Waste-
water from both plants may be difficult to clean up and potentially could con-
tain hazardous compounds. The H-Coal plant will generate considerably more
solid waste residue for disposal. As in the other processes, there is no
apparent overall difference in significance of adverse plant operational impacts
However, the potential for the presence of hazardous materials in H-Coal wastes
could present a problem for air, water, and biological environments. Careful
27
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TABLE 14. RELATIVE ENVIRONMENTAL IMPACT SUMMARY
OF STRAW/MANURE AND COAL TO SPG-
Site Specific
Factors
Climatology and
Meteorology
Air Quality
Surface Water
Availability
Surface Water
Quality
Ground-water
Availability
Groundwater
Quality
Soils, Geology
Land
Availability
Ecology
Aesthetic
Resources
Historical,
Archaelogical
Resources
Community
Economy
Community
Population
and Services
Labor
Availability
Power
Availability
Transportation
Availability
TOTAL
Feedstock Procurement
Straw/Manure Coal
0 0
-6 -2
0 -1
-1 -6
0 -7
0 -7
-7 -8
0 -1
0 -7
0 -8
0 -7
5 5
0 0
1 1
0 0
-6 -6
-14 -54
Conversion
Plants
Straw /Manure
-1
-6
-1
-1
-6
-6
-7
-6
-6
-7
-6
5
-1
-1
5
-6
-51
Coal
-2
-6
-1
-1
-6
-7
-6
-6
-6
-7
-7
5
-2
-2
10
-6
-48
*See Table 10 for rating scale.
28
-------
TABLE 15. COMPARISON OF PRINCIPAL RESOURCE REQUIREMENTS -
WOOD AND COAL TO FUEL OIL
Resource Category,
Normalized Units
Wood-to-Fuel Oil
1,764 BPD
Coal-to-Fuel Oil
(H-Coal)
66,856 BPD
Land, acres/MM Btu/hr
Feedstock, Ib/MM Btu
Auxiliary Fuel, Btu/MM Btu
Power (Consumed) , kW/MM Btu/hr
Catalysts and Chemicals,
Ib/MM Btu
Water, gal/MM Btu
Manpower, mh/MM Btu
0.24
353.7
3,590
39.5
1.15
27.2
0.078
0.024
133.3
79
Net production
0.545
31.35
0.011
management of waste disposal can minimize potential environmental problems.
Because of the lower feedstock procurement impact, the x^ood liquefaction facil-
ity might be considered a better environmental choice in this scenario.
CONCLUSIONS AND RECOMMENDATIONS
Four of the six conversion processes can be considered as advanced processes
not yet in the commercial-plant stage that was assumed in the scenarios. Much
developmental work is still needed to provide detailed engineering data for
commercial installations. Similarly, more experimental data are needed to
adequately characterize environmental emissions from both the biomass and
coal conversion processes. Pollution control technologies applicable to the
processes need further evaluation to identify best available technologies and
their effectiveness and costs. Some of this work is already underway, and no
specific recommendations are offered.
It is felt that this type of scenario comparison of hypothetic commercial-scale
plants is a useful way of identifying major advantages and disadvantages of
biomass versus coal conversion. This approach also illustrates, mainly by
data absence, places where important information is needed to make proper
comparative evaluations. Publication of up-to-date process and environmental
information from pilot and demonstration-scale biomass conversion facilities
would help to make these types of evaluations or comparisons more useful. It
29
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TABLE 16. RELATIVE ENVIRONMENTAL IMPACT SUMMARY OF
WOOD AND COAL TO SYNTHETIC FUEL OIL*
Site Specific
Factors
Climatology and
Meteorology
Air Quality
Surface Water
Availability
Surface Water
Quality
Groundwater
Availability
Groundwater
Quality
Soils, Geology
Land
Availability
Ecology
Aesthetic
Resources
Historical,
Archaeological
Resources
Community
Economy
Community
Population
and Services
Labor
Availability
Power
Availability
Transportation
Availability
TOTAL
_ , ' , _ Conversion
Feedstock Procurement „,
Plants
Wood Residue Coal Wood Coal
0 0-1-1
-1 -1 -6 -9
o o-oo
-1 -7 -1 -i
0 -700
0 -6 -6 _6
-7 -8 -6 _6
-1 -6 -6 _6
1 -9 -6 _6
i n
1 -3 -10 -9
n ^
° 0 -6 _6
5 5 5 r
J j
0 0 _! _!
-*- J.
1 0 -i _!
n r,
U ° 5 10
-6 -6 -6 _6
-48 -46 _43
-See Table 10 for rating scale
30
-------
is also recognized that many biomass conversion (and coal conversion) processes
are proprietary in nature, and hence certain process and environmental details
will remain unavailable to the public. A standard method of cost estimation
and economic analysis would also be useful to many organizations so that eco-
nomic comparison of different biomass conversion processes could be made more
easily.
From this scenario study, several conclusions and recommendations can be made
for biomass versus coal, using coal conversion as the basis for comparison.
Biomass conversion plants will almost intrinsically be of small commercial scale,
given the low area densities and low bulk densities of most biomass materials
compared with coal deposits. Thus, biomass conversion plants will almost
intrinsically suffer losses of economy-of-scale with respect to the much larger
coal conversion facilities. Conversion efficiencies of the three biomass con-
version processes were lower on a Btu-in/Btu-out basis than the three respective
coal conversion processes. These two factors combine to make the production
costs of clean energy from biomass considerably higher than the costs of similar
products from coal. Low biomass feedstock costs relative to coal appear to be
very important to the economic viability of biomass conversion.
Environmental impacts of the three biomass conversion plants themselves (i.e.,
without including resource collection) will be smaller in an absolute sense
because the plants are smaller. On a relative basis, the impacts may be of
different types in some cases, but the overall plant impacts are similar (the
processing plants do basically the same thing, but the scale is different).
If the coal conversion plants were on the same small scale, the biomass con-
version plants would be environmentally preferable. Pollution control invest-
ments for large coal conversion facilities will be extensive, but these control
costs, though substantial, will not shift the economics enough to favor small-
scale biomass conversion plants with their lower conversion efficiencies.
That is, the cost of reducing pollutant emissions to environmentally accept-
able levels does not dominate the economics of coal conversion.
Collection of biomass residues from farmland and forestland should have fewer
adverse environmental consequences than coal mining. Management programs would
be needed to avoid overharvesting of residues. Experimental test collection
programs should be carried out to determine optimum harvesting schemes and
costs. There is also the environmental benefit of utilizing a renewable
resource rather than a nonrenewable material such as coal. Low-cost methods
of improving the heating values (removing moisture) and increasing the bulk
densities of biomass materials are needed to offset these disadvantages with
respect to coal, at least in thermal biomass conversion processes.
Of the three biomass conversion processes, wood-fired power plants appear to
offer the best possibility for near-term implementation. There are, of course,
many wood-fired steam and power boilers operating today in the pulp and paper
industry. In wood-rich areas where the cost of purchased electricity or the
cost of fossil fuels is high, wood-fired plants should be logical candidates
for economic evaluation. Co-firing of wood and fossil fuels in steam-electric
generating units may become more widespread if retrofit costs can be overcome
31
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by a lower wood fuel cost. Larger, more efficient wood-fired generating sta-
tions are a possibility in the future if delivered wood fuel costs can be kept
low.
Anaerobic digestion of biomass is unlikely to become a major route to high-Btu
gas. A better understanding of the biological conversion mechanisms is an
important research need. The practical goal is a significant improvement in
conversion efficiency. For the present, however, evaluations of anaerobic
digestion should focus on a more favorable application such as:
* Small-scale plants producing medium-Btu gas (no upgrading) for
local consumption (e.g., industrial fuel or gas-turbine power
generation)
• Low cost, intrinsically wet feedstock produced year-round in
high local concentration (e.g., cattle manure from a large
feedlot or manure plus microalgae produced from feedlot
waste)
• Evaluation of unconverted residue as animal feed or soil amend-
ment (i.e., a salable byproduct is needed)
Wood liquefaction is also unlikely to become a major route to fuel oil. Further
experimental work on conversion processes (both pyrolysis and catalytic reduc-
tion) may lead to significant improvements in yields and oil properties, but
there is a very substantial economic disadvantage to overcome.
Investigation of other scenarios should be more attractive for biomass con-
version: for example, chemical synthesis from cellulose materials and produc-
tion of ethanol by hydrolysis/fermentation processes. A combination of three
factors is desirable:
• A relatively low-priced biomass feed material
• A process that has a relatively high conversion (actual or
potential)
• A higher-priced product than oil or gas
If the economics improve, then the relative environmental benefits of biomass
conversion versus coal conversion will become a more persuasive force toward
renewable resource utilization. At this point, however, coal conversion into
clean fuels such as gas and oil seems much more promising because of the clearly
superior economics.
32
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SECTION 3
SCENARIO 1-
WOOD AND COAL TO POWER IN THE SOUTH CENTRAL REGION
In this scenario, a 50 megawatt (MWe) wood-fired power plant and a 500 MWe
coal-fired plant are to be constructed and operated in the south central
region of the U.S. Figure 5 indicates the regional location. Each plant
will be located at a similar, hypothetical site. Offsite power transmission
facilities are excluded from the scope.
A regional environmental setting is presented as well as brief site descrip-
tions. The settings provide a background for assessing the general impacts of
feedstock procurement and of plant operation. Environmental assumptions in-
clude the applicability of proposed (draft) new source performance standards
(NSPS) for electrical utility steam generating units of more than 250 MM Btu/hr
input capacity (see Table 2). There are no unusually stringent state or local
or environmental regulations that are assumed to be applicable. Preconstruc-
tion environmental costs are excluded from consideration, however.
REGIONAL ENVIRONMENTAL SETTING
The biomass and coal energy conversion plants are located at a hypothetical
location in the Southern Coastal Plains of the U.S. in a state such as Georgia,
Alabama, or Tennessee. The following sections describe this region's environ-
mental setting.
Land Use
Except for small urban use, almost all the land area in the region is in farms.
Federal land ownership is quite limited. One-half to three-fourths of the
area is woodland, most in small holdings, but some in large tracts. The pro-
portion of woodland is greatest in the western portion of the region. Crop-
land area varies between one-third of total in the east to about one-tenth in
the west. Less than one-tenth of the area is in pasture. A recent trend is
to more pasture and woodland and less cropland (13).
The Southern Coastal Plains region is the heart of the old Cotton Belt. Cotton
has long dominated regional agriculture as a cash crop. General farming based
on cotton, corn, and forage crops is the rule (14). Tobacco is important in
sections of Georgia and the Carolinas, peanuts are important in southwestern
Georgia and neighboring parts of Alabama, and potatoes are important in south-
western Alabama.
33
-------
Lo
-P-
Flgure 5. Wood and coal to power region — Scenario 1,
-------
Topography and Elevation
The Southern Coastal Plains form a belt up to 400 miles wide around the Gulf
of Mexico.
The topography is diverse. The elevation generally varies between 100 and 600
feet, increasing gradually from the lower Coastal Plain to the Piedmont.
Stream valleys are narrow in their upper reaches, but in the lower parts they
broaden out and form widely meandering stream channels. Local relief is main-
ly in a few tens of feet, but some of the more deeply dissected parts exhibit
relief of 100 to 200 feet (13).
Climate
Average annual precipitation varies between 40 and 60 inches. Between 50 arid
70 percent of the total annual rainfall occurs during the cool season, October
to March. The frequent shortage of rainfall in the crop growing season is a
perennial problem in the region (13, 14).
The region has a long growing season and mild winters. The number of frost-
free days ranges from 200 days per year in the north to 280 days in the ex-
treme south. The average winter temperature is abour 45°F throughout the
area. The average annual temperature ranges between 60 F in the north and
68°F in the south.
Soils
Red-yellow Podzolic soils dominate the region. They developed generally from
a variety of parent materials under conditions of a high degree of weathering
and leaching of bases. The soils are predominantly acid and low in organic
matter and in plant nutrients. The soils developed from marine sands and
clays, and the predominantly sandy surfaces are naturally erosive. Under
high-intensity rains during spring and summer, soil loss is a big problem,
especially on hilly terrain. Moreover, the coarse-textured soils do not hold
the moisture well. At the other extreme, some areas of clay and sandy clays
(low-humic gley and humic gley soils) are found which often do not permit
ready infiltration (13, 14, 15).
Vegetation
Two majnr forest and range ecosystems in the Southern Coastal Plains are the
"longleaf-slash pine" and the "loblolly-shortleaf pine" ecosystems (16). The
latter is the largest ecosystem in the south and southeast in terms of area.
The longleaf-slash pine ecosystem is confined to flat and irregular southern
Gulf Coastal Plains on relief less than 300 feet. About 50 percent or more
of the stand is longleaf pine (Pinus palustris) or slash pine (P. elliottii).
Common associates include other southern pines, oak (Quercus spp.),, and sweet
gum (Liqui-dcmbar styrao^flua). On most sites, grasses either dominate the
understory or share dominance with shrubby vegetation. Wiregrasses (Aristida
spp.) are the dominant herbaceous plants east of the Apalachicola River, but
35
-------
in the western section bluestreams (Andropogon spp.) provide most of
herbage. More prominent shrubs are gallberry, saw-palmetto, waxmyrtle, and
shining sumac.
The loblolly-shortleaf pine ecosystem generally occurs on irregular Gulf Coast-
al Plains and the Piedmont on gently sloping lands. Local relief is 100 to
600 feet on the Gulf Coastal Plains and 300 to 1000 feet on the Piedmont.
Approximately 50 percent or more of the stand in this ecosystem is loblolly
pine (Pinus taeda)J shortleaf pine (P. echinata), or other southern yellow
pines. Common associates include oak, hickory (Carya spp.), black gum, red
maple (Acer rubrum), and winged elm (Ulmus alata). The main grasses are blue-
stems, panicums, and longleaf uniola. Dogwood (Cornus florida)., viburnum,
haw (Crataegus spp.)., blueberry, American beautyberry, yaupon, and numerous
woody vines are common (16, 17).
Wildlife
A wide variety of wildlife is found in the various regional habitats. White-
tailed deer are widespread. Rarely, the black bear or the endangered Florida
panther may be encountered in the longleaf-slash pine ecosystem. Common small
mammals include the raccoon and fox, which are hunted in many areas.
The longleaf-slash pine forest provides habitat for opposums, tree squirrels,
rabbits, and numerous species of ground-dwelling rodents. Wild turkey and
the bobwhite quail are common. Similarly, numerous resident and migratory
nongame birds and various species of migratory waterfowl are found. The red-
cockaded woodpecker is an endangered species. The reptiles are well repre-
sented. The largest of the reptiles is the endangered American alligator.
In the loblolly-shortleaf pine forest, wild turkey, bobwhite quail, and mourn-
ing dove are quite widespread. The pine warbler, cardinal, summer tanager,
Carolina wren, ruby-throated hummingbird, blue jay, hooded warbler, eastern
towhee, and tufted titmouse are very common in the mature forest.
WOOD-TO-POWER PLANT SITE DESCRIPTION
The biomass energy conversion plant is located in a rural area on purchased
farmland approximately one-quarter mile from a navigable river.
Topography and Elevation
The site, about 50 acres, is gently sloping with no major topographical fea-
tures and averages about 100 feet in elevation. Rolling to steeply sloping
hills rise to about 300 feet in elevation away from the river.
Transportation
A state highway passes within one mile of the plant and a major north-south
rail line is within \\ miles. The nearby river is a major waterway for ship-
ping in the state.
36
-------
Climate and Air Quality
The climate in the site is continental, but is occasionally influenced by
ocean breezes. The winters are mild and of short duration. Snow, sleet, and
chilly spells are rare. Summers are long and sometimes hot, but generally
tempered by ocean breezes. The average frost-free season is 230 days.
The annual rainfall of about 57 inches is generally well distributed, especial-
ly in the cropgrowing season. The driest months are September, October, and
November. The area is subject to occasional severe windstorms, hailstorms,
and tornadoes usually during February to May. Table 17 summarizes principal
climatic conditions at the hypothetical site.
Air quality in the site area is generally good; however, it is currently
listed as a nonattainment area for photochemical oxidants.
TABLE 17- ASSUMED CLIMATIC CONDITIONS
Elevation:
Temperature:
Annual Average
5-Percent Design
Conditions
Annual Minimum
Prevailing Wind:
Precipitation:
Annual Precipitation
Annual Runoff
Annual Lake Evaporation
1-yr, 24-hr "Storm
10-yr, 24-hr Storm
Annual Frost-Free Period:
100 feet
67 F dry bulb
61.5°F wet bulb
94°F dry bulb
79°F wet bulb
8°F
South at 6.6 mph
57 inches
25 inches
44 inches
3.5 inches
7.0 inches
230 days
37
-------
Land Use
The immediate vicinity of the site area is predominantly rural. A
is the manor industry. Corn and cotton are the main crops. Other crops of
mprance include winter oats, soybeans, hay, peanuts sorghum sweet potatoes,
fruit, and vegetables. Much of the area is in range and pasture. About
90,000 acres in the county are woodland.
Water Resources
River flow at the plant averages about 22,730 cfs with a minimum annual daily
dischar-e. of about 2000 cfs. Water quality is good; both hardness and^is-
solved solids are low. (See Table 18.) Mean annual temperature is 60 F with
a 44°F to 79°F range. All of the plant water requirements are supplied by
the river.
Soils
The site area lies within the region of the Red and Yellow Podzolic soils and
within the Gulf Coastal Plains physiographic region. Most soils are acidic
and have a light-colored surface soil with a much heavier textured subsoil.
Cattle are pastured on bottomlands near the river and woodlands. Most of the
area near the site is sloping to rolling in topography and very erosive, suited
mostly to forest. Some of the soil is very acid, very heavy and sticky clay,
too difficult to till, and is used for forestry.
Vegetation.and Wildlife
The site is principally wooded, with southern yellow pine species predominat-
ing. Some shrubby vegetation and grasses are also found, especially near the
river where timber clearing has occurred in the past. A small portion of this
area near the river is used for cropland. Wildlife on the site is typical of
that found in the region, small game animals (mammals and rodents) and a varie-
ty of resident and migratory bird species. No rare or endangered species is
known to inhabit the site.
FOREST RESIDUE PROCUREMENT
Approximately 480,000 tons (wet) per year of wood chips and bark are consumed
by the power plant. On the order of 1.7 million tons (dry) per year of logging
waste and collected forestry waste are located within 36 mean transport miles
of the plant site. Annual consumption is about 15 percent of this reportedly
available waste. In this scenario, the conversion plant owner purchases chips
delivered to the plant gate. However, feedstock procurement has associated
economic and environmental effects on biomass conversion and is briefly de-
scribed .
Most of the feedstock is purchased by contract from independent pulpwood pro-
ducers that harvest forestland mainly in private ownership. In addition to
supplying roundwood and some chips to mills in the area, the producers also
harvest logging residue for sale to the plant.
38
-------
TABLE 18. ASSUMED AVERAGE RIVER WATER QUALITY
Component
Value
Component
Value
pH 7.1
Temperature 44-7 9°F
Turbidity 35 JTU
Dissolved Oxygen 9 mg/1
Biochemical Oxygen Demand 3.3 mg/1
Chemical Oxygen Demand 12 mg/1
Total Dissolved Solids 80 mg/1
Calcium 15.9 mg/1
Magnesium 2.5 mg/1
Sodium 11.5 mg/1
Sulfate 38.4 mg/1
Chloride 4.3 mg/1
Bicarbonate 30.5 mg/1
Silica (as SiO ) 2 mg/1
Nitrate 0.3 mg/1
Nitrite 0.02 mg/1
Ammonia-Nitrogen 0.07 mg/1
Total Organic Nitrogen 0.3 mg/1
Phosphorus 0.1 mg/1
Arsenic 0.002 mg/1
Chromium-Total 0.015 mg/1
Copper 0.003 mg/1
Iron, Total 1.6 mg/1
Lead 0.002 mg/1
Manganese 0.013 mg/1
Mercury 0.001 mg/1
Zinc 0.02 mg/1
Phenols 0.001 mg/1
39
-------
Residues (culls, dead trees, stumps, tops, branches) are collected and
chipped in the forest by crews whether during conventional harvesting ot
round wood or separately during a second pass in the forest track. The crews
employ chainsaws for cutting and stripping and dozer-tractors (also mechanical
stump pullers) for residue movement to the mobile chippers. Manual collection
is also practiced. Chipped residue is blown into trucks for transport to con-
centration yards or directly to the plant if nearby. At the concentration
yards, the chips are unloaded, then reloaded onto larger truck-trailers and
rail hopper cars for shipment to the conversion plant. These yarding and
shipping operations allow scheduling of shipments to the plant on a regular
basis over the year.
Assuming a forest residue concentration of 15 to 17.8 tons/acre, a minimum of
27,000 to 32,000 acres of forestland would need to be harvested for residue
each year. Wood growth is about 1.3 tons/acre/year. More land area would
actually be affected, since it might not be desirable to practice complete
removal in many areas.
WOOD-TO-POWER PROCESS DESCRIPTION
Electric power generation from the combustion of wood wastes is fairly common
in the pulp and paper industry. Combination fuel firing is more prevalent
than wood-only firing. Most of the installed boiler units have steam capaci-
ties below 500,000 Ib/hr. The increases in fossil fuel costs have sparked a
renewed interest by the utility industry in wood-fired power plants. Large
capacity generating stations are probably impractical at present for two rea-
sons: lack of operating experience and large wood-only fired boilers, and
uncertainty in the availability and cost of large tonnages of wood -fuel. This
conversion scenario is based on an industrial-scale power boiler in an an
area where, theoretically, fuel availability is not a problem.
Summary
The biomass conversion plant produces about 50 MW of electric power from
1870 tpd of chipped forest residue and bark. The power boiler process used
is well established on an industrial utility scale. A local utility has been
assumed to be the owner and operator of this facility located in the south
central region of the United States. Wood chips and bark are purchased by
the utility on a contract basis from loggers and mills in the region and de-
livered at unit prices ($/ton) at the plant gate (freight included). Wood
only is burned in the power plant, but natural gas is available for lightoff.
Gas is used as a supplemental fuel in the event of a severe depletion of the
onsite wood supply or during peak loads. A conventional steam turbine gene-
rator converts steam energy into electrical energy. Power from the main trans-
former is distributed through transmission lines to a local power grid serving
the area's residential, commercial, and industrial users. The plant boundaries
are indicated by the fenced area in Figure 6.
The process description is divided into feedstock receiving and storage facili-
ties (Figure 7), the combustion process, the steam generator cycle, and the
40
-------
Figure 6. Wood to power plant, general arrangement
-------
HVbRAULlC.
DUMP
50
CA.P,
CHIP DUMP
HOPPER
IA-,000 cu FT
«/ BOTTOM
CHIP
10,000 CL/ FT C*P.
CHIP TRANSFER
BELT CONVCypR
48" VJ X 300'
42O TPH vP-
(50'LI FT;
US TPH
TOGO CFM
ISO HP
CHIP STOBAC,£.
pae.
TOM* 3
S.G. MILLION CU FT
UN&ELR PILE.
SUPPLY)
RECLKIUED CHIP
TRANSFER COHVEfOR
"W X SOO'
IOO TPH CAP
Figure 7. Wood chip receiving and storage section
(wood to power).
-------
auxiliary facilities (including environmental controls) . Design bases and
assumptions are summarized below. Figure 8 is a simplified process flow dia-
gram of the conversion process.
Design Basis
A nominal 50 MWe plant capacity was selected as a practical size considering
both boiler technology and local fuel resources.
Table 19 indicates the average wood fuel properties assumed. The chipped resi-
due is assumed to be delivered by a mix of rail hopper cars and large trailer
trucks.
TABLE 19. ASSUMED WOOD FUEL PROPERTIES
Composition (dry basis) Value
(Proximate)
Volatile matter, % wt 79.4
Fixed carbon, % wt 20.1
Ash, % wt 0.5
100.0
Moisture (as received) 50.0
(Ultimate)
Hydrogen, % wt 6.3
Carbon, % wt 51.8
Sulfur, % wt trace
Nitrogen, % wt 0.1
Oxygen, % wt 41.3
Ash, % wt 0.5
100.0
Heating value (HHV), Btu/lb 9130 (dry)
4565 (as rec'd)
Density, specific, Ib/cu ft 60 (green)
Density, bulk, Ib/cu ft 20 (chips)
Other principal design bases and assumptions are:
• Onsite fuel storage: 30-day supply
• Boiler: Stoker or suspension-fired furnace, (single pass) drum
boiler with superheater, economizer, and air heater
43
-------
DUCED PfiAF T
CQWPONt NT~
FLOW, M 16/HR
FLOVJ, K «FM (GPM)
PB«SS., p$i». (m u/c.)
ItMP. -, *F
ENTHKLPX, 6TU/LE
HtATRMK1 MMQTU/HR
PO\NtR, MW
155.95
-
14.1
SO
45 65
1 II. $11
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(i)
JVZ
-
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-
™««
4TO.O
(«H)
U50
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615.9
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no. 7
50,01
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(681)
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(»»n)
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(SSZ)
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2.1
Figure 8. Wood to power process flow diagram,
combustion and steam cycle.
-------
• Steam Cycle: Single flow (no reheat) 50,000 kW steam turbine,
surface condenser, and three feedwater heating stages
• Heat rejection: Mechanical-draft cooling tower
• Flue gas cleanup: 99+ percent particulate removal, wet or
dry collection device
• Solid waste disposal: Onsite landfill
• Plant water supply: River water
• Onsite water storage: 3-day capacity
• Plant load factor: 70 percent
• Plant operating life: 30 years
From these general, and perhaps arbitrary, bases, conversion process details
were developed. Economic tradeoff studies in many areas would be needed to
optimize conversion efficiency versus cost. The conceptual conversion plant
is intended to provide a basis for a reasonable assessment of conversion costs
and environmental impacts.
Feedstock Receiving and Storage
Wood chips and bark are delivered to the plant by rail hopper car and by end-
dump trailer truck, as•indicated in Figure 7. The plant is connected to a
main rail line by a 1%-mile rail spur and to a state highway by a one-mile
all-weather access road. A 14,000-cubic-foot underground hopper dump serves
both rail and truck shipments. Rail shipments are handled seven days a week,
trucks six days a week during daylight hours. Truck trailers (2000-cubic-foot
capacity) are unloaded by a hydraulic dump platform which raises the truck
and trailer, allowing the diips to discharge by gravity into the hopper pit.
The dump cycle is accomplished in about ten minutes. Bottom-dump hopper cars
are unloaded automatically while being pulled slowly over the rail hopper dump.
The dump facility is able to handle seven-pocket hopper cars of 7000-cubic-foot
capacity.
A multistrand chain conveyor under the hopper transfers the chips onto an en-
closed high-speed inclined belt conveyor which carries the chips to a pneumat-
ic transfer system. The chips drop from the conveyor into twin 10,000-cubic-
foot bins equipped with dust collectors. Rotary air locks at the bottom feed
the chips into the pressurized air stream from the rotary blowers. The chips
are pneumatically conveyed through thin-wall pipes to the outside chip storage
pile. The pipes lie on the pile surface and are moved periodically to distrib-
ute the chips fairly uniformly. Normal feedstock storage is about 56,000 tons
(5.6 million cubic feet) or a 30-day fuel supply. The pile covers three to
four acres (40-foot average height) and is underlain by the reclaim system. A
bulldozer working on the pile pushes chips toward the long axis of the pile.
45
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Two high-speed belt conveyors in an underground tunnel along thxs axis each
feed material to the centroid of the pile. Auger (screw) conveyors mounted
on carriages which can move parallel to the belt conveyors, along the; ^s,
draw chips from near the pile bottom, and discharge them onto the moving belts.
The auger conveyors are shrouded by a triangular arch of wood and concrete.
At the centroid, the chips are transferred onto an inclined-belt conveyor
which emerges from the ground beyond the pile and terminates at the hold bin^
of the boiler pneumatic feeding system. The 100-ton-Per-hour reclaim system
is able to supply fuel at 125 percent of the boiler design fuel rate.
Combustion System
Wood chips are discharged from the surge bin with a vibrating feeder onto a
vibrating distribution conveyor. Chips are distributed equally to four pneu-
matic feeders. Four blowers inject preheated air into the air-lock feeders
to carry the chips into the tangential firing zone of the waterwall furnace.
Preheated air is injected through tangential wind boxes high up in the furnace
section to promote rapid drying of the wood chips as they enter the combustion
zone. Secondary air is injected above the grate to promote complete combus-
tion of the chips in suspension. The traveling grate discharges bottom ash
into the ash pit. Design firing rate is about 78 tons per hour.
A forced-draft fan takes outside air and pushes it through the Ljungstrom
regenerative air heater, where heat exchange with hot flue gas increases the
air temperature to about 450 F. About five percent of the combustion air is
used in the pneumatic feed system. The furnace is fired at 40 percent excess
air. The heat release rate is about 25 million Btu per cubic foot of furnace
volume.
The combustion products (flue gas) pass up into the radiant section of the
boiler, where heat is transferred by radiation and convection to the boiler
and superheater tubes and to the finned tubes of the economizer. The flue
gas is further cooled to about 300 F in the regenerative air heater (AH) . A
mechanical dust collector is included ahead of the air heater to prevent AH
pluggage and to reduce carbon carryover to the precipitator. At the heater
exit, the flue gas is about nine inches (W.C.) below the atmospheric pressure.
Flyash is removed from the flue gas in a plate-type electrostatic precipitator
at a design collection efficiency of 99.5 percent. Plate collection area is
nearly 100,000 square feet. Plate rappers periodically knock collected dust
from the plates into hoppers. An ash reinjection system separates (by vibrat-
ing screens) grit from the lighter wood ash and educts the ash into the furnace
with steam ejectors. Soot blowers periodically remove accumulated deposits
from heat transfer surfaces in the boiler. An induced-draft fan boosts the
flue gas pressure to just above atmospheric. Flue gas passes into a 10-foot-
diameter (at tip) by 175-foot-tall concrete chimney from whence it discharges
to the atmosphere. Airside equipment capacity is rated for 120 percent of
design flow (144 percent design pressure drop).
The boiler efficiency is about 70 percent. Fuel moisture, the water in the
fuel and that produced by combustion of hydrogen, accounts for more than
two-thirds of the heat loss.
46
-------
Steam Cycle —
The boiler design steam conditions (continuous) are 474,700 Ib/hr, 1250 psia,
900 F at the superheater outlet. The two-drum vertical boiler configuration
takes heated feedwater at 411 F and converts it to steam at the above condi-
tions to drive the 50,000 kW condensing turbine. Boiler capacity is 110 per-
cent of the design steam flow. The single-case, single-flow turbine has three
extraction points for feedwater heating. About 28 percent of the throttle
steam flow is withdrawn from the turbine for three stages of feedwater heating.
The turbine exhausts steam at two inches of mercury absolute pressure. Gross
turbine output (mechanical energy) is about 52 megawatts. Generator electri-
cal output is about 50 megawatts. Losses from the 60,000 kW hydrogen-cooled
generator are about 2% percent. Electrical power is transformed up to trans-
mission voltage (115 kV) by the main transformer. Overhead transmission lines
carry the power to the local utility grid.
Turbine exhaust steam is condensed in a two-pass surface condenser. Tempera-
ture rise across the condenser is 15°F (80°F to 95°F). Heat is rejected to
the circulating water (tube side) by steam condensing at 101 F on the outside
of the tubes (shell side). Boiler feedwater makeup is added to the hot well.
The hot-well pump pumps condensate through the first closed feedwater heater.
Steam from the turbine condenses in the heater shell, heating the feedwater
in the exchanger tubes. The feedwater is deaerated in a contact (tray type)
deaerating 'heater. The third stage is a closed heater. The feedwater tempera-
ture increase across each heater is approximately equal (or 100 F). The boiler
feedwater pump after the second heater and the booster pump after the third
heater boost the feedwater supply pressure to the boiler to about 1360 psig.
Steam condensates from the closed heaters are pumped forward to commingle with
the feedwater steam. Boiler blowdown and steam losses amount to about three
percent (13,800 Ib/hr) of the steam circulation.
Auxiliaries
Water Systems—
Figure 9 presents a simplified water balance diagram for the plant. The river
water intake structure houses three 55-percent capacity pumps which pump
617 gpm of water through an underground pipeline to the water storage pond.
This clay-lined basin of 3,000,000-gallon capacity provides a three-day supply
of plant water at the maximum demand of 700 gpm. Basin pumps supply 552 gpm
of makeup water directly to the cooling tower basin and 65 gpm of other plant
water to a gravity sand filter. Firewater pumps at the basin supply the fire-
water piping system. The pump motors are connected to the emergency diesel
generator.
Plant water is filtered and chlorinated before entering the distribution sys-
tem. Normal usage is 5 gpm of potable water, 30 gpm of utility water, and
28 gpm of boiler feedwater. The boiler feedwater makeup is demineralized by
ion exchange. This system consists of two parallel cation exchange beds fol-
lowed by a vacuum deaerator and then by two parallel anion exchange beds and
a demineralized water storage tank. Fifty-percent sodium hydroxide and 66°
Baume (Be) sulfuric acid are used as regenerants.
47
-------
1 T 5 0
COOUIN& TOWER 1 Z
' CIRC
TOWER
, ^. > POTt,6L5_ »J
/ WME-R '
| I (SfePM)
/ 1 ^ j> RR« WVIE.R '
1 1 ^ -^ UTILITY J
/ 1 ViATER '
/ / RIVER
/ IWTMtt &RA.^ITV SFUJ
Ql ,^W*TER ^
7 UntPM) STQRW.t (65&PM) SkMDFlCItW TKEM WENT
j 1 1 " '1 "'1 '
/ BRINES | |
/ ( 2*00 GPP) J (
/ ' 1 * i 1
/ UEU1RMIZM-
BKS.IH
\ | (- 1 6PM) ,
1 _^=s _„„„,„
! RUKJOFF
| ( ~ 4G 6PM W3 . j
STORM PROCESS EFFUJtWT
, DiitH*.R6t ( loz GPM)
(9\ u; A.T £ R ^ '
BIFT V.OSS
"3 C.PM)
UUTR (t, SVlM
LQND£MSEK
, 4
TUE61M6 J
-i
TPM) BOILER
FUBN^CC
C.T.
B.D .
==>ST
LO
(9
60ILt R
B.C.
(I3&PM
,
&IOLOC
iM 1
1
V
\ m^fmmm^^mtm **" 1 WTK.BWIITH. KIT FLOW
Wd.
- •» CUNTINUOLl£ FLOW
IN GPH ^T TO°F
AVC,, CLIMA.TIC CONDITIONS
Figure 9. Wood to power plant, simplified water balance.
-------
The recirculating cooling water system dissipates the condenser heat load to
the atmosphere by evaporation and convection in an induced-draft cooling tower.
The tower consists of four cells 73 feet wide by 32 feet long, each equipped
with a 24-foot diameter fan (normally three cells are in operation). Hot water
(about 42,400 gpm) from the condenser enters the top of the tower and is dis-
tributed across the tower fill. The water droplets are cooled as they fall by
contact with the induced air and by evaporation of part of the water. Three
55-percent capacity circulating pumps take cooled water from the tower basin
and circulate it to the condenser. Slowdown is taken from the discharge side
of the circulating pumps. The cooling tower also serves to dissipate heat
from the service cooling water system. A service water flow.of 2200 gpm is
supplied by a 110-percent capacity pump (plus spare) to the bearing coolers,
the generator stator and hydrogen coolers, and the turbine oil cooler. The
circulating water system is maintained at a minimum of ten cycles of concen-
tration. At annual average conditions (18.5 F approach, 15 F cooling range),
evaporation and drift losses are about 497 gpm and 9 gpm, respectively. Total
heat dissipation is about 333 MM Btu/hr (97.6 MWt). The circulating water is
shock chlorinated for a total of two hours daily.
Wastewater Systems—
Wastewater sources are sanitary sewage, boiler blowdown, cooling tower blow-
down, demineralizer brines, yard and floor drains (utility water), and storm-
water runoff.
Sanitary wastewater is treated in a package biological system which provides
tertiary filtration and disinfection (chlorination). Boiler (19 gpm) and
cooling tower (46 gpm) blowdown. are collected in a 100,000-gallon lined set-
tling basin which provides 24-hour equalization and settling capacity and dis-
sipation of residual chlorine. Acid and caustic demineralizer brines are dis-
charged to a neutralization basin where caustic is used to neutralize excess
acidity and settle out suspended solids before discharge to the blowdown set-
tling basin. Confined yard and floor drainage water are collected in local
sumps equipped with oil skimmers. Skimmed water drains to the storm sewers.
Storm drainage is collected from 30 acres of the plant site by a combination
surface and underground drainage system. Annual runoff (30 inches) averages
46 gpm of continuous flow. The stormwater retention basin is designed to im-
pound about 60 percent of the total runoff from a ten-year, 24-hour duration
storm — providing about a 14-hour average settling time.
The combined plant wastewater is discharged through a 24-inch diameter gravity
pipeline below the river water surface level at approximately mid-channel.
The discharge line is about 1000 feet downstream from the intake pumphouse.
Ash Disposal—
Approximately 390 Ib/hr of ash is discharged into the furnace ash pit and
collected in dumpster boxes. This material, mainly wood ash and grit, is
buried in an onsite landfill along with a small amount of plant trash and gar-
bage. The five-acre landfill site is sufficient for solid waste disposal over
the 30-year plant operating life (about 3.9 million cubic feet). Conventional
spread, compact, and cover techniques are employed. Average fill depth is
49
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20 feet. The site is developed in five-year capacity increments. Soil cover
is provided by the excess excavated material stockpiled from plant construction
activities.
Other Facilities—
Other auxiliary facilities include plant buildings - turbine hall, warehouse,
shops, and administration building - switchyard, parking area, transmission
line, access roads, rail spur, fences, gate houses, and other site improve-
ments. Environmental controls are discussed in the plant impact section.
Thermal Balance
The overall plant heat rate is 15,790 Btu/kWh at design (100 percent) condi-
tions. Table 20 summarizes major factors in the plant thermal balance.
The plant's gross electrical output of 50 MWe is about one-quarter of the
gross heat input as fuel. A large fraction of the energy loss is heat, dissi-
pated to the atmosphere by flue gases vented from the stack and cooling tower
exhaust — carrying away waste heat picked up by the cooling water in the sur-
face condenser.
TABLE 20. WOOD TO POWER THERMAL BALANCE ELEMENTS
Element
Wood Fuel Input
(-) Furnace losses at 30%
(rejected to atm)
= Input to steam
(-) Steam cycle losses (mechanical &
other heat rejection to atm,
water)
= Output at turbine exhaust
(-) Turbine generator losses at 2^%
(mechanical & electrical)
= Gross plant output
(-) Auxiliary power losses
MM Btu/hr
711.9
(123.6)
498.3
(323.2)
175.1
(4.4)
170.7
(16.8)
kW
280,580
(62,580)
146,000
(94,700)
51,300
(1,290)
50,010
(4,930)
% of
Input
100.0
(30.0)
70.0
(45.4)
24.6
(0.6)
24.0
(2.4)
formers, "Hotel" load & elec-
tric motor drives)
= Net Plant Output 153.9 45,080 21.6
50
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WOOD-TO-POWER CAPITAL AND OPERATING COSTS
A conceptual estimate was made for the wood-to-power plant located on the
hypothetical 50-acre site in the South Central Region of the U.S. Cost esti-
mating methodology for the biomass conversion processes is summarized in
Appendix C. The estimate is at first quarter, 1978, price and wage levels,
with no allowance for future escalation. Table 21 summarizes the major capi-
tal, cost elements. Direct field costs are broken down into six categories,
themselves composed of summations of materials and labor costs, in most cases.
Process mechanical equipment is, of course, the largest direct field cost item.
Installed pollution control equipment is about four percent of the direct field
cost. The largest cost item is the electrostatic precipitator. Table A-l in
the Appendix identifies major pollution control equipment. This rather low
percentage primarily reflects the nature of wood as a clean solid fuel.
Total capital cost for the 45 MWe net plant is about $1200/kWe, perhaps 50 to
60 percent higher than a large coal-fired power plant with fluegas desulfuri-
zation, but still significantly more expensive than a plant without an FGD
system. As noted in Section 1, \
-------
WOOD COST, S/MMBTU
125
100
X
O
O
o
50
WOOD-TO-POWER
• H^^H PRIVATE
UTILITY
25
_L
10
20 30
WOOD COST, SfTON
40
Figure 10. Effect of wood cost on cost of electricity
with both private and utility financing.
52
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TABLE 21. WOOD TO POWER CAPITAL COSTS
Element $1,000,000's
Site and Yard 1.0
Civil/Structural 4.4
Process Mechanical Equipment 15.6
Pollution Control Equipment 1.0
Piping and Instrumentation 3.3
Electrical 1.5
DIRECT FIELD COST 26.8
Indirect Field Cost 4.5
TOTAL FIELD COST 31.3
Engineering Services 3.8
35.1
Allowance for Uncertainty 7 . Q
TOTAL CONSTRUCTION COST 42.1
Land 0. 2
Other Owner Costs 0.8
Startup 4.2
Allowance for Funds During Construction 4.3
FIXED CAPITAL INVESTMENT 51.6
Working Capital 2. 6
TOTAL CAPITAL COST 54.2
First Quarter 1978, Price and Wage Levels
53
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TABLE 22. ANNUAL OPERATING AiND MAINTENANCE COSTS* - WOOD TO POWER
Element
$l,000,000's
Supplies
Utilities
Operating Personnel
Maintenance Labor and Materials
Supervision
Administration and Overhead
Local Taxes and Insurance
TOTAL ESTIMATE ANNUAL OPERATING COST
First Quarter 1978, Price and Wage Levels
0.1
0.1
0.3
0.2
0.1
0.3
1.1
2.2
•"Excluding wood feedstock
TABLE 23. ANNUALIZED COST OF ELECTRICITY
Element
Annualized Capital Cost (9%)
Annual Operating Cost
Annual Feedstock Cost
(Base: $10/ton)
TOTAL ANNUALIZED COST
$l,000's
5,247
2,200
4,770
12,217
Mills /kWh
(net)
19.0
8.0
17.3
44.3
$/MM Btu
(net)
5.57
2.33
5.07
12.97
54
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WOOD-TO-POWER ENVIRONMENTAL ASSESSMENT
Feedstock procurement impacts and impacts of the operating plant are described
in the context of the hypothetical location in the South Central Region of the
J.S.
Residue Procurement Impacts
ibout 480,000 tons per year of residue will be removed from forestlands in the
/icinity of the conversion plant. General impacts on land, water, air, and
Biological resources are described in this section. Specific impacts for a
specific location would have to be assessed in an EIR or EIS for an actual bio-
nass conversion project of this magnitude.
Forest Protection—
Residue collection and removal will serve as a forest-fire protection measure
and will help to reduce the damage caused by insect pests and plant diseases
spread by insects. These beneficial impacts will directly affect only those
areas being harvested for residue: over the years a good portion of the forest-
land in the area will be affected and receive soae benefit.
Forest Improvement—
Stand improvement can be aided by removing residues that impede germination
and development of seedlings. However, complete residue removal may not be
desirable since moist decayed organic matter can form seed beds for new
growth and provide a nutrient supply to seedlings.
Soil Fertility and Erosion Control—
Plant nutrients contained in the residues will be removed through residue col-
lection. The extent to which residues can be removed without causing serious
deficiencies will depend upon the nutritive makeup of the soils in the area
and the importance of residues in nutrient replenishment. Leaves, which are
rich in nutrients, would normally be left on the forest floor. Partial har-
vesting of residue would be preferable to a complete harvesting which might
require importation of fertilizers to maintain soil productivity.
Soil stability may be adversely affected by excessive removal of residues and
disturbance of other ground cover by collection activities. Soil erosion on
slopes and cuts could become a significant adverse impact without a well-
nanaged harvesting program.
•Jater Quality—
Secondary impacts resulting from soil erosion may degrade the quality of local
surface waters. Wind- and water-carried soils and forest residues in streams
:an adversely influence stream biology. Organic matter can increase biological
Dxygen demand and reduce the dissolved oxygen available for fish. Turbidity
;an impede fish migration, while heavy siltation can impede fish breeding, the
matching of eggs, and the survival of larvae. An increase in color and turbid-
ity may make the streams less acceptable as surface water supplies.
-------
Wildlife— . ,, ,
Removal of forest residue may be detrimental to some species ot small mammals
and birds inhabiting the forest lands. During collection activities, the
wildlife habitats will be disturbed, forcing temporary displacement of these
species into nearby areas. Displacement in habitats which already support the
maximum populations possible (carrying capacity has been reached) usually re-
sults in mortality of the displaced species. This is particularly true of
strongly territorial animals, which require a specific living space to breed
and feed. Residue removal may also sufficiently disturb the habitats of some
animals that repopulation of the disturbed area from the nearby populations
is limited.
Recreation and Aesthetics—
Optimum removal of residues will usually improve the aesthetic appearance of
logged areas and may enhance the recreational value of the forestland. Com-
plete harvesting, which may cause severe soil erosion, displacement of animals,
and other undesirable secondary impacts, would not be beneficial.
Transportation—
Wood harvesting in the forestlands and wood hauling to and from yarding sites
will involve vehicles operating on and off local roads and highways. An aver-
age of about 100 truck loads or 40 rail carloads will be shipped to the plant
each day — most from yarding facilities. The additional traffic burden on
roads and rail lines is expected to be small compared with the current vehicle-
mileage or ton-mileage levels in the collection area (3000 to 4000 square
miles). Local congestion may occur at times along principal haul routes to
and from yarding sites and in the vicinity of the conversion plant.
Motor fuel consumption for residue collection will be on the order of two to
three percent of the conversion plant's energy output and less than one per-
cent of the delivered wood fuel energy content. Vehicle pollutant emissions
will increase because of this additional fuel consumption, causing a small,
adverse impact on ambient air quality. Hauling activities will also increase
local fugitive dust emissions, especially on unsurfaced roadways.
Socioeconomics—
Feedstock collection will provide new employment opportunities in the area.
Some 30 to 50 permanent jobs and additional part-time employment will be gene-
rated. Several million dollars ($4.8 million at $10/ton) of income will be
added to the economy of the area through sale of residue to the plant owner.
The magnitude of the collection operation is small enough to be accommodated
by local manpower and community service resources.
Summary—
Forest residue procurement activities will have both positive and negative
impacts on the environment of the area. Table 24 summarizes expected impacts
and potential mitigating measures. Some social and economic benefits will be
derived through increased employment. Residue removal itself can be benefi-
cial to forest productivity, but detrimental to soil fertility, soil stability,
and wildlife habitats. On balance, it appears that judicious residue removal
through a careful collection management program can mitigate many of the po-
tential adverse impacts.
56
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TABLE 24. PROCUREMENT IMPACT SUMMARY - FOREST RESIDUE
Environmental
Factors
Residue Procurement
Impacts
Potential
Mitigating Measures
Air Quality
Minor adverse impact from ve-
hicle combustion product emis-
sions and localized fugitive
dust emissions
Surface Water
Quality
Groundwater
Quality
Land
Availability
E co lo gy an d
Critical Habitat
Soils and
Geology
Potential degradation of water
quality resulting from soil
erosion — increased siltation
and organic loading of streams
No discernible effect
Abundant forestland in region;
yarding requires small amount;
agreements with owners needed
for collection of enough resi-
due for plant operation over
30-year life
Some 30,000 to perhaps 100,000
acres of land subjected to
residue collection each year;
judicious collection can im-
prove forest productivity, re-
duce fire and insect damage;
some damage to vegetation dur-
ing collection, disturbance of
wildlife habitats and possible
permanent loss of individuals
of some species
Plant nutrients in residue re-
moved — can result in degrada-
tion of soil fertility and com-
plete residual removal may cause
serious deficiencies, potential
adverse effect on soil stability
in sensitive areas
Avoid or limit col-
lection on unstable
soils
Develop residue
collection and man-
agement plan to en-
sure supply and
minimize damage to
forestland
Surveys needed to
avoid critical
habitats; manage-
ment of collection
activities to mini-
mize damage of vege-
tation and wildlife
Soil surveys and
monitoring of col-
lection activities
to prevent signifi-
cant damage to fer-
tility and stabil-
ity; import
fertilizer, if
necessary
(Continued)
57
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TABLE 24. (Continued)
Environmental
Factors
Residue Procurement
Impacts
Potential
Mitigating Measures
Aesthetic and
Recreational
Resources
Community
Economy
Community
Population and
Services
Labor
Availability
Transpo rtation
Improvement in appearance of
logged areas; potential increase
in recreational value
Significant benefit to local econ-
omy through plant purchase of de-
livered forest residue — $4.8 mil-
lion annual input
Little increase expected in local
population and in demands for
services
Full-time and part-time jobs will
be created by procurement ac-
tivities; local manpower resources
are adequate and will benefit from
jobs
Small increase in rail and road
traffic in region; local conges-
tion may occur on principal haul
routes at times
58
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Plant Impacts
The wood-to-power plant will have impacts on the environments which are nor-
mally categorized as physical/chemical, biological, socioeconomic, and aesthet-
ic in nature. Of these, the physical/chemical impacts will be given the most
attention since they primarily involve direct emissions to the environment.
Construction and operation of the plant will also involve the commitment of
physical resources. It is assumed that the total plant construction period
will be three years with field construction predominating during the last two
years. The plant will be operated for 30 years.
Table 25 summarizes the major resources utilized in operating the plant.
Table 26 summarizes annual chemical requirements.
TABLE 25. PRINCIPAL RESOURCES COMMITTED TO PLANT OPERATION
Resource Category
Normalized Quantity
(Output)*
Land
Feedstock (Wood Residue)
Auxiliary Fuel
Chemicals (Total)
Auxiliary Power Consumed
Water
Manpower (30 employees)
50 acres
477,207 tons/yr
52 MMM Btu/yr
64 tons/yr
30.2 MM kWh/yr
266 MM gal/yr
60,000 manhours/yr
1.11 ac/MWe
3.46 Ib/kWh
(15,790 Btu/kWh)
188 Btu/kWh
0.00046 Ib/kWh
0.109 kW/kW
0.82 gal/kWh
0.67 men/MWe
*Basis 275.9 MM kWh/yr net output
Physical/Chemical Emissions and Impacts—
Air Emissions—Emissions of pollutants to the atmosphere from the plant site
are not expected to significantly degrade ambient air quality with respect to
the five designated pollutants (particulate matter, sulfur oxides, nitrogen
oxides, carbon monoxide, and photochemical oxidants). Table 27 summarizes
major emission sources and estimated pollutant emissions. The boiler stack
and the cooling tower exhaust will be the two largest point sources of dis-
charge in terms of flow. Wood chip transfer operations will be the primary
sources of fugitive dust emissions (particulate matter).
59
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TABLE 26. SUMMARY OF ANNUAL CHEMICAL REQUIREMENTS - WOOD TO POWER
Chemical
Amount Per Year
Sulfuric acid (66 Be)
Caustic Soda (50%)
Chlorine
Lime
Cleaning Chemicals (HC1, Citric Acid,
and Soda Ash)
Dispersant (Phosphate)
Miscellaneous BFW Chemicals
Ion Exchange Resins
Lube Oil
Auxiliary Fuel
Diesel
Gasoline
Natural Gas
30 tons
17 tons
8 tons
5 tons
5 tons
1 ton
0.5 ton
10 cu ft
2,000 gal
50,000 gal
13,000 gal
44,000 MSCF
60
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TABLE 27. SUMMARY OF ESTIMATED AIR EMISSIONS ~ WOOD TO POWER
Emission Source Estimated Flow
Pollutants
Emission Rate
Boiler Stack 856,300 Ib/hr,
(175 feet high) 196,300 SCFM
total flow
Particulate matter
Cooling Tower
Exhaust
Wood Chip
Dump Hopper
Chip Storage
Pile
Chip Transfer
Bins
Pneumatic
Conveyors
Boiler Feed Bin
Miscellaneous
12 MM Ib/hr
(dry air)
NOX
CO
HC
Thermal
Water droplets (drift)
Salts (in drift)
2000 tons/day of Fugitive dust
chips unloaded
56,000 tons stored Fugitive dust
(3-4 acres)
2000 tons/day chips Fugitive dust
1.8 MM CFD vent
gas
2000 tons/day chips Fugitive dust
6.7 MM CFD air
flow
2000 tons/day chips Fugitive dust
1.6 MM CFD vent gas
Plant area and Fugitive dust
roads
Mobile equipment
exhausts _. Combustion products
Fuel Storage tanks Hydrocarbon vapors
2 lb/hr(a)
0.003 Ib/MM Btu
<3 lb/hr(b)
356 lb/hr(c)
71 lb/hr(d)
71 lb/hr(e)
185 MM Btu/hr at 300°F
4,400 Ib/hr
•v,5 Ib/hr
333 MM Btu/hr(added)
100 Ib/day
(0.05 Ib/ton)
22 Ib/day
(1 ton/yr/acre)
3 Ib/day (0.01 gr/CF
after collector)
960 Ib/day
(0.1 gr/CF)
3 Ib/day (0.01 gr/CF
after collector)
small
small
small
(a) Based on 99.5 percent reduction-
(b) Based on 0.01 percent sulfur in fuel-
(c) Estimated as 0.5 Ib N02/MM Btu input-
(d) Estimated as 0.1 Ib CO/MM Btu input-
(e) Estimated as 0.1 Ib/MM Btu input-
61
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The boiler stack gas is expected to meet the proposed stationary source NSPS
for particulate matter and sulfur oxides. The new standard for particulate_
matter (99 percent reduction of uncontrolled emissions) requires high-efficiency
collectors regardless of the level of uncontrolled dust loading. The gas
cleanup system will include a mechanical collector ahead of, and to protect,
the air heater and an electrostatic precipitator for final cleanup. Flyash
reinjection will also be practiced. Overall removal efficiency is expected
to be 99.5 percent. Particulate matter emissions are expected to be consider-
ably lower than the proposed limit of 0.03 Ib/MM Btu heat input in part
because of the low ash content of the wood. Similarly, sulfur oxide emissions
are expected to be low because of the low (trace quantity) sulfur content of
the wood. No sulfur oxide (SO ) removal system will be needed because un-
controlled emissions will be less than 0.2 Ib SO /MM Btu heat input (above
this limit, 90-percent removal would be required by the proposed regulation).
Emissions of nitrogen oxides (NO ), carbon monoxide (CO), and unburned hydro-
carbons (HC) are less easily estimated and are related to boiler design and
combustion conditions. Fuel nitrogen content is low and would contribute
little to NO emissions. The high excess air rate which promotes air nitro-
gen fixation would be somewhat offset by moderate combustion temperatures.
It is possible that the 0.6 Ib NO /MM Btu input standard would be met with
good combustion control. (Sixty-five percent reduction of uncontrolled emis-
sions may not be achieved.) Similarly; CO and HC emissions should be low with
good combustion control and high excess air flow. The ash reinjection system
should help to reduce the emission of unburned carbon particles. The esti-
mates in Table 27 are about one-half those indicated as emission factors
(Ib emission/ton fuel burned) for wood and bark combustion in a recent EPA
report (20).
Emissions of hazardous materials, i.e., carcinogenic organics and heavy metals,
are not expected to be significant, either in concentration in the fluegas
or in effects on public health.
The cooling tower will discharge nearly 100 MW of thermal power to the atmo-
sphere and will evaporate nearly 250,000 Ib/hr of water. The heat load and
water vapor do not normally constitute pollutants, and impacts on the local
air quality and climate will be insignificant. However, a visible and persis-
tent plume could occur at times, particularly if the ambient humidity is high,
and could constitute an aesthetic impact.
Cooling-tower drift loss will be on the order of two tons per hour of water
in droplet form. About 15 tons per year of salts contained in the drift could
be deposited on the ground in the vicinity of the tower. These salts could
arfect sensitive plant species directly through leaf burn, or indirectly
through buildup in- the soil.
Fugitive dust emissions will result from handling the wood chip fuel within
the plant. The suspendible particulate matter content of the wood is unknown.
However, it is likely that most of the particulate matter emitted from wood
handling will be settleable and drop to the ground near the source. Emission
of dust will be low from bin vents equipped with fabric filter collectors.
Wind-blown dust and perhaps chips from the chip storage pile may be a local
62
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nuisance at times. A relatively large surface area (three to four acres) will
be exposed to the wind. Movement of the bulldozer on the pile will tend to
compact the surface layer and help retard surface erosion. Most of the wind-
blown material will resettle on the pile itself. However, some will be dis-
tributed on the ground near the pile and the smaller (suspendible) material
could be carried offsite.
Pollutant emissions to the air will have two principal kinds of impact:
effects on the air quality, and effects on biota. Air-quality degradation in
the vicinity of the plant is expected to be minor overall. Emissions of NO ,
CO, and HC will have some, though perhaps not measurable, adverse impact on
the air quality. Emissions of heat and water vapor will probably be too low
to cause any perceptible modification of the climate in the area. Plant and
animal life in the vicinity will suffer little damage from plant air emissions
(see Biological Impacts).
The plant would be considered a'new major source and hence could be subject
to the current "offset" policy if located in a nonattainment area. Namely,
the plant would be responsible for reducing emissions from existing sources
in the area to offset its own (controlled) emissions (NO about 1000 tons/yr,
CO and HC about 200 tons/yr each). X
Water Emissions—The plant will discharge about 100 gpm of process wastewater
to the river from which the plant withdraws water. In general, the wastewater
will contain the same constituents (and quantities) present in the river water
supply plus chemicals added to this water in the plant. The added chemicals
represent the principal pollutant load contributed by the plant — primarily
dissolved and suspended solids. Table 28 summarizes the estimated wastewater
emissions.
Over one-half of the process effluent is water related to the steam cycle sec-
tion of the plant. Boiler blowdown, feedwater treatment brines, and cooling-
tower blowdown are essentially purges of undesirable dissolved and suspended
solids. Boiler blowdown is concentrated boiler feedwater containing small
concentrations of chemical additives. Regenerant brines contain sodium and
sulfate ions (added as NaOH and H SO in the regeneration cycle) and the anions
and cations removed from the river water in the ion exchange treatment process.
Cooling-tower blowdown is essentially river water concentrated by evaporation.
Sulfuric acid, a phosphate dispersant, and chlorine are added to control scal-
ing and fouling in the cooling system. By the concentration process alone,
the blowdown will also contain fairly high concentrations of those chemicals
present in the river water (see Table 18). After settling treatment, the
blowdown effluent will contribute mainly dissolved solids (from chemical addi-
tions) as a pollutant load to the river.
Stormwater runoff will be the single, intermittent source of effluent that
does not originate from the river. Runoff will pick up silt and may leach or
wash off some inorganic and organic materials through contact with various
surface areas in the plant. Confined yard and floor drainage will be skimmed
of any free oil and settled for suspended solids removal. Storm runoff will
also be collected and settled for suspended solids removal. Normal process
wastewater and treated sanitary waste will contribute some small quantities
63
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TABLE 28. SUMMARY OF ESTIMATED WASTEWATER EMISSIONS -
WOOD TO POWER
Source
Estimated Flow
Pollutants
Emission Rate
Boiler Slowdown
Regenerant Brines
Cooling Tower
Slowdown
Yard and Floor
Drains
Sanitary Waste
Chemical Cleaning
Wastes
Storm Drainage
19 gpm
Intermittent,
2400 gal/day
46 gpm
(10 cycles of
cone.)
30 gpm
5 gpm
Intermittent,
100,000 gal/
cleanout
Total dissolved solids
(TDS)(80 mg/1)
Total suspended solids
(TSS)(20 mg/1)
pH (alkalinity reduced
by blending)
TDS (7500 mg/1')
Acidity/alkalinity-
neutralized
PH
TSS (30 mg/1)
TDS (1150 mg/1)
Chlorine (residual
<0.1 mg/1)
PH
Oil & Grease
(10 mg/1)
TSS (20 mg/1)
PH
BOD (25 mg/1)
TSS (10 mg/1)
Coliforms (<200 MPN/
100 ml)
PH
Acidity — neutralized
TSS (50 mg/1)
TDS (10,000 mg/1)
PH
3.4 Ib/day
0.8 Ib/day
150 Ib/day
(a)
6-9
16 Ib/day
635 Ib/day
(b)
<.05 Ib/day
6-9
3.6 Ib/day
7.2 Ib/day
6-9
1.5 Ib/day
0.6 Ib/day
6-9
42 Ib/batch
8330 Ib/batch
6-9
Intermittent, Oil & Grease(<5 mg/1) 2.8 Ib/day
46.5 gpm annual TSS (<50 mg/1) 2.8 Ib/day
avg. PH 6-9
(a) 123 Ib/day of Na+ & S04 added.
(b) 185 Ib/day of S04 = NaP03 and Cl~ added.
64
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of pollutants to the receiving water. The plant effluent will have a minor
adverse impact on receiving water quality; it is unlikely that any resulting
changes in river quality will be detectable.
Plant water consumption (about 617 gpm) will be a small fraction of the total
river flow. This consumption will have a very small impact on surface water
resource availability, and no impact on groundwater resources.
Solid Waste Emissions—The two major solid wastes generated by the plant will
be furnace ash and general plant trash (see Table 29). Intermittent (and
infrequent) wastes will be sludges from basin, pond, and cooling tower clean-
outs. All wastes will be buried in an approved onsite landfill. About 5^ tons
of moist wood ash will be buried each day. This ash is expected to be rich in
minerals, be somewhat alkaline, and contain trace concentrations of a number
of heavy metals. Plant trash and garbage will be collected and buried less
frequently. The burial site will be operated much like a sanitary landfill,
with proper care taken to prevent leachate formation, litter blowing, burrow-
ing of rodents, and other nuisances.
TABLE 29. SOLID WASTE DISPOSAL SUMMARY
WOOD TO POWER
Source
Estimated
Quantity
Potential
Pollutants
Disposal
Boiler Ash
Plant Trash
and Garbage
390 Ib/hr wood
ash and grit
69 Ib/hr mois-
ture (15%)
150 Ib/day
Alkalinity,
trace metals
Decomposable
waste, some
oily materials
Ash moisturized (15%
H90) and buried in
landfill - about
480 cu ft/day
Collected twice per
week and buried -
about 30 cu ft/dav
The major impact of solid waste emissions will be the utilization of about
five acres of land over the plant life. With proper operation of the landfill,
there should be little damage to the environment in terms of degradation of
air quality and surface and ground water qualities. The size of the landfill
could be reduced by using some or all of the wood ash as a soil amendment.
Soils and Geology—Approximately 40 acres of land surface will be altered
during construction of the plant. Although most of the site is fairly level,
earthwork will involve clearing and grading, including some cut and fill areas
and excavation for basins and foundations. The application of construction
materials for foundations and roadways will further change the physical surface
65
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Site topography, drainage patterns, and soils will be permanently Altered
during construction. Burial of boiler ash will also increase the height of
the five-acre landfill site by 20 to 25 feet over the plant operating lite.
Although the physical changes in the land surface could be considered as a
localized adverse impact, the site is similar to other sites in the region
(no uniquely distinguishing features), and no significant regional impacts
are anticipated.
Biological Impacts—
Construction and operation of the plant will have primary and secondary im-
pacts on biological species in the vicinity. As a direct result of site
preparation, 50 acres of vegetation and the associated wildlife on the site
will be removed or disturbed. Wildlife in nearby habitats may also be af-
fected by construction activities, particularly by construction noise. Sen-
sitive species will leave the area, but some may return during the plant
operation phase. Others may adapt to the increased noise levels and human
presence and may suffer only temporary discomfort. The plant fence will be
a barrier to the movement of larger animals onto and off the site. Careful
plant siting would avoid disturbances or destruction of rare, unique, or en-
dangered species of vegetation and wildlife, and ensure that all of the vege-
tation and wildlife types present on the plant site are well represented in
other areas of the region.
Other seondary biological impacts result from changes in air, water, or soil
qualities. Secondary impacts resulting from construction activities will be
temporary and different from those resulting from plant operation. Local
damage to plant species along roadways could occur from deposition of high
concentrations of dust on leaves. Changes in offsite drainage patterns due
to construction-site work may result in some local areas of soil erosion and
consequent damage to vegetation. Sediment loadings in surface waters may in-
crease because of runoff from construction areas, resulting in temporary
stress or damage to aquatic plants and animals. With proper construction
planning and management, these secondary impacts can be minimized.
As noted earlier, air and water emission from operation of the plant will have
minor adverse impacts on air and water qualities. Secondary effects on bio-
logical species resulting from these adverse impacts are expected to be minor.
Since emissions will be relatively continuous over the conversion plant life,
long-term exposure may result in damage to plants and animals because of the
cumulative effect. For example, some plant species are sensitive to increases
in nitrogen oxide concentrations. Plants downwind of the boiler stack may be
exposed to higher than normal (ambient) NOX levels over a long period and may
suffer some leaf damage. Generally, the'plume will be well enough dispersed
and high ground-level concentrations will occur only during short-term ad-
verse meteorological conditions.
The cooling-tower drift will deposit salts on the ground downwind of the tower.
A localized increase in soil salinity may damage some less tolerant species.
Any damage to aquatic species as a result of plant wastewater emissions will
probably be confined to a localized area near the discharge point.
66
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A combination of good river water quality and the low emission of pollutants
is expected to result in little harm to plant and animal life outside of the
mixing zone. Some small organisms will be withdrawn from the river (entrained)
in the intake water, and most will be destroyed in the plant water systems.
Screens in the intake pump house will prevent the entrance of larger species
such as fish.
Overall, the major biological impact will be the direct removal of plants and
animals from the site during plant construction and the loss of productive
farmland, but this impact is not expected to be significant to the region.
Aesthetic Impacts—
Visually, the conversion plant will contrast with the rural surroundings.
Local relief is low and taller plant structures will be visible from a con-
siderable distance. As viewed from the access road approach to the hypothet-
ical plant, the turbine building, the boiler precipitator, and the 175-foot
high stack will appear as a dominant cluster of tall structures on a level
ground area, with the wood chip pile appearing as a large, rather regular
light-colored mound (about 40 feet high) in the background. The cooling tower
and its characteristic white plume will be most visible at angles away from
the prevailing wind direction. The plant itself is small and so should not
be as striking visually as some large power plants, especially those with
natural-draft cooling towers which can visually dominate almost any natural
topographical feature. The overhead transmission line, the switchyard, and
the rail facilities will generally be considered as detrimental to the aes-
thetic quality of the area, as might other plant structures.
Adverse impacts on aesthetics can be mitigated somewhat through plant and
building design, site layout, and landscaping. Landscaping the undeveloped
plant grounds along roads and fence lines will help to mitigate or obscure
the contrast between the structures and the level surroundings. However, on
balance, the plant will probably have a negative effect on the aesthetic
quality of the site as perceived by local residents and some visitors.
Social and Economic Effects—
The capital investment ($54 million total) in the plant and annual operational
expenditures will stimulate the local economy. Temporary jobs will be created
for several hundred construction workers, and about 30 permanent jobs for
operating employees will result. Income from these jobs will result in in-
creased spending in nearby towns. Average income in the region is below the
national average and a new source of employment would probably be welcomed.
Some portion of the capital investment for equipment and materials will also
be expended in nearby communities. The local industrial tax base will also
be expanded, and the taxes will provide additional community services.
Plant operating labor and most of the construction workforce can be obtained
from the unskilled and skilled labor pools in the region. Little increase in
local population is anticipated as a direct result of the conversion plant
construction. Demands on community services will be highest during construc-
tion; however, it is likely that any needed expansion of services could be
accommodated without significant economic impact on the community. Economic
benefits derived from taxes, wages, and spending in the community will
67
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outweigh to some extent the adverse impact of increased demands on local ser
vices during construction.and operation. The plant itself will generate power
to meet the new electrical demands of residential, business, and industrial
consumers, and will permit a further expansion of the economy of the region.
As a summary, Table 30 lists principal plant impacts discussed above and poten-
tial mitigating measures.
COAL-TO-POWER PLANT SITE DESCRIPTION
The hypothetical site for the coal-fired power plant is similar to that for
the wood-to-power plant, though larger in size. The 365-acre fenced site is
on gently rolling farmland and woodland about one mile from a navigable river.
A buffer zone of equal acreage is assumed to surround the site. All topo-
graphic, climatic, hydrographic, biologic, and demographic conditions are also
similar.
The plant owner is assumed to construct a coal-barge unloading facility on the
river bank, to install structures for water intake (pumphouse and supply pipe-
lines to the plant) and discharge (discharge pipeline and submerged diffuser
section in the river) , to construct an all-weather access road and a rail spur
to the plant site. Underground transmission lines (345 kV) from the plant
switchyard to the plant fence line are also x^ithin the scope of the project.
Connection to a regional utility grid is by others.
The site is in Seismic Zone 1. The air quality region is currently listed as
a nonattainment area for photochemical oxidants.
COAL PROCUREMENT
In this scenario, approximately one million tons per year of coal is shipped
to the power plant from surface mines in the northern part of the state. In
1975, more than nine million tons of strip-mined coal were produced in three
contiguous counties, one of which is assumed to be the hypothetical source of
coal for the plant (21). Strippable reserves in these counties exceed 100 mil-
lion tons. The plant receives 1^-inch by 0 (primary and secondary crushed)
coal by barge from a mining company on a long-term contract basis. A brief
description of the mining and transport operation is presented for comparison
with forest residue collection.
The plant feedstock is classified generally as high volatile-B bituminous
coal. More than one site may be mined over the plant life and part of the
production from more than one mine might reasonably be shipped to the plant.
Coal production is a completely separate operation from that of the power
plant. In this case, the production from two strip mines is dumped in a
common area. Part of the run-of-mine (ROM) coal is crushed, loaded on
barges, and shipped downriver to the plant. Total production is four to five
million tons per year.
The mining area is typically hilly terrain, hilltops locally to 600 feet ele-
vation. Several strip mines on either side of the river are active, while
68
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TABLE 30. SUMMARY ENVIRONMENTAL MATRIX - WOOD- TO POWER
Environmental
Factors
Effect of Plant
Construction and Operation
Potential
Mitigating Measures
Climatology and
Meteorology
Air Quality
Surface Water
Availability
Surface Water
Quality
Groundwater
Avallab ili tv
No discernible impact, discharged
heat and water vapor not expected
to have noticeable effect on
climate
Potential localized impact of
fugitive dust from construction;
small adverse impact from plant
operation
Requires about 1 gal/kWh of energy
output; minor adverse impact of
water resources
Minor adverse impact on quality
No consumption; no effect
Groundwater
Quality
Land
Availability
Regional Ecology
and Critical
Habitat
Low potential for contamination
Requires about 50 acres of land;
no significant impact
About 40-50 acres of vegetation
removed and associated wildlife
displaced or destroyed during
construction; minor adverse im-
pact, potential — low indirect
impacts during construction and
operation
Ponds and basins
lined; proper
management of
landfill required
Careful siting to
avoid sensitive
areas
Careful siting to
avoid critical
wildlife habitats
and rare or en-
dangered biologi-
cal species
(Continued)
69
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TABLE 30. (Continued)
Environmental
Factors
Effect of Plant
Construction and Operation
Potential
Mitigating Measures
Aesthetic
Resources
Historical,
Archaeological
Resources
Community
Economy
Community
Population
and Services
Labor
Availability
Power
Availability
Transportation
Availability
Small to moderate negative
impact-appearance conflicts with
farmland/woodland surroundings
Insignificant impact
Substantial benefit from construc-
tion and operation through
broadened tax base, wages paid into
community
Minor increase in local population
and residential services; minor
adverse impact on community
resources
Requirements for 200-300 con-
struction and about 30 operation
personnel; local manpower re-
sources adequate
Temporary power source needed for
construction, plant will export
power to local grid (power trans-
mission facilities supplied by
power purchaser)
Requirement for construction of
access road and rail spur; small
adverse impact on environment
from new transportation corridors
(and transmission corridor)
Plant design,
layout and
landscaping
Siting surveys
to protect cul-
tural- resources
Plant to train
unskilled work-
ers as necessary
Careful selection
of corridors to
minimize impacts
on land use;
ecology and
water resources
70
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other sites have been mined out and abandoned. Mined coal is typically
hauled either to the river or to rail lines for shipment. On the site, the
overburden ranges from zero feet at outcrops to about 100 feet at the maximum.
The coal seam averages six feet. Vegetation is cleared and topsoil is stripped
and stockpiled. Then the overburden is drilled (high-wall drill, electric
crawler) and blasted with an ammonium nitrate-fuel oil mixture. Large electric
shovels and a dragline remove the overburden and deposit it in spoils banks.
Bulldozers are used to support the drilling and stripping operations. With
the seam exposed, electric shovels excavate the coal and load 120-ton bottom-
dump trucks. Front-end loaders are used for cleanup and auxiliary loading.
The trucks haul coal over temporary roads from the active mining areas to
the dump site near the river. New haul roads are constructed as needed to
provide off-highway access from the mine to the coal dumping area. Most of
the coal is recovered by area mining, although some contour stripping is done
at outcrops on steep hills.
At the coal dump-loading site, run-of-mine coal is prepared for shipment.
Trucks dump the coal into a receiving hopper equipped with grizzly bars to
reject oversize material. An ROM storage pile is provided as an alternate
dump site. A reciprocating feeder feeds coal to a vibrating grizzly. Plus
6-inch material is crushed in a rotary breaker. Minus 6-inch material from
the grizzly is combined with breaker product and fed to another vibrating
grizzly. Plus lh;-inch material is sent to a double roll crusher for size re-
duction to 1%-inch by 0. Crusher product is combined with minus 1^-inch coal
from the grizzly and conveyed to a storage pile near the barge loading facil-
ity. Under-pile feeders and a 48-inch reclaim conveyor transfer coal to
the barges. The coal passes over a belt scale, onto a hinged boom, and
through a revolving chute that spreads coal evenly into barges 175 feet long
by 26 feet wide. The discharge end of the hinged boom can be adjusted to
allow for differences in water level and barge height during loading. Coal
tows of five to 15 barges (5,000 to 15,000 tons) are moved downriver to the
power plant.
As areas of the coal seam are mined out, the surface reclamation process is
initiated and carried on concurrently with mining. Overburden is backfilled
in the mined area by dragline and bulldozers. Bulldozers and graders contour
the surface to gently rolling terrain (also striking off the tops of spoil
ridges). Stockpiled topsoil is transported by carryalls and is spread over
the slopes by a bulldozer and a grader. Prior to seeding, the soils are
tested to determine nutrient levels. Revegetation species are standardized
in the state (forest, grasses, and legumes). In this area, pine seedlings
and native grass seed mixtures are used predominantly. Surface mine soils
tend to be somewhat acid and low in potassium content. Approximately 100 to
150 acres of land are stripmined each year to provide the coal production
for the power plant. More land would be disturbed and require reclamation
if, as has been assumed, the hypothetical mining company supplied coal to
other users of both steam and metallurgical coal.
COAL-TO-POWER PROCESS DESCRIPTION
The 500 MWe power plant is assumed to be owned by a regional utility produc-
ing power for transmission at 345 kV to its utility grid. Cleaned and sized
71
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coal (minus Ik-inch) is purchased on a contract basis and delivered to the
plant's dock facilities by standard coal barges (1000-ton capacity). _lne^
single-unit generating station has a nonregenerable flue gas desulfurization
(FGD) system to comply with the proposed new source performance standards
(NSPS) for the coal-fired steam-electric generating category. The plant has
a nameplate rating of 508 MW and produces about 476 MWe net output at 100-
percent load and average conditions. Coal consumption is about one million
tons per year. The general plant layout is illustrated in Figure 11.
Design Basis
The conceptual plant design is intended to be representative of commercial-
size units that are currently being constructed or being planned by utilities
in the U.S. This case considers only a single unit station, whereas two or
more unit stations in sequenced construction are becoming more common. No
provisions (or costs) were included for a second unit, however. The scenario
area is a developing industrial and commercial region and the increased demand
for power justifies the need for the facility. Abundant coal resources avail-
able in the region can support many more stations of this size.
Table 31 presents the composition of the assumed coal feedstock for the plant.
The high volatile-B bituminous coal contains about 1.5 percent sulfur and
hence cannot be burned without flue gas cleanup for sulfur oxides removal.
Table 32 presents .general design bases assumed for the conceptual plant.
The process description is broken down into major sections: coal handling,
combustion, flue gas cleanup, steam-turbine cycle, and auxiliaries, including
water and wastewater treatment and solid disposal systems. Figure 12 is a
simplified process flow diagram of the plant.
Coal Handling
The coal-handling facilities include the coal unloading dock, an overload
conveyor to the coal yard, an alternative car unloading dump, the live and
dead coal storage, the reclaim system, and the impact cascade system feeding
the boiler silos.
One-thousand-ton barges of coal are unloaded one shift per day, six days a
week, an average of five barges per day. Barges are unloaded by an inclined-
boom continuous bucket unloader. Three rows of buckets extend the full width
of the barge.
The barges are spotted by a tug in the unloading area. The bucket reclaimer
discharges coal into a 50-ton surge bin on the elevated dock structure. Un-
loading capacity is 2000 tons per hour. An apron feeder loads a 42-inch wide
belt conveyor which transports the coal at 1000 tons per hour, a distance of
3000 feet to a transfer house and sample station. The overland conveyor is
fully enclosed to prevent windblown loss of coal. A belt scale is located
near the feed end of the conveyor. At the transfer house, coal is discharged
into a chute which feeds a 42-inch stacker feed conveyor. A magnetic separa-
tor above the belt removes tramp iron. A two-stage sampling system removes
72
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Figure 11. Coal-fired power plant, general plant layout,
-------
TABLE 31. ASSUMED COAL FUEL PROPERTIES
Composition Moisture Free As Received
Proximate
Volatile Matter, % wt 38.4
Fixed Carbon, % wt 57.4
Ash, % wt 4.2
100.0
Ultimate
Hydrogen, % wt 5.5 5.27
Carbon, % wt 76.3 73.17
Sulfur, % wt 1.5 1.44
Nitrogen, % wt 1.7 1-63
Oxygen, % wt 10.8 10.36
Ash, % wt 4.2 4.03
Moisture, % wt _ 4 10
100.0 100.00
Heating Value (HHV), Btu/lb 13,590 13,033
Bulk Density. Ib/cu ft _
74
-------
jtNCHATOR
i7oRW\+l>lta
FLOW, M Lt/HR
TeMP., -F
HEM RME,HWBTU/HR
IHHOHLL
2411.5
1000
4922.1
RE.HIVT
3.1 IS. 16
360
tXHAJJSI
5Ht
104.1
:«^s
601 LtR
4lVfa
,MS.0
OUTPUT
-
-1
Co h* P 0 N 777f~^-— _^_^
FLQrt, M ACFM (&PM)
TEMP, , 'F
HEAT RATt , MM BTlJ/HR
SOLIDS, V« IWT
SOX , HLBfHft
NO, , M LBjHS
PU , M LB/HH
SiLOS
ao
ISSl.B-4
9S.91
AIR
m«
60
-
-
-
AIR
SO
-
"
10 e.%P&
253
-
10.059
i.T3l
11.364
OUTLET
123
i.oo a
Z.T
o.oto
STACK
115
loot.
0 OtO
ID auSNtH
- £>0
75 ft*
-
;
REC1RC.
-
10
-
ReaCLt
(«»<)
-
[+
SPRAY WBJ
-
-
;
BLIED
0*5)
-
10
;
SLUBR-V
•(!«.•)
-
-
25
VAC. FIL-
TCnOKK.
<(tw.e)
40
SMUltD
SLUOU.
t..MI
-
51.1
LiMtTD
^LAktR
-
-
IOO
LIMt
tUMMV
(IM3)
-
-
10
Figure 12. Coal-fired power plant, simplified process
flow diagram.
-------
TABLE 32. 500 MWe POWER PLANT DESIGN BASES AND ASSUMPTIONS
Coal Receiving
Onsite Coal Storage
Boiler
Steam Generator Cycle
Heat Rejection
Flue Gas Cleanup
Flue Gas Reheat
Solid Waste Disposal
Plant Water Supply
Onsite Water Storage
Plant Load Factor
Plant Operating life
1000-ton-capacity river barges (175 x 26 ft)
(rail hopper cars as alternate)
60 days dead, 3 days live
Pulverized coal, tangentially fired, balanced
draft furnace, controlled circulation drum-type
boiler with superheater, economizer and
regenerative air preheaters (2650 psig/1000 F)
Tandem-compound, quadruple flow, condensing,
single reheat turbine (553 MW output capacity,
at 1.5 in. Hga exhaust pressure), 2-shell
surface condenser, 7 stages of feedwater heating
(1 open); 590 MVA/0.95 pf generator, 22kV
Mechanical (induced) draft cooling tower, 30
range
Electrostatic precipitator (99% removal
efficiency) and line scrubbers (90% S07 removal)
50 F, direct firing-hot gas mixing
(indirect-steam coil heating as alternate)
Onsite landfill
River water (pumphouse intake system)
3-day storage capacity
70% (255 days/yr)
30 years
76
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an unbiased sample from the discharge end of the conveyor by reciprocating
cutter. The sample is screened, cut further, and portions combined into a
30-pound sample for analysis. Rejects are returned to the coal chute.
Coal can also be received by rail hopper car. An underground hopper is pro-
vided for bottom-dump cars. A 42-inch inclined-belt conveyor takes coal from
the hopper feeders and discharges it into the transfer house chute.
The inclined stacker feed conveyor runs through the reclaim transfer house
(a belt tripper can direct coal to the boiler feed system instead of the
stacker) and onto the elevated stacker conveyor. Coal is discharged through
telescoping chutes onto one of two conical live storage piles. Three-day
live storage is provided. A 60-day dead storage pile lies adjacent. Bull-
dozers move coal into and out of dead storage as required. Nearly all of
the 252,000-ton pile (six acres by 60 feet high) is compacted and sealed to
prevent spontaneous combustion and to retard dust blowing.
An under-pile dual reclaim system provides coal to the boiler at a nominal
175 tph. Each parallel system has a 355 tph design capacity (200 percent of
nominal usage). In the reclaim tunnel under the live piles, six of the twelve
60 tph vibrating feeders discharge coal onto one of the two 30-inch reclaim
belt conveyors. These inclined conveyors emerge from the tunnel and termi-
nate in the transfer (crossover) house. Coal from the divided transfer chute
feeds one of two 30-inch-wide belt conveyors taking coal to the boiler cas-
cade distribution system. The cascade system loads the five 300-ton capacity
boiler silos to full-level indication in sequence (or specifically indivi-
dually upon low-level indication). Normally four silos are in use at the
100-percent load conditions. The silos and conveyor discharge points are
ducted to a baghouse dust collector (3250 square feet collection area) where
a 13,000 cfm fan provides positive air flow.
Combustion Section
A pulverized-coal tangentially-fired balanced-draft boiler takes siloed coal,
pulverizes it, and burns it in the presence of 20-percent excess air, releas-
ing about 4552 million Btu per hour in the combustion zone of the water well
furnace. Heat is transferred by radiation and convection to the boiler tubes,
generating steam. Flue gas exits the boiler through two regenerative air
preheaters and passes to the electrostatic precipitators at negative pressure.
Five gravity feeders supply coal from the silos to five 100,000 Ib/hr roller
mills (four normally in operation). Primary air (blend of preheated air and
cold air at 600 F) is fed to the mills from the PA fans and conveys the pul-
verized coal to a set of 24 burners (at corners on six levels). Ambient air
discharged from two forced-draft fans passes through the steam air heaters
and the air preheaters and enters the windbox plenum serving the tangential
burners and the overfire air ports. A combustion control system regulates
coal air rates and combustion temperatures. Natural gas is used for startup.
The ignitor windbox houses electric ignitors adjacent to the warmup guns.
77
-------
Combustion products pass through the boiler section, through the air pre
heaters, and into the ducting to the precipitators. At full load (100 per-
cent), about 175 tph of coal are burned and about 1.3 MMCFM of flue gas enters
the precipitators. Bottom ash is collected in two hoppers below the combustion
section. Ash hoppers are also provided for the economizer and the flue gas
exit side of the air preheaters. It is assumed that 15 percent of the entering
ash is collected in.the bottom ash and economizer hoppers. Ash handling is
discussed later.
Boiler efficiency is about 89.7 percent (heat input to steam) at 100-percent
load and average conditions. Over eight percent of the input heat is lost in
the dry gas and the water from the fuel (fuel moisture and water produced from
fuel hydrogen).
Flue Gas Cleanup
The flue gas cleanup system is composed of electrostatic precipitators for
particulate matter removal (flyash collection) and lime scrubbing for sulfur
oxides removal. In addition, sludge stabilization is provided wherein de-
watered scrubber sludge, dry flyash, and a cementation agent (lime) are
blended to give a stabilized material suitable for landfill disposal.
Flue gas from the air preheaters enters two parallel precipitators, each
handling 50 percent of the flow (650,000 ACFM each and two gas paths). Each
precipitator is 99 feet wide, 73.5 feet high, and 78 feet deep and contains
233,280 square feet of effective collection area with eight bus sections in
the direction of flow. Design particulate removal efficiency is 99 percent.
Maximum power capability is 0.04 kW per MCFM.
Collected ash is discharged into the precipitator hoppers by plate rappers
operating on a sequential timer control. The bulk of the ash is collected
in plate sections near the precipitator inlet faces. Flyash is removed from
the hoppers by a pneumatic conveyor system, again by sequential timer control.
Cleaned gas leaves the precipitators at 250 F and 15 inches (water column)
below atmospheric pressure. Two 5000 hp induced-draft fans boost the flue
gas pressure to plus 10 inches (water column) to overcome the pressure drop
in the FGD system.
Sulfur dioxide removal is accomplished in the following conceptual design.
It is noted that such a system has not yet been operated over an extended
period and with the degree of reliability required by the bypass provision.
The system consists of three parallel scrubbing trains each handling one-
third (378,500 ACFM saturated) of the gas flow. Gas bypass ducting is pro-
vided for startup of the boiler. Each scrubber can be taken offline indepen-
dently with concurrent reduction in boiler load. The absorbers are 32-foot
diameter by 100-foot high spray towers capable of 90+ percent removal of in-
let S0? (about 1000 ppmv). Gas is distributed to the absorber inlet pre-
saturaEion sections (base of tower) and cooled by sprays of recirculating
slurry. Gas proceeds upward through the towers being contacted counter-
currently with a series of sprays which absorb SO from the gas phase. The
liquid-to-gas ratio is 80 gallons per thousand cubic feet. The wet gas passes
78
-------
through a mist eliminator section tor removal of entrained particulate mois-
ture and solids. Saturated exit gas at 125 F from each scrubber is recombined
in the outlet ducting and reheated to 175 F before entering the 300-foot high
concrete stack. Reheat is accomplished by direct mixing of flue gas with hot
combustion gas from a natural gas-fired horizontal combustion unit. Table 33
summarizes the major FGD design parameters.
From the absorber, S02~rich slurry falls into the 280,000-gallon absorber de-
lay tank located below the spray tower. Five minutes residence time is pro-
vided to complete the reaction of lime with S02 forming calcium sulfite and
calcium sulfate, which precipitate as solubility limits are exceeded.
TABLE 33. FGD SYSTEM DESIGN PARAMETERS
(90 percent SO,-, removal by lime scrubbing)
No. of Absorber Trains
Absorber Type
Superficial Gas Velocity
Total System Pressure Drop
Liquid to Gas Ratio (L/G)
Presaturation Sprays
Mist Eliminator Spray
CaOiSO,., (Absorbed) Stoichiometric Ratio
Delay Tank Residence Time
Absorbent Solids Concentration
Lime Slurry Makeup Concentration
Dewatered Sludge Solids
Stack Gas Reheat
Spray tower
8.5 feet per second
9.5 in. water column
80 gal/MCF
2 gal/MCF
2 gal/sq ft
1.1
5 minutes
10 percent
20 percent
40 percent
50°F
79
-------
Lime slurry makeup is added to the delay tanks to maintain the desired
1.1 CaO:SO (absorbed) stoichiometric ratio. Six 6150 gpm capacity pumps
circulate the 10-percent (solids) slurry to the presaturator and spray tower
spray nozzles. A slurry bleed stream from each delay tank is pumped to a
surge tank and then fed to a 95-foot diameter thickener.
Another recirculating system (washer tray recycle) is provided to prevent
scaling and plugging of the mist eliminator and wash tray section of each
tower. A recycle pump supplies water to irrigate the wash tray below the
mist eliminators in each tower. Tray water is decanted back to a 15,800-gallon
recycle tank. A bleed stream from the recycle pump discharge purges accumu-
lated solids from the system. The three purge streams are sent to a 65-foot
diameter clarifier where the solids are settled out. Clarifier overflow is
pumped back from an overflow surge tank to the mist eliminator and wash tray
spray systems of the three scrubbers. Fresh (filtered) makeup water (255 gpm
total) is added to the spray water supply. Underflow slurry from the clari-
fier is pumped to two thickened slurry surge tanks which also receive under-
flow from the slurry thickener.
At 90-percent SO removal, approximately 250 tons per day of thickened (23 per-
cent solids) slurry are removed from the absorber trains. This sludge is de-
watered, mixed with flyash, and stabilized with lime for landfill disposal.
The dewatering and stabilization system operates 40 hours per week. Hence,
large (338,000-gallon) surge tanks are provided to store accumulated sludge
(three-day capacity total). Three rotary vacuum filters 12 feet in diameter
by 22 feet long (830 square feet filter area) dewater the sludge to a mini-
mum 40-percent solids cake. Filtrate is pumped from the receiving tanks to
a 338,000-gallon surge tank where accumulated filtrate is worked off con-
tinuously by being returned to the absorber recirculating slurry loops. The
filter units are enclosed in a separate building. Filter cake is discharged
onto an enclosed-belt conveyor which transfers the cake directly to one of
two 200-ton-per-hour capacity pug mills for blending with flyash and lime (as
a cementation agent). The pug mills are located in the sludge stabilization
building.
Flyash is pneumatically conveyed from the precipitator hoppers and the air
preheater hoppers to twin 475-ton capacity flyash silos. Each provides three-
day storage capacity at design load and assuming 90 percent ascending ash in
the boiler. Exhaust conveying air from the silo product separators is passed
through a baghouse prior to discharge into the atmosphere. At the bottom of
each flyash silo, a volumetric screw feeder meters flyash into a pneumatic
conveyor supplying a proportional quantity of flyash to the pug mill for
blending with dewatered sludge. Lime is also metered by weigh feeder from
a 130-ton capacity silo and transported to the pug mill by belt conveyor.
Lime is added for cementation of flyash/sludge at two percent on a dry solids
basis (1.4 tons per hour lime). The flyash/scrubber sludge/lime blend from
the pug mill is transferred by belt conveyor to twin 150-ton capacity truck
load-out bins. About 140 tons per hour of stabilized sludge (51.3 percent
solids) are generated for disposal. Two 40-ton capacity end-dump trucks haul
sludge to the landfill area 40 hours per week. At about 70 pounds per cubic
foot, some 160,000 cubic feet of solids per week are landfilled. Miscellaneous
80
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sludges produced intermittently in the plant (filter backwash sludge, basin
cleanouts, etc.) are also processed in the dewatering and stabilization system.
About 116 tons per day are utilized in the FGD system for 862 removal. This
lime along with the lime used in sludge stabilization is delivered to the plant
in bulk rail cars. Two 1000-ton capacity lime silos provide about 17 days of
storage capacity. The rail cars are unloaded pneumatically (vacuum) and a
filter collector (baghouse) collects dust escaping the product separators.
The stabilization lime silo is also filled from rail cars. Lime is supplied
to the scrubbers as a 20-percent slurry. Dry lime is slaked in a 150-ton-per-
day package slaker unit with fresh water used for slaking and vacuum filtrate
water used for dilution to the 20-percent concentration. The lime slurry is
pumped from the slaker transfer tank to a 74,000-gallon agitated slurry stor-
age tank and thence to a similar slurry surge tank. Each tank holds an eight-
hour supply of lime slurry at design lime demand in the absorbers. A slurry
feed tank pump supplies' lime slurry to the three absorber delay tanks.
The entire FGD system operates continuously with equipment shut down for re-
pair or maintenance only during reduced boiler loads. Normal bypassing of
the FGD system is not permitted, so critical equipment is spared. Sulfur di-
oxide analyzers monitor SC>2 concentrations at the inlet and outlet ducting
of the FGD system. NOX and opacity are also monitored continuously in the
stack.
Steam Cycle
The boiler maximum continuous capacity is 3,980,000 Ib/hr steam flow at
2675 psia and 1005 F at the superheater outlet. At the 100-percent load con-
dition (shown in Figure 12), steam flow at the turbine throttle (high-pressure
section) is about 3.37 million Ib/hr at 2411.5 psia and 1000 F. The turbine
consists of a single-flow, high-pressure section, a single-flow (reheater flow)
intermediate-pressure section, and two double-flow, low-pressure sections con-
nected in tandem. Steam from the high-pressure stages returns to the reheat
section of the boiler and reheated steam (1000 F) then flows through the in-
termediate-pressure stages. The exhaust steam flow is divided and enters the
two double-flow low-pressure sections, finally exhausting into the two-shell
surface condenser. Steam is withdrawn from seven extraction ports for feed-
water heating and for driving the steam turbine driver boiler feed pumps.
The hydrogen-cooled generator produces about 504.3 MW (gross output) of power.
Its rated capacity is 590 MVA (3600 rpm, 0.95 power factor, 22 kV). Net out-
put is about 476 MW. An isolated phase bus connects the generator to the
main transformer where generator voltage is transformed to 345 kV line volt-
age for transmission to the utility's grid.
Turbine exhaust steam is condensed at 2.5 inches Hg absolute in a twin shell,
two-pass, divided waterbox condenser, also serving the boiler feed pump tur-
bines. Circulating water in the tube side of each shell picks up heat from
the steam condensing at 108.7 F. Boiler feedwater makeup is added to the hot
well. Condensate accumulates in the interconnected hot wells under each shell
and is pumped by motor-driven condensate pumps (three 50-percent capacity)
-------
through the gland steam and the air ejector condensers and through three low-
pressure closed feedwater heaters. The condensate is deaerated by steam con-
tact in a horizontal-spray tray type deaerator. A deaerated condensate storage
tank provides five minutes surge capacity for the booster pumps which pump con-
densate through two intermediate-pressure feedwater heaters to the boiler feed
pumps. The steam-turbine-driven boiler feed pumps supply condensate at about
2900 psia to the high-pressure feedwater heater, and the heated feedwater enters
the economizer section of the boiler at about 460 F.
Feedwater flow from the economizer discharges into the upper horizontal steam
drum. Four boiler circulating pumps maintain the desired circulating flows
to the various inlet headers of the steam generating circuits. Boiler blow-
down (0.5 percent) is taken from the water surface in the steam drum to a blow-
down flash tank before discharge to a hold tank. An auxiliary gas-fired boiler
is provided for startup of the main boiler and also for boiler chemical clean-
ing. During normal operation, the auxiliary steam supply will be saturated
250 psig steam (pressure reduced) from the main boiler steam drum. Auxiliary
steam is used in the plant heating system and in the air ejectors. Steam
losses (including soot blowing) total about 14,000 Ib/hr.
Auxiliary Systems
Environmentally related auxiliary systems discussed here are the water systems,
wastewater treatment, and solids disposal. The following systems are not de-
scribed: bearing cooling water, lube oil handling, compressed air, sampling,
fire protection, heating, ventilating and air conditioning, and electrical.
Water System—
Figure 13 shows a simplified water balance for the plant. Plant makeup water
is supplied from the river intake water pumphouse by three 50-percent capacity
(2,200 gpm) vertical wet-pit pumps. The intake structure is equipped with
trash racks and traveling screens to prevent intake of debris. River water
is pumped through a 20-inch diameter pipeline to the onsite water storage
basin. The 18.2-million-gallon earthen basin provides a three-day supply of
x^ater for the plant. Main fire pumps are also located in this pond. Average
plant water demand at the 100-percent load condition is about 4100 gpm.
The circulating water system and service water system provide cooling water
to the main condenser and to all of the auxiliary system coolers (service
water). Two induced-draft cooling towers reject the waste heat to the atmo-
sphere by evaporative cooling. Each tower is 288 feet long by 71 feet wide
by 51.5 feet high and contains eight standard cells each with a 28-foot diam-
eter, 200 hp fan. The total cooling duty at average conditions is about
2350omillion Btu/hr with a cooling range of 30°F (72.7°F to 102°F) and an
11.2 F approach to the wet bulb temperature. The circulating water system
is maintained at a minimum of 10 and an average of 25 cycles of concentration.
At average conditions, evaporation and drift losses total about 3533 gpm.
The 50-percent capacity (90,000 gpm) pumps circulate cool water from the tower
basins through a 90-inch diameter line to the surface condenser. Slowdown
is taken from the discharge side of the circulating pumps. Service water is
82
-------
H
I RIVER
1 INTAKE
£( „ WATER
I (4092SPM) STORAGE.
R /
V
E.
R , r^=
1 die,
)
COAL PILE
\ RUNOFF
evAPORATIQW A
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(3J02 &PM) "I1 C
h^>
C.T. MAKIUP k^
UbAS &PM) LOOLING P
* lOWtR 1
(C.T.) 1 1
SCRUBBER MAKEUP
POTABLE. WATER
^— — -*(lD 1PM) */
- > > FIRE WATtR
(O-i'ioo &PM)
UTILITY WATtR
^ ^ (20 5PM) *f
DUM-ME.DIAI BFW 1
. * ULltK 1 •iKtATWtMTl
(l.iGPMjA^H, SLUICE MAKEUP
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-^ 12 ACKcs | BACKWASH ACID
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i
' r-<=2 '<
/ | (IE* &PH >•
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^ 51 GPM) BASIN
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BACKWASH! KII\JTR*LI- 1
L-x ~, 1
SETTLING!""* •* Z^ION TK 1
TK 1 SLUDSE |
. EFFLUENT i BRINE.
| (II.8C.PM) ;(T.66PN)
O Aroii, ^ 1 ._ V
5RIFT LOSS
SLAKER fLU£ GAS
E.VAP. EVAP.
COWOIUST.R
{, COOLERS
VJ4UI IIP
BFWf TURBINE.
(«.8 BOILtF
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FURNA(
.L
L
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-r-^-
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lZ.t.2 GP
-s=->
' | (4.SGPM)
, '(*04PM)
. BOTTOM ASH
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"""T"™"^
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BLOWOOWN SETTLED- ASH
((15 6PM ( a. ft &phO
PROCESS tFFLOtNT (le
, IH,ERM1T
FGD 1 STABILISED
SYSTEM r* ? SLUDGE.
1 ITO.S &PM)
^^^ SAWITARY
, BIOLOSICALltF
) * TREATMENT! •
COLLECTION!
/— • 4 OIL SKIM. 1
M) I
UTILITY
WASTE MATER
BOILE.R
B.D.
(52,6 GPM)
UI.T&PM) BLOWOOWNJ
• BAblW 1 *
IT GPM)
TEMT PLOW
FLUENT
( 10 GPM)
MJG CUItAATIC CONDITIONS
Figure 13. Coal-fired power plant, simplified water balance.
-------
supplied by two (one spare) 12,000 gpm capacity pumps downstream of the cir
culating water pumps. Hot circulating water returns to the distributors at
the top of the two cooling towers. Makeup is supplied by the pondwater pumps.
Sulfuric acid and a dispersant chemical are added to the circulating water to
prevent scale formation and solids deposition on heat transfer surfaces. The
circulating water is also chlorinated for 24 minutes, three times per day, to
prevent the growth 'and buildup of fouling microorganisms. Residual chlorine
is monitored at the outlets of the condenser.
Except for ash sluicewater makeup, the remainder of the plant makeup is
treated for the various uses. A dual-media filtration system (two 500-gpm
capacity gravity filters) filters water from a pondwater booster pump. A
filtered water clearwell provides about 3% hours of surge storage at average
use rates. Filter backwash water is collected and settled in a tank before
discharge of clarified water to waste.
Boiler feedwater makeup is produced in a demineralizer system consisting of
two parallel trains, each having a cation exchange unit, an anion exchange
unit, and a mixed bed polishing unit. Each train can produce 20 gpm of boiler
feedwater, and filtered water is 'supplied to the trains by two demineralizer
feed pumps located in the filtered water clearwell. Average demand is about
61 gpm. A 175,000-gallon tank provides surge storage of demineralized water.
The ion exchange beds are regenerated with (diluted) 66 Be sulfuric acid and
50-percent sodium hydroxide. Hydrazine, ammonium hydroxide, and phosphate
are added to the boiler feedwater for oxygen scavenging and water conditioning.
Filtered water is chlorinated and supplied separately to an aboveground water
tank for distribution to the potable (domestic) water system. The FGD system
makeup and other utility water is supplied to the plant water distribution
system by clearwell pumps.
Wastewater Systems—
Major plant wastewater sources are sanitary wastes, cooling tower blowdown,
boiler blowdown, confined yard and floor drainage (utility wastewater), de-
mineralizer regenerant wastes (intermittent), filter backwash (intermittent),
coal yard, switchyard, and general plant area runoff (intermittent). Equip-
ment cleaning and basin and tank cleaning wastes are infrequent sources of
wastewater.
Sanitary wastewater is collected separately and treated in a packaged biologi-
cal treatment unit which includes biological oxidation, clarification, filtra-
tion, and disinfection. Cooling tower blowdown and boiler blowdown streams
are collected in a 750,000-gallon concrete basin which provides (at full level)
about iy2 days' equalization and suspended solids settling capacity. It also
receives utility wastewater from local sumps equipped with oil skimmers. The
basin water is monitored for pH, oil and grease, residual chlorine, and sus-
pended solids. This basin is also used for retention and treatment of equip-
ment cleaning wastes. Overflow enters the stormwater settling pond. Deminer-
alizer regeneration brines are collected and neutralized in a tank before dis-
charge to the blowdown basin. Similarly, filter backwash water is collected
-------
in a tank to allow solids settling and clarified backwash is discharged to
the blowdown basin. Backwash sludge is pumped intermittently to the FGD
sludge filtration system.
Plant yard areas that have storm drains or drainage ditches total about
112 acres, including the initial five-year sludge landfill site. Coal yard
runoff (12 acres drained) is collected separately in a 1.1-million-gallon
clay-lined pond which can impound the first 50 percent of the runoff from a
10-year, 24-hour duration storm. Annual runoff (35 inches assumed) from
this area would average about 22 gpm as a continuous flow. The coal yard
pondwater is monitored for pH and suspended solids. Lime slurry from the
FGD lime makeup system can be used to neutralize acidity if needed before
discharge to the main stormwater pond. Switchyard runoff passes through an
oil separator (corrugated plate interceptor) to collect lighter- and heavier-
than-water fluids.
The remainder of the plant area drainage (about 100 acres) is collected in
a 7.8-million-gallon settling pond provided for settling out suspended solids
picked up by the surface runoff. The sludge disposal landfill area is drained
to this pond. About 50 percent of the runoff from a 10-year, 24-hour duration
storm can be impounded. At 30 inches of annual runoff, this runoff would
average about 155 gpm as a continuous flow. Impounded stormwater could be
used as cooling tower makeup during storm periods when river water turbidity
is likely to be high. Unimproved portions of the 365-acre plant site have
drainage patterns directed away from the main plant drainage system.
Normal plant effluent can be directed through the stormwater basin before
discharge to the river, though usually the basin is bypassed. Plant effluent
and stormwater flow by gravity through a pipeline to the river discharge dif-
fuser downstream of the intake pumphouse. Effluent is discharged below the
water surface through multiple pipe section diffusers on a header pipe.
Ash Handling—
Bottom ash, coal mill rejects, and economizer ash are handled in a recircu-
lating sluice system which deposits the ash in one of three small (one acre)
ash ponds. About 2110 Ib/hr of ash is collected (15 percent of entering ash).
Economizer ash is discharged to the bottom ash hoppers. A low-pressure pump
continuously recirculates ash sluicewater from a surge tank near the boiler.
The tank receives makeup water (during non-sluicing periods) from the river
water pond booster pump. During the sluicing operation (once per day), a high-
pressure pump sluices ash from the bottom ash hoppers to the pond. In the
same cycle, rejects from the mill reject bins are also sluiced to the ash pond.
A recycle pump in the ash pond decant section returns water to the surge tank
to maintain the sluicewater supply during the operation. The three one-acre
clay-lined ash ponds are rotated in service about every eight or nine months.
Each contains a decant section for clarifying sluicewater for recycle. When
filled with ash, the pond is taken out of fill service and sluiced ash from
the boiler is routed to an empty pond. Decant water continues to be used until
a low water level is reached. The ash is then dredged out and hauled by truck
to the landfill site. Assuming the dredged ash has a 40-percent moisture con-
tent, some 425,000 cubic feet (10,760 tons) would be disposed of per year.
85
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Solid Waste Disposal—
Over six million cubic feet per year of stabilized flyash/FGD sludge is pro-
duced along with the bottom ash and a small amount of plant trash and garbage.
It is assumed that these materials can be deposited to an average height of
25 feet on fairly level terrain without stability problems occurring and with-
out the need for constructing impoundments or retaining structures. The land-
fill areas are developed in five-year increments (32-37 acres). The materials
are dumped, spread, and compacted in two- to three-foot layers. 'Soil cover is
applied on areas where the final height has been built up. Soil stabilization
and revegetation commence when a workable area has been filled and covered.
Other Facilities—
As indicated in Figure 11, plant physical facilities include buildings — the
turbine hall, warehouse and shops, the administration building, the water treat-
ment, filter, and sludge stabilization buildings — roads, rail spur, parking
areas, fences, gatehouse, and other site improvements.
Thermal Balance
The overall plant heat rate is about 9563 Btu/kWh at 100-percent load conditions
and excluding the heat input (78 MM Btu/hr) for flue gas reheating. Table 34
summarizes major factors in the plant thermal balance. A large portion of the
energy input is (lost) dissipated to the atmosphere in the form of enthalpy
(added) of cooling-tower exhaust air and water vapor — heat rejected from cool-
ing water.
Auxiliary power losses include about 6.6 MWe consumed by the electrically driven
equipment in the FGD system or about 1.3 percent of the gross output. This is
about the same amount as the electric power consumed by the PA, FD, and ID fans
(6.9 MWe). Net plant output is about 476 MWe or 35.7 percent of the coal heat
input.
A 50 F flue gas reheat system has been included to mix hot gas from a natural
gas-fired combustion box with the saturated flue gas from the scrubbers. Gas
consumption represents about 1.7 percent of additional heat input and lowers the
overall plant thermal efficiency to about 35.1 percent (total input basis).
Other reheat options would be indirect steam coil heating of outside air to mix
with the cold flue gas or direct steam coil heating of the flue gas. Both op-
tions would use steam either from the auxiliary boiler or from the main steam
system. Both options would be somewhat less efficient than the simple system
chosen for illustration.
-------
TABLE 34. COAL TO POWER THERMAL BALANCE ELEMENTS
MM Btu/Hr
Coal
(-)
(-)
(-)
(-)
Fuel Input
Furance Losses at 10.3%
Input to Steam
Steam Cycle Losses
Output at Turbine Exhaust
Turbine Generator losses
at 1.7%
Gross Plant Output
Auxiliary Power Losses
Net Plant Output (9563 Btu/kWh)
4,551.
(468.
4,083.
(2,332.
1,750.
(29.
1,721.
(96.
1,624.
8
8)
0
0)
9
7)
2
6)
6
kW
1,333
(137
1,196
(683
513
(8
504
(29
476
% of Input
,670
,730)
,300
,280)
,020
,720)
,300
,300)
,000
100.
(10.
89.
(51.
38.
(0.
37.
(2.
35.
0*
3)
7
2)
5
7)
8
1)
7
*Gas fuel input to reheat flue gas excluded — this adds to input:
78.2 MM Btu/hr, 2290 kW, 1.72% of coal heat input.
COAL-TO-POWER PLANT COSTS
Capital and annual operating cost summaries for the 500 MWe conceptual plant
are given in Tables 35 and 36. Appendix C discusses the cost estimation basis
and methodology. The $384 million total capital cost represents about $800/kW
(net). Major pollution control equipment is estimated at $20 million or about
10 percent of the direct field cost. The electrostatic precipitators and the
FGD system constitute the bulk of this installed equipment cost. On a total
capital cost basis, the pollution control portion would be roughly $85/kW
(net) or 10 percent. A considerable part of the startup costs could be attrib-
uted to the FGD system. Excluded are all costs associated with preparing an
environmental impact report, obtaining environmental permits, and obtaining
any emission offsets that may be required. Distribution costs are also ex-
cluded.
87
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TABLE 35. COAL-TO POWER CAPITAL COSTS
" Element $1,000,OOP's
Site and Yard 9.5
Civil/Structural 23.0
Process Mechanical Equipment 97.0
Pollution Control Equipment 20.2
Piping and Instrumentation 22.8
Electrical 19-8
DIRECT FIELD COST 192.3
Indirect Field Cost 22.4
TOTAL FIELD COST 214.7
Engineering Services 25.7
240.4
Allowance for Uncertainty 48. 1
TOTAL CONSTRUCTION COST 288.5
Land 0.7
Other Owner Costs 14.4
Startup 14.4
Allowance for Funds During Construction 47.7
FIXED CAPITAL INVESTMENT 365.7
Working Capital 18.3
TOTAL CAPITAL COST 384.0
First Quarter 1978, Price and Wage Levels
-------
TABLE 36. ANNUAL OPERATING AND MAINTENANCE COSTS* - COAL TO--POWER
Element
Supplies
Utilities
Operating Personnel
Maintenance Labor and Materials
Supervision
Administration and Overhead
Local Taxes and Insurance
TOTAL ESTIMATED ANNUAL OPERATING COST
$l,000,000's
2.0
1.2
0.7
2.0
0.3
0.9
7.7
14.8
First Quarter 1978, Price and Wage Levels
-'Excluding coal feedtock.
The annual operating cost, excluding coal, of $14.8 million represents about
five mills/kWh (net). No estimate was made of the pollution control portion.
Certainly, lime for the FGD system is a major fraction of the chemicals cost
(supplied). Disposal of the stabilized FGD sludge was assumed to be rather
straightforward with no particular handling or environmental hazard difficul-
ties. Sludge disposal would be considerably more expensive were the material
designated as a hazardous waste.
Figure 14 shows the effect of delivered coal costs on the cost of electricity
for private and utility financing. At, say, $25/ton in this region, the fuel
cost is about one-third of the 20 mills/kWh cost of electricity.
COAL-TO-POWER ENVIRONMENTAL ASSESSMENT
Feedstock procurement impacts and impacts of the operating plant are described
in the context of a hypothetical South Central U.S. site.
89
-------
0.5
COAL COST, S/MMBTU
1.0 1.5
2.0
,125
COAL-TO-POWER
PRIVATE
UTILITY
100
75
X
^
t/J
_1
_J
o
cc
CJ
LU
_l
LU
150 O
H
C/l
O
u
25
10
20 30
COAL COST, S/TON
40
Figure 14. Effect of coal cost on cost of electricity
with both private and utility financing.
90
-------
Coal Procurement Impacts
About one million tons per year of coal will be required from strip mines in
the area proposed as the source of coal for the plant. Impacts on land, water,
air, and biology will be typical of strip mines regardless of location, al-
though site-specific characteristics may modify the significance of the im-
pacts. The impacts are summarized in Table 37.
Topography—
The normally hilly terrain will be disrupted at the mine site, with from zero
to 100 feet of overburden removed (excavated) and stockpiled prior to coal
removal. Land reclamation will result in an approximation of the original
topography, but it is likely that elevations of hills will be lower by at
least the amount of coal and other materials removed; that normal topographical
irregularities will be replaced with a-more regular, rolling terrain; and that
the contours of the mined area will not be exactly as the original contours.
However, given past uses of the area and the likely continued use for strip
mining, these topographical changes will not be unusual. Therefore, the direct
impact of strip mining on topography will be marked, but not significant to
the regional topography.
Soils and Geology—
Removal of the required million tons of coal per year will result jLn three
direct changes in regional soils and geology:
• Disruption of the natural geologic structure and the
physical properties of the overburden by destroying the
original stratification of beds, geologic structures,
and natural strength
• Removal and consumption of the coal, a nonrenewable resource
• Intermixing of soil horizons, possibly bringing to the
surface materials that may be harmful to plant growth
Stockpiling of soils and subsoils may also result indirectly in "bulking," or
an increase in volume, of the overburden, with the result that, upon reclama-
tion, the fill would be less dense and subject to compaction and settling over
time. In addition, stockpiling of topsoil may result in lowered productivity
of the soil since the stockpile will become biologically sterile with time.
Upon reclamation, productivity cannot be restored until the area has been bio-
logically reinoculated and the normal bacteriological and mycological popula-
tions have been restored.
Groundwater—
Possible impacts on groundwater (depending on aquifer structure at the mine
site and the location of recharge areas) are:
• Removal of existing shallow aquifers or portions thereof,
and replacement by unstructured overburden or spoil
91
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TABLE 37. PROCUREMENT IMPACT SUMMARY - COAL
Environmental Factors
Coal Mining Impacts
Mitigating Measures
Topography
Soils and Geology
Groundwater
Quality
Surface Water
Air Quality
Vegetation and
Wildlife
Land Use
Aesthetics
Minor changes in land form
after reclamation
Possible settling and com-
paction of, reclaimed area;
reduced soil productivity;
consumption of nonrenewable
resource (coal)
Possible interruption or
loss of aquifers (shallow)
and recharge areas as well
as related change in ground-
water quality
Alteration of drainage pat-
terns , flows; increased ero-
sion and siltation in streams;
losses of some tributaries
Increased particulate
emissions-fugitive dust
Removal of mature woodlands
and associated animals; po-
tentially significant local
impact on endangered red
cockaded woodpecker
Short-term commitment to
mining; potential long-term
reduction in productivity;
altered uses resulting
Sharp visual contrast but
not significant given sur-
rounding land uses; short-
term
Mine-site reclama-
tion to simulate
existing topography
Mine-site controls
on drainage; re-
clamation to re-
store drainage
pattern if possible
Revegetation plans,
wildlife management
incorporated into
reclamation of
mine site
Reclamation of
mine site
Reclamation
(Continued)
92
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TABLE 37. (Continued)
Environmental Factors
Coal Mining Impacts
Mitigating Measures
Community Economy
Community Population
and Services
Labor Availability
Potential for increased em-
ployment, personal and re-
gional income
Small population increase
possible with equivalent
increase in demand for
goods and services
Local labor pool adequate
Training programs
to be initiated
Transportation
Mine-site roads required —
no discernable effect; local
congestion may occur on haul
roads between mine site and
plant at times
• Reversal of- recharge/discharge relationships by interfacing
with recharge areas and/or draining aquifers Cdewatering)
during the mining operation
• Altering groundwater quality by changing the sources of
chemicals in the water (rock and biosphere); by changing
hydraulic, thermal, and chemical gradients; and by losses
of precipitation, ion exchange, sorption, and biosphere
effects on the groundwater
The effect, whether permanent or temporary, cannot be predicted without studies
of mine-site groundwater. However, while changes in groundwater availability
and quality are likely and will be adverse, their regional significance will
depend on present groundx^ater problems as a result of mining, regional depen-
dence upon groundwater as a potable water supply, and future needs which might
require protection of all potential water supplies.
Surface Water—
Changes in topography will result in changes in drainage, possibly altering the
quantity and quality of water downstream of the mine. Strip mining and over-
burden stockpiles near rivers or streams can result in erosion, increased tur-
bidity, and siltation. In addition, physical barriers to runoff, including
removal of streams and small watersheds, can affect river flows locally. Uses
of erosion control methods and reclamation of the mine site as mining progresses
(rather than long-term stockpiling) will reduce the long-term significance of
these effects. The present mining use has probably already affected surface
93
-------
waters and, if care is taken in expansion of the mining operation, additional
impacts on surface water can be kept to a minimum.
RemoSafofvegetation and disruption of topsoil will contribute to _ increased
particulate emissions in the form of fugitive dust. The quantity in tons per
year will depend on the area disturbed (dependent on richness of the coal vein
and the timing of reclamation) as well as the average wind speed in the area
Most emissions produced will likely be extensions of present air quality prob-
lems attributable to mining in the area.
Vegetation —
An unknown quantity of longleaf pine, slash pine, and loblolly-shortleaf pine
vegetation will be removed in the course of -mining. The exact acreage will
depend on the richness of the coal vein and therefore upon the quantity of
surface area to be disturbed for economic removal of the required quantity of
coal. While this acreage may not be significant to the regional ecology (which
is predominantly loblolly-shortleaf pine) , the local impact will be significant
and long-term. Standardized reclamation procedures, with specified pine, grass,
and legume species, will reduce the impact over the long term, but the quality
of habitat produced may not be equivalent to the present vegetation. This may
be particularly true if soil productivity is reduced, if altered topography
affects plant growth, or if the specified plant species for revegetation do
not allow a community to develop which is equivalent in variety to the present
pine flatwoods.
Wildlife—
A major potential effect would be the loss of mature pine flatwoods which are
the preferred habitat of the red cockaded woodpecker, an endangered species
which requires stumps or dead stubs of trees found only in a mature woodland.
Since strip mining could result in a major long-term loss of mature woodland,
this endangered species could be seriously affected in the mining region.
In addition, the normal wildlife populations in the removed vegetation types
will be displaced or removed when the vegetation is removed. In both instances,
increases in mortality of local species will result. Nearby populations will
be available to repopulate revegetated habitat should the area be able to sup-
port these animals. Some species, such as raptors, may benefit since more open
grassy fields will probably support larger populations of prey species (e.g., ro-
dents) than pine flatwoods. However, decades may be required for restoration
of habitat for species dependent on mature woodlands.
Land Use —
Careful planning of mine-site reclamation keyed to simulate or even enhance
alternative land use (i.e., recreational plans, wildlife management, soil en-
hancement for agriculture, woodlot planting) may benefit future uses of the
area. Present uses of the land surface will be preempted during mining, and
some uses may be restricted after revegetation.
•
Overburden compaction and settling may restrict building
on the reclaimed site
94
-------
• Altered soils may temporarily reduce the value of the
area to agriculture or grazing
• Economically important woodlands (lumber, pulp) may not
be available for many years following revegetation
• Present recreational uses (hunting) will be eliminated
during mining and may not be appropriate in the reclaimed
areas
Since present land use includes surface mining, these changes may not be in-
consistent with projected land use of local plans and zoning.
Aesthetics—
Constrasts in color (variations in soil color, exposed coal beds, and subsoils),
land forms (open pits, service roads cut into hillsides, unshaped stockpiles
of overburden, and topsoil), and texture (bare soil-vegetation) will make the
mine site aesthetically displeasing. The overall effect, however, will be in
keeping with the present appearance of the area due to present mining activi-
ties, and reclamation activities will further moderate the impact.
Social and Economic Effects—
The major socioeconomic impacts generated by strip mining include:
• Increases in population and employment associated with
expanded mining efforts
• Increases in regional and personal incomes as a result
of expansion of mine-related employment and the sale of
coal
• Increased demand for goods and services proportional to
population increases but offset at least partially by
increased incomes
The degree of impact cannot be determined without complete data on the expan-
sion of mining effort required. However, given past production in the region
of nine million tons per year, and a requirement by this project of one million
tons per year, it might be reasonable to assume an employment increase of a
maximum of one-ninth the present workforce and resultant income proportional to
this maximum increase. Most of the new employees will probably be hired from
the local labor pool (skilled and unskilled), but some population increase may
also result. Net socioeconomic impacts are likely to be beneficial.
Plant Impacts
Impacts of the coal-fired power plant on the environment will occur during
plant construction and during the operating life of the facility. Construction
activities will cause primarily short-term impacts except for the direct altera-
tion of the land surface. Operation impacts are longer-term in nature and re-
sult primarily from air, water, solid waste, and noise emissions from the operat-
ing plant. In addition, the plant will consume resources that will then not be
95
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available for alternative uses. Table 38 summarizes principal resource require-
ments (on an annual consumption basis) and consumption versus product output
(power). The land requirement includes about 230 acres for land disposal of
solid wastes over the plant operating life. Table 39 lists approximate chemi-
cal consumptions.
Plant impacts are broken down into physical/chemical, biological, aesthetic,
and socioeconomic categories for discussion.
Physical/Chemical Emissions and Impacts—
Physical/chemical emissions will occur during both the construction and opera-
tion stages. Estimates of air, water, and solid waste emissions are summarized
for the operating plant and general impacts described.
Air Emissions—The major point-source emissions to the atmosphere will be the
boiler stack gas and the exhaust from the two cooling towers. Material handling
TABLE 38. PRINCIPAL RESOURCES COMMITTED TO PLANT OPERATION -
COAL TO POWER
Resource Category
Quantity
Normalized Quantity
(Output)*
Land
Coal (13,033 Btu/lb)
Natural Gas (1,024
Btu/cu ft)
Diesel and Gasoline Fuel
Auxiliary Power
Water
Chemicals
Manpower (95 employees)
365 acres
1,068,720 tons/yr
470 MM cu ft/yr
89,000 gal/yr
173.2 MM kWh/yr
1,500 MM gal/yr
32,200 tons/yr
190,000 manhours/yr
0.77 acre/MWe
0.734 Ib/kWh
(9,563 Btu/kWh)
165.2 Btu/kWh
4. 1 Btu/kWh
0.06 kW/kW
0.51 gal/kWh
0.022 Ib/kWh
0.2 men/MWe
*Basis 2913.12 MM kWh/yr net output.
**1.54 acre/MWe if 365 acre buffer zone is included.
96
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TABLE 39. SUMMARY OF ANNUAL CHEMICALS CONSUMED -
COAL TO POWER
Chemical
Amount Per Year
Lime (90% CaO)
Sulfuric Acid (66% Be)•
Caustic Soda (50%)
Chlorine (Gaseous)
Hypochlorite (10%)
Trisodium Phosphate
Hydrazine (35%)
Ammonium Hydroxide (29.4%)
Dispersant (Proprietary)
Polymer
Boiler Cleaning Chemicals (Citric Acid, Soda Ash)
Dust Suppression Chemicals
Ion Exchange Resins (3-Year Life)
Lube Oil
31,800 tons
139 tons
33 tons
61 tons
3 tons
6 tons
26 tons
8 tons
12 tons
1 ton
60 tons
1,500 gal
45 cu ft
10,000 gal
97
-------
operations will be a source of fugitive dust emissions
Table 40 lists anticipated source and estimates of pollutant
A variety of dust control techniques will be used to limit fugitive emissions
A variety or oust COULLU H iareely be handled in enclosed convey-
from point and area sources. Coal will largely u f^r^ f-nt-or-
v,. , . . „ ;,-,•_,„ nr rhutes equipped with ducting to fabric filter
us-efcSecto1" I et chemical suppression (sprays) will be used at the
a u" adJng station, at the feeders .in the reclaim tunnel, and as needed
on the coal storage piles. As -indicated in Table 40, windblown dust emissions
at the barge dock and at the live storage pile are expected to be significant
at times Coal-dust particles will be deposited in the river around the barge
dock during unloading. Telescope chutes on the stackers at the live storage
piles will discharge coal at the surface of the conical piles. This will help
to reduce the exposure of falling coal to the wind. In addition, the piles
will be sprayed periodically with chemical dust supressants to retard windblown
losses. The dead storage pile will be compacted and treated with a crusting
agent.
Outside live storage piles could be replaced -by enclosed storage (large concrete
silos) to reduce windblown dust emissions. Enclosed storage is not a common
practice, however.
The boiler stack gas discharge is expected to comply with the proposed NSPS for
particulate matter, opacity, sulfur oxides, and nitrogen oxides. The flue gas
cleanup train of electrostatic precipitators and wet lime scrubbers will remove
more than 99 percent of the uncontrolled particulate emissions and 90 percent
of the uncontrolled sulfur oxide (SOX) emissions. A small fraction of the ni-
trogen oxides (NOX) may also be captured by the wet scrubbing system. About
12 tons per day of SOX and 32 tons per day of NOX will be discharged to the
atmosphere from the 300-foot high stack. It is anticipated that the 0.6 Ib
N0x/million Btu heat imput standard can be met with good combustion control.
Lesser quantities of carbon monoxide and unburnt hydrocarbons also will be
emitted.
About 130 MW of thermal power will be emitted from the stack — somewhat less
than 10 percent of the total plant heat input. Combustion of coal at high flame
temperatures (2300-3000 F) may liberate some trace elements as vapors and may
also form carcinogenic organics. High boiling species (nonvolatiles) will
generally be retained in the bottom ash (slag) and flyash. Intermediate boil-
ing elements (antimony, arsenic, cadmium) may vaporize and then condense on
particulate matter as the flue gas is cooled. Low boiling elements (mercury,
fluorine, and chlorine) may occur primarily as vapors, but are unlikely to pass
completely through the flue gas cleanup train. Nevertheless, some small quan-
tities will be emitted, either in vapor form or associated with particulate
matter.
The two cooling towers will discharge about 690 MW of thermal power (2350 MM
Btu/hr) to the atmosphere and will evaporate nearly 876,000 Ib/hr of water under
average conditions. Although heat and water vapor are not normally considered
air pollutants, their release will have a small localized adverse effect; water
vapor condensing in the plumes may increase local fogging. A natural draft
tower-could be used, if necessary, to reduce the incidence of ground level
fogging.
98
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TABLE 40. SUMMARY OF ESTIMATED -AIR EMISSIONS - COAL TO POWER
Emission
Source
Coal barge
Unloading
Transfer and
Sample House
Coal Stackers
(Live Piles)
Coal Storage
Piles
Reclaim
Transfer
House
Boiler Cas-
cade System
Lime Storage
Silos
Flyash Storage
Silos
Solid Waste
Disposal Area
Miscellaneous
Sources
Flow Quantity
1000 tph,
5000 tons in 8 hr
100 tph,
5000 tons in 8 hr
(4 x MMCFD vent air)
1000 tph,
5000 tons in 8 hr
12,600 tons live,
252,000 tons dead
storage
175 tph,
(3.6 MMCFD vent air)
175 tph (avg)
(3.6 MMCFD vent air)
125 tpd lime (avg)
(0.4 MMCFD conveying air)
143 tpd ash
(1.6 MMCFD conveying air)
1123 tons placed in 8 hr,
3 to 5 acres exposed
surface (avg)
Plant area and roads
Mobile equipment exhausts
Pollutants
Fugitive
coal dust
Fugitive
coal dust
Fugitive
coal dust
Fugitive
coal dust
Fugitive
coal dust
Fugitive
coal dust
Fugitive
lime dust
Fugitive
dust
Fugitive
•dust
Fugitive
dust
Combustion
Products
Emission Rate
500 Ib/day
(after wet supression)
12 Ib/day
(0.02gr/CF after
collector)
500 Ib/day
(telescopic chutes)
250 Ib/day
(wet chemical
supression)
10 Ib/day
(0.02gr/CF after
collector)
10 Ib/day
(0.02gr/CF after
collector)
6 Ib/day
(O.lgr/CF after
collector)
23 Ib/day
(O.lgr/CF after
collector)
100 Ib/day
(wet chemical
suppression)
small
small
Fuel storage tanks
Hydrocarbon small
vapors
(Continued)
99
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TABLE 40. (Continued)
Emission
Source
Flow Quantity
Pollutants
Emission Rate
Boiler Stack
(300 ft high)
4,704,960 Ib/hr*
(1,253,310 CFM)
flue gas and
reheat gas
Cooling
Tower
84.9 MMlb/hr dry air
(18.5 MMSCFM)
Particulate
matter
sox
NOX
CO
HC
Thermal
Water
droplets
(drift)
Salts (in
drift)
Thermal
(added to
air)
60 Ib/hr
(0.013 Ib/MMBtu)
1,006 Ib/hr
(0.22 Ib/MMBtu)
2,700 Ib/hr
(0.6 Ib/MMBtu)**
228 Ib/hr
(.05 Ib/MMBtu)**
91 Ib/hr
(.02 Ib/MMBtu)**
454 MMBtu/hr
15,670 Ib/hr
40 Ib/hr
2350 MMBtu/hr
*Hot flue gas will contain trace quantities of volatile heavy metals
present in coal feed; most of the metal constituents are retained in
the bottom and flyash or condense on the ascending particulate matter
(ash)
**Assumed emission factors
100
-------
In addition, about 190 tons per day of water in droplet form-(drift loss)
will be emitted from the towers. Some 120 tons of salts (as IDS in the water
droplets) in the drift will be released annually. Most of these salts will
be deposited on the ground in the vicinity of the towers. This deposition
of salts over time could result in buildup of salts in the soil and/or in in-
direct adverse impacts on vegetation.
The overall impact of particulate matter, SOX, NOX, CO, and hydrocarbon emis-
sions to the atmosphere will be a small degradation of ambient air quality in
the vicinity of the plant. The tall stack will help to disperse the pollu-
tants. The emissions of unburnt hydrocarbons will probably exceed 100 tons
per year. Since the hypothetical site is a nonattainment area for photochemi-
cal oxidants, an emission offset may be required. It is unlikely that primary
air standards for other pollutants will be exceeded as a result of emissions
from this plant.
Water Emissions—Plant wastewater will be discharged to the river downstream
form the intake pumphouse. Figure 10 presented a simplified water balance for
the plant. Process effluent will normally be less than about 200 gpm and will
contain dissolved and suspended pollutants, most of which are present in the
river water at lower concentrations (see Table 18). The plant water treatment
system will remove constituents from the river water as dissolved solids, and
various chemicals will be added for water conditioning. These, for the most
part, will appear in the wastewater effluents. The boiler steam system and the
cooling water circuits will act as. concentration systems; constituents in the
makeup water will appear at concentrated levels in the blowdown streams. The
FGD system and the bottom ash sluice system will normally produce no aqueous
effluents. Estimated pollutant emissions after effluent treatment are given
in Table 41 and are approximate values.
The steam system will have two effluent sources, a blowdown stream to maintain
steam purity and the intermittent wastes from ion exchange regeneration. Steam
drum blowdown will be fairly clean and somewhat alkaline. Ammonia, hydrazine
(N-H,), and phosphate additives will appear in the blowdown, but N-H7 decomposes
info N and H_0 so it should not pose a problem. Suspended solids~wlll be pri-
inarily~calcium and magnesium sludges that are settled out in the blowdown basin.
Trace quantities of iron and copper may be present as corrosion products. Re-
generant brines and rinse waters will contain anions and cations removed from
the river water by the ion exchange resins plus sodium and sulfate ions from
the acid and caustic used in regeneration. The combined wastes after neutrali-
zation and settling will have a high dissolved solids content. The relatively
high organic and iron content of the river water may make it prudent to include
additional water treatment — for example, activated carbon beds — to protect
the ion exchange resins.
Cooling tower blowdown at 25 cycles of concentration will contain high concen-
trations of river water constituents plus sulfate (from sulfuric acid), organic-
phosphate dispersant, and chloride from chlorination of the circulating water
thrice daily. It is assumed that no metal-based corrosion inhibitor will be
used in the circulating water systems, but the exchanger surface in the service
water system may need protection. If so, a nontoxic organic inhibitor would
be added to the circulating water (and a discharge permit variance requested).
101
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TABLE 41. SUMMARY OF ESTIMATED WASTEWATER EMISSIONS ~
COAL TO POWER
Source
Boiler Slowdown*
(after settling)
Regenerent Wastes**
(after neutralization
and settling)
Cooling Tower
Blowdownt
(after settling)
Sanitary Waste
(after treatment)
Filter Backwash
(after clarification)
Floor and Confined
Yard Drains
(after oil skimming)
Coal Yard Storm
Drainage (after
neutralization
and settling)
Estimated Flow
32.6 gpm
7. 6 gpm avg.
(intermittent)
115 gpm
(25 cycles of
concentration)
10 gpm
11.8 gpm avg.
(intermittent)
20 gpm
22 gpm annual
avg. (inter-
mittent flow
from 12 acres)
Pollutants Emission Rate
NH3 (2 mg/1)
TDS (90 mg/1)
TSS (25 mg/1)
pH (alkalinity
neutralized)
TDS (2970 mg/1)
TSS (25 mg/1)
pH (acidity/alkal-
neutralized)
TDS (2610 mg/1)
TSS (30 mg/1)
Chlorine (residual
<0.1 mg/1)
Dispersant-pro-
prietary (40 mg/1)
pH
BOD (25 mg/1)
TSS (10 mg/1)
Colif orms
(<200 MPN/100 ml)
PH
TSS (50 mg/1)
PH
Oil and grease
(10 mg/1)
TSS (30 mg/1)
pH
Oil and grease
(<10 mg/1)
TSS (<50 mg/1)
Iron, total
1 Ib/day
35 Ib/day
10 Ib/day
8-9 units
270 Ib/day
2 Ib/day
6-8 units
3600 Ib/day
41 Ib/day
0.1 Ib/day
55 Ib/day
6-7 units
3 Ib/day
1 Ib/day
—
6-9 units
7 Ib/day
6-7 units
2 Ib/day
7 Ib/day
6-9 units
<3 Ib/day
<13 Ib/day
(<5 mg/1) <1.3 Ib/day
pH (acidity
neutralized)
6-9 units
(Continued)
102
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TABLE -41. (Continued)
Source
Estimated Flow
Pollutants
Chemical Cleaning
Wastes (periodic
equipment
cleaning)
Basin Cleanouts
Ash Pond Overflow
1-2 million
gallons per year
(infrequent
batch discharge)
Drained basin
water and clean-
ing water volume
not estimated
Normally no
flow
Acidity/alkalinity,
boiler scale, cor-
rosion products,
soot — suspended
and dissolved
solids
Accumulated solids
and sludges
Emission Rate
Plant Storm
Drainage (after
settling)
155 gpm annual
avg. (inter-
mittent flow
from 100 acres)
Oil and grease
(<10 mg/1)
TSS (<50 mg/1)
PH
<19 Ib/day
<93 Ib/day
6-9 units
Alkalinity, sus-
pended solids,
possibly heavy
metals and iron
Wastes impounded,
neutralized, and
settled before
discharge —
TSS <30 mg/1,'
oil and grease
<15 mg/1, iron
<1 mg/1, copper
<1 mg/1, pH 6
to 9
Wastes settled
before discharge
- TSS <30 mg/1,
oil and grease
<15 mg/1, pH
6 to 9
None, unless
emergency
*Boiler conditioning chemicals added increase TDS of blowdown.
**NaOH and H-SO, regenerants add to TDS of wastes.
tRiver water constituent concentrations increase through concentrating
effect of the system; H?SO,, dispersant and chlorine chemical additions
add TDS to blowdown.
103
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Trace quantities of corrosion products may also be present in^the blowdown.
The blowdown basin will provide more than adequate holdup for the decay of
residual chlorine.
Treated sanitary effluent will be a low-emission-rate source of BOD and sus- _
pended solids. Utility wastewater collected from floor and confined yard drains
will probably contain washdown solids and some lube oil from leaks and occasion-
al spills. Sump skimmers will be provided to remove floating oil.
Most of the yard and roof drainage will be collected by storm sewers and
ditches and should be relatively uncontaminated after settling. On an annual
basis, the runoff flow will be large, and significant quantities of suspen-
dible materials washed from plant surface areas could be discharged were a
settling basin not provided.
The exposed surfaces of the sludge landfill area will be a potential source of
pollutants that may leach from stabilized sludge and bottom ash. It is diffi-
cult to assess whether significant amounts of heavy metals could be leached by
intermittent contact with direct rainfall, but, in a properly managed landfill,
these leachates should not reach groundwater or surface water supplies.
Coal yard runoff will contain dust and may also be acidic if pyrite oxidation
occurs from air and water contact with exposed coal surface. Trace metals and
some salts may also be leached. The extent of contamination is difficult to
predict because of the many factors involved. In this conceptual plant, the
runoff would be impounded for settling. If the drainage were acidic, lime slur-
ry from the FGD system could be used for neutralization.
Chemical cleaning wastes generally represent a troublesome problem in power
plants. Equipment cleaning is infrequent, but large volumes of waste need to
be handled. In this hypothetical plant, impoundment, chemical addition for
metal hydroxide precipitation, and settling will be used in batch treatment of
cleaning wastes. Effluent discharged will still be high in TDS because of the
salts contributed by the cleaning chemicals. Waters from basin elements will
be another infrequent source of pollutant discharge. No estimates of the quan-
tities of pollutants discharged were made.
Pollutants contained in the process effluent and in storm runoff are unlikely
to cause a detectable change in the river water quality outside of the mixing
zone. During heavy rainfall periods, storm discharges may contribute signifi-
cant quantities of suspended solids to the river, but the turbidity, of the river
water is likely to be high because of large contributions from natural drainage
flows. Surface water withdrawal of about 4100 gpm is only a small fraction of
the river flow. The impact on surface water availability would be small.
Solid Wastes—Other than plant trash and garbage, the solid wastes generated
routinely in the plant will be collected bottom ash, flyash, and the FGD sludge.
Table 42 indicates estimated quantities and disposition, which total about
150 acre-feet per year. A total landfill requirement of 230 acres will be com-
mitted for the life of the plant. Properly managed, no other impacts on the
physical (water quality) or biological environments should occur from solid
waste disposal. The stabilized sludge engineering and physical properties are
104
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TABLE 42. SOLID WASTE DISPOSAL SUMMARY - COAL' TO POWER
Source
Estimated
Quantity
Potential
Pollutants
Disposal
Stabilized
Sludge from
FGD System
and
Precipitators
Bottom Ash.
Dredged from
Ponds
Plant Trash
and Garbage
Miscellaneous
Basin Cleanout
Sludges
1122.4 tons per
8-hr day, 5 days
per week (160,800
cu ft/week)
10,765 tons per
year (425,340 cu ft)
40 percent moisture
Alkalinity,
trace metals,
suspended
solids
Alkalinity,
trace metals,
suspended
solids
475 Ib/day general
rubbish (~60 cu ft/
day compacted)
Infrequent dredging
of basins — assume
300 tons per year
Decomposable
waste, some
oily materials
Various solids
accumulated in
basins — some
organics and
precipitated
metals, mostly
inorganics
Sludge hauled to
landfill, spread and
compacted, later
covered with soil
Bottom ash hauled
to landfill 1 to 2
times per year,
mixed and spread
with stabilized
sludge, compacted
and later covered
with soil
Collected twice
per week and buried
under stabilized
sludge in landfill
Sludges hauled to
landfill mixed with
stabilized sludge
^Approximate sludge composition: CaS03 • ^2°> CaS04 • 21^0, CaC03,
inerts - 32.5%, free water - 48.7%, flyash - 17.8%, lime (cementation
agent) - 1.0%.
105
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uncertain. It was assu.ed that the ..
" te=hnlque could
needed if the material were classified as a hazardous waste.
Soils and Geology-Approximately 365 acres of land will be altered during con-
struction and operation of the plant. Earthwork will involve clearing, grading,
cut-and-fill, and excavation (for settling basins or ponds, landfills and foun-
dations of structures). The construction of buildings and roadways_will further
change the physical character of the surface. Site topography, drainage patterns,
and soils will be permanently altered during construction. Burial of solid
wastes will increase the height of the 230-acre landfill over the plant operat-
ing life, further contributing to the long-term changes in topography.
Although the physical changes in soils and geology constitute a local adverse
impact, care in selecting a site with no uniquely distinguishing features should
minimize the regional impact. However, the extent of topographical change may
result in a moderate regional effect, given the present agricultural value of
the area.
Biological Impacts—
Construction of the plant will affect approximately 365 acres of biological and
agricultural land uses. As a result of earthwork, the vegetation and wildlife
associated with the acreage will be removed or disturbed and nearby habitats
may be disrupted by increased noise, human activity, and vehicle traffic. Sen-
sitive species will leave the area; others may adapt and remain during the con-
struction phase. However, displacement of wildlife will probably result in
locally increased mortality during the beginning of construction, particularly
of species which are strongly territorial and/or which are at carrying capacity.
Fencing will present a barrier to movement of larger animals such as deer, but
this barrier should not pose a significant problem to most wildlife. Careful
siting would avoid disturbance of critical or unique biological habitats, rare
or endangered species of vegetation or wildlife, or any economically or recrea-
tionally important species.
Secondary biological impacts would include construction-related effects such as
plant damage from increased dust on site and at roadsides, increased losses of
vegetation from onsite erosion, and stress in aquatic systems resulting from
changes in drainage, increased runoff, and turbidity and stream sedimentation.
Proper construction management, such as the use of cofferdams and holding ponds
on site and dust control, will minimize these impacts.
Air and water quality degradation from plant emissions can affect biota onsite
and nearby. While the emissions themselves will not have direct effects on
biota, long-term or chronic exposure downwind or downstream could result in cu-
mulative damage. For example, long-term exposure to low levels of NOX or build-
up of salts in the soil downwind of the cooling tower could result in plant
damage. Similarly, buildup in the sediments or in the biota (through biomagni-
tication) of toxic materials in the river downstream from the wastewater dis-
charge could result in a loss of some species of aquatic life in an area near
the mixing zone.
106
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Small aquatic organisms, such as plankton and fish eggs or larvae, could be
entrained in the plant's makeup water system; most would be destroyed either
in water treatment or in the plant itself. However, this impact should not
be significant if the intake is not placed in a fish spawning ground and if
flows and intake screens are designed to minimize entrainment.
In summary, with careful siting and design, biological impacts should be lo-
calized, with little impact on regional ecology.
Aesthetic Impacts—
The coal-fired power plant will contrast visually with the surroundings. The
plant buildings, stack (300 feet high), induced-draft cooling towers (51 feet
high), coal handling facilities, and solid waste collection and disposal facil-
ities will impart an industrial atmosphere to the area, now predominantly
agricultural. While these facilities can be masked to some extent by land-
scaping, use of a buffer zone around the plant site, and plant layout and de-
sign, this change in land use constitutes a moderate adverse aesthetic impact.
Social and Economic Effects—
Capital investment in the plant ($384 million) and annual operating expendi-
tures will stimulate the local economy. Temporary jobs will be created for
about a thousand construction workers, stimulating the local construction in-
dustry. In addition, about 95 permanent operating jobs will be created. In-
come from these jobs will probably be spent in nearby towns, as will some
portion of capital expenditures for equipment and materials. The plant will
also expand the local tax base, offsetting at least in part the increased de-
mand for community services.
Plant operating labor and most of the construction workforce can probably be
obtained from the regional labor pool, if training programs are implemented
for skilled" labor needs. However, some increase in local population may occur
during construction and this increase, although temporary, will probabaly
strain community services. Economic benefits accrued from wages and spending
in the nearby communities may offset this strain to some extent; cooperation
between the sponsoring utility and the region to absorb some of the costs for
temporary housing and services may also be necessary.
The plant will generate power for export to the regional grid, allowing ex-
pansion of residential, commercial, and industrial development in the area
and further expansion of local economies.
Table 43 summarizes the principal impacts of coal-to-pox%rer development and po-
tential mitigation of adverse effects.
107
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TABLE 43. SUMMARY ENVIRONMENTAL MATRIX - COAL -TO POWER
Environmental
Factors
Effect of Plant
Construction and Operation
Potential
Mitigating Measures
Climatology and
Meteorology
Air Quality
Surface Water
Availability
Surface Water
Quality
Local fogging from cooling
tower plume possible in
periods of high humidity
Localized fugitive dust, ve-
hicle emissions from con-
struction; small emissions
of NO , SO , particulate,
hydrocarbons during opera-
tion; coal handling, trans-
port storage a potential
source of fugitive (coal)
dust
0.51 gal/kWh; minor ad-
verse impact
Releases of TDS, TSS and
chemicals — minor, local-
ized impact in receiving
water
Groundx<7ater
Availability
Groundwater Quality
Land Availability
Regional Ecology
and Critical
Habitat
No consumption — no effect
Potential leaching from coal
storage piles, fly ash and
bottom ash, and sludges
730 acres required; no sig-
nificant regional impact
365 acres of vegetation and
associated wildlife removed
or disturbed; potential ad-
verse secondary impacts dur-
ing operation
Management of land-
fill ; including
lining of ponds and
basins, sealing of
landfill cells, etc.
Care in siting to
avoid sensitive or
valuable areas
Care in siting to
avoid critical
habitat, rare or
endangered species
(Continued)
108
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TABLE 43. (Continued)
Environmental
Factors
Effect of Plant
Construction and Operation
Potential
Mitigating Measures
Aesthetic Resources
365 acres of industrial use
in rural area — visual con-
trast, plant noise, in-
creased traffic detract
from rural character of area
Plant design, lay-
out, landscaping,
365 acre buffer
zone
Historical,
Archaeological
Resources
Communitv Economy
Insignificant impact
Substantial benefit from in-
come, local capital expendi-
tures and broadened tax base
Care in siting to
avoid likely sites
of value; site
protection and re-
covery plans
Community Population
and Services
Potential for increase in
local population during con-
struction and resultant strain
on services
Coordination of
utility-community
to provide tem-
porary housing,
subsidize services,
etc.
Labor Availability
Power Availability
Transportation
Availability
Requirements for construction
personnel (1,000) and opera-
tion staff (95 full-time) —
local manpower pool adequate
Temporary consumption of
power, fuels during construc-
tion; export power to grid
during operation
Access road, rail spur, barg-
ing facilities needed; trans-
mission corridor needed
Labor training
programs as
necessary
Careful selection
of corridors to
minimize impact
109
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SECTION 4
SCENARIO 2 —
STRAW/MANURE AND COAL TO SPG IN THE MIDWEST REGION
In this scenario, a 7 MM SCFD anaerobic digestion (biogas) plant and a 274 MM
SCFD coal gasification (HYGAS) plant are to be constructed and operated at
hypothetical sites in the midwest region of the U.S. Figure 15 indicates the
regional location considered. The biogas plant feedstocks are wheat straw and
cattle manure collected locally and delivered to the biogas plant. Subbitu-
minous coal is shipped to the gasification plant from a strip mine in a western
state. Both plants produce high-Btu synthetic pipeline gas (SPG). Product
•gas is piped a short distance offsite to an interstate gas line.
A regional environmental setting and brief plant site description are presented
to provide a background for the environmental assessments. Principal environ-
mental assumptions include:
• The proposed NSPS for steam-electric generation will apply
• Sulfur recovery units will have 99.8 percent sulfur capture
• Fugitive emissions of sulfur compounds are < 500 ppmv as
S02* and < 10 ppmv H2S
• Fuel gas will have < 0.1 gr H2S/dSCF
• Best available control technology (BACT) will apply to
aqueous effluents
• Major residues from conversion will be disposed of offsite and
are assumed to be nontoxic; the disposal costs are included
in the feedstock costs
• No preconstruction environmental costs are included
• No costs for any emission offsets are included
• Product distribution costs and distribution impacts are
excluded.
*Higher than the proposed NSPS for sulfur recovery units (40 CFR60, Subpart J)
110
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Figure 15. Straw/manure and coal to SPG region — Scenario 2.
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REGIONAL ENVIRONMENTAL SETTING
The biomass and coal conversion plants will be located at a hypothetical site
in the Northern Plains of the Midwest (e.g., in Kansas or Nebraska). The fol-
lowing describes the regional environmental setting of the plants.
Land Use
Broadly speaking, three land resource regions are represented. Approximately
four-fifths of the land in western Kansas and about one-half of southern
Nebraska is in the Central Great Plains Winter Whest and Range Region. About
one-half of Nebraska north of the Platte River is in the Western Great Plains
Range and Irrigated Region. The rest, immediately west of the Missouri River
to the north and along the border of the state of Missouri, is in the Central
Feed Grains and Livestock Region (22).
Nearly all the land is in farms and ranches. About one-half of the area is
cropland. Hard winter wheat and grain sorghum are the main cash crops. Corn
and alfalfa are also grown, mostly under irrigation. About two-fifths of the
area is in range or pasture of native grasses, forks, and shrubs. Beef cattle
are the principal livestock, though dairy cattle are also found in some areas.
Elevation and Topography
Large areas of nearly level to gently rolling plains are a dominant character-
istic of the topography of the Northern Plains. This smooth relief is inter-
rupted only occasionally by relatively small areas of land with steeper slopes.
These areas of greater relief are often associated with the more prominent
moraines or with dissection bordering the large streams. In some areas many
of the larger east-flowing streams have formed badlands or steep, nearly barren
eroded places such as in northwestern Nebraska. Sand dunes have also produced
localized areas of rolling terrain. The most extensive of these is in the
Sand Hills of Nebraska (23).
Climate
Cold to warm, temperate, semi-arid to humid continental climates characterize
the North Central Region. Winters are fairly cold and summers warm or hot.
A greater proportion of rainfall occurs during the spring and summer months.
In the western part, the annual precipitation averages 15 to 20 inches or less.
It increases, however, to the east and southeast and attains average values of
40 inches or more along the southeastern part of Kansas.
Along the northern border of the region the -climate is cold. The average annual
temperature there is below 40°F and the average frost-free period is less than
120 days. Both the temperature and the length of the frost-free period in-
crease toward the south, where values of 55°F and 200 days for average annual
temperature and the frost-free period are common. Frost penetrates to appre-
ciably greater depth in the northwestern parts of the North Central Region
than in the southern parts, particularly on bare ground. Consequently soil
temperatures average appreciably lower in the northern part of the region (23).
112
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One of the most serious climatic problems in the Great Plains is the wind.
Windspeeds are highest in spring and cause soil blowing. Thunderstorms also
occur over the region during summer, but they are less destructive than winds
in their action on soil erosion.
Soils
Soils of the area are predominantly Mollisols, Entisols, Alfisols, and Utisols.
Many have a subsurface horizon of accumulated clays and carbonates or salts.
The soils in the Nebraska sandhills show weak pedogenic development and, con-
sequently, become dry quickly during periods of drought; these soils are easily
weatherable (16).
Vegetation
The soils in the area support a prairie-type of vegetation, although forest
ecosystems may be found along watercourses and at higher elevations. The
prairie vegetation may belong to one of a number of ecosystems; from west to
east, they are:
• Grama - buffalo grass, dominated by blue grama (Boutetoua
gra.ci.1-is) and buffalo grass (Buchloe dactyloides)
• Wheatgrass - bluestem - needlegrass, dominated by western
wheatgrass (Agropyron smith-ii) , big bluestem (Andr>opogon
gerardi), and needlegrass (Stipa spartea.)
• Bluestem - grama, dominated by little bluestem (Andropogon
scapar-Lus), side-oats grama (Boutsloua curtipendula), and
blue grama
• Bluestem, dominated by little bluestem, big bluestem, switch-
grass (Pa.ni.cum viTgatum), and Indian grass (Sorghas tmm
nut cms)
Specialized soil conditions support variations of these prairies: the Nebraska
Sandhills prairie ecosystem, the sandsage - bluestem prairie ecosystem, or the
northern cordgrass ecosystem (24, 25).
The forest ecosystems of the area include the northern flood plains (cotton-
wood, black willow, American elm), the oak-hickory forest (white, red or black
oaks, bitternut, or shagbark hickories), the oak-hickory-pine forest (hickory,
shortleaf or loblolly pines, and white or post oaks), and the Cross Timbers
area (groves of blackjack and post oaks in little bluestem prairie).
Wildlife
An unusual variety of wildlife and fish species is found in the region due to
the variety of potential vegetation types intermixed with agricultural and
pasture land uses. Deer are the most abundant big game, followed by antelope.
Pheasant is the most important upland game species, followed in importance by
bobwhite quail. Wetlands attract migrating waterfowl in large numbers (26).
113
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BIOGAS PLANT SITE DESCRIPTION
The plant site is in a rural area on purchased farmland. This area is called
the subhumid wheat region of the Great Plains.
Topography and Elevation
The site is nearly level and adjacent to a broad flood plain of a major local
river. The surrounding topography is undulating to gently rolling, and some
areas adjacent to the major drainage have slopes of as much as 15 percent. The
site is approximately 1400 feet above mean sea level.
Transportation
A state highway passes within a mile and a half of the plant and connects it
with a network of state highways ^and county roads. A major rail network is
accessible within two miles of the plant site. The nearest town is about two
miles north of the plant. A major population center (greater than 250,000)
lies 15 miles north of the plant. Two natural gas pipelines cross within three
miles of the plant. These connect with other major and secondary pipelines in
the area.
Climate and Air Quality
The climate at the site is typical of the Great Plains. Table 44 summarizes
pertinent climatic conditions. Air quality at the site is characterized as
generally good. Currently, ambient air. quality standards are not being met for
photochemical oxidants and carbon monoxide. The standard for particulate matter
is sometimes exceeded locally.
Land Use
Land surrounding the plant is in farms with approximately two-thirds of the
area under crops. Wheat is by far the most extensively grown crop, but large
acreages of grain sorghum and alfalfa are also grown. Corn is a major crop
north of the site. A little more than two-fifths of the area west of the site
is in range or pasture of native grasses and shrubs. East of the site, about
one-fourth of the land is in range or pasture and grazed by beef cattle.
Some dairy cattle are also found in the area.
Plant Water Resources
River flow at the plant averages 1095 cfs with a minimum annual daily discharge
of 120 cfs. The water is high in dissolved solids content and alkalinity
(see Table 45). Mean annual temperature is 62°F with 33°F to 84°F (daily)
range. All of the plant water requirements will be supplied by the river,
with the exception of potable water, which will be pumped from shallow wells
drilled on the site. The plant elevation is about 50 feet above the normal
river water level.
114
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TABLE 44. ASSUMED CLIMATIC CONDITIONS AT THE SITE
Elevation: 1400 feet
Temperature:
i A 57°F dry bulb
Annual Average
50°F wet bulb
5-Percent Design 95 F dry bulb
Conditions 75 F wet bulb
Annual Minimum (Design) -10 F
Annual Extremes (Daily) 23°F to 92°F
Prevailing Wind: South at 13.5 mph (mean)
Precipitation:
Annual Precipitation 30.7 inches
Annual Runoff 5 inches
Annual Lake Evaporation 56 inches
10-yr, 24-hr Storm 5 inches
Average Frost-Free Period: 190 days
Soils
The soils of the subhumid wheat region have a high proportion of productive
soils which have consistently produced more wheat per acre of farmland than
any other soils in the northern Great Plains (14).
The soils at and around the site are Hapludolls and Arguidolls based on the
latest soil classification system (22, 27). Both great soil groups are
Mollisols, very dark in color and rich in bases. The association includes
deep and moderately deep, nearly level to undulating and hummocky soils on
low terraces and uplands. Most soils are coarse-textured and highly erodible.
These soils are used chiefly for dryland farming and range. Conservation of
moisture, control of erosion, and maintenance of fertility are the major
management needs. They are accomplished by proper use of crop residues, wind
strip cropping, the growing of cover crops, contour farming, minimum tillage,
and fertility control.
115
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TABLE 45. ASSUMED AVERAGE RIVER WATER QUALITY
Component Value
Flow, Average Discharge 1,095 cfs
Flow, Minimum Daily 120 cfs
PH 7.9
Temperature 62 F
Turbidity 60 JTU
•Dissolved Oxygen 10.2 mg/1
Chemical Oxygen Demand 48' mg/1
Calcium 79 mg/1
Magnesium 17 mg/1
Sodium 244 mg/1
Potassium 8 mg/1
Bicarbonate 238 mg/1
Carbonate 0 mg/1
Sulfate 123 mg/1
Chloride 469 mg/1
Phosphorus 1.6 mg/1
Nitrate + Nitrite - Nitrogen 1.0 mg/1
Ammonia Nitrogen 1.7 mg/1
Total Organic Nitrogen 2.5 mg/1
Total Dissolved Solids 1,094 mg/1
116
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Vegetation
Rangeland now occupies approximately one-third of the farmland around the area
and is used for livestock grazing. Large areas of range occur along the river.
The wood species growing along most of the streams and drainage ways are rep-
resented by cottonwood, green ash, and wild plum, but the principal vegetation
on range soils still remains the native grass. The climax plant cover on flood
plains and stream terraces consists of a mixture of such salt-tolerant grasses
as switchgrass, Indian grass, alkali scaton, western wheatgrass, tall dropseed,
prairie cordgrass, vine mesquite, and saltgrass. Commonly grown windbreak
trees in the area include the American plum, bur oak, catalpa, cottonwood,
eastern redcedar, green ash, hackberry, honeylocust, mulberry, osage orange,
ponderosa pine, Russian olive, and Siberian elm (28).
Wildlife -
Deer are present today and are probably more numerous than 100 years ago, owing
to better feed availability and protection by game laws. Ring-necked pheasant,
mourning dove, and fox squirrel are now numerous thanks to changes in vegeta-
tion due to a changed land use.
Fish, cottontail rabbit, ring-necked pheasant, and bob-white quail are impor-
tant game species. Other animals include raccoon, badger, opossum, skunk,
gray squirrel, fox squirrel, coyote, jackrabbit, beaver, muskrat, mink, and
waterfowl.
Large streams provide ample fishing and recreational opportunity, mainly for
several species of catfish.
WHEAT STRAW AND MANURE PROCUREMENT
Wheat Straw
Hard red winter wheat is extensively grown in the area around the proposed
plant site. The state produced one-fifth of the entire U.S. wheat crop and
ranked first in the nation. The county where the site is proposed is a con-
sistent leader as the top wheat producing area. The surrounding five counties
are also leaders in wheat production (29).
Winter wheat in the site area is usually seeded between September 15 and about
October 10 and harvested from June 10 to July 1. Nearly all straw is left in
the field's to protect soils from wind and water erosion and later buried in
the surface soil by moldboard plows. The average yield of grain in the area
is around 33 to 35 bushels per acre (or about 1 ton/acre). A rule of thumb
used for estimating straw produced by a wheat crop is a straw-grain ratio of
1.7 (100 Ib straw/bushel of wheat) (30), although winter wheat may attain a
straw-grain ratio of 2.0 (120 Ib straw/bushel of wheat) (31). Approximately
two million tons of wheat residues are returned to the soil in the five coun-
ties surrounding the plant. Since the conversion plant will consume only
about 330,000 tons/yr of wheat straw, there is ample supply available for
feedstock provided it could be removed without any harmful effects on the soil.
117
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Since little wheat straw is currently collected in the region, wheat straw
procurement for the plant is to be specially induced in the area The twenty-
year plant life should be enough incentive for independent capital investment
in wheat straw collection, yarding (storage), and transport equipment.
After wheat harvesting, farmers or independent contractors bale the straw
residue mechanically and load the bales on trailers for transport to roadside.
Bales may be stacked and stored by individual farmers or loaded on trailer
trucks for transport to contractor-owned yarding facilities in the area. At
this period in the year, virtually all of the plant's annual feedstock require-
ment is offsite, distributed throughout the area in various storage facilities.
As needed during the year, the yarded bales are loaded on truck-trailers mech-
anically and delivered to the conversion plant.
At a wheat straw field density of 1.5 tons/acre/year, a minimum of about
220,000 acres of cropland is subject to residue collection. In fact, much
more area is involved since complete collection is not desirable.
Manure
The annual plant requirement is about 330,000 tons (wet)" of livestock manure.
Currently most of the manure in the region is not classified as waste material,
being deposited on the land as a fertilizer. There is reportedly about 78,000
tons per year (dry basis) of manure potentially available in five counties
surrounding the plant (32) . Nearly 65 percent of this is needed by the con-
version plant, since fresh manure is about 85 percent moisture, and 15 percent
dry solids.
Livestock production (mainly beef and dairy cattle) is a major agricultural
industry in the area because of the proximity of large quantities of feed
crops. Large, confined feed lots (greater than 10,000 head) are not predom-
inant, but intermediate-sized feed lots are spread throughout the area. Uncon-
fined pastureland accounts for the remainder of the livestock production. In
this scenario, manure is purchased on a delivered tonnage basis to the plant.
As in the case of wheat straw procurement, procurement is to be an induced
independent industry with the incentive of a long-term demand. Independent
suppliers contract with ranchers for pickup rights to manure collected and
stockpiled. Collection service is provided by front-end loaders and trailer
trucks; no yardage facilities are normally used by the suppliers.
BIOGAS PROCESS DESCRIPTION (ANAEROBIC DIGESTION)
Summary
The biogas plant produces about seven million standard cubic feet per day
(SCFD) of methane gas from 1000 tons per day of wheat straw and 1000 tons per
day of cattle manure by anaerobic digestion. Wheat straw and cattle manure
are purchased by the plant on a contract basis from farmers in the region and
delivered to the plant at a per-ton unit price.
^Equivalent to 49,500 tons on a dry basis.
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The biogas plant converts the feedstocks to pipeline quality fuel gas and
waste solids. Some of the digester gas (raw gas) is used within the plant to
generate process steam. The remaining raw gas is compressed and treated to
produce pipeline quality gas (4870 SCFM) having a heating value of 950 Btu/SCF.
The sulfur content is 15 ppmv H2S and the moisture content is 200 ppmv or less.
The treated gas at 320 psia is piped three miles to the nearest gas pipeline.
The waste solids - 534 tons per day (dry) of undigested materials - are dewa-
tered and trucked away to farmlands to be used as soil conditioner. The plant
boundaries are indicated by the fenced area in Figure 16.
The process description is divided into feedstock receiving and preparation,
digestion and effluent treatment, gas cleaning, and auxiliary facilities.
The principal design bases and assumptions are summarized below.
Design Basis
There have been,many research and development projects on anaerobic digestion
of organic materials for methane gas production. These have been primarily
laboratory studies, quite insufficient to provide the data necessary for
design of a full-scale biogas plant, especially a plant using wheat straw
and cattle manure. In order to develop the conceptual design, of the bio.gas
plant for this study, numerous assumptions and simplifications had to be made
on the feedstock characteristics, reaction rate, reaction conditions, and
properties of materials at various process stages.
The plant capacity is somewhat arbitrary. The size is somewhat limited by
the quantity of feedstock that can reasonably be collected in the area and
can reasonably be accommodated in the plant without severe handling problems.
The assumed characteristics of the feedstocks as they are received at the
biogas plant are presented in Table 46. Design and operating criteria for
each of the process sections are summarized in Tables 47 through 50.
Feedstock Receiving and Preparation
Wheat Straw Receiving and Storage—
An average of 1000 tons per day of wheat straw is consumed in the plant. The
receiving facilities are designed to operate six days per week and two shifts
per day. A heavy delivery of wheat straw is expected during a period imme-
diately after the harvest season. The remainder of the baled straw is yarded
offiste by the straw suppliers. The delivery will be somewhat reduced as the
next harvest season is approached. A bale storage facility (60 days storage
capacity) is provided at the plant site. Figure 17 depicts the feedstock
receiving and preparation operations.
Wheat straw is delivered to the plant by end-dump trailer trucks of 2000-cubic-
foot capacity. The trucks are unloaded by hydraulic dump platforms which
raise the truck-and-trailer allowing the bales to discharge by gravity into
the hopper pit.
The wheat straw receiving ramp is provided with five hydraulic dump platforms.
The trucks back onto the platforms and discharge their loads as the platforms
raise. The dump cycle of each platform is about ten minutes.
119
-------
. , BALED STRKW STORAGE ABE*.
LJ I I (to DAV CAP.)
Figure 16. Straw/manure to gas, general plant arrangement.
-------
1-30 KICKS fl 4QO TOU1
WHEAT
STRAW
OtUl/tKV
IOOO TP0
M*MEH H)Ll. HkHjUg MILL'X
< PRIMARY) f SCCt
TPH, 256 BHP 2? TPrt ,2oo
SCKKCM J'fl*
MANURC SLURRY
10 FtlD S10R "-it.
H, jy
U./I1
MAK.KUP Z, Rt
PROCEft* t
WMtM SIRUd SLUR^V
TO FUD iTORKCiE
4S7ATPI4 4% "LIPS
I I agiT
Figure 17. Straw/manure receiving and feed preparation section.
-------
TABLE 46. ASSUMED CHARACTERISTICS OF FEEDSTOCKS
Composition
Proximate
Moisture, % wt
Ash, % wt
Volatile Solids, % wt
Bulk Density, Ib/cu ft
Ultimate
Hydrogen, % wt
Carbon, % wt
Sulfur, % wt
Nitrogen, % wt
Oxygen, % wt
Ash, % wt
Heating Value (HHV) , Btu/lb
Wheat Straw
12.2
7.2
80.6
100.0
12
5.6
44.8
0.2
0.5
44.7
8.2*
100.0
9,736 (dry)
Cattle Manure
85.0
3.1
11.9
100.0
62
5.3
37.5
0.3
2.1
34.1
20.7**
100.0
8,168 (dry)
* Phosphorus in ash - 0.1% wt.
** Phosphorus in ash - 0.4% wt.
122
-------
TABLE 47- DESIGN AND OPERATING CRITERIA - FEED PREPARATION
Feedstock Delivery
Wheat Straw Trucks - 2000 cu ft capacity
Cattle Manure Trucks - 20 tons capacity
Feedstock Storage at Plant
Wheat Straw - 60 days on open gravel area
Cattle Manure - 15 days in building
Size Reduction
Wheat Straw - crushed to 1/8 inch by
hammermills, then pulped by hydropulper
Cattle Manure - pulped by hydropulpers
Feed Slurry
Wheat Straw and Cattle Manure -
8% solid slurry
Feed Slurry Storage
Wheat Straw Slurry - 4 hours
Cattle Manure Slurry - 4 hours
Facility Operation
Feedstock Receiving - 2 shifts/day and
6 days/week
Size Reduction - 3 shifts/day and
7 days/week
123
-------
TABLE 48. DESIGN AND OPERATING CRITERIA - DIGESTION
Feed
12,850 tons/day slurry (1,028 tons/day total
solids, 925 tons/day volatile solids)
Detention Time
10 days
Temperature
PH
95°F, controlled with steam/hot water
6.5 to 7:5, controlled with lime (0.02 Ib lime
per Ib of dry solid in feed)
Biological Conversion
Digester Effluent
Digester Mixing
6.94 SCF product gas per Ib of volatile solids
(VS) (6.5 SCF/lb of VS in cattle manure and
7.0 SCF/lb of VS in wheat straw): product gas
contains 60% methane, 38.9% carbon dioxide,
1% hydrogen, and 0.1% hydrogen sulfide
(dry basis)
12,566 tons/day slurry containing 593.5 tons/day
total solids
Compression and recycle of raw product gas
through special draft-tube heater-mixers,
0.16 SCFH/cu ft of digester volume
124
-------
TABLE 49. DESIGN AND OPERATING CRITERIA - GAS CLEANING
Feed
Product
Gas Cleaning
Maximum 12.8 MM SCFD (dry) raw gas feed (design
average of 11.3 MM SCFD) containing 60% CH^,
38.9% C02, 1.0% H2 and 0.1% H2S (dry basis;
325 psia
Design average of 7.0 MM SCFD fuel gas containing
93.6% CH4, 4.88% C02, 1.5% H2, <_15 ppm H2S, and
£200 ppm H20; 320 psia, 950 Btu/SCF (dry)
A package gas cleaning system based on "hot
potassium carbonate acid gas absorption/
regeneration"; the system design capacity is
13.5 MM SCFD of raw gas
Gas Dehydration
A package dehydration system based on "glycol
water absorption/regeneration"; the system is
designed for 7.2 MM SCFD feed gas
Acid Gas
A package gas incineration system sized for
incineration of 3,400 SCFM acid gas (0.44% CH
99.3% C02, and 0.28% H?S) ; the system is
also provided with a waste heat boiler
generating 6,000 Ib/hr low pressure steam
'4'
125
-------
TABLE 50. DESIGN AND OPERATING CRITERIA - EFFLUENT TREATMENT
Digester Effluent Dewatering
Centrifuge
Centrate Recirculation
Cake Storage
12,600 tons/day feed (594 tons/day solid),
29% solid cake product, 0.5 hp/gpm power
requirement
80% of the centrate is returned directly to
the feed preparation facility
432,000 cu ft storage bins
Vastewater Treatment
Wastewater
Primary Clarifier
Aeration System
Secondary Clarifier
Polishing Pond
360,000 gal/day containing 4000 mg/1 SS and
800 mg/1 BOD.
600 gal/day/sq ft, 13,000 mg/1 SS underflow,
90% SS removal
400,000 gal aeration tank, 4800 Ib/day oxygen,
24 hours detention 2000 mg/1 MLVSS, and 90% BOD
reduction
600 gal/day/sq ft, 10,000 mg/1 SS underflow,
90% SS removal
30 days detention; the pond effluent can be
discharged to the receiving stream or to the
process makeup waste system
126
-------
Wheat straw bales dropped into the hopper pit are transferred to the size
reduction facility by a combination of a 54-inch belt conveyor and a 42-inch
belt conveyor. Wheat straw handling is shown in Figure 17.
When the straw is to be diverted to the storage area, a 42-inch belt conveyor
(reversible) brings bales to the storage area and then a 42-inch portable belt
conveyor is used to direct the bales for stacking. These conveyors are re-
versible and can also bring out the stored bales for processing.
Wheat Straw Storage—
The storage of wheat straw for 60 days of operation is equivalent to 10 million
cubic feet of baled straw. The storage area, approximately 250 feet wide and
and 3200 feet long, is provided with a reversible 42-inch belt conveyor system
which delivers the bales from the receiving -area for storage and also transfers
the stored bales to the feed preparation area when the stored bales are to be
processed.
The bales are stacked about 30 feet high (20 bales) on both sides of the belt
conveyor. Two auxiliary portable belt conveyors (42 inches wide and 100 feet
long) are used to stack the bales. The bale storage area is gravel-based to
provide easy draining.
Wheat Straw Feed Preparation—
To obtain a high biological conversion of the wheat straw, it is pulverized
to submillimeter-size fibers before feeding to the digesters. The straw size
reduction is a three-step process —-preliminary shredding (hammermills),
secondary shredding (hammermills), and pulping (hydropulpers).
The bales brought to the size-reduction facilities are first unbaled auto-
matically and then fed to two primary shredders (hammermills) of 40-ton-per-
hour capacity. The primary shredders are operated two shifts per day. Each
shredder is equipped with discharge grates to produce lij-inch top size straw
pieces (80 percent minus 3/4-inch length)-
The straw from the primary shredders is transferred to the secondary shredders
by a penumatic conveyor. The straw is further crushed in the secondary shred-
ders (two 22-ton-per-hour hammermills) to about 90 percent, minus 1/8-inch
size. The shredded straw is transferred to a 20-foot diameter hydropulper by
a pneumatic conveyor for the final size reduction. The hydropulper reduces
the straw to submillimeter sizes. The pulped wheat straw is then degritted
and concentrated by cyclones.
The first set of hydrocyclones removes the grit in the slurry and the second
set (twelve 16-inch diameter units) concentrates the straw slurry to eight-
percent solids content. The overflow from the second set of hydrocyclones
is returned to the hydropulper. The pulped, degritted, and concentrated
wheat straw (slurry) is pumped to the digester feed surge tank.
Wheat straw receiving and unloading is a two shifts per day and six days per
week operation, while the primary shredding is a two shifts per day and seven
days per week operation. During the weekends, the bales from the storage area
are brought to "the primary shredders. The secondary shredding and hydropulp-
ing is a three shifts per day and seven days per week (continuous) operation.
127
-------
Eight 40-foot diameter by 40-foot high bins provide 400,000 cubic feet of
capacity to store shredded straw from the primary shredder. During the third
shift, the straw is transferred to the secondary shredder by an eight-inch
diameter pneumatic conveyor.
Cattle Manure Receiving and Storage—
An average of 1000 tons per day* of cattle manure is delivered to the plant.
Cattle manure is delivered to the plant by 20-ton dump trucks which unload
the contents into a receiving bin. The receiving bin is provided with two
screw conveyors which transfer cattle manure to a tube conveyor system. The
cattle manure handling is shown in Figure 17.
The conveyor system, consisting of two 2500-foot long, eight-inch diameter
tube sections, is designed to transfer cattle manure from the receiving area
to the feed preparation facility where the feedstock is subjected to size
reduction and degritting. The conveyor system also transfers the feedstock
to the storage facility. The returning section of the conveyor is used to
transfer the stored manure to the feed preparation area when the stored manure
is to be processed.
During normal operation, delivery and unloading are carried out two shifts per
day and six days per week. During the third shift and on weekends, the manure
in the receiving bin is processed first until the bin is empty, and then
manure from the storage facility is transferred to the preparation facility
for processing.
The manure conveyor system is a special type. It consists of a continuous
tube in which flat discs connected to a continuously travelling chain are
mechanically pulled by a driving mechanism. The feedstock is pushed by the
discs until it reaches a discharge opening. The enclosed tubular conveyor
minimizes the odor problem and potential spills.
The manure transferred to the pulper is discharged directly into the pulper
feed hopper. By closing the discharge valve, the manure can be conveyed to
the storage area. By selectively opening the discharge valves on the over-
head tube line, the manure can be deposited by free fall into a series of
overlapping conical piles.
When stored manure is to be processed, a front-end loader pushes it from the
piles into a loading bin recessed in the floor. The manure is then fed into
the returning tube conveyor line which transfers it to the feed preparation
facility.
The cattle manure storage facility consists of a building with a concrete
floored area 150 feet wide by 600 feet long. The storage area is enclosed to
house the overhead tube conveyor lines and also to prevent a potential runoff
problem. A part of the returning tube conveyor is installed under the floor.
Two independently operated conveyor systems allow effective use of the stor-
age area and uninterrupted plant operation.
^Equivalent to 150 tons per day on a dry basis.
128
-------
Cattle Manure Feed Preparation—
Manure feed preparation involves size reduction, degritting, and slurry feed
concentration. The manure is fed to a 12-foot diameter hydropulper directly
from the tube conveyor discharge opening. The pulped slurry is then pumped
to two sets of hydroclones. The first set (four 6-inch diameter units) re-
moves grit and the second set (four 12-inch diameter units) concentrates the
slurry to eight percent solids content. The overflow from the second set is
returned to the pulper. The pulped, degritted, and concentrated cattle
manure slurry is pumped to the digester feed surge tank.
Anaerobic Digestion and Effluent Treatment Facilities
Wheat straw and cattle manure in slurry form are pumped to storage tanks
(Figure 18). The wheat straw storage tank design capacity of 480,000 gallons
provides four hours detention time. The manure slurry storage tank capacity
is 81,000 gallons and also provides four hours detention time. Wheat straw
slurry and cattle manure slurry are pumped by 2000 gpm and 350 fpm pumps
respectively to six anaerobic digesters. Each digester is 200 feet in dia-
meter and 24 feet tall (5.6 million gallons capacity) and together they pro-
vide a detention time of 10 days. The digesters are equipped with fixed
concrete roofs and are insulated to minimize heat loss.
The pH of the digester contents is monitored continuously by probes and is
maintained within the range of 6.6 to 7.0 by the addition of lime to the
digester influent. The lime is supplied as a 10-percent slurry from a pack-
age unit consisting of a storage silo, weight feeder, feed conveyor, slaker,
transfer tank, slurry storage tank, slurry surge tank, agitators, and pumps.
The slaker capacity is 1600 pounds of lime per hour.
Sludge distribution and thermal homogeneity are provided by heater/mixers
which use the raw product gas of anaerobic digestion. A portion of the prod-
uct gas is used to fire a boiler, while another portion is compressed and
recirculated through the mixing units. Compressed gas is released in the form
of large bubbles into a stack in the lower portion of the digester. Each
rising bubble forces liquid above it up through the stack while drawing liquid
behind it. After leaving the stack, the bubble travels freely to the liquid
surface. Heat is transferred to the sludge from a hot-water jacket surround-
ing the stack pipe. A bubble is emitted into the stack just before the pre-
ceding bubble leaves, thus providing continuous flow. Each digester is pro-
vided with 98 twelve-inch diameter heating and mixing units, and each unit is
supplied with gas at 18 SCFM. Seven 195-horsepower compressors (including
one installed spare) supply the gas to the heating-mixing units. The temper-
ature of the digester contents is maintained at approximately 95°F by using
14,000 pounds per hour of 75 psig steam.
Product gas is released in the gas space under the digester cover, and is
collected for recirculation and cleaning. The nutrients required for bacter-
ial activity are contained in the feed to the digesters.
The liquid effluent from each digester is transferred by a 375 gpm progressive
cavity pump to centrifuges for dewatering. Five 250-horsepower centrifuges,
including one installed spare, are supplied. Polymer is added to the centri-
fuge feed to improve the dewatering characteristics of the solids. The polymer
129
-------
"-^DiiuurfiiH
^^--^^
BOO ^/ir
Tii, 1 ft /&kt
GAt, irtM SCFD
<£>
uui
S MtlR
_
-
A
LIXI-
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-
~
<^S
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ftki
iri
^s
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liM
-
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-
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Figure 18. Straw/manure to gas, process flow sheet,
digesters and waste treatment.
-------
is fed from a package system consisting of a dry polymer storage bin, feeder,
disperser, mixing-aging tank, feed tank, agitators, and metering pump. Ap-
proximately 10 pounds of dry polymer are added per hour.
The centrifuge sludge cake (29 percent solids) is transported by a series of
conveyors to a sludge hopper of 432,000-cubic-foot capacity. The sludge hop-
per has six compartments, each with about a one-day sludge storage capacity.
Two compartments are normally used, the other four being reserved for periods
when sludge hauling is not practical. The sludge is loaded out from the hopper
into trailer trucks five to six days per week. The material is hauled to
farmlands for use as a soil conditioner. Sludge cake can also be stored
outside in emergency situations. There is a possibility that this material
can be used as an animal feed and thus be sold as a valuable byproduct.
Approximately 80 percent of the centrifuge centrate is recycled to the process
and the remainder goes to a 34-foot diameter primary clarifier. Solids in the
centrate are collected in the bottom of the clarifier and pumped to the feed
preparation section of the process. The clarifier overflow goes to a plastic-
lined aeration basin where residual organics are metabolized by aerobic bac-
teria. The aeration basin has a capacity of 400,000 gallons, with water
surface dimensions of 90 feet by 90 feet and a 10-foot side water depth. The
aeration basin provides a detention time of one day. Four 25-hp floating
mechanical aerators (including one installed spare) provide mixing energy
and transfer dissolved oxygen to the basin contents to ensure optimum opera-
tion. The basin effluent flows to two 28-foot diameter clarifiers, each with
a 10-foot side water depth and four-hour detention time. Sludge scraping
mechanisms move settled sludge towards the center of the clarifier where it
collects in a sump and is recycled by four 200 gpm pumps (including two
installed spares) to the aeration basin (165 gpm) and to the process (20 gpm) .
The clarifier overflow goes to a clay-lined polishing pond having about a
10-million-gallon capacity and a detention time of 30 days. The pond measures
495 feet by 260 feet at the water surface, with a 12-foot side water depth.
The polishing pond effluent can flow by gravity via a discharge line to the
nearby river or be recycled (to the process) by a 250 gpm pump for use as
makeup water. About 50 percent of the effluent is assumed to be discharged
during normal operation. The maximum fraction of effluent recycling would
have to be determined in actual operation of the plant.
Storm runoff from 94 acres of plant process area is collected in storm sewers
and routed to the polishing pond for sediment removal. Ten inches per year
of runoff would add an annual average of about 50 gpm to the pond influent.
The runoff from a ten-year, 24-hour storm event would fill the pond (if
empty). Several hours' holdup is provided for storm runoff by keeping the
pond at less than maximum water level.
Gas Cleaning
An average of 11.35 million (MM) SCFD (dry basis) of raw gas from the digest-
ers is treated to remove carbon dioxide, hydrogen sulfide, and water vapor,
upgrading the heating value to 950 Btu/SCF (dry). The gas cleaning and upgrad-
ing process is shown in Figure 19. Design processing capacity is 13.5 MM SCFD
(dry). About 1.5 MM SCFD of the raw gas is burned to generate process steam.
131
-------
LO
[aENPitLP)*C|D jjkS RtMQVM-
cw
ftOILER
50,000 LBjHR CKP,
IS
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LB/HR
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(laoPPMv)
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ACID
-------
The raw gas from the mixing gas blower output is compressed from 27 psia to
325 psia for treatment in a Benfield hot potassium carbonate absorption system.
The Benfield plant (proprietary process) reduces the sulfur content of the
gas from 0.1 percent by volume to 15 ppmv hydrogen sulfide and reduces the
carbon dioxide content to 4.88 percent. At the same time, the heating value
of the digester gas is upgraded from 610 to 950 Btu/SCF on a dry basis.
In the Benfield absorber,•the descending lean potassium carbonate solution
physically absorbs the carbon dioxide and hydrogen sulfide from the raw gas
as it rises through the column. The rich potassium carbonate solution is
regenerated in a stripping column. The acid gas from the stripping column
contains primarily carbon dioxide and water vapor with small quantities of
hydrogen sulfide and methane.
The acid gas stream is diverted to an incinerator/waste heat recovery system
in which the acid gas (170,000 SCFH gas containing 0.175 percent H2S) is
incinerated using about 10,000 SCFH of clean product gas as fuel. The acid
gas incinerator is equipped with a waste heat boiler which recovers energy
from the hot gas by generating about 6000 Ib/hr of 50 psig steam. The acid
contains too much hydrogen sulfide to be vented directly to the atmosphere.
The wet product gas from the Benfield plant is fed into the absorber section
of a glycol dehydration system in which the moisture content of the product
gas is reduced to about 200 ppmv. The spent glycol (dilute glycol) is regen-
erated by heating and recirculated to the absorber.
Seven million SCFD of clean product gas at about 320 psia is piped three miles
to the nearest gas pipeline.
Auxiliary Facilities
Utility Boiler—
A package boiler system generates 50,000 Ib/hr of steam at 75 psig for pro-
cess use (digesters and reboiler heating). The package also includes a
340 gph boiler feedwater treatment system consisting of a media filter and
a softener.
River Water Supply—
River water is used for process makeup water. Figure 20 shows the plant water
balance. A 310-gpm-capacity pump transfers water from the intake pumphouse
at the river to a 1,200,000-gallon-capacity, clay-lined holding basin which
stores a three-day supply for maximum makeup demand. The holding basin mea-
sures 200 feet by 100 feet at the water surface with a 10-foot side water
depth. Total makeup averages about 200 gpm. Makeup water is pumped to the
process as needed.
Potable Water Supply—
Potable water is pumped at 16 gpm from one of two shallow wells on the site
into a storage tank. The storage tank provides a two-day water supply capac-
ity (54,000 gallons) at 20 gpm maximum demand. Boiler feedwater makeup is
also supplied from this tank. The tank contents are chlorinated at two mg/1
dosage.
133
-------
-P-
Lint SLURRN W^TtR Ci6«iPM)
DtrtlDRMlON I *• > PRODUCT GAS
I (<* o.at APM)
_____ r G»STO INCH.
ABSORPTIOul I KeGtNtRKllwl (1.6 SFMI
do" 6PM)
WMJEUP
( b SPM) ^
BF*' I f BOILER*. L _> > STUIM i, (QHD. L
ATMtNTl I O4PM)
B.D, (14PM)
iM ^ BRIHE.
- 0,( 6PM)
Figure 20, Straw/manure to gas, simplified plant water balance.
-------
Cooling Water System—
A recirculating water system supplies cooling water to exchangers in the gas
cleaning section. About 1940 gpm circulation is provided by pumping water
from the cooling tower basin. A two-cell tower with two 8-foot diameter,
25 hp fans has a 3000 gpm rating at a 25°F cooling range with a 30°F approach
to the wet bulb temperature. Average heat dissipation is about 25 million
Btu/hr. Makeup water (25 gpm) is supplied to the tower from the river water
storage pond. Cooling tower blowdown is sent to the polishing pond.
Sanitary Waste Treatment—
Sanitary wastewater is collected and treated in a package biological treat-
ment unit. The treated effluent is disinfected before being sent to the
polishing pond.
Flare System—
All pressure vessels and equipment are connected to the plant relief and
blowdown system. A 12-inch diameter, 100-foot high elevated flare is capable
of burning all of the product gas.
Other—
Other facilities, excluding buildings and civil structures, include the elec-
trical distribution system, the drainage system, the fire protection system,
and the compressed air system.
Plant Thermal Balance
The overall thermal efficiency of the plant is estimated on a fuel heat content
basis. Energy inputs are the heat values of the manure and wheat straw and
the electric power consumed. The auxiliary fuel consumed (natural gas, diesel
and gasoline fuels) is omitted from the balance.
Table 51 summarizes major factors in the thermal balance. Electric power is
converted to fuel equivalent basis by assuming a 33-percent conversion effi-
ciency for a natural-gas-fired power plant.
About 40 percent of the feedstock heat value is converted to fuel energy in
the form of raw product gas. Internal gas consumption reduces the product
gas output to 34 percent of the feedstock heat value and 31.9 percent overall
output. Most of the input energy is lost as "unconverted" residue, a con-
sequence of the digestion process.
BIOGAS PLANT COSTS
A conceptual estimate was made for the straw-and-manure-to-gas plant located
on the hypothetical 140-acre site in the midwest. Table 52 summarizes the
major capital cost elements. Mechanical equipment and piping are the largest
direct field cost elements.
Pollution control equipment costs .are a relatively low percentage (4.5) of
the field costs — most of this is for wastewater cleanup. The total capital
cost of $85.2 million represents an investment of about $12,800/MM Btu/day
135
-------
TABLE 51. BIOGAS PLANT THERMAL BALANCE FACTORS
Factors
Input
Straw (input)
'Manure (input)
Electric power (7300 hp * 0.33
conversion effic.)
Total
Outputs and Direct Consumption
Digester gas product (8910 SCFM
at 610 Btu/SCF)
(-) gas used in digester
heating
(-) gas used in gas cleaning
(-) gas used for building
heating
(-) gas used for incinerator
fuel
(-) heat in acid gas stream
incinerated
MM Btu/hr
712.
102.
56.
870.
326.
(16.
(20.
(1.
(9.
(1.
4
1
3
8
1
4)
0)
1)
9)
1)
MW
208.
19.
16.
255.
95.
(4.
(5.
(0.
(2.
(0.
% of Input
7
9
5
1
5
8)
9)
3)
9)
3)
81.
11.
6.
100.
37.
(1.
(2.
(0.
(1.
- (0.
8
7
5
0
4
9)
3)
1)
1)
1)
Dry product gas to
pipeline 277.6 82.3 31.9
Losses (balance) 593_2 1?3>8 ^^
(dissipated as heat, rejected
as nonconverted residue)
136
-------
TABLE 52. STRAW/MANURE-TO GAS CAPITAL COSTS
Element $l,000,0t)0's
Site and Yard 1.5
Civil/Structural 7.2
Process Mechanical Equipment 16.8
Pollution Control Equipment 1.9
Piping and Instrumentation • 13.0
Electrical 1.6
DIRECT FIELD COST 42.0
Indirect Field Cost 7 .0
TOTAL FIELD COST 49.0
Engineering Services 5. 9
54.9
Allowance for Uncertainty 11.0
TOTAL CONSTRUCTION COST 65.9
Land 0.6
Other Owner Costs 1.3
Startup 6.6
Allowance for Funds During Construction 6.7
FIXED CAPITAL INVESTMENT 81.1
Working Capital 4.1
TOTAL CAPITAL COST 85.2
First Quarter 1978, Price and Wage Levels
137
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of gas output. This is, as expected, quite a bit higher than estimated
investments for large high-Btu g-asification plants. For comparison, a 1975
Parsons report (4) indicated a similar investment at a low gas production
rate for a municipal refuse-to-SNG plant by PUROX* pyrolysis and methanation -
$80 million at 7.6 MMM Btu/day. In contrast, SRI (11) estimates an invest-
ment of about $8350/MM Btu/day for a 5.1 MM SCFD SNG plant for anaerobic
digestion of cattle manure.
Annual operating costs are summarized in Table 53. The plant operation is
labor intensive and has a large fraction of high maintenance equipment. Elec-
tric power consumption is high and also adds significantly to the operating
costs. Table 54 presents annualized costs for capital, operation, and feed-
stock. The annualized capital cost is based on 100-percent debt financing
at nine percent interest, the simplified basis used in Section 3 also. As
noted earlier, no credit is taken for the digester solids residue. If this
material could be used as animal feed, a significant byproduct credit would
offset the high annual operating costs.
On this basis, however, both the annual capital and the annual operating
costs exceed the total feedstock costs. These base feedstock prices repre-
sent about $1.70/MSCF ($1.80/MM Btu) of gas produced, or 20 percent of the
total production cost of gas.
Figure 21 illustrates the sensitivity of gas cost to feedstock prices on both
a utility and private financing basis. These gas costs are about $7.68 and
$10.63/MM Btu, respectively, at zero straw and manure costs. On a feedstock/
Btu basis, each $1/MM Btu of straw and manure cost adds about $2.50/MM Btu
to the gas cost. Feedstock costs are quite important, especially in view of
the high cost of gas production as estimated here.
BIOGAS ENVIRONMENTAL ASSESSMENT
Impacts will occur from wheat straw and manure collection activities as well
as from construction and operation of the biogas plant. General environmental
impacts for the hypothetical plant located in the midwest are described below.
Feedstock Procurement Impacts
Removal of about 330,000 tons per year each of wheat straw and manure from the
land will cause certain environmental impacts away from the plant site itself.
Feedstock procurement impacts are discussed in general. Much more detailed
site information would be needed to accurately assess impacts in a specific
locale — as would be done in an environmental impact report for a project
such as hypothesized here.
Wheat Straw—
Residue removal from soils has the potential for causing the largest adverse
impact resulting from feedstock procurement. Relatively large land areas
are affected by residue collection because of low field density of wheat
straw. Soil erosion is the principal concern in this geographic region.
Soil related impacts are discussed below.
138
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TABLE 53. ANNUAL OPERATING AND MAINTENANCE COSTS" -
STRAW/MANURE TO GAS
Element
$l,000,000's
Supplies
Utilities
Operating Personnel
Maintenance Labor and Materials
Supervision
Administration and Overhead
Local Taxes and Insurance
TOTAL ESTIMATED ANNUAL OPERATING COST
First Quarter 1978, Price and Wage Levels
0.6
1.2
1.4
1.0
0.3
0.3
1.7
6.5
"'Excluding straw/manure feedstock.
TABLE 54. ANNUALIZED COST OF GAS PRODUCTION
Element
Annualized Capital Cost (9%)
Annual Operating Cost
Annual Straw Cost
(Base: $10/ton)
Annual Manure Cost
(Base: $2/ton)
TOTAL ANNUALIZED COST
$l,000's
9,264
6,500
3,285
657
19,706
$/MSCF
(net)
4.02
2.82
1.43
0.28
8.55
$/MM Btu
(net)
4.23
2.97
1.50
0.30
9.00
139
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STRAW OR MANURE COST, S/MMBTU
0.5 1
20
STRAW/MANURE-TO-BIOGAS
15
D
1-
CD
10
O
o
PRIVATE
UTILITY
MANURE COST, S/TON
4
10 20
STRAW COST, S/TON
Figure 21.
30
Effect of straw/manure cost and cost of gas
with both private and utility financing.
140
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Erosion—Moderate to strong surface winds are common in the Great Plains.
Wind velocity in the vicinity of the site is highest in March and April,
and soil blowing is a serious problem during dry and windy periods in spring.
Compounding the problem is the fact that a good proportion of local soils are
coarse-textured. Whenever windspeed exceeds 11 to 13 mph, the unprotected
fine, loose, and dry soils with a smooth and bare surface blow freely. USDA
has estimated 35 million acres of Great Plains cropland is severely erodible.
From one to 16 million acres with a 40-year average of about five million
acres are damaged annually in the region (33).
Wheat is sown on a good proportion of soils that are sands, loamy sands, and
sandy loams. Unprotected, they may lose as much as 180 tonnes/ha/yr of sur-
face soil (30). The resulting damage to the environment includes deterioration
in soil fertility (34), air pollution, loss .of visibility, injury to human
and animal health, damage to equipment and machinery, traffic hazards, reduced
seedling survival, poor yield and low quality of horticultural crops, and
increased incidence of plant diseases.
Present technology for wind erosion control requires maintenance of a vege-
tative cover on erodible soils as one of the basic principles. In the past,
it has been assumed that approximately one-half of crop residues may be
removed from soils without serious consequences from wind erosion. However,
recent research data have shown that this may not be true in all cases.
Skidmore and Siddoway (30) undertook an investigation to determine the quan-
tity of crop residue that may be removed from soils in the Great Plains with-
out exposing the soils to degradation by wind erosion. Their data demonstrated
that the highly erosive soils (Wind Erodibility Group 1) would require from
1120 to 3300 kg/ha (2944 Ib/acre) of flat wheat straw depending on the climatic
factor. Based on an average U.S. yield of all wheat per harvested hectare at
2000 kg (1784 pounds) and straw-grain ratio of 1.7, the estimated straw yield
would be approximately 3400 kg/ha, or 3033 Ib/acre. Therefore, one-third to
virtually all wheat straw would be needed for acceptable erosion control of
soils in the wind erodibility group.
Skidmore and Siddoway also calculated straw requirements of soils in Pratt
County, Kansas (30). Using local wheat straw yield of 2800 kg/ha (2498 lb/
acre), they concluded that the loamy fine sands and fine sandy loam soils
will all straw removed would probably lose more than 100 tonnes/ha/yr
(44.6 tons/acre/yr). Even the fine-textured soils would lose more than
50 tonnes/ha/yr (22.3 tons/acre/yr). If all straw were left on the soil,
even the highly erodible, coarse-textured soils should not erode. If half
the straw were left and maintained in upright standing position, the finer-
textured soils should be adequately protected.
If field width were decreased, more wheat straw could be removed. For example,
with a decrease in field width from 300 (984 feet) to 60 m (197 feet), the
protective straw requirement would decrease from 3140 to 2910 kg/ha (2801 to
2596 Ib/acre) on highly-erodible soils. This decrease is even more pronounced
on fine-textured, less-erodible soils. Thus, on a wide field with no strip
crops or other barriers, the wind erosion hazard is more pronounced than on
well-managed, small-width fields. Wind breaks and different combinations of
trees, shrubs, and tall growing crops (corn, sorghum, sudangrass, sunflowers,
etc.) would likewise decrease straw requirement for wind erosion control.
141
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Crop residue is also essential for protection of soils against water erosion,
especially during summer thunderstorms which are sometimes accompanied by
high winds, large hail, and heavy downpour. They last only a short time,
but cause sheet erosion on bare and loose soils.
Great care will be needed in management of wheat straw procurement activities
to protect the affected soils from serious wind and water erosion. This will
mean that, in some areas, residue collection will not be possible; in some,
partial collection will be practiced; and in others, full collection may be
possible on a rotational basis. Since the plant's annual requirements are
small compared to the total crop residue produced in the area, significant
damage should be avoidable by selective collection practices augmented by
increased use of erosion control techniques. Procurement management activ-
ities, if extensive, _could have a_neg_ative economic impact on the plant in
the form of a higher cost of delivered feedstock.
Fertility—The average U.S. wheat straw yield amounts to 3400 kg/ha/yr. This
is equivalent to an addition of about 22 kg of nitrogen, 2.4 kg of phosphorus,
and 30 kg of potassium per hectare to the soil if straw is plowed into the
soil. In addition, approximately 5 kg of calcium, 3 kg of magnesium, 4 kg
of sulfur, 0.008 kg of copper, 0.14 kg of manganese, and 0.04 kg of zinc are
added per hectare (35). Assuming no nutrient elements are lost by leaching
or other causes, to the extent that straw is removed, the soil will not receive
these nutrients. Decreased soil fertility by residue removal will be partly
offset by using digested sludge from the conversion plant on the croplands
in place of decomposing straw. Although the sludge cake will not be of any.
great value in erosion control, its organic and nutrient contents will par-
tially make up for the losses incurred by removal of the residue. The cake
material will contain nearly all of the nutrients present in the original
residue less some carbonaceous matter that is converted to gas.
Over 1800 tons per stream day of digested straw and manure residue will be
available for land application. Application to crop lands will take place
outside the wheat growing season, so that a management program will have to
be developed for distributing the material, as needed, to farmers who supply
feedstock to the plant. The feedstock contractor (whose trucks also pick up
sludge cake at the plant) is assumed to provide sludge residue management
services. He will also need to provide sludge storage for periods in the
year when application to crop land is not practiced.
In summary, there is a potential for significant loss of cropland productivity
in the area by indiscriminate removal of wheat straw residue. The adverse
impact can be mitigated through a careful management program in which residues
are selectively collected and the impacts of collection on soil erosion and
productivity -are monitored carefully.
Manure
Livestock manure collection will cause relatively small environmental impacts.
Virtually all of the manure supplied to the plant will be from confined feed-
lots where the material is readily collectible daily. Feedlot wastes are also
a significant source of water pollution and often represent a disposal problem
142
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for the feedlot operators. Presently, most of this material is aged and
spread on nearby farmland as a fertilizer. Collection and removal of fresh
manure will be beneficial in situations where pollution problems can be
lessened. Flies are often a significant problem at feedlots. To the extent
that the manure is not allowed to accumulate in exposed areas, the attrac-
tion of flies will be somewhat lessened.
Relatively small areas will be affected by manure collection — the feedlots,
adjacent farmland, and haul roads. Loss of soil productivity of nearby farm-
land which currently receives manure as fertilizer can be offset by return-
ing some of the plant digested sludge to these lands.
Transportation
Feedstock collection will increase the transportation burden on local (county)
and state roads in the vicinity of the plant. Approximately 100 truck loads
per day of feedstock will be delivered to the plant. Some of the trucks will
haul digested sludge on return trips, either to yarding facilities or to
farmlands. Approximately two million vehicle-miles annually would be traveled
in feedstock and residue hauling. Vehicle densities on active haul roads
near the plant could be quite high at times, causing localized congestion.
Employee traffic at shift changes would add to the problem. Away from the
plant, the vehicular densities would be quite low and should not overburden
the road system.
Motor fuel consumption (about 0.2 percent of plant energy output) and vehicular
emissions will increase as a direct result of procurement activities. In com-
parison to the annual vehicle-miles expended in the collection .area (about
3800 square miles), these increases will be small. In addition to vehicle
pollutant emissions, some increase in fugitive dust emissions can be expected
from hauling activities on farmlands and roads.
Social and Economic
Feedstock collection will create permanent employment opportunities for 30
to 50 people in the area. Farmers and feedlot operators supplying feedstock
will receive income from the sale of their residues. The contractors who
procure the residues will receive income from the plant itself through- the
sale of feedstocks delivered to the plant. Approximately four million dol-
lars per year will be added to the local economy through feedstock procure-
ment activities.
As a summary. Table 55 lists the general impacts expected from collection and
transport of wheat straw and manure to the biogas plant.
Plant Impacts
Environmental impacts of constructing and operating the biogas plant are
broken down into four categories:
• Physical/chemical
9 Biological __
143
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TABLE 55. PROCUREMENT IMPACT SUMMARY - WHEAT STRAW AND MANURE
Environmental
Factors
Biomass Procurement
Impacts
Potential
Mitigating Measures
Air Quality
Surface Water
Quality
Straw - minor adverse impact
from vehicle combustion emis-
sions from field collection;
potential severe fugitive
dust emissions from wind ero-
sion of unstable soils
Manure - minor impact from
vehicle combustion emissions
Straw - potential degrada-
tion of water quality could
result from an increase in
soil erosion
Limit or avoid col-
lection on highly
erodible soils
Limit or avoid col-
lection on highly
erodible soils
Groundwater
Quality
Land
Availability
Ecology and
Critical Habitat
Manure - potential reduction
of pollutant emissions from
some feedlots, benefitting
local stream qualities
Straw and manure-little
direct impact
Straw - abundant cropland in
region; agreements with
owners needed for collection
of enough straw over plant
operating life; some land
area needed for straw yarding
Manure - little impact on
land availability; may en-
courage development of large
feedlots to supply manure
Straw - some 220,000 to per-
haps 600,000 acres of land
will be subjected to straw col-
lection each year; temporary
displacement of animals during
collection, possible distur-
bance of habitats (removal
of ground cover) of some small
animals
(Continued)
144
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TABLE 55. (Continued)
Env i r onmen t a 1
Factors
Biomass Procurement
Impacts
Potential
Mitigating Measures
Ecology and
Critical Habitat
(continued)
Soils and
Geology
Aesthetic and
Recreational
Resources
Manure - little impact on
plant and animal life
Straw - potential for severe
wind and water erosion of some
soils with complete or even
partial residue removal; de-
crease in soil fertility due
to removal of nutrients in
residue
Manure - potential for some
reduction of soil fertility
where raw manure used as
fertilizer on farmland
Straw and manure - no
discernible effect
Develop residue col-
lection and manage-
ment plan including
soil surveys, erosion
control plans, moni-
toring of collection
activities; replenish-
ment of nutrients by
application of undi-
gested residue from
plant
Replenishment of nu-
trients by application
of undigested residue
from plant
Community
Economy
Community
Population and
Services
Straw and manure - about $4
million annual input to
regional economy through pur-
chase of delivered residues
Straw and manure - little in-
crease expected in local pop-
ulation and in demand for
services
Labor
Availability
Straw and manure - local man-
power resources are adequate
to provide personnel for jobs
created by procurement activi
ties; benefit to local work-
force
Transportation
Straw and manure - small in-
crease in traffic burden on
local roads and highways;
localized congestion may occur
at times
145
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• Socioeconomic-
• Aesthetic
Table 56 summarizes the physical resources committed to the operation of the
conversion plant. Table 57 shows estimated annual chemical requirements.
TABLE 56. PRINCIPAL RESOURCES COMMITTED TO PLANT OPERATION
Resource Category
Quantity
Normalized Quantity
(Output)*
Land
Feedstock
Wheat Straw
Cattle Manure
Auxiliary fuel
Chemicals (Total)
Electric Power
Water
Manpower (99 Employees)
140 acres
328,500 tons/yr
328,500 tons/yr
11,900 MM Btu/yr
6,150 tons/yr
42.9 MM kWh/yr
94 MM gal/yr
198,000 manhours/hr
0.5" acre/MM Btu/hr
300.2 Ib/MM Btu
300.2 Ib/MM Btu
544 Btu/MM Btu
5.6 Ib/MM Btu
19.6 kW/MM Btu/hr
42.9 gal/MM Btu
0.09 mh/MM Btu
*Basis: 2.1886 trillion Btu/yr net output.
The construction period (start of engineering to construction completion) is
assumed to be three years. Several hundred workers will be onsite at the
peak of construction. Resources such as fuel, power, water, and manpower will
also be consumed during plant construction.
Physical/Chemical Emissions and Impacts—
Air Emissions—The straw-and-manure-to-gas (biogas) plant will have several
types of air emissions as summarized in Table 58. Fugitive dust emissions
will result from materials handling operations. Odors may emanate from manure
and digested sludge handling. The incincerator and utility boiler will be
sources of combustion gases and the cooling tower will exhaust water vapor
and water droplets (drift). None of the sources, except the acid gas incin-
erator, is expected to be a major emitter of air pollutants if properly
146
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TABLE 57. SUMMARY OF ANNUAL CHEMICAL REQUIREMENTS
STRAW AND MANURE TO GAS
Chemical
Amount Per Year
Lime
Polymer
Chlorine
Sodium Chloride
Sulfuric Acid
Glycol
Benfield.Solution
Lube Oil
Auxiliary Fuel
Diesel
Gasoline
Natural Gas
6,100 tons
41 tons
2 tons
2 tons
2 tons
1.6 tons
333 gal
1,000 gal
66,000 gal
16,000 gal
1,000 MSCF
147
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TABLE 58. SUMMARY OF ESTIMATED AIR EMISSIONS -
STRAW AND MANURE TO GAS
Emission
Source
Flow Quantity
Pollutants
Emission Rate
Straw dump
bin
Unbaler and
hammermill
crushers
Straw
(shredded)
pneumatic
conveyor
Straw
secondary
crushers
Straw
(ground)
pneumatic
conveyor
Baled straw
storage area
Lime storage
silo
Manure storage
area, sludge
centrifuge
and loadout
bin
1000 tons/day
of baled straw
62.5 tons/hr
for 16 hr/day
(1MMCFD air)
62.5 tons/hr
for 16/hr day
(2400 CFM)
44 tons/hr for
23 hr/day
(1 MMCFD air)
44 tons/hr
for 23 hr/day
(1600 CFM)
30,000 tons of
baled straw stored
20 tons/day lime
45,000 CFD air
Fugitive
dust
Fugitive
dust
Fugitive
dust
Fugitive
dust
Fugitive
dust
Fugitive
dust
Fugitive
dust
Odor
potential
10 Ib/day
2 Ib/day
(after collector)
4 Ib/day
(after collector)
2 Ib/day
(after collector)
4 Ib/day
(after collector)
10 Ib/day
1 Ib/day
(after collector)
Glycol
reboiler
heater
100 SCFM
(11 MM Btu/day)
N°x*
SOX
CO*
HC*
5.5 Ib/day
0.3 Ib/day
<1 Ib/day
<1 Ib/day
(Continued)
148
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TABLE 58. (Continued)
Emission
Source
Acid gas
incinerator
Utility boiler
stack
Cooling tower
Flow Quantity
5370 SCFM
(230 MM Btu/day)'
9750 SCFM
(900 MM Btu/day)
150,000 SCFM
(dry air)
Pollutants
NO*
sox
CO*
HC*
NO*
sox
CO*
HC*
Water
(droplets)
Salts
Emission Rate
1,933 Ib/day
115 Ib/day
<23 Ib/day
<23 Ib/day
450 Ib/day
249 Ib/day
<90 Ib/day
<90 Ib/day
970 Ib/hr
128 Ib/day
Assumed emission factors:
<0.1 Ib HC/MM Btu
0.5 Ib NO /MM Btu, <0.1 Ib CO/MM Btu,
operated and controlled.
on ambient air quality.
Cumulatively, there will be a minor adverse effect
Handling of straw bales will not result in the release of significant amounts
of dust. Straw grinding and pneumatic transport facilities are equipped with
mechanical collectors (for straw) and fabric filter collectors for dust
removal from vented air.
Manure handling is not expected to be a significant source of dust emissions.
the material is moist and nonparticulate in nature. Its odor, however, may
be objectionable to workers. Exposure of employees will be limited. A sim-
ilar odor problem may occur with the digested sludge from the centrifuges
(its odorous nature is not known). Enclosed areas will be ventilated and
ventilation air ducted to roof vents. Both materials may attract flies and
other insects. Some chemical treatment may have to be used to control
insects at the dump hopper and truck loadout areas. For the most part, the
manure and digested sludge will be handled in enclosed equipment or buildings.
Three combustion units in the plant will be sources of combustion product
emissions. The incinerator will burn the acid gas stream from the Benfield
plant because the stream will contain a concentration of hydrogen sulfide
too high to be vented to the atmosphere. Incinerator flue gas will contain
the sulfur as sulfur oxides — nearly one ton a day. Small amounts of nitrogen
oxides, carbon monoxide, and hydrocarbons will also be emitted.
149
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The utility boiler will burn raw product gas to produce process, steam. The
raw gas will contain about 1.4 Ib of sulfur per million Btu ot heating value.
The small capacity (about 37 million Btu per hour heat input) of the boiler
exempts it from current stationary new source SOX standards. Other pollutant
emissions will be low. A very small portion .of the product gas will be burned
to generate reboiler steam for the glycol regeneration column. The heater
flue gas flow will be small and pollutant emissions low.
The cooling tower will discharge heat and water vapor (8250 Ib/hr) to the
atmosphere. The drift (water droplets) from the tower will contain about
20 tons per year of salts that will be deposited on the ground in the vicinity
of the tower. Miscellaneous emission sources will include the emergency
flare (pilots continuously burn a small amount of gas), fuel storage tank
vents, mobile equipment exhausts, and combustion products from periodic test-
ing of the auxiliary diesel generator.
The air resources area is designated as nonattainment for photochemical oxi-
dants and CO standards. The plant will contribute small amounts (less than
100 tons/yr) of these pollutants. The overall impact of plant pollutant
emissions will be a small, though adverse, effect on ambient air quality.
The emissions will have no discernible effect on the climate in the vicinity
of the plant.
Water Emissions—Wastewater sources are summarized in Table 59. The conver-
sion process employs water as the biomass carrying medium. The digester
throughput will be nearly 2000 gpm. With direct recycling and at least par-
tial recycling of treated effluent, process wastewater emissions may be kept
fairly low. However, digester effluent will probably contain high concen-
trations of organic and inorganic materials. Activated sludge treatment
followed by long detention in a polishing pond is expected to reduce the
biochemical oxygen demand (BOD) to a level acceptable for discharge to the
river. If 50 percent of the polishing pond effluent could be recycled to the
process, only about 115 gpm of digester effluent would be discharged. Prin-
cipal pollutants will be BOD, suspended solids, and dissolved solids. Dis-
solved solids will be high because of leaching of digester solids and addition
of lime and recycling (concentrating) effluent. The effluent-will also contain
some nitrogen and phosphorus extracted from the feed materials. Amounts which
would be present in the effluent are undefined, and a large fraction of these
biostimulants could be retained in the digester sludge. However, if organic
and ammonia nitrogen contents of the polishing pond effluent are high, a
nitrogen removal step will need to be incorporated in the effluent treatment
system.
Use of a solar evaporation pond to impound all of the process effluent would
be a possibility in areas of high annual net evaporation rates. A signifi-
cant amount of land area would need to be added to the plant site for such
a pond (about 100 acres at 20 inches net evaporation).
Other plant wastewater streams will be relatively minor sources of pollutant
emissions (Table 59). All will be routed through the polishing pond before
discharge or reuse. Storm runoff collected from the plant process areas
(about 94 acres) will be a significant water pollutant source on an annual
150
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TABLE 59. SUMMARY OF ESTIMATED WASTEWATER EMISSIONS
STRAW AND MANURE TO GAS
Source Estimated Flow Pollutants
Digester 115 gpm
Effluent
(after polishing
pond)
Utility Wastewater 20 gpm
(after treatment)
Cooling Tower 6.5 gpm
Slowdown
(after settling)
Boiler Slowdown 3 gpm
(after settling)
Sanitary Wastewater 10 gpm
(after treatment)
Storm Runoff 48.5 gpm
(after settling) annual avg
BOD
TSS
TDS
Nitrogen
Phosphorus
PH
Oil & grease
TSS
PH
TSS
TDS
Cl2 residual
~PH
TSS
TDS
PH
BOD
TSS
PH
BOD
TSS
PH
(80 mg/1)
(40 mg/1)
(^10,000 mg/1)
(^50 mg/1)
(-v-10 mg/1)
(<10 mg/1)
(<30 mg/1)
(40 mg/1)
(5500 mg/1)
(<•! mg/1)
(50 mg/1)
(300 mg/1)
(<35 mg/1)
(<35 mg/1)
(<10 mg/1)
(<50 mg/1)
Emission Rate
100 Ib/day
55 Ib/day
^13,800 Ib/day
^69 Ib/day
^14 Ib/day
6-9
<2.4 Ib/day
<7.2 Ib/day
6-9
3.1 Ib/day
429 Ib/day
<.001 Ib/day
6-9
1.8 Ib/day
10.8 Ib/day
6-9
<4.2 Ib/day
<4.2 Ib/day
6-9
<5.8 Ib/day
<29 Ib/day
6-9
151
-------
basis. During heavy rainfall, much of the stormwater will be discharged
after passing through the polishing pond, since complete inpoundment is not
provided. Discharged stormwater will contain some suspended solids carried
over from the pond. However, runoff collected in the polishing pond will
tend to dilute the process effluent, decreasing the total effluent loading
to the river. The runoff itself will carry silt into the pond. Periodic
cleanout of accumulated solids will be needed.
Increased recycling might be practiced during wet weather periods, reducing
the river water intake demand.
Plant effluent discharges into the receiving water will have adverse, though
small, effects on the river water quality. Mass emission rates of BOD, sus-
pended solids, and other pollutants will be 'low compared with total mass flow
of such pollutants in the river. Increases in pollutant concentrations in
the river are unlikely to be measurable. Nevertheless, the potential value
of the river as a surface water supply will..be decreased slightly. Additions
of oxygen demand, biostimulants, and total solids will not be beneficial to
stream quality. The plant water demand of about 200 gpm of river water and
about 16 gpm of well water will also reduce available water resources by a
small amount.
Solid Waste Emissions—The plant will have two main sources of solid waste
(Table 60). The largest is the residue of undigested manure and wheat straw
in the form of a centrifuge cake. About 534 tons per day of solids will be
recovered as waste solids from the digesters. The material still contains
many of the nutrients from the feedstock materials that would be beneficial
for soil productivity. Regular hauling of the residues to farmlands for use
as a soil amendment will result in an overall beneficial effect on the environ-
ment — at least compared with the awkward alternatives. If it were feasible,
the use of this material as an animal feed would be an attractive solution.
The large quantities will make it nearly impractical to provide for onsite
disposal of sludge in landfills. The wet sludge would be susceptible to
erosion and pollution of surface and groundwaters if deposited in large
exposed piles on the land. It could also attract flies and other pests.
Interim storage (e.g., during winter months) will be needed for periods when
land application is not possible. At interim storage sites, there will still
exist the potential for contaminated leachate and runoff. Surface and ground-
waters need to be protected from contact with contaminated water. Improper
handling and disposal of the large quantity of residue offer potential for
significant damage to water resources.
Plant general trash and garbage will be collected and buried on site in a
small sanitary landfill. About 10 acre-feet of such waste will be generated
over the life of the plant. Disposal by landfilling will cause relatively
little impact on the physical/chemical environment.
Soils and Geology—The biogas plant will be constructed on a hypothetical site
currently used as cropland. The area altered by plant construction and oper-
ation will be about 140 acres. Some additional off site land will be disturbed
152
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TABLE 60. SOLID WASTE DISPOSAL SUMMARY -
STRAW AND MANURE TO GAS
Source
Centrifuge
Sludge Cake
(Digester
Solids)
Plant Trash
and Garbage
Estimated
Quantity
1,840 tons/day
wet, 534 tons/day
dry solids
300 Ib/day
Potential
Pollutants
Organic mate-
rials,'" calcium,
nitrogen, phos-
phorus, potas-
sium, sulfur
Decomposable
waste, some
oily material
Disposal
About 13,000 tons
per week hauled to
farm lands for
disposal
About 400 cu ft
per week collected
and buried onsite
Miscellaneous
Scrap Mate-
rials, Basin
Cleanouts
Intermittent
(no estimate of
quantity)
Organics, sus-
pended solids
Collected periodi-
cally and buried
onsite
*Potential pesticide/insecticide residues if such materials were present in
the straw or manure feedstocks.
by construction of the access road, the connector gas pipeline, and the
imported power transmission facilities. In the main plant construction,
earthwork will include removal of soil cover, leveling most of the area,
and some excavation for basins and foundations. Much of the area will be
permanently covered with new surface materials. In the undeveloped or buffer
portion (within the fence line), changes in the land surface will be less
drastic.
The changes in the land surface will be substantial on the site but will be
minor overall, compared with the large amount of land area in the region with
similar characteristics.
Biological Impacts—
During plant construction, native vegetation (mainly grasses) and wildlife on
those portions of the 140-acre site not now farmed will be removed or dis-
turbed. Winter wheat will no longer be grown as a cash crop on a portion of
the site. Wildlife in nearby habitats will be subjected to human presence
and construction noise. Movement of animals across the site will be restricted
by the boundary line fence. During the plant operating phase, most of the
wildlife would probably return to similar habitats in the vicinity of the
site but avoid the heavily traveled access road. All of the vegetation and
wildlife species on the site are well represented in nearby areas of the
region; therefore, the destruction of onsite vegetation and the displacement
of wildlife will not have a significant overall effect on the biological life
in the region.
153
-------
Secondary effects resulting from construction activities will be limited to
temporary and localized damage offsite. Some vegetation may be damaged by
fugitive emissions or by erosion resulting from changes in drainage ways.
Construction site runoff may temporarily increase sediment loading in surface
waters and cause harm to aquatic species.
The effect of the operating plant air emissions on biological life should be
small. The sulfur oxide (SOX) concentration in the incinerator stack dis-
charge will be high (nearly 1500 ppm) . Theoretically, some damage to the
leaves of SOX sensitive species (alfalfa, wheat grass) could occur if plume
concentrations were forced to the ground by adverse meteorological conditions.
Normally, the plume will be dispersed sufficiently so that no significant
impact on vegetation is anticipated.
The small quantity of salt from the cooling-tower drift is not expected to ,
cause plant damage offsite. Landscape plants near the tower might be affected.
the uncertainty in the quality of effluent from the plant makes it difficult
to assess the magnitude of the secondary impacts.
Wastewater emissions could cause a minor degradation of river water quality
which, during low river flow periods, could stress aquatic plants and animals.
Nitrogen and phosphorus in the plant effluent may stimulate undesirable plant
growth, and ammonia concentrations may become high enough to affect sensitive
organisms. Generally, significant damage would be limited to a relatively
small mixing zone at the point of discharge into the river.
Smaller plant and animal organisms suspended in the intake water may be
damaged or destroyed in the plant water systems. Intake screens will prevent
the passage of most large aquatic animals. Only a very small fraction of the
biological life in the river will be affected by the intake system.
Aesthetic Impacts—
The hypothetical plant site is not considered to be in an area of high visual
quality although the farmland setting near a river does possess aesthetic
characteristics that will be altered by construction of the plant. The
visual appearance of the plant will contrast sharply with the rural surround-
ings. As approached from the access road, a mix of shapes will be evident —
ranging from the "chemical plant" impression of the gas cleaning, utilities,
and digester sections on the right to the more farm-like cluster of buildings,
bins, and bales of straw further to the left. The foreground will be rela-
tively open and uncluttered by structures. The major plant structures
(digesters, feed preparation buildings, and straw storage) will be fairly
low and broad (massive) in appearance but will not be noticeable from any
great distance, even in nearly level terrain. Taller structures such as the
flare, boiler stack, and Benfield columns will be visible but not dominating
because of their slenderness. One general impression residents and casual
observers might receive could be that the plant is vaguely displeasing because
of its overall size and the unattractive collection of shapes. Its overall
appearance, however, will not be totally foreign to this largely agricultural
economy. Landscaping the plant boundary with shrubs and trees would provide
a screen and help to mitigate the negative aesthetic effects.
154
-------
Social and Economic Impacts—
Construction and operation of the conversion plant will be of significant
economic benefit to the community. A significant fraction of the $85 million
capital investment will be spent locally for equipment, materials, and con-
struction labor. Temporary jobs for several hundred construction workers
will be created. The plant will provide permanent employment for nearly one
hundred people; most will be recruited locally. Increased spending in nearby
towns will result, and the industrial taxes will provide additional revenue
to offset the demand, at least partially, for additional community services.
Manpower resources in the area are abundant and range from unskilled through
highly skilled workers. Very little increase in local population will result
from the construction or operation of this facility, and the demand for new
community services for workers and their families should be small. The plant
itself will produce enough fuel to generate about 25 MW of power. Employment,
spending, and taxes are positive impacts that will be produced by this facility.
Table 61 presents a summary of the principal environmental impacts antici-
pated from construction and operation of the biogas plant.
155
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TABLE 61. SUMMARY ENVIRONMENTAL MATRIX
STRAW -AND MANURE TO GAS
Environmental
Factors
Effect of Plant
Construction and Operation
Potential
Mitigating Measures
Climatology and
Meteorology
Air Quality
Surface Water
Availability
Surface Water
Quality
Groundwater
Availability
Groundwater
Quality
Land
Availability
Regional Ecology
and Critical
Habitat
No discernable impact from
plant construction or
operation
Potential localized impact
of fugitive dust from con-
struction; minor adverse
impact from plant operation
Requires about 40 gal/1000
SCF product gas; small
adverse impact on water
resources
Small adverse impact on
quality; potential for
emission of biostimulants
(and nitrogen phosphorus)
Requires about 3 gal/1000
SCF product; minor adverse
effect on water resources
Little potential for degra-
dation, ponds and basins
lined; proper management
of landfill site required
Requires about 140 acres
of land; no significant
impact
About 140 acres of vegeta-
tion (mainly grasses and
wheat) removed and asso-
ciated wildlife displaced
during construction; minor
adverse direct impact; small
indirect impacts on vegeta-
tion and aquatic species
Potential for"
increasing reuse
Experimental work
needed to assess
potential problems;
include nitrogen re-
moval step or use
solar evaporation •
pond
Careful siting to
avoid sensitive
areas
Careful siting to
avoid critical
wildlife habitats
and rare or endan-
gered biological
species
(Continued)
156
-------
TABLE 61. (Continued)
Environmental
Factors
Effect of Plant
Construction and Operation
Potential
Mitigating Measures
Aesthetic
Resources
Historical,
Archaelogical
Resources
Community
Economy
Community
Population
and Services
Labor
Availability
Power
Availability
Transportation
Availability
Small to moderate adverse
impact-appearance conflicts
with farmland surroundings
Insignificant impact
Substantial benefit from
construction and operation
expenditures in local com-
munities; broadened tax
base
Small increase in local
population and residential
services; little adverse
impact on community resources
Requirements for several
hundred construction and
about 100 operation personnel;
local manpower resources
adequate
Requires about 5 MW (- 18 kWh/
1000 SCF) of electric power
for plant operation; current
generating capacity adequate
Requirement for construction
of access road and small
product gas pipelines; small
adverse impact on environment
from new transport corridors
Plant design, lay-
out and landscaping
Siting surveys to
protect cultural
resources
Plant to support
community in ex-
panding services,
if necessary
Plant to train
unskilled workers
as necessary
Plant could gener-
ate required power
with raw gas as
fuel
Careful selection
of corridors to
minimize impacts on
land use, ecology,
and water resources
157
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COAL GASIFICATION PLANT SITE DESCRIPTION
The hypothetical site for the coal-to-synthetic pipeline gas plant is vir-
tually the same in character as the biogas plant site. The 440-acre fenced
tract is assumed to be a relatively flat rural location currently in agri-
cultural land use. An additional 440-acre buffer zone is assumed to surround
the fenced site. All topographic, climatic, hydrologic, biologic, and demo-
graphic conditions are similar to those of the biogas plant site.
The site is in Seismic Zone 1. The air quality region is currently a non-
attainment area for photochemical oxidants and carbon monoxide. Potential
costs of emission offsets were not considered in this scenario.
The plant owner is assumed to construct a river water intake system and a
discharge pipeline, an all-weather access road and a rail spur to the plant,
and a three-mile long, 28-inch diameter gas connector pipeline to an inter-
state natural gas line. The product is supplied to residential, commercial,
industrial, and utility consumers in the midwest region. Western coal is
received by unit train, and residual ash materials are returned by rail to
the coal mine for burial.
COAL PROCUREMENT
The coal gasification plant annually consumes about 6.7 million tons of low
sulfur western coal. In this scenario, it is assumed that the coal is sup-
plied by a single strip mine located in a western state. The coal is shipped
by unit train to the plant located in the south central area of a midwestern
state (Kansas, Iowa, Nebraska). Coal procurement is briefly described to
allow comparison with the biomass procurement scenario.
In the county where the mine site exists, there are more than five billion
tons of reserves at leasehold involving about 60,000 acres of land surface.
At full production, it is anticipated that more than 120 million tons per
year of coal will be produced from the 12 to 15 mines in the county. The
typical mine will produce more than enough coal for the conversion plant's
needs. Most of the coal is sestined for the steam generating utility market.
The hypothetical mine is on a 4000-plus-acre federal-leasehold. Production
will average between nine and ten million tons per year over its 35-year
life. The leasehold was formerly used for grazing and as cropland, and the
terrain is characterized as gently rolling.
The coal bed ranges in thickness from 70 to 90 feet and the overburden ranges
from 30 to 260 feet in thickness. An area surface mining method is employed
in sequentially mining a series of rectangular units. A rectangular pit the
width ^of a unit is excavated in a series of benches to the coal bed and the
coal is then excavated in benches. Overburden removed from the next con-
tiguous unit is backfilled in the previous pit when sufficient volume exists
for backfilling to start.
In developing a unit, wheeled scrapers remove and stockpile the topsoil.
Earth-moving equipment prepares a smooth bench for drilling and blasting.
158
-------
After shooting, electric shovels on the bench excavate the overburden and
load it on end-dump trucks for hauling to the previous pit. The truck-shovel
method allows continuous replacement of overburden and reclamation of mined-
out areas. The coal bed is also mined in benches by shooting (where necessary),
excavating with electric shovels (or wheeled reclaimers), and hauling with
bottom-dump trucks to the preparation plant.
The ROM coal is delivered to the dump at the preparation area and reduced to
minus three-inch by primary and secondary crushing. Crushed coal is trans-
ported by enclosed belt conveyor to the 15,000-ton-capacity storage silos
for carload-ing. Nominally two 100- to 120-car unit trains (100-ton-capacity
hopper cars) will be shipped per day to the conversion plant. The moving
cars are floodloaded from the bottom of the silos at a rate of 2500 tons per
hour. A dust suppression chemical is sprayed on the coal surface layer to
reduce coal loss during transport. The trains proceed from the rail spur to
the main line (common carrier) crossing the southern part of the leasehold.
The round trip averages two days (approximately 1600 miles). The mine oper-
ator accepts ash from the conversion plant for backfill in stripped portions
of the mine.
The reclamation of the disturbed acreage (average of less than 100 acres per
year) is aimed at returning the land to its prior use with gently rolling
topography similar to its original form. Vegetation established on the top-
soil-covered, backfilled spoils is intended primarily for livestock grazing.
Forage production has increased over the former natural productivity of
forage species.
COAL GASIFICATION PROCESS DESCRIPTION - STEAM-OXYGEN HYGAS
The coal gasification facility described in this section is based upon the
use of the HYGASR process developed by the Institute of Gas Technology. The
HYGAS process is considered one of the promising second-generation gasifica-
tion processes. The facility is designed to convert approximately 6.7 mil-
lion tons per year of western coal into synthetic pipeline gas (SPG). Low
sulfur western coal is shipped to the plant by dedicated unit trains on a
contract dollars-per-ton-delivered basis.
The processing steps are such that the gas produced is interchangeable with
natural gas and has a higher heating value of approximately 915 Btu/SCF.
The design capacity of the plant is 250 billion Btu per day of SPG (about
274 MMSCFD).
Design Bases
The conceptual plant process design presented in this section is based upon
the design work performed by C.F. Braun & Co. for the Joint ERDA-AGA Coal
Gasification Program with only minor balance-of-plant (nonprocess) modifi-
cations to reflect a different hypothetical plant site.
159
-------
The specific reference material (6) used in this evaluation is:
"Factored Estimates for Western Coal Commercial Concepts,"
prepared by C. F. Braun & Co. for the United States Energy
Research and Development Administration and the American
Gas Association under Contract No. E(49-18)-2240 March 1, 1976.
Table 62 presents the composition of the assumed coal feedstock for the plant,
Table 63 presents the general design bases assumed for the conceptual plant.
Table 64 presents the overall summary material balance for the HYGAS process.
The process descriptions, which follow, describe the major process facilities
depicted on the simplified block flow diagram, Figure 22. Table 65 presents
the compositions of the major process streams identified on the block flow
diagram. Additional process details can be found in References 5 and 6.
Figure 23 indicates the general layout of the plant at a hypothetical site.
Coal Handling and Preparation
Minus three-inch raw coal enters the plant by unit train from the mine. The
100-ton capacity cars pass through a car dump station from which the coal is
transferred by belt conveyor to the live storage pile stackers.
The live storage piles have a 14-day capacity. A 60-day dead storage pile
(1.23 million tons) is also provided. A bucketwheel reclaimer takes coal
from the pile and sends it by conveyor to the preparation areas. A venturi
scrubbing system is provided at the coal preparation facilities to control
fugitive dust emissions from handling the dry coal. The process coal is
wet-ground in a rod mill, since the coal will eventually be fed to the gasi-
fiers in a water slurry. The boilers and superheaters in the steam and power
system contain their own pulverizing equipment. Design consumption is about
2300 tons per day.
Slurry Feed Preheating
Ground coal in water slurry is pumped to an agitated tank containing eight
hours intermediate storage. From this tank the coal-water slurry is pumped
to a smaller slurry mix tank, where raw water is added to bring the solids
content of the slurry to 47.5 weight percent. The slurry is pumped in two
stages to about 1300 psig and is then preheated to about 500°F by hot process
streams and high-pressure steam.
Gasification (Two Trains)
The hydrogasification reactor consists of four fluidized beds arranged ver-
tically in a common shell. All the beds operate at about 1200 psig and
increase in temperature from 600°F at the top to 1850°F at the bottom. Two
gasification reactors are required. Each vessel is approximately 25 feet in
160
-------
Aitz.
Figure 22. HYGAS gasification plant, simplified
block flow diagram.
-------
LAHDFILL-
P-AVJ
WATtH-
tToKAfte
•iToK-M WATER I
ftoiJD
Zden-li-1^
-To^ta?
LQV ^fafif,»i&
\o\ /
\o\ /
\o\
\o\
\ I 1 ' "H
\ /
ere*M
Eol^A^,
\
EMU w*Te
-------
TABLE 62. ASSUMED COAL FEEDSTOCK PROPERTIES (5)
Composition Moisture Free As Received
Proximate
Volatile Matter, % wt 37 .-7 29.4
Fixed Carbon, % wt 54.6 42.6
Ash, % wt 7.7 6.0
Moisture, % wt - 22.0
100.0 100.0
Ultimate
Hydrogen, % wt 4.61 3.58
Carbon, % wt 67.70 52.62
Sulfur, % wt 0.66 0.51
Nitrogen, % wt O.S5 0.66
Oxygen, % wt 18.46 14.63
Ash, % wt 7.72 6.00
Moisture, % wt - 22.00
100.00 100.00
Heating Value (HHV), Btu/lb 11,290 8,800
163
-------
TABLE 63. COAL TO PIPELINE GAS DESIGN BASES AND ASSUMPTIONS
Plant Capacity
Coal Receiving
Onsite Coal Storage
Coal Feed Preparation
Gasification
Gas Treatment
Oxygen
Liquid Effluent
Solid Waste Disposal
The design capacity of the commercial plant is
250 billion Btu/stream day (HHV) of synthetic
pipeline gas
Unit train delivery* and transported into the
processing facilities by conveyor belt from
dump hopper
60 days dead,* 14 days live
Spare mills and classifying equipment is provided
in an amount equivalent to 25% of total plant
capacity
A minimum of two gasifiers have been provided;
similarly, facilities for gas quench and solids
removal will be separate for each gasifier
Two trains, 50% each, have been provided for the
following major process units:
Shift Conversion
Acid-Gas Removal
Methanation
Product Gas Drying
Fixed catalyst beds have been designed for 25%
of plant capacity, two beds for each 50% train
Two 1500 ton per day oxygen plants have been pro-
vided without any spare capacity. Liquid oxygen
storage for the output of one plant has been
provided
Process liquid effluent treating will have two
trains, 50% each; one common spare sour water
stripper with its auxiliary equipment has been
provided
Filtered biological sludge, plant trash and
garbage and intermittent basin and equipment
cleanout sludges are buried in an onsite sani-
tary landfill;* all other solid wastes, such as
gasifier and boiler ash, and the solids from the
wastewater evaporator are prepared for return to
the mine by rail car*
(continued)
164
-------
TABLE 63. (Continued)
Gas Effluent All gaseous effluents from the plant will meet
the prevailing federal and state standards
Plant Water Supply River water (pumphouse intake system*)
Onsite Water Storage 3 days storage capacity*
Plant Load Factor 90 percent
Plant Operating Life 20 years
Balance of plant modifications or assumptions different from
C.F. Braun & Co. reports (5,6)
165
-------
TABLE 64. SUMMARY MATERIAL BALANCE - IGT STEAM-OXYGEN HYGAS PROCESS
Streams
Inlet
Coal to Process, Dry
Water in Coal to Process
Coal to Steam Plant, Dry
Water in Coal to Steam Plant
Oxygen to Gasifier
Combustion Air, Nitrogen
Combustion Air, Oxygen
Raw Water
TOTAL
Outlet
Product Gas
C09 Vent
Cooling Tower Losses
Flue Gas
Ammonia
Sulfur
Byproduct Oil
Organics Removed in Biox. Unit
Waste Solids, Dry
Water in Waste Solids
Miscellaneous Water Losses
TOTAL
Lb/Hr
1,135,800
320,400
194,800
55,000
246,200
1,670,300
504,600
962,500
5,08-9,600
446,400
1,264,700
409,900
2,543,800
7,400
8,300
52,600
6,600
131,800
67,900
150,200
5,089,600
Percent
of Total
22.3
6.3
3.8
1.1
4.8
32.9
9.9
18.9
100.0
8.8
24.9
8.1
50.0
0.1
0.2
1.0
0.1
2.6
1.3
2.9
100.0
166
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TABLE 65. HYGAS GASIFICATION PLANT — 250 MMM BTU/DAY — OVERALL MATERIAL BALANCE
Stream Mo.
Description
C
HZ
N2
02
S
H20
MPH
Ib/hr
Ib/hr ash
Total Ib/hr
1
Process
Coal
Slurry
MPH
64,157.0
26,212.5
345.2
6,560.2
234.5
69,888.9
167,398.3
2,307,408
87,792
2,395,200
H2
CO
C02
CH4
C2H6
NH3
H2S
COS
C6H6
C7
H20
MPH
Ib/hr
2
Raw
Product
Gas
MPH
24,702.0
20,762.0
20,772.0
14,214.0
1,110.0
368.0
232.0
9.6
168.0
326.0
53,726.0
136,389.6
2,854,200
3
Shifted
Sour
Gas
MPH
35,160.0
10,280.0
30,372.0
14,206.0
1,108.0
—
220.0
4.4
136.0
—
76.0
91,562.4
1,986,600
4
Methane
Feed
Gas
MPH
35,144.0
10,252.0
488.0
13,996.0
896.0
—
—
—
—
—
4.0
60,780.0
630,920
5
Wet
Product
Gas
MPH
3,534.0
30.0
476.0
26,018.0
—
—
—
—
—
—
28.0
30,086.0
445,996
6
Wet
Product
Gas
MPH
3,532.0
30.0
476.0
27,008.0
—
—
—
—
—
—
4.0
30,050
445,400
-------
diameter and approximately 280 feet in height. The following is a descrip-
tion of the processing steps that take place within the hydrogasification
vessel.
Slurry Dryer—
Coal is dried in the first stage by vaporizing the slurry water. The slurry
from the slurry preparation section is injected into the top fluidized bed.
The hot gases passing upward from the hydrogasification stages maintain the
bed in a fluidized state and flash the slurry water from the coal particles.
The dry coal flows from this bed by gravity into the first hydrogasification
reaction stage. The operating conditions of the slurry dryer bed are 600°F
and 1205 psig and a residence time of 15 minutes.
Low-Temperature Reactor—
Hydrogasification begins in the second zone — the low-temperature reaction
stage. The dry coal is flash-heated to the reaction temperature. The resi-
dence time in the low-temperature reaction stage is measured in seconds, and
the flow characteristics are cocurrent, dilute-phase contact of the solids
with the hot hydrogen-rich gas rising from the higher-temperature stage
below. In this first stage of reaction, the short residence time and high
pressure favor devolatilization and the rapid-rate, direct methanation of
the more active constituents of the coal. The hot off gases from this stage
rise to the slurry drying bed above, and the partially gasified coal is
diverted to the high-temperature stage below. The operating conditions of
the low-temperature bed are 1360°F and 1210 psig and a residence time of
ten seconds.
High-Temperature Reactor—
Hydrogasification of the less reactive carbon continues in the dense-phase,
fluidized, high-temperature reaction stage. The less reactive carbon requires
a temperature of about 1720°F and a longer residence time to achieve adequate
reaction. The high pressure aids the direct methane production. Gases from
this stage proceed upward to the low-temperature reactor, and the residual
char is diverted to the steam-oxygen gasifier below. The operating condi-
tions of the high temperature bed are 1720°F and 1214 psig and a residence
time of 44 minutes.
Steam-Oxygen Gasifier—
The hydrogen-rich gas for the reaction stages is manufactured in the fourth
(bottom) zone by the reaction of steam and oxygen on the carbon in the resid-
ual char from the high-temperature reactor. Ash is expelled from the base
of the hydrogasifier and transported in a water slurry to the ash handling
facility. The operating conditions of the steam-oxygen bed are 1850°F and
1219 psig and a residence time of ten minutes.
Raw Gas Quench (Two Trains)
Raw gas from the gasifier at 600°F is quenched and scrubbed with water in a
column to remove entrained solids. The gas is then further cooled by indirect
heat exchange to about 460°F. At this temperature, the gas contains the
proper amount of water vapor for shift conversion. The scrubbed solids are
sent as a slurry to the solids recovery facility.
168
-------
Shift Conversion (Two Trains)
The H2/CO ratio of the raw gas must be adjusted prior to methanation. This
is done in the Shift Conversion Unit. The shift converters are fixed-bed
catalytic reactors containing a cobalt molybdate catalyst. Part of the raw
gas is bypassed around the shift converters to achieve the desired H£ to CO
ratio. Heat evolved is removed by heat exchange. Steam contained in the
shift effluent gas is condensed, the condensate going to a condensate strip-
per. The cooled gas enters the acid gas removal unit.
Acid Gas Removal (Two Trains)
This unit removes H2S and any COS and CS2 from the gas to protect the metha-
nation catalyst. Also, C02 must be removed .to allow the product gas to meet
quality specifications after methanation. Acid gas is removed by the Selexol
Process, a proprietary process o'f Allied Chemical Corporation. Waste sulfur-
bearing gases from this unit are routed to the sulfur recovery facilities.
As designed, waste C02 goes either to the plant inert gas system or to the
atmosphere through a vent stack. The C02 and nitrogen rich gas also contains
some trace of sulfur and hydrocarbon compounds. These two gas streams will
probably need to be incinerated or at least wet-scrubbed before release to
the atmosphere.
The acid gas removal unit consists of two separate stages. The first stage
removes essentially all of the H2S and other sulfur compounds and some of
the C02- The second stage removes nearly all of the remaining C02- This
design maximizes the sulfur compound concentration in the feed to the sulfur
recovery unit.
Methanation and Dehydration (Two Trains)
The methanation unit converts the purified raw gas into the final product gas
interchangeable with natural gas. Methanation is carried out in a series of
three spherical fixed-bed catalytic reactors. The methanation reaction is
' highly exothermic, and the reaction temperature is controlled by a combina-
tion of heat recovery and hot product gas recycle. The hot recycle allows
the recovery of essentially all of the methanation heat of reaction as high-
level useful energy. The methanation reaction also produces water, the bulk
of which is condensed.
After methanation, the final product gas is cooled, then dehydrated, using a
triethylene glycol drier. Glycol is thermally dehydrated (regenerated), and
the water-rich gas is vented to the atmosphere.
The product gas (274 MMSCFD) then leaves the plant at about 1000 psig and is
sent through a short connector pipeline to an interstate gas pipeline.
Auxiliary Systems
Sulfur Recovery—
Sulfur in the feed coal (93 long tons per day) is converted by either gasi-
fication or combustion to H2S, COS, or S02- The quantities of such gases
169
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which may leave the plant are set by environmental regulations (see environ-
mental assumptions). The sulfur recovery is accomplished by the use of the
IFP Stackpol process, a proprietary process by Institute Francais du Petrole.
This unit treats the flue gases from combustion and acid gases from the acid
gas removal unit and the condensate stripping facilities. Sulfur compounds
are removed from these gases and converted to elemental sulfur (molten), which
is sold as a byproduct (88.9 LTSD) and shipped from the plant by truck. As
designed, the treated gases leave the plant through a tall stack. These
gases might need some additional cleanup such as scrubbing to remove trace
quantities of COS and t^S if environmental regulations are made more stringent.
Flyash removed from the flue gases is sent to solids recovery.
Sour Water Stripping (Two Trains)—
Sour water is produced in the gas quench, shift conversion, and acid gas
removal sections. In the IGT Steam-Oxygen HYGAS process, the quench condensate
(about 1500 gpm) does not contain .phenols, while the shift condensate (about
1550 gpm) does. These are handled in two separate sour water stripping units.
Stripped quench condensate is reused directly in the plant water systems.
Stripped shift condensate goes to a biological oxidation system for consump-
tion of the phenols before reuse as coal slurry makeup water. Acid gases from
the sour water strippers are passed through ammonia recovery and sent to
sulfur recovery.
Ammonia Recovery—
Ammonia in the overhead streams from the sour water strippers is recovered by
use of the PHOSAM-W Process. This process is offered by U.S. Steel Engineers
and Consultants, Inc. Ammonia is recovered in the anhydrous form by this
process. Approximately 88.8 STPD are recovered and stored in tanks for truck
shipment offsite as a saleable byproduct.
Oil Recovery—
The HYGAS process also produces a hydrocarbon oil product which is basically
a mixture of benzene and toluene. This oil product is recovered in the sour
water stripping system and pumped to storage for eventual sale as a byproduct.
Oxygen Plant—
Two 1500-ton-per-day oxygen plants supply the oxygen requirements for gasi-
fication. Ambient air is filtered and compressed to the required operating
pressure. The air compressor configuration generally consists of an axial-
type first-stage machine with water aftercooling and liquid knockout capa-
bility. This is followed by a centrifugal-type second-stage compressor,
also equipped with water aftercooling and liquid knockout capability. The
compressed air then enters a reversing circuit of air-oxygen-nitrogen ex-
changers, where it is cooled to temperatures which permit carbon dioxide and
water to be separated from air by solidifying out on the exchanger surface.
The air then passes through the liquefier exchanger for further cooling.
From the liquefier exchanger, the air is subjected to high-pressure and low-
pressure distillation, where the components of air — oxygen and nitrogen —
are separated by fractionation.
170
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The oxygen product is taken from the low-pressure column and exits the sys-
tem by passing back through the liquefier and reversing exchangers while
being heated. The oxygen product is then compressed to the required gasi-
fication pressure.
Steam and Power—
The IGT Steam-Oxygen HYGAS process does not recover enough high-pressure steam
from the process to satisfy all motive and process steam requirements. There-
fore, three 50-percent-capacity coal-fired boilers are installed. The boilers
produce approximately 1.5 million pounds per hour of 1500 psig steam. In-plant
power is generated by three 50-percent-capacity steam turbine-driven generator
sets. The net power output of the generator sets is approximately 38 MWe.
Water Systems—
The plant is designed for zero aqueous discharge of process wastewater. Only
storm runoff will be discharged to the river. About 1925 gpm of river water
is consumed by the plant (Figure 24). Evaporation and residual water present
in solid wastes account for this consumption. Water enters with coal and
is also produced in the methanation step (and in sulfur recovery, combustion,
etc.). Cleanup and reuse of process effluents minimize the makeup demand.
A multiple-effect evaporator recovers additional water from the high TDS
process blowdown streams.
Intake water is withdrawn from the river and pumped to an onsite river water
storage pond. Three half-capacity pumps in the intake pumphouse supply water
through a 12-inch diameter pipeline. The 8.6-million-gallon basin provides
storage for three days of makeup water. Two pondwater pumps feed the plant
water systems.
About 470 gpm of pondwater is pumped to coal feed preparation and to the gasi-
fiers as slurry makeup and ash quench makeup, respectively. The balance of
the plant feedwater is cold lime-softened, clarified, and filtered. About
400 gpm of softened water is used as utility water and potable water in the
plant. About half of this is recovered and resoftened. Nearly all of the
other softened water is fed to the high (H.P.) and low (L.P=) pressure boiler
feedwater treating systems. High-pressure BFW makeup treatment consists of
reverse osmosis followed by mixed bed demineralization for residual TDS
removal (different from Braun report). Reverse osmosis concentrate (brine)
and ion exchange regenerant wastes are sent to the wastewater evaporator for
further concentration and water recovery. A separate condensate polishing
system removes residual TDS from methanation product water which is then used
as BFW makeup (about 730 gpm). Total makeup to the deaerator is about
1738 gpm, excluding the steam system condensate return.
Low-pressure BFW makeup is sodium-zeolite-softened and deaerated. Only about
20 gpm of lime-softened river water is used as L.P. makeup. The remainder
is stripped condensate from raw gas quenching and a small stream from acid
gas removal. Sodium zeolite regenerant waste and lime softener sludge blow-
down are processed in the wastewater evaporator.
171
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(zoo)
DISCHARGE (145
E.TTLIMG I
BASIN I* f i I3'5' < * * •* * u-
I I UTILITY WHTtR POTABLE. WAT
^fmmm^J Uoo; (UVISC. USES)
( LOSStS ~ I6S )
Figure 24. HYGAS simplified water balance.
-------
The oxygen product is taken from the low-pressure column and exits the sys-
tem by passing back through the liquefier and reversing exchangers while
being heated. The oxygen product is then compressed to the required gasi-
fication pressure.
Steam and Power—
The IGT Steam-Oxygen HYGAS process does not recover enough high-pressure steam
from the process to satisfy all motive and process steam requirements. There-
fore, three 50-percent-capacity coal-fired boilers are installed. The boilers
produce approximately 1.5 million pounds per hour of 1500 psig steam. In-plant
power is generated by three 50-percent-capacity steam turb'ine-driven generator
sets. The net power output of the generator sets is approximately 38 MWe.
Water Systems—
The plant is designed for zero aqueous discharge of process wastewater. Only
storm runoff will be discharged to the river. About 1925 gpm of river water
is consumed by the plant (Figure 24). Evaporation and residual water present
in solid wastes account for this consumption. Water enters with coal and
is also produced in the methanation step (and in sulfur recovery, combustion,
etc.). Cleanup and reuse of process effluents minimize the makeup demand.
A multiple-effect evaporator recovers additional water from the high TDS
process blowdown streams.
Intake water is withdrawn from the river and pumped to an onsite river water
storage pond. Three half-capacity pumps in the intake pumphouse supply water
through a 12-inch diameter pipeline. The 8.6-million-gallon basin provides
storage for three days of makeup water. Two pondwater pumps feed the plant
water systems.
About 470 gpm of pondwater is pumped to coal feed preparation and to the gasi-
fiers as slurry makeup and ash quench makeup, respectively. The balance of
the plant feedwater is cold lime-softened, clarified, and filtered. About
400 gpm of softened water is used as utility water and potable water in the
plant. About half of this is recovered and resoftened. Nearly all of the
other softened water is fed to the high (H.P.) and low (L.P.) pressure boiler
feedwater treating systems. High-pressure BFW makeup treatment consists of
reverse osmosis followed by mixed bed demineralization for residual TDS
removal (different from Braun report)- Reverse osmosis concentrate (brine)
and ion exchange regenerant wastes are sent to the wastewater evaporator for
further concentration and water recovery. A separate condensate polishing
system removes residual TDS from methanation product water which is then used
as BFW makeup (about 730 gpm). Total makeup to the deaerator is about
1738 gpm, excluding the steam system condensate return.
Low-pressure BFW makeup is sodium-zeolite-softened and deaerated. Only about
20 gpm of lime-softened river water is used as L.P. makeup. The remainder
is stripped condensate from raw gas quenching and a small stream from acid
gas removal. Sodium zeolite regenerant waste and lime softener sludge blow-
down are processed in the wastewater evaporator.
171
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--J
to
FtED
PREP.
GASIF-
11AT I 0 N
r
(42, 1 ) HAKtup
FILTRATE
BOILtR 5 S.H.
SOLIOS TO MIME
(05.8) C ^—
RAW GAS I 5HIFT , ACID GAS I MCTHA.M- |
CONV. ' REMOVAL ' ATION
PROOUCT fclkS
il* UHSCFD
(tVt.l) H5H SLURRY
(4,4)
SOLIDS
DISPOSAL
SULFUR
RECOUERV
HUtNCH
SIBIPPING
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C O Nt> .
ST RIPPIM6
AMMONIA 1
RECOVERY 1
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COMbBMSATE
•• IMTCRMITTEMT
*• CONTIMUOUS
( ) FLOWS IM GF'M
AT TO't
EVAPORATION
(its)
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ilOLOMCAL I .
rREMMlKTl—*=> '" >
I TO PUST COWTROL
^•••••••••J ^ LKNDSCA.P1HG
TO PLXMT
MAKEUP ((kLTJ
Figure 24. HYGAS simplified water balance."
-------
L.P. BFW is used in various process steam generators to generate 50 psig and
150 psig steam for process use. H.P. BFW is fed to the three 50-percent-
capacity coal-fired auxiliary boilers and to the methanator waste heat boilers
and coal-fired superheaters to generate 1450 psig process steam. Six hundred
psig.steam for process use is driver exhaust steam from the acid gas removal
compressor. The bulk of the steam system condensates is of excellent quality
and hence returned to the H.P. feedwater system.
All other water demands are met from recycle of process effluents. Makeup
to the cooling water system is a combination of blowdown from the steam gen-
erators (143 gpm), part of the stripped condensate from the raw gas quenching
(630 gpm), and effluent from the ammonia recovery unit (169 gpm). The cool-
ing water system removes process heat and rejects it to the atmosphere in an
induced-draft cooling tower (four cells). The circulating-water rate is
only about 20,500 gpm. The cooling range is 35°F. Air coolers are used
wherever possible to minimize the heat load on the evaporative (wet) cooling
system. Evaporation and drift losses from the tower average 820 gpm. Blow-
down (123 gpm) is routed to the wastewater evaporator. The tower operates
at six to seven cycles of concentration. A chromate-zinc based corrosion
inhibitor is added to the circulating water. Chlorine gas is used in shock
treating the CW for biofouling control.
Shift conversion condensate is a major process effluent stream contaminated
with the organics even after stripping for NH3 removal. A three-stage bio-
logical oxidation system (two trains) is provided to treat this almost
1500 gpm stream. Stripped water first passes thorugh a dissolved air fil-
tration (DAF) unit to recover flotable hydrocarbons. DAF effluent is treated
for dissolved organics removal in three activated sludge-clarifier units
operated in series. Waste sludge generated in each unit is thickened in
a second DAF unit. The thickened sludge is aerobically digested and then
vacuum filtered, producing a sludge cake for land disposal. The cake (7.5 tpd)
is transported by belt conveyor to the plant solid waste loadout facilities
from which it is trucked to an onsite landfill. The bio-treated effluent
from the third-stage clarifier is filtered in a gravity sand filter. Fil-
tered effluent is pumped to coal feed preparation for reuse as a portion of
the coal slurry makeup water.
The plant's high solids blowdown streams total about 205 gpm and contain about
19 tpd of total solids. A multiple-stage flash evaporator concentrates these
streams into a slurry waste by evaporating and recovering most of the water.
Evaporator condensate is recycled to the H.P. BFW makeup system after polish
demineralization. The evaporator brine slurry is pumped to the solids recov-
ery system.
Sanitary wastewater (35 gpm) is collected in a separate sewer system and bio-
logically treated in a package unit which includes tertiary filtration arid
disinfection with sodium hypochlorite. Treated sanitary effluent is used
for landscaping water and dust control within the plant. Waste sludge is
aerobically digested and filtered.
Storm runoff from the process areas and the coal storage area is collected
in separate storm drainage systems.
173
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Solid Waste Disposal—
The major solid wastes generated in the plant are: (1) ash from the gasi-
fiers (54 tph), (2) scrubbed ash solids from raw gas quenching (2.1 tph) ,
(3) boiler fly ash from sulfur recovery (1.5 tph), (4) boiler and superheater
ash from coal-fired steam generators (7.5 tph), (5) solids from the waste-
water evaporator (1600 Ib/hr), (6) waste biological sludge (9.75 tph at
15 percent solids), and (7) general plant trash and garbage (1700 Ib/day).
All except the last two are prepared in the solids recovery facility for
return to the mine by rail car. The slurry streams are thickened, blended
in pug mills, and transported by belt conveyors to sludge loadout bins. Ash
slurry from the gasifiers is diluted to a ten-percent slurry and passed over
sieve bends to concentrate the coarser fraction. The fines portion (-100 mesh)
is combined with quench ash solids and fly ash and settled in a gravity thick-
ener. The thickened slurry underflow is vacuum filtered to an 80-percent
solids cake which is 'fed to the pug mill. Clarified slurry water is recycled
to the gasifiers for ash quenching.
Wastewater evaporator slurry is combined with the boiler and superheater ash
and fed to the pug mill. The blended solids from the pug mill total about
66 tph of dry solids and about 34.0 tph of water. At about 70 Ib/cu ft,
some 68-,500 cubic feet per day of solid waste is fed to the loadout bins
(about 788,400 tpy). Three days of solids storage capacity is provided by
two 4000-ton silos. Solids are flood-loaded into a unit train on occasion
for the return trip to the mine.
Filtered biological sludge, plant trash and garbage, and intermittent basin
and equipment sludges are buried in an onsite sanitary landfill.
Plant Thermal Balance
Table 66 shows an overall plant thermal efficiency of 77.6 percent, of which
the product SPG represents 69.7 percent. The conversion plant produces a
more useful (clean gas) and more valuable product than the feed coal. The
conversion penalties are the conversion costs and the energy losses. Energy
loss is primarily in the form of heat rejected to the atmosphere.
COAL GASIFICATION PLANT COSTS
Capital and operating costs for the conceptual HYGAS facility were updated
to first quarter 1978 from the estimate presented by C. F. Braun & Co. in a
1976 EKDA report (5). The capital costs were broken down by major process
unit, and the same general format has been retained (see Table 67). The
escalation methods are described in Appendix C. Nonprocess changes in the
conceptual design included addition of a rail car hopper dump, a river water
intake system (with a reduction of the water storage pond size), a solid
waste loadout facility, an onsite landfill, an access road, a rail spur, and
a three-mile gas pipeline. Only major cost items were added. Minor cost
items were assumed to be offset by the smaller air-moving equipment (fans,
blowers, etc.) that this conceptual plant would have due to altitude of
1400 feet instead of 3330 feet.
174
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TABLE 66. SUMMARY ENERGY BALANCE — IGT STEAM-OXYGEN HYGAS PROCESS
Element MM Btu/hr Percent of Total
Energy Input
Coal to Process, HHV 12,749 85.4
Coal to Steam Plant, HHV 2,186 ' 14.6
Total Input 14,935 100.0
Energy Distribution
Product Gas, HHV 10,415 69.7
Byproducts, HHV
Ammonia 67 0.5
Sulfur 33. 0.2
Oil 1,071 7.2
Subtotal Product and
Byproducts 11,586 77.6
Consumption and Losses 3,349 22.4
Total Energy Distribution 14,935 100.0
Cold Gas Efficiency, Percent 69.7
Plant Thermal Efficiency, Percent 77.6
175
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TABLE 67. HYGAS CAPITAL COSTS
Element $ 1,000,000's
Coal Storage and Reclaiming 13.2
Coal Preparation 16.6
Coal Feeding 25.5
Gasification 44.0
Raw Gas Quenching 18.6
Shift Conversion 30.4
Acid Gas Removal 105.7
Methanation 28.4
Liquid Effluent Treatment • 56.8
Sulfur Recovery 58.7
Solids Disposal 10.8
Product Gas Drying 0.8
Steam and Power 133.0
Plant Water System 16.6
Oxygen Plant 44.0
General Facilities 68.6
DIRECT FIELD COST 671.7
Indirect Field Cost 100.8
TOTAL FIELD COST 772.5
Engineering Services 92.7
865.2
Allowance for Uncertainty 129.8
TOTAL CONSTRUCTION COST 995.0
Land ^ Q
Other Owner Costs 3 3
Startup 29.9
Allowance for Funds During Construction 155.2
FIXED CAPITAL INVESTMENT 1,189.9
Working Capital 23.3
TOTAL CAPITAL COST 1,213.2
First Quarter 1978, Price and Wage Levels
176
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The total capital cost of $1.213 billion, represents an investment of about
$4350 per MM Btu/day of gas output. This cost is about 14 percent higher
than C. F. Braun's January 1, 1976 capital cost (5). Pollution control
equipment costs were not identified separately by Braun. A rough value can
be obtained from the sum of the process unit costs for liquid effluent treat-
meat, sulfur recovery, and solids disposal — about $126 million or 18.8 per-
cent of the direct field cost (some portion could reasonably be attributed
to byproduct recovery). Some additional pollution control equipment items
are included in the costs for the coal-handling systems.
The annual operating costs in Table 68 indicate that labor constitutes nearly
30 percent of the annual operating expenses. Taxes and insurance are about
one-third of the operating costs. Byproduct credits of $28.9 million per
year for sulfur, ammonia, and oil reduce the annual operating cost (exclud-
ing feedstock) to $53.6 million or about $0.65/MM Btu of gas product instead
of $1/MM Btu,
TABLE 68. ANNUAL OPERATING AND MAINTENANCE COSTS — HYGAS
Element $1,000,000's
Water 0.4
Catalyst and Chemicals 3.7
Operating and Maintenance Labor 24.5
Operating and Maintenance Supplies 12.5
Administration and General Overhead 14.7
Local Taxes and Insurance 26.7
TOTAL ANNUAL OPERATING COST 82.5
Byproduct Credits (28.9)
NET ANNUAL OPERATING COST 53.6
First Quarter 1978, Price and Wage Levels
^Excluding coal feedstock.
177
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The cost for returning solid waste (mainly ash) to the mine and burying it
under overburden is assumed to be included in the cost of the coal. Were
the wastes classified as hazardous materials, the cost for environmentally
safe disposal could be quite high. A separate, secure landfill site might
have to be developed and operated by the plant if the mine site were not
suitable for disposal. Assuming a disposal cost of, say, $10/ton, the annual
cost would be nearly $8 million or about $0.10/MM Btu of gas output.
Figure 25 shows the sensitivity of gas cost to the cost of coal for utility
and private financing. The gas production costs (zero coal cost) are $2.42
and $3.75/MM Btu, respectively. Both are considerably above the current
regulated price of new interstate gas. The gas cost approximately doubles
for utility and private financing at coal costs of $30/ton and $45/ton,
respectively. At $15/ton ($0.85/MM Btu), the gas price required by a private
developer is about $5/MM Btu.
COAL GASIFICATION ENVIRONMENTAL IMPACTS
Coal Procurement Impacts
About 6.7 million tons per year of western coal will be required from surface
mines as feedstock for the HYGAS plant. Impacts on land, water, air, and
biology will be as described in Section 3 (Coal Procurement Impacts), although
the quantity of coal mined (almost seven times the coal-to-power needs) and
the characteristics of the mine site itself may modify the significance of
these impacts on a local and regional scale.
Topography—
The normally gently rolling terrain will be disrupted at the mine site, with
overburden being removed (excavated) and stockpiled prior to coal removal.
Land reclamation will result in an approximation of the original topography,
but it is likely that elevations of hills will be lower by at least the amount
of coal and other materials removed; that normal topographical irregularities
will be replaced with a more regular, rolling terrain; and that the contours
of the mined area will not be exactly as the original contours. However,
given past uses of the area, the probable continued use for strip mining,
and the possible use of the mine as a disposal site for HYGAS solid waste,
these topographical changes will not be significant to the regional topography.
Soils and Geology—
Removal of the required 6.7 million tons of coal per year will result in three
direct changes in regional soils and geology:
• Disruption of the natural geologic structure and the physical
properties of the overburden by destroying the original
stratification of beds, geologic structures, and natural
strength
• Removal and consumption of the coal, a nonrenewable resource
• Intermixing of soil horizons, possible bringing to the surface
materials that may be harmful to plant growth
178
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0.5
COAL COST, S/MMBTU
1.0
1.5
20
COAL GASIFICATION
(HYGAS)
PRIVATE
UTILITY
15
10
CO
t^
<
t/5
o
0
10 20
COAL COST, S/TON
30
Figure 25.
Effect of coal cost on cost of gas with
both private and utility financing.
179
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Stockpiling of soils and subsoil may also result indirectly in "bulking," or __
an increase in volume, of the overburden, which means that, upon reclamation,
the fill would be less dense and subject to compaction and settling over time.
In addition, stockpiling of topsoil may result in lowered productivity of the
soil since the stockpile will become biologically sterile with time. Upon
reclamation, productivity cannot be restored until the area has been geolo-
gically reinoculated and the normal bacteriological and mycological popula-
tions have been restored.
Since wind and erosion are serious problems in the region and wind speeds may
average more than 10 mph, loosened silt, sand, and clay-size particles of
soil and subsoil will be moved and add to the loss of productive soil mate-
rial. In addition, surface runoff and consequent soil erosion and sedimen-
tation will result where soil permeability and infiltration are reduced by
compaction from mining activities. Also, alterations of stream beds and
watersheds will affect offsite erosion.
Groundwater—
Possible impacts on groundwater (depending on aquifer structure at the mine
site and the location of recharge area) are:
• Removal of existing shallow aquifers, or portions thereof,
and replacement by unstructured overburden or spoil
• Reversal of recharge/discharge relationships by interfering
with recharge areas and/or draining aquifers (dewatering)
during the mining operation
• Altering groundwater quality by changing the sources of chem-
icals in the water (rock and biosphere), changing hydraulic,
thermal, and chemical gradients; and by losses of precipita-
tion, ion exchange, sorption, and biosphere effects on the
groundwater
The effect, whether permanent or temporary, cannot be predicted without studies
of mine-site groundwater. However, while changes in groundwater availability
and quality are likely and will be adverse, their regional significance will
depend on present groundwater problems as a result of mining, regional depend-
ence on groundwater as a potable water supply, and future needs which might
require protection of all potential water supplies.
Surface Water—
Changes in topography will result in changes in drainage, possibly altering
the quantity and quality of water downstream of the mine. Strip mining and
overburden stockpiles near rivers or streams can result in erosion, increased
turbidity, and siltation. In addition, physical barriers to runoff, includ-
ing removal of streams and small watersheds, can affect river flows locally.
Uses of erosion control methods and reclamation of the mine site as mining
progresses (rather than long-term stockpiling) will reduce the long-term
significance of these effects.
180
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Air Quality—
Removal of vegetation and disruption of topsoil will contribute to increased
particulate emissions in the form of fugitive dust. The quantity in tons
per year will be proportional to the acreage mined per year (about 100 acres
of surface) and can contribute significantly to the particulate concentration
in the air.
Vegetation—
Approximately 100 acres per year of prairie species will be removed in the
course of mining. While this disturbance is not significant to the regional
ecology (which is predominantly grazing or agricultural land), two factors
could increase the significance of the impacts:
• This amall acreage, in addition to that disturbed by 12 to
15 other mines in the county, could significantly reduce
the amount of native vegetation in the region at any one
time
• The revegetation of prairie vegetation may be limited by
available x^ater, reduced soil productivity, and the cost
of fertilizers, resulting in the use of forage species
more tolerant to the new conditions
The net result could be a significant replacement of native species by forage
species which, in the long term, may not support the same animal species or
diversity and which may be less productive than native plants.
Wildlife—
Revegetated grasslands, particularly those specifically planted for grazing
use, do not support as diverse a wildlife population as native grasslands.
Populations of deer and antelope may not return after revegetation because
of changed plant species and topography. Species dependent on specialized
vegetation associations (sand hills, riparian or flood plain, cross timbers)
may be permanently lost if these vegetation types are removed. Waterfowl
may no longer visit marshy areas on or near the mine site because of changes
in topography and drainage patterns which may eliminate or reduce wetland
areas. All organisms associated with streams or livestock ponds will be
destroyed when mining activities excavate these areas.
In addition, the normal wildlife populations in the removed vegetation types
will be displaced or removed when the vegetation is removed. In both
instances, increases in mortality of local species will result.
Nearby populations will be available to repopulate revegetated habitat should
the area be able to support these animals. Some species, such as raptors,
may benefit, since more open grassy fields will likely support larger popu-
lations of prey species while grazing is prohibited. However, decades may
be required for restoration of habitat for species dependent on mature
woodlands.
Land Use—
Careful planning of mine-site reclamation keyed to simulate or even enhance
alternative land use (i.e., recreational plans, wildlife management, soil
181
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enhancement for agriculture, woodlot planting) may benefit future uses of
the area. Present uses of the land surface will be preempted during mining
and some uses may be restricted after revegetation:
• Overburden compaction and settling may restrict building on
the reclaimed site
• Reduced soil productivity may reduce the value of the area
to agriculture or grazing
• Present recreational uses (hunting) will be eliminated during
mining and may not be appropriate in the reclaimed areas
Aesthetics—
Contrasts in color (variations in soil color, exposed coal beds, and sub-
soils), land forms (open pits, service roads cut into hillsides, unshaped
stockpiles of overburden and topsoil), and texture (bare soil-vegetation) will
make the mine site aesthetically displeasing.
Social and Economic Effects—
The major socioeconomic impacts generated by strip mining include:
• Increases in population and employment associated with expanded
mining efforts
• Increases in regional and personal incomes as a result of
expansion of mine-related employment and the sale of coal
• Increased demand for goods and services proportional to pop-
ulation increases, but offset at least partially by increased
income
Most of the new employees probably will be hired from the local labor pool
(skilled and unskilled), but some population increase may also result. Net
socioeconomic impacts are likely to be beneficial.
Table 69 presents a summary of likely coal procurement impacts.
Plant Impacts
The coal gasification plant will be constructed over a five-year period, start
of engineering to construction completion, and will be operated for 20 years
before decommissioning. The peak construction work force will be about 3000.
More than 700 full-time employees will constitute the operating staff. Impacts
to the environment will result from plant construction and from plant opera-
tion. In this brief environmental assessment, emphasis is placed upon esti-
mation of plant operation impacts for a hypothetical site in the midwest.
Important construction impacts are noted in less detail.
The plant will produce 82.125 trillion Btu/yr of thermal power in the form
of clean fuel gas for offsite consumption. However, the plant will also
182
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TABLE 69. PROCUREMENT IMPACT SUMMARY
Environmental Factors
Coal Mining Impacts
Mitigating Measures
Topography
Soils and Geology
Groundwater
Quality
Surface Water
Air Quality
Minor changes in land form
after reclamation
Possible settling and com-
paction of reclaimed area;
reduced soil productivity;
consumption of nonrenew-
able resource (coal)
Possible interruption or
loss of aquifers (shallow)
and recharge areas as well
as related change in
groundwater quality
Alteration of drainage pat-
terns, flows; increased
erosion and siltation in
streams; losses of some
tributaries
Increased particulate emis-
sions-fugitive dust
Mine-site reclama-
tion to simulate
existing topography
Mine-site controls
on drainage;
reclamation to re-
store drainage
if possible
Vegetation and
Wildlife
Land Use
Aesthetics
Loss of native grasses and
associated animal species;
possible long-term reduc-
tion in plant and animal
diversity, production
Short-term commitment to
mining; potential long-
term reduction in produc-
tivity altered uses resulting
Sharp visual contrast but not
significant given surround-
ing land uses; short-term
Revegetation plans,
wildlife manage-
ment incorporated
into reclamation
of mine site
Reclamation of
mine site
Reclamation
(Continued)
183
-------
TABLE 69. (Continued)
Environmental Factors
Coal Mining Impacts
Mitigating Measures
Community Economy
Community- Population
and Services
Labor Availability
Potential for increased em-
ployment, personal and
regional income
Small population increase
possible with equivalent
increase in demand for
goods and services
Local labor pool adequate
Training programs
to be initiated
Transportation
Mine-site roads required -
no discernable effect;
local congestion may occur
on haul roads between mine
site and plant at times
consume resources that will not then be available for alternative uses.
Tables 70 and 71 summarize an estimate of principal resources consumed by
the plant. Resources consumed during plant construction will include fuel,
power, water, chemicals, plant construction materials, and manpower.
Physical/Chemical Emissions and Impacts—
The operating facility will be a source of air, water, and solid waste emis-
sions which will affect the environment around the plant. Emissions and
their general impacts have been estimated and are discussed in the following
subsections. The C. F. Braun report (5) is the primary source of process
information used in the assessment, with some assumptions made where little
or no information was available.
Air Emissions—The gasification plant will contain relatively few point emis-
sion sources. Table 72 presents estimates of pollutant discharges to the
atmosphere. Fugitive dust from coal handling represents one emission category
that is difficult to predict with confidence. It is anticipated that dust
control techniques such as telescopic chutes, enclosures of transfer points,
wet chemical suppression, and sealing of dead storage piles will be used to
control windblown dust losses in exposed transfer operations. The high wind
speed at the site would result in considerable windblown losses if such con-
trol techniques were not practiced. There are still likely to be substantial
releases of coal dust from coal handling and storage. Values in Table 72 are
very rough estimates. A substantial fraction of the suspended dust particles
will settle out within the plant boundaries and hence will contribute little
to offsite particulate matter ambient air concentrations.
184
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TABLE 70. PRINCIPAL RESOURCES COMMITTED TO PLANT OPERATION
Resource Category
Quantity
Normalized Quantity
(Output)*
Land
Feedstock Coal
Auxiliary Fuel (Vehicle)
Power
Water (1,925 gpm)
Catalyst and Chemicals
(Bechtel Estimate)
Manpower (Bechtel
Estimate-738 Employees)
440 acres
6.725 MM tons/yr
100,000 gal/yr
0
910.6 MM gal/yr
2,900 tons/yr
0.07 acre/MM Btu/hr**
163.8 Ib/MM Btu
134 Btu/MM Btu
0
11.1 gal/MM Btu
0.071 Ib/MM Btu.
1.56 MM manhours/yr 0.019 manhour/MM Btu
*Basis: 82.125 trillion Btu/yr HHV net output.
'-^Increases to 0.14 acre/MM Btu/hr if 440 acres buffer zone included.
TABLE 71. ESTIMATE OF ANNUAL HYGAS CHEMICAL REQUIREMENTS —
BECHTEL ESTIMATE
Material
Quantity
All Process Catalysts
All Process Solvents
Water Treatment Chemicals
Dust Suppression Agent
Diesel and Gasoline Fuels
400 tons/yr
500 tons/yr
2,000 tons/yr
5,000 gal/yr
100,000 gal/yr
185
-------
TABLE 72. SUMMARY OF ESTIMATED AIR EMISSIONS - HYGAS
Source
Flow Quantity
Pollutants
Emission Rate
Rail Car Dump
(wet suppression)
Coal Stackers
(wet suppression)
Coal Reclaimer
(wet suppression)
3,000 tph
24,000 tpd (6 days)
3,000 tph
24,000 tpd- (6 days)
853 tph
28,472 tpd
Dead Storage Pile, 1,230,000 tons,
60 days (sealed) 16 acres
Live Storage Pile.
14 days
(wet suppression)
Coal Preparation
Vent Gases
(after scrubber)
286,600 tons
8 acres
853 tph
48,000 CFM air
Acid Gas Removal 283,750 SCFM
C02 Vent Gases (2)
Sulfur Plant
Tailgas(l)
Dehydration
Vent Gas(2)
09 Plant
Nitrogen Vent
499,730 SCFM,
(includes 470,065
SCFM flue gases
from boilers - 2186
MM Btu/hr input)
164 SCFM
91,500 SCFM
Nitrogen
Fugitive coal
dust (0.05 Ib/tpd)
Fugitive coal
dust (0.05 Ib/tpd)
Fugitive coal
dust (0.05 Ib/tpd)
Fugitive coal dust
(0.01 Ib/ton/mo)
Fugitive coal dust
(0.1 Ib/ton/mo)
Fugitive coal dust
(0.05 gr/CF)
H2
CO
CH4
C2H6
H2S, COS
Potentially toxic
organics
1200 Ib/day
1200 Ib/day
1000 Ib/day
400 Ib./day
1000 Ib/day
165 Ib/day '
31.4 Ib/hr
759 Ib/hr
3220 Ib/hr
6240 Ib/hr
Small amounts
Trace amounts
Particulate matter
(99.5% reduction) 74 Ib/hr
SOX 1056 Ib/hr
NOX(0.2 Ib/MM Btu)* 437 Ib/hr
C0(0.02 Ib/MM Btu)* 44 Ib/hr
HC(0.01 Ib/MM Btu)* 22 Ib/hr
H2S, COS Small amounts
CH/
None
32 Ib/hr
(Continued)
186
-------
TABLE 72. (Continued)
Source
Flow Quantity
Pollutants
Emission Rate
Cooling Tower
Flare
917,200 SCFM dry air
404,766 Ib/hr water
vapor
Normally no process
emission, except for
pilot gas combustion
Misc. Process Areas
Plant Areas
Fuel Storage
Vehicle Exhausts
Drift(water droplets) 5,124 Ib/hr
Salts(2000 mg/1) 10 Ib/hr
Chemicals** 3.4 Ib/hr
Thermal 359 MM Btu/hr
Sulfur compounds
Hydrocarbons
small amounts
small amounts
Fugitive hydrocarbons small amounts
Fugitive dust small amounts
Hydrocarbons small amounts
Combustion products small amounts
^Assumed emission factors.
**Chemical additives in the circulating water include sulfuric acid, a proprie-
tary dispersant, a proprietary corrosion inhibitor and a biocide (shock
chlorination).
The coal preparation facilities (crushing) will employ a venturi scrubbing
system to remove coal dust from vent gases prior to release. Vent gas PM
concentration was estimated at 0.05 grain per cubic foot.
Substantial quantities of gaseous pollutants will be released from two process
sources, the C02 vent gas and the sulfur plant tail gas. Both will have a
fairly high volumetric flow. The carbon dioxide-rich vent gases from the
acid gas removal plants (two trains of Selexol) will contain approximately
600 ppmv of CO, 4470 ppmv of CH4, and 4670 ppmv of C2H5 along with small
amounts of reduced sulfur compounds (COS and H2S). Trace concentrations of
other hydrocarbons that may be classified as toxic or hazardous may also be
present. Potentially, the C02 vent gases may need further cleanup before
release.
The sulfur plant tail gas will contain approximately 12 tons per day of sul-
fur dioxide discharged to the atmosphere through a stack. More than 95 per-
cent of the sulfur present in the feed coal and more than 99.8 percent of
the feed sulfur to the sulfur plant will be captured, including S02 in the
boiler flue gases. The sulfur oxide concentration in the tail gas, as
designed, will exceed the federal NSPS for sulfur recovery units in the
Petroleum Refining point-source category. Some small amounts of reduced
sulfur compounds (COS and H2S) are also likely to be present in the tail
gas. Additional gas cleanup may be required for this stream, also.
187
-------
Vent gas from product gas dehydration (two trains) will be composed of water
vapor and about seven percent volume methane. The volumetric flows will be
small, so that this is a minor source of hydrocarbon release.
Other point sources in the HYGAS facility will release rather small amounts
of air pollutants. The cooling tower will discharge water vapor and heat.
(Air coolers dissipate most of the process heat load.) Drift from the tower
will contain salts and chemicals added to the circulating water. Organics
and ammonia in the circulating water will also be carried out as dissolved
constituents in the drift and perhaps as stripped vapors in the gaseous
exhaust.
Fugitive hydrocarbons will also be released as leakage from valves, pumps,
process vessels, and storage tanks. Plant areas will also be minor sources
of windblown fugitive dust emissions. Combustion products from plant vehicles
will probably be insignificant contributors to air pollution.
The HYGAS facility, as designed, would release hundred-ton-per-year quantities
of fugitive dust, SC>2, NC>2, CO, and hydrocarbons. Overall, these pollutant
releases at the hypothetical plant site would result in a small, adverse
effect on ambient air quality in the area. It is likely that emission off-
sets (N02, CO, nonmethane hydrocarbons) will be needed to avoid significant
deterioration as the site, is located in a nonattainment area for carbon
monoxide and photochemical oxidants.
Water Emissions—The conceptual plant, as designed (5,6), will not normally
discharge any aqueous process effluent. Principal discharge pathways will
be in water losses to the atmosphere and in water retained in the solid wastes.
Internal recycle of process and water treating wastewater will minimize the
plant makeup water demand (see Figure 24). Table 73 lists the plant's major
aqueous streams and their dispositions. The wastewater treatment and reuse
schemes described earlier indicate that most of the plant's waterborne con-
taminants will be routed to solids recovery and disposal. Estimates of pol-
lutant concentrations in the internal recycle streams were not attempted.
Streams that are treated and routed to the circulating water system or makeup
would be concentrated by the evaporation of water in the cooling tower. Any
trace organics, ammonia, dissolved solids, and perhaps hydrogen sulfide may
be present in appreciable concentrations in the cooling water. Fairly vola-
tile compounds such as ammonia, l^S, and some organics could be stripped
partially into the exhaust air. The contaminants in high TDS streams routed
to the flash evaporator will presumably be retained in the reject brine
slurry and go out as a solid waste.
If upsets were to occur in the complex recycling systems, some aqueous streams
might have to be routed temporarily to the storm basin, for later reprocessing
or for discharge to the river. There is, hence, a potential for pollutant
releases to the river.
Storm runoff from plant areas will constitute the only aqueous discharge from
the conversion plant, and discharge will occur on an intermittent basis. A
188
-------
TABLE 73. SUMMARY OF ESTIMATED WASTEWATER EMISSIONS - HYGAS
Source
Gasifer Ash
Slurry
Quench Flashed
Slurry
Stripped Quench
Condensate
Estimated Flow
647.8 gpm
(routed to solids
disposal)
38 . 4 gpm
(routed to solids
disposal)
1481.8 gpm
(used as C.T.
makeup )
Pollutants
Ash
TDS
Ash
TDS
BOD
NH3
H2S
PH
Emission Rate
No aqueous emission
No aqueous emission
No aqueous emission
Stripped Shift 1396.9 gpm
Condensate (used as coal slurry
(after biox treating) makeup)
Ammonia Recovery
Effluent
Methanation
Condensate
Lime Clarifier
Sludge
Filter
Backwash
Softener
Regenerant Waste
RO Filter
Backwash and Brine
169 gpm
(used as C.T.
makeup)
379.8 gpm
(used as BFW makeup)
38 gpm
(routed to
evaporator)
16 gpm
(routed to
evaporator)
64.6 gpm
(routed to
evaporator)
116 gpm
(routed to
evaporator)
BOD(117 mg/1) No aqueous emission
Phenols(72 mg/1)
NH3
H2S
BOD
NH
TSS
pH
TSS
TDS
TDS
TSS
pH
No aqueous emission
No aqueous emission
No aqueous emission
No aqueous emission
No aqueous emission
No aqueous emission
(Continued)
189
-------
TABLE 73. (Continued)
Source
Ion Exchange
Regenerant Wastes
(after
neutralization)
Boiler Slowdown
Cooling Tower
Slowdown
Sulfur Recovery
Slurry
Sanitary Effluent
(after treatment)
Utility Wastewater
(after settling)
Estimated Flow
47.7 gpm
(routed to
evaporator)
143.5 gpm
(used as C.T
makeup)
123 gpm
(routed to
evaporator)
4 . 4 gpm
(routed to solids
disposal)
35 gpm
(used for .dust
control and
landscaping)
200 gpm
(routed to lime
softener)
Pollutants
TDS
pH
TDS"
TSS
PH
TDS*
TSS
PH
TSS
NH
BOD
TSS
pH
Oil & Grease
TSS
PH
Emission Rate
No aqueous emission
No aqueous emission
No aqueous emission
No aqueous emission
No aqueous emission
No aqueous emission
Coal Yard Runoff
(after settling)
Plant Storm
Runoff
(after settling)
27 gpm avg annual,
intermittent flow-
formally routed
to biox unit)
118 gpm avg annual,
intermittent flow
Oil & Grease
(<10 mg/1)
TSS (<50 mg/1)
pH
Oil & Grease
(<10 mg/1)
TSS (<50 mg/1)
pH
<3 Ib/day
<16 Ib/day
6 to 9
<14 Ib/day
<70 Ib/day
6 to 9
*Includes chemical additives •
190
-------
storm runoff basin will collect and settle drainage before discharge. Col-
lected stormwater could also be used as plant makeup water, so that discharges
to the river would occur only during heavy storm periods when the impoundment
and workoff capacities were exceeded.
As designed (5), the live storage piles will be curbed with coal pile runoff
directed to a sump for routing to the biological oxidation system. Runoff
in excess of the sump pumping capacity and runoff from other areas including
dead storage in the coal yard would go to another storm settling basin from
which runoff would be discharged to the river.
The settled runoff (145 gpm average annual basis) will add some dissolved and
suspended pollutants to the river, resulting in a minor degradation of water
quality at times. Normally, with no aqueous, discharge from the plant, there
will be no impact on surface water quality. The average plant consumption of
about 1925 gpm (0.4 percent of average river flow) will normally have little
impact on downstream surface water availabilities, except during low river
flow periods. Groundwater could potentially be affected by percolation
through soils of pollutants from the storm basins or from the onsite solid
waste landfill. The plant will not consume groundwater supplies directly.
Overall, the plant will have little adverse impact on surface or groundwater
qualities.
Solid Wastes—Ash material from the feed coal will constitute the bulk of the
plant's solid waste production. Table 74 presents estimates of the major
solid wastes and their disposition. Dewatered ash streams and sludge from
the wastewater evaporator will be blended for transport back to the coal
source strip mine. Pollutant characteristics of the blended solid wastes
are not well known. It was assumed that burial in the strip mine would be
environmentally acceptable. There is a potential that the wastes will be
classified as hazardous and will require a more isolated disposal site.
If mine disposal were acceptable, waste burial under overburden at the mine
site would help to offset the volumetric loss resulting from coal removal.
On a tonnage basis (about 2390 tons per day), the net solid waste will be
about 11.7 percent of the tonnage of coal shipped from the mine.
Digested and dewatered sludge from biological oxidation will contain poten-
tially harmful organics (both dissolved and suspended). An onsite clay-lined
landfill will be provided to bury this material along with a small amount of
general plant trash and garbage. On the order of 58 to 60 acre-feet per year
of waste will be emplaced onsite. Proper management of the land disposal
operation will be needed to prevent contamination of groundwater and surface
runoff. Incineration of the sludge and combustible plant trash could be
considered as a method of reducing the volume of waste to be buried.
It is assumed that salvageable materials (scrap metals, spent oils, spent
catalysts) will be shipped offsite for recovery. Other waste materials
resulting from equipment cleaning or basin cleaning would likely be dewa-
tered and buried onsite.
191
-------
TABLE 74. SOLID WASTE DISPOSAL SUMMARY — HYGAS
Source
Estimated
Quantity
Potential Pollutants
Disposal
Gasifier Ash (After
Dewatering)
Quench Solids (After
Dewatering)
Boiler Flyash from
Sulfur Recovery
Bottom and Super-
heater Ash (After
Dewatering)
Evaporator Solids
(Blended with Ash)
Biox Waste Sludge
(Digested and
Dewatered)
Plant Trash and
Garbage
Miscellaneous:
Basin Cleanout
Sludges
Equipment Cleaning
Sludges
Spent Catalysts
and Chemicals
1,295.5 tpd solids
455.7 tpd water
50.4 tpd solids
12.6 tpd water
36 tpd solids
9 tpd water
180 tpd solids
48 tpd water
19.2 tpd solids
283.7 tpd water
34.8 tpd solids
199.2 tpd water
1,700 Ib/day
Infrequently
produced, no
quantities
estimated
Minerals, trace metals,
alkalinity, suspended
solids
Minerals, trace, metals,
organics, alkalinity,
suspended solids
Minerals, trace metals,
alkalinity, suspended
solids
Minerals, trace metals,
alkalinity, suspended
solids
Inorganic solids, organ-
ics, heavy metals,
suspended solids
Organics, NH3, suspended
solids (biological cell
matter)
Decomposable wastes and
oily materials
Blended with other wastes,
loaded into cars, shipped
to mine for disposal
Blended with other wastes,
loaded into cars, shipped
to mine for disposal
Blended with other wastes,
loaded into cars, shipped
to mine for disposal
Blended with other wastes,
loaded into cars, shipped
to mine for disposal
Blended with other wastes,
loaded into cars, shipped
to mine for disposal
Buried in onsite landfill
(clay-lined)
Buried in onsite landfill
(clay-lined)
Salvaged, or dewatered and
buried onsite
-------
Soils and Geology—Approximately 440 acres of land will be altered during
construction and operation of the plant. Earthwork will include clearing and
grading, cut-and-fill, and some excavation for basins and foundations. Addi-
tional offsite land will be affected by construction of rail spurs and access
roads, transmission facilities, gas connector pipeline, water pipeline, and
a discharge system. Solid waste will be burned at the mine site. Use of
new surface materials for roadways and foundations will alter the surface
characteristics of a portion of the site, but the undeveloped 440-acre buffer
zone will be less affected and the overall regional impact will not be
significant.
Biological Impacts—
Construction on 440 acres will affect primarily agricultural use. However,
some prairie vegetation and wildlife will be. removed or disturbed in fallow
fields, along fence rows and roadways, and in isolated grasslands not con-
verted to agriculture. Operation of the facility and increased traffic and
human use, as well as construction activity, will likely disturb sensitive
species nearby. However, careful site selection will ensure that no rare,
endangered or important species or critical habitats will be affected, and,
on a regional scale, this biological impact will be minor.
Secondary results related to construction will include damage to vegetation
from dust or from erosion. Runoff from construction areas may also increase
the sediment load in streams nearby, stressing sensitive aquatic biota. In
addition, stream beds, farm ponds, or other aquatic habitat may be eliminated
within the 440 acres by cut-and-fill activities.
The effect of SOX and NOX plant emissions on vegetation may be adverse down-
wind of the facility, particularly if the plume is forced to the ground- by
adverse meteorological conditions. In addition, salt from cooling-tower
drift may accumulate in the soil downwind and damage sensitive vegetation.
Disposal of storm runoff wastewater to the river may cause a minor degradation
in water quality which, in turn, could stress aquatic plants and animals in
the vicinity of the discharge and downstream from the discharge point. In
addition, the plant water intake and discharge system could entrain smaller
aquatic animals; intake screens will prevent entrainment of fish and other
large animals. No significant impact on river populations is expected from
either of these activities, however.
Aesthetic Impacts—
The HYGAS plant will contrast markedly with the surrounding environment. The
280-foot-tall hydrogasification vessels, tall stacks, live and dead coal stor-
age piles, rail yard, and coal handling facilities are not typical of the
rural, agricultural nature of the area. In addition, contrasts in color of
the coal piles against the surrounding countryside will serve to emphasize
the" differing nature of the facility. However, screening with trees, use of
a 440-acre buffer zone, and plant design and layout can be used to minimize
the visibility of the facility, reducing the impact in this farmland setting.
193
-------
Social and Economic Effects
A portion of the $1.2 billion capital investment will be spent locally for
equipment and materials. Labor and temporary jobs for about 3000 construc-
tion workers will be created. The increased regional income from these con-
struction monies as well as the salaries and wages of more than 700 full-time
employees will be a significant benefit to the economies of nearby towns.
This additional income may also partially offset the demands for community
goods and services caused by population increases in the region during
construction.
Manpower for construction may be available in the region or through training
programs, but temporary increases in population near the plant should be
expected. These population increases will result in a proportional increase
in demand for housing, schools, and other services which may be outside local
abilities to provide. Plant management and local government may work together
to provide planning, temporary housing, and services to reduce the impact of
this demand.
The plant will consume approximately 134 Btu of fuels for each million Btu
of gas produced, and coal feedstock at the rate of 127.4 Ib/MM Btu. No
purchased electricity will be consumed in gas production, although startup
and shutdowns may require a small commitment of power for lighting, venti-la-
tion, electric motors, and other machinery. Use of coal as feedstock does
constitute consumption of a nonrenewable resource and forecloses alternative
uses of that resource. The plant, however, will generate a clean fuel in
the form of synthetic gas, which offsets other consumptive uses.
Table 75 summarizes the principal environmental effects anticipated from con-
struction and operation of HYGAS.
194
-------
TABLE 75. SUMMARY ENVIRONMENTAL MATRIX - HYGAS
Environmental
Factors
Effect of Plant
Construction and Operation
Potential
Mitigating Measures
Climatology and
Meteorology
Air Quality
Surface Water
Availability
Surface Water
Quality
Groundwater
Availability
Groundwater
Quality
Land
Availability
Regional Ecology
and Critical
Habitat
Potential fogging from cooling
tower during periods of high
humidity — local
Fugitive dust-coal; HC, CO,
NOx, SOX emissions; salts from
cooling tower drift during
operation. Fugitive dust and
vehicle emissions during
construction
About 12 gal/MMSCF required
(or 11 gal/MM Btu) — no signi-
ficant effect on water supply
Releases of sediment during
construction as result of
erosion; releases of small
quantities of oil, grease, TSS
during operation — local
weather quality degradation
No consumption, no effect
Potential degradation from
leaching of coal piles, solid
waste landfill, waste ponds
880 acres of agricultural
land-insignificant regional
440 acres of vegetation,
wildlife — insignificant in
region
Line ponds, proper
management of land-
fills , pads under
coal piles
Care in siting to
prevent use of prime
land (for agricul-
ture) as site
Care in siting to
avoid critical lands,
rare or endangered
species, etc.
(Continued)
195
-------
TABLE 75. (Continued)
Environmental
Factors
Effect of Plant
Construction and Operation
Potential
Mitigating Measures
Aesthetic
Resources
Historical,
Archaeological
Resources
Community
Economy
Community
Population
and Services
Labor
Availability
Tall massive structures, color Landscaping, plant
contrast of coal with surround- layout and design,
ing soil and vegetation — buffer zone of
moderate local aesthetic impact 440 acres
No significant impact
Substantial benefit from
capital expenditures, wages,
tax base
Potential increase in demands,
population during construction
3000 construction and more than
700 permanent employees may be
available from regional labor
pool
Care in siting
Community — plant
coordination in
planning temporary
housing, services
Training programs
for unskilled labor
pool
Power
Availability
Transportation
Availability
No electricity consumption
planned under normal operating
conditions; power consumed
during construction
Build pipeline, rail spur,
access road
196
-------
SECTION 5
SCENARIO 3 -
WOOD AND COAL TO FUEL IN NORTHEAST REGION
In this scenario, a 2000 tpd wood liquefaction plant and a 25,000 tpd coal
liquefaction (H-Coal) plant are to be constructed and operated at different,
but similar, sites in the northeast region of the U.S. Figures 26 and 27
indicate the biomass and coal conversion regional locations. Separate re-
gional environmental settings and hypothetical plant site descriptions are
presented.
Plant feedstocks are assumed to be procured locally: forest residue from
mills and forestland and coal from deep mines. Both plants produce a heavy
fuel oil assumed to be suitable for firing in a steam electric generating
plant without the need for flue gas desulfurization. The costs for products
transported offsite (pipeline, truck, rail) are excluded. The wood-to-oil
plant purchases electric power. As in the Fluor commercial evaluation re-
port (7), the H-Coal plant has onsite power generation using process fuel
gas. The H-Coal conceptual design (7) assumes offsite landfill disposal of
solid wastes (conversion residues) for a contract disposal charge. An
aqueous waste disposal charge is also assumed in the cost estimate (7); how-
ever, additional onsite waste treatment would be a more realistic assumption
Principal environmental assumptions are:
• Proposed NSPS for steam-electric generating will apply
• Process fuel gas for combustion will have <_0.10 gr/dSCF
* BACT for aqueous effluents will apply
• Conversion residues are assumed to be nonhazardous
• Preconstruction and emission offset environmental costs
are excluded
• Product distribution costs and distribution impacts are
excluded
197
-------
Figure 26. Wood to fuel oil region — Scenario 3.
Figure 27. Coal to fuel oil region — Scenario 3.
198
-------
REGIONAL ENVIRONMENTAL SETTINGS
Biomass
The biomass conversion plant is-located at a hypothetical location in the
New England Region of the U.S. The following describes the environmental
setting of this region.
Land Use—
Approximately 77 percent of New England land is in forest. Only 31 percent of
land area is cultivated, of which less than a fourth is in crops. About one-
tenth of the region is urban, but this is increasing rapidly, especially in
the south. Extensive agriculture has given way to intensive farming such as
dairying, potatoes, tobacco, blueberries, and cranberries. Greenhouse and
open-field vegetables are grown near big towns and cities (16). Most of the
forest is in small holdings in farm woodlots. Lumber is the principal prod-
uct. The woodland is widely used for hunting and other recreation. Christmas
trees and maple syrup are other important products.
Topography and Elevation—
Topographically the region has four major divisions: mountains, upland pla-
teau, lowland plain, and ridge and valley. Much of the area is between sea
level and 1000 feet. Low hills up to 2000 feet are common but a few peaks
of around 3000 feet do occur. The northeastern mountains have a few isolated
peaks of more than 5000-feet. The till-mantled rolling to hilly uplands are in-
terrupted by many level-to-gently-sloping valleys that slope toward the coastal
lowlands. The relief is mostly in a few feet to a few tens of feet in the
valleys and in several tens of feet to a few hundred feet in the uplands.
Climate—
New England receives rainfall which is well distributed and makes possible the
production of crops suited to temperate regions. The annual rainfall varies
from 50 inches in southern New England to less than 32 inches in the extreme
north. Prevailing temperatures vary between 67 F average in summer and a win-
ter average of 20 to 30 F. The average growing season varies from 100 to
125 days in the extreme north to some 200 days in the southern part (13, 14,
16, 36).
Soils—
Spodisols dominate the New England soils, but Inceptisols and Alfisols are
found in the western portion of the area. The Spodisols have a low supply of
bases and a horizon in which organic matter and iron and aluminum compounds
have accumulated (16).
Vegetation—
Many kinds of forest vegetation are found in New England. In the north the
most important commercial forests are of spruce (Picea spp. ) and the balsam
fir (Abies balscanea) — the spruce-fir ecosystem. Other associates include
northern white-cedar (Cedrus spp.), tamarack (Larix laricina), maple (Acer
SPP- )j birch (Betula spp.)., eastern hemlock (Tsuga canadensis), and eastern
white pine (Pinus spp.) (14).
199
-------
The northern hardwoods, or maple-birch-beech ecosystem, typically occur on
open high hills and low mountains on ridges rising 500 to 3000 feet above the
broad valleys. Common associates of the ecosystem include hemlock, elm (Ulmus
spp.), basswood (Tilia spp.), and white pine (14).
Wildlife—
The fauna of the spruce-fir ecosystem include moose, woodland caribou, lynx,
marten, black bear, long-tailed weasel, mice, and shrews. The ruffed grouse
is common and the wild turkey occurs to the south of the area. The eastern
timber wolf is an endangered species resident in this forest type (16).
The white-tailed deer occurs throughout the northern hardwoods ecosystem,
utilizing the farmed areas for food. The black bear is also common and the
red and grey foxes are also widespread. Several species of squirrel and mice
are found in this ecosystem. Common birds include the ruffed grouse, the bob-
white, and several songbirds.
H-Coal
The H-Coal conversion plant is located at a hypothetical location in the
eastern region of the U-. S. The following describes the environmental setting
of this region.
Land Use—
The area is located in the east and central general farming and forest region,
the central feed grains and livestock region, the northeastern forage and
forest region, and the Atlantic and Gulf Coast lowland forest and truck crop
region of the U.S. The major land use is cropland, with interspersed patches
of forest, woodland, and pasture. The eastern (coastal) portion of the area
is heavily urbanized; the more undeveloped areas are found primarily at the
higher elevations of the Appalachian Mountains (22).
Topography and Elevation—
Elevation ranges from sea level to 5000 feet above sea level, with the higher
elevations being located in the Appalachian, or Eastern, Highlands. The coastal
plains dominate the eastern part of the area while the open hills and low moun-
tains dominate the west. The majority of the land is gently sloping, with
local relief ranging from 0 to 100 feet in the plains and 1000 to 3000 feet
in the hills.
Climate—
The eastern area receives between 32 and 64 inches a year of precipitation; the
highest rainfall coincides with the areas of higher elevation, but, in general,
the rainfall is evenly distributed throughout the region. Prevailing tempera-
tures range from a summer average of 80°F to a winter average of 35°F. Cooler
temperatures prevail in the highlands. The average growing season varies from
120 to 150 days per year (22).
200
-------
Soils—
The major soils in the eastern region are Ultisols, Inceptisols and Alfisols,
but the soil associations vary widely. Some have subsurface horizons of accu-
mulated clays and salts but are typically low in bases (16).
Vegetation—
The dominant ecosystem types are Appalachian oak, northern hardwoods, and oak-
hickory-pine forests. Higher elevations in the Appalachians may support a
northeastern spruce-fir forest, and river drainages near the coast are typi-
cally southern floodplain forest. The most important tree species are:
• White oak (Quepcus alba) and northern red oak (Quercus)
in Appalachian oak forests, with maples (Acer spp.)s birch
(Betula lenta)3 hickories (Carya spp.), beech (Fagus
grandifolia)., and the tulip tree (Li,in,odendron tulipifera)
well represented
• Sugar maple (Ace? saccharim) j yellow birch (Betula alle-
gheniensi-s)_, beech and hemlock (Tsuga canadensis) in
northern hardwoods, with pines also represented
• Hickory, shortleaf pine (Pinus echinata), loblolly pine
(P. taeda),white oak (Q. stellata) in oak-hickory-pine
forests
Wildlife--
Dense, mixed forests support deer, small mammals (raccoon, squirrel, chipmunk,
mice, and voles), small birds (titmouse; bluejay; redbellied, hairy, and
downy woodpeckers), hawks, and owls. Typical forest reptiles (garter snake,
black racer, timber rattlesnake, box turle) may also occur (37). Other impor-
tant species include black bear, bobcat, grey fox, grouse, bobwhite, mourning
dove, and turkey (16) .
WOOD-TO-OIL PLANT SITE DESCRIPTION
The biomass conversion plant is located in a hypothetical forested rural area
in the Eastern Uplands approximately one-half mile east of a major river in
the region.
Topography and Elevation
Rolling hills rise to about 700 feet in elevation in the vicinity. The plant
site is on a gently sloping terrain above the flood plain at about 400 feet in
elevation and about 100 feet above the normal river water level.
Transportation
A state highway and a common carrier.rail line each pass within one mile of the
plant site. Another state highway across the river to the west is about two
miles from the plant. Several small towns are nearby, located on either side
of the river. The nearest city (about 42,500 population) is about 10 miles
downstream and has additional road and rail transportation.
201
-------
Climate and Air Quality —
The climate in the site area is cool and humid, characterized by long cold
winters and short cool to warm summers, moderated by the Atlantic Ocean.
Great variations in seasonal and diurnal temperatures are a common phenomenon.
Rainfall is ample (43 inches, including the water equivalent of snow) and is
evenly distributed. The sky is cloudy about half the time and partly cloudy
16 percent of the time. Relative humidity ranges from 71 percent in March to
79 in November with a yearly average of 75. The prevailing winds are north-
westerly or northeasterly in winter and southwesterly in summer. Hurricanes
or damaging rains are rare.
The average length of the freeze-free season ranges from approximately 130 days
in the north part of the county to 170 days in the more protected areas.
The number of thunderstorms varies from year to year. An average of 15 to 20
may be expected annually from May through August. Most of them are not damag-
ing to crops. Generally, hailstones fall only about once or twice a year,
usually in spring or summer thunderstorms. Heavy rains accompanying the more
severe thunderstorms sometimes injure crops and erode soils (38). Table 76
shows assumed climatic data at the site.
TABLE 76. ASSUMED CLIMATIC CONDITIONS AT THE SITE
Elevation = 400 feet p = 29.5 Hga
Temperature:
Annual Average 44°F dry bulb
40°F wet bulb
5-Percent Design 83°F dry bulb
Conditions _ o
70 F wet bulb
Annual (daily) Extremes -20°F to 95°F
Prevailing Wind: Eastsoutheast at three mph
Precipitation:
Annual Precipitation 43 inches
Annual Runoff 25 inches
Annual Lake Evaporation 23 inches
10-yr, 24-hr Duration Storm 4.5 inches
Annual Freeze Free Period: 150 days
202
-------
Air quality in the vicinity of the plant is generally good; however, the air
quality region is currently listed as a nonattainment area for photochemical
oxidants.
Land Use
The site is primarily used as forestland in private ownership. A small portion
near the river is currently in use as pastureland.
Water Resources
River flow at the plant averages 6104 cfs with a minimum annual (daily) dis-
charge of 2100 cfs. Water quality is very good; both dissolved solids and
hardness levels are low (see Table 77). The mean annual temperature of the
river water is 50 F with a 32 F to 75 F daily annual average. All of the
plant's water makeup will be supplied by the river.
Soils
Soils of New England have developed in a cool humid climate under forest. The
major soil groups are classified as gently sloping Haplorthods and Fragiothods
(Order Spodosol, suborder Orthods), Haplaquepts (Order Inceptisols, suborder
Aquepts), and Planosols (27).
The subject soils range from well or excessively drained to very poorly drained.
In general, better drained soils are on the higher lands and poorly drained
soils on lower slopes or in depressions. Soils on glacial till often are hilly
and have complex slopes; those from granitic till usually are extremely stony,
acid, and sandy. The soils are generally shallow in steeply sloping areas and
are in forest. Erosion is not a serious problem since 70 percent of the area
is forested.
Vegetation
Two-thirds of the land in the vicinity of the plant is woodland. Timberland
is the most important resource in the area. The bulk of the wood is used by
the pulp and paper industry, which is well established in the area.
Mixed hardwoods, sugar maple, red maple, beech, and ash are prevalent in the
site area, particularly on the well-drained till soils and the associated up-
land soils. The stands are interspersed with hemlock, white birch, and white
pine. White pine occurs as pure stands on farmland that has reverted to forest.
It also grows well on sandy and gravelly soils in the river valley where compe-
tition from hardwoods is less severe. Hemlock maintains itself among hardwoods
and in areas never cleared for farming. White birch is also important, parti-
cularly in areas once clear cut or on burnt-over land.
Wildlife
The site area is rich in wildlife. Woodland species include ruffed grouse, wood-
cock, thrush, vireo, scarlet tanager, gray squirrel, red squirrel, white-tailed
deer, raccoon, snowshoe hare, and other kinds of birds and mammals. Wetland
203
-------
TABLE 77. ASSUMED RIVER WATER QUALITY AT THE SITE - AVERAGE
Component Value
Flow, Average Discharge 6,104 cfs
Flow, Minimum Annual 2,100 cfs
PH 6.7
Temperature 50 F
Dissolved Oxygen H mg/l
Alkalinity (as CaC03) 13 mg/l
Bicarbonate Alkalinity (as HC03) 16 mg/l
Carbonate Alkalinity (as CCO 0 mg/l
Calcium and Magnesium Hardness 19 mg/l
Noncarbonate Hardness 6 mg/l
Total Dissolved Solids 48 mg/l
Calcium 5.8 mg/l
Magnesium 0.9 mg/l
Sodium 7.5 mg/l
Potassium 0.9 mg/l
Chloride 9.6 mg/l
Sulfate 8.5 mg/l
Fluoride 0.2 mg/l
Silica 4.9 mg/l
Phosphorus 0.04 mg/l
Nitrate 0.21 mg/l
Nitrite 0.01 mg/l
Iron, Total 0.53 mg/l
Manganese 0.04 mg/l
204
-------
wildlife includes black duck, wood duck, rail, heron, shore birds, mink, musk-
rat, beaver, and other kinds of birds normally living in ponds, swamps, and
marshes (38, 39). A large herd of moose is found in the northwestern part of
the county. Moose are protected animals.
FOREST RESIDUE PROCUREMENT
Approximately 650,000 tons (wet) per year of wood chips and bark would be con-
sumed by the wood-to-oil conversion plant. On the order of 360,000 tons (dry)
per year of logging and collected forestry waste are located within 32 mean
transport miles of a power plant about 20 miles south of the conversion plant
(18). About 900,000 (dry) tons per year are available in nine counties sur-
rounding the conversion plant. Annual consumption would be about 40 percent
of the waste reportedly available in the nine-county area. In this scenario,
the conversion plant owner purchases wood waste delivered to the plant site.
Mean transport distance is assumed to be 45 miles.
Most of the feedstock is purchased on a contract basis from independent pro-
ducers and pulpwood dealers who harvest forestland, mainly in private owner-
ship. Forest residues are collected and chipped on site by special crews
either concurrent with conventional harvesting or during a later pass through
the tract. The crews employ chain saws for cutting and stripping (in some cases
stump-pullers for stump and root extraction) and dozer-tractors for movement
of the waste to mobile wood chippers. Hand collection of smaller branches is
also common. Chipped waste is blown into trailer trucks on the logging roads
to the highway and thence directly to the plant or to concentration yards in
the area.
The chipped residue is transloaded to rail hopper cars and large trailer trucks
for shipment to the plant. Residue harvesting is somewhat seasonable with
lower production in the winter and spring quarters of the year. The yarding
operations provide surge storage to somewhat level the deliveries to the con-
version plant over the year.
In this forestland area, the total biomass inventory is on the order of 100
(over dry) metric tons per hectare (44.6 tons/acre) of which some 40 to 45 per-
cent may be classified as possible forest residue. Annual growth (whole tree)
is about 3 MT/ha (1.3 tons/acre). At a minimum, some 20,600 acres of forest-
land would need to be completely harvested for residue each year.
WOOD-TO-OIL PROCESS DESCRIPTION
Summary
The wood-to-oil process design is based on the Pittsburgh Energy Research Cen-
ter (PERC) conversion process now under development at the Biomass Liquefaction
Experimental Facility in Albany, Oregon. In this scenario, the commercial plant
converts about 2000 tons (1965 tons) per day of wood waste into about 1764 bar-
rels per day of heavy fuel oil. A private company is assumed to be the owner
and operator of this facility, which has a 20-year plant life. Wood chips and
bark are purchased (at dollars per ton delivered) by the owner on a contract
basis from loggers and mills in the region. One thousand tons per day of wood
205
-------
is used directly in the conversion process. Most of the remainder is used to
generate gas (CO) for the wood-to-oil reduction reaction. A small amount is
used to generate process steam. The heavy fuel oil product is shipped from
the plant in heated tank trucks for use as a supplemental clean fuel by local
utilities. Overall direct thermal efficiency is about 53 percent. The plant's
boundaries are indicated by the fenced area in Figure 28.
The process description is divided into six sections — feedstock receiving and
storage, feed preparation, reaction, product separation, syngas production,
and auxiliaries. (See Figures 29 through 32). Two parallel (50 percent capac-
ity) processing trains are provided for wood conversion and syngas production.
Design Basis
The wood-to-oil plant is based on-a modification of the PERC process. Many
parts of this conceptual design have not been demonstrated. Major design bases
and assumptions made to define the process are summarized in Tables 78 and 79.
Feedstock Receiving and Storage
Wood chips and bark are shipped to the plant in rail hopper cars and in end-
dump trailer trucks. A single 18,000-cubic-foot underground hopper dump re-
ceives chips from both hopper cars and trailer trucks. Rail^cars and trucks
are unloaded six days per week — an average of 2300 tons per day.
Bottom-dump hopper cars are unloaded automatically while being pulled across
the rail hopper dump. Rail siding is available for full and empty cars. Truck
trailers are raised and tilted by hydraulic platforms which allow the chips
to flow into the hopper pit. The wood chip truck circuit in the plant is one-
way with the trailers being weighed (gross and tare) at the plant gate (see
Figure 29).
The dump hopper conveyor transfers chips onto a high-speed belt conveyor which
delivers them to twin 10,000-cubic-foot surge bins. Chips from the bins are
pneumatically conveyed to the outside chip storage pile through pipes lying on
the surface of the pile. Conveyor capacity is 125 tons per hour each. The
transfer pipes are moved periodically to build up depleted areas of the pile.
Normally a 60-day feedstock supply is maintained (120,000 tons, or 12 MM cubic
feet). At an average of 30 feet, the base of the pile covers 9 to 10 acres of
land. The stockpile is worked down somewhat during the winter months when
logging operations are curtailed. An underpile reclaim system pulls chips from
the pile bottom along its long axis, providing a fairly uniform feed (composite)
Auger conveyors, mounted on carriages, draw chips from the pile and discharge
them onto two belt conveyors in an underground tunnel in the long axis. The
two belt conveyors move the chips to the center of the tunnel where the chips
are transferred to two parallel inclined belt conveyors. The inclined con-
veyors emerge from a tunnel beyond the base of the pile and terminate at the
top of the transfer house. Each 30 inch-wide belt conveyor can supply 100 tons
per hour of chips to the feed distribution system. The transfer house contains
magnetic separators (tramp iron removal) and a series of transfer bins with
206
-------
Figure 28. Wood to oil plant, general arrangement.
-------
ho
O
00
P PLATFORMS**!
5OTON CAP
Q D C\\ IP S T Q Q, A Ci C
^0,000 lONt (fcfl- D^
12- MtUlON (.y FT
WOOD CHjP TR*.NS F
Figure 29, Wood chip receiving and storage section
(wood to oil).
-------
B*.* 6INS(<)
HQOC {2-'»<40'
DRVtR/GRIHDEF
i- H.P. FLUH SUR6»-
RtfcCTOR/FURMAC^S (^t PRUHS(t.> DRL»AS(7.)
\J'« * 60' 5«tUL bV»l*' 6'»
<
^
1
20O6PM
r
RCCYCLC. OIL.
£=*
SOIVCK1T VTORAGC
CQMBUSTQRSfc) 5,OOQ G*
10 MW8TU7HR 2ZHH>
jOLVfcNT
SURGE,
TA-NK^(Z)
30,OOQ&fcL
^t.
LCl
Jo <»
Figure 30. Wood to oil process flow diagram — preparation,
reaction, and product recovery.
-------
S-*WGM Ftc.0
jT^.ia*\ j r ^«.u ^ ,
CQMpaKtiOH^ai \ r~
lloo<:rM.3-sr6 \f— '
JOCK) UP Q
Figure 31. Wood to oil process flow diagram— syngas
production and catalyst recovery.
-------
PR155URL , PSU
TEMPERATURE ,»F
HI , M LB/HH
H,0,
Mi,
CO,
CO,,
OIL, '
50LVENT, •
WOOOfC>H,Oili '
IN6RTS INjiASH),
NdiCOj,
TOTAL (i-TRMW)tN».^Hl$
l. U-TRMN5) "
" TPP
<>
14.5
GO
18.150
-
-
-
J2.6I9
O.Z9S
-
41.661
83.333
1000.0
<£>
14.1
200
-
2 .5*6
-
-
-
-
22.6H
0.298
25-443
50.886
610.6
<3>
2500
400
-
2. 546
-
-
fcO.22!
26.901
(.•US
1.312
92.513
2220.5
<*>
3500
100
-
1 .402
~
-
-
-
0.350
1 .152
3.i01
42.0
<£>
0 OR
4000
420
0.826
0.026
15.055
O.IZ.5
-
16.032
32 064
384.8
<&>
600
650
0.926
3 914
4.292
11.036
15.610
5.381
1 .465
1 . 122
110.106
220.612
1641.1
50
515
-
-
15.311
-
l.0»4
0.298
0.350
34.238
410.9
10
100
-
-
-
~
31 .194
-
-
31.194
161. 1
I 50
-
-
-
-
15.311
11.131
-
0-058
0. SSO
41.516'
95.032
1140.4
50
1 10
-
1 .402
-
~
15.511
-
0.058
0.350
n.iai
J4.314
4C2.5
<$>
30
180
trace
-
-
-
15. in
-
-
0.056
trace
15.135
10.810
310.4
<§>
180
-
1 .402
"
-
-
0 .350
3 .504
42.0
<3>
15
160
-
-
"
-
0.021
1 .094
0.360
-
1.415
2.950
35.4
30
60
-
0.063
-
-
0. 121
1.5
<£>
45
HO
-
50.JOO
-
-
-
1 00.000
1200.0
^^atSCRlPT.ON
COMPQNEtsiT -*^
PRESSURE , RSI's
Nj , M L6/HR
Na »
CO ,
Oil
C01}
OIL ,
SOLVENT ,
WOODlC.WyOj), "
NijCOj,
(2 -TRAINS) I
u TPD
5CBU6B"
14.7
0.926
.,.292
IT.OJ6
tr^ct
-
46.t10
560.0
14.8
Si.btJ
-
n . 5 is
28.414
~
156.619
313.256
nsa.8
OR-r/6HI~o
141
65.066
-
I!.I86
19. 140
-
-
115.023
230.046
2160.1
14.1
41.351
-
0.869
14.366
-
-
19.018
158.036
1896. +
14.1
-
31.036
5.612
9.413
-
62.605
125.210
1502.5
D.Lo-nou
14.1
15.410
2 .697
4 .693
-
-
il.20l
62.102
148.8
14.5
-
-
-
-
-
I9.&03
36.011
12.155
465.9
t>5
1
-
14.424
-
-
-
-
14.424
28.S-I5
346.2
14.1
0 .dil
-
15 .061
-
14.655
0.119
52.151
105.503
1 266.0
45
-
-
-
100.000
200.000
2400.0
200
o.sn
15.061
-
14.655
-
-
-
-
il.ltt
62.446
149.4
14.5
0.001
0.012
-
14.530
-
-
I5.90«
3I.8I«
581. «
14. S
-
-
-
1 .200
2 .400
28.8
14.5
-
-
-
-
-
O.Olt
0 .014
0 .\49
i.a
OILY BD
14.5
J . 1ZO
0 .040
-
0.074
Figure 32. Wood to oil plant material balance.
-------
TABLE 78. DESIGN FEEDSTOCK COMPOSITION
Composition
Hydrogen, % wf
Carbon, % wt
Sulfur, % wt
Nitrogen, % wt
Oxygen, % wt
Ash, % wt
Moisture, % wt
HHV, Btu/lb
Green Density, Ib/cu ft
Bulk' Density (Chips), Ib/cu ft
Moisture Free
6.2
51.8 '
Trace
0.1
40.7
1.2
-
100.0
9,050
As Received
3.41
28.49
Trace
0.055
22.385
0.66
45.00
100.00
4,977
42
20
*Assumed 80% pine, 20% spruce bark.
212
-------
TABLE 79. PLANT DESIGN BASIS AND ASSUMPTIONS
Nominal 2000 tons per day based on forest
residue availability at a hypothetical site
in New England
90% or 330 operating days per year
20 years
Private company
Supplemental fuel oil for local utilities
Nominal 6-days-a-week truck and rail shipment -
2000 cu ft end dump trailers, 4000 to 7000 cu ft
chip hopper cars; truck/rail mix about 40:60 on
tonnage basis
Nominal 60-day feedstock supply capacity -
120,000 tons at 20 Ib per" cu ft bulk density
200 tons per hour or 240% of design feed rate
2-parallel trains at 500 tons per day design
rate, 600 tons per day maximum
Wood Chip Drying/Grinding Dried to 10% moisture with 900 F (inlet) hot gas
Plant Capacity
Plant Stream Factor
Plant Operating Life
Plant Ownership
Product Utilization
Wood Chips Receiving
Wood Chip Storage Pile
Wood Chip Reclaim Capacity
Wood Chip Conversion
Wood-to-Oil Reaction
Stoichiometry (Assumed)
and ground to minus 50 mesh (90%+)
Basis 0.5 Ib CO consumed/lb wood converted —
"wood
C6H3.
57°3.544
650°F
2500 psia
carbon monoxide
2.453 CO
"oil"
IT n r.
8.57 1.091
carbon dioxide
2.453 C00
Reactor Conversion
Reactor
Reactor Product Gas/
Liquid Separation
Reactor Heating
80% conversion per pass, 95% overall conversion
at 4:1 recycle (370.4 tons per day total con-
version)
Helical coil in an indirectly-fired heater
followed by vertical soaking vessel, 30 min.
residence time
Two-stage flash system
Hot gas from combustion of flash gas
(Continued)
213
-------
TABLE 79. (Continued)
Product/Wood Separation
Solvent Recovery
Solvent Losses (Assumed)
Catalyst Removal
Product Oil Properties
(Assumed)
Product Oil Storage
Syngas Production
Wood-to-Carbon Monoxide
Reaction Stoichiometry
(Assumed)
Oxygen Requirements
Syngas Cleanup
Acid Gas Removal
Catalyst Recovery (Assumed)
Process Wastewater
Treatment
Process Steam
Electric Power
Solid Waste Disposal
2:1 solvent to oil dilution, vacuum filtration at
0.1 gprn/scj ft of filter area
Vacuum distillation, thermosiphon reboiler (steam)
0.2% of solvent circulation (1.5 tons per day)
Water extraction from product oil
15,000 Btu/lb HHV, 10 Ib/gal bulk density,
nitrogen-trace, sulfur-trace, ash- 0.5% wt,
carbon-73.05%', hydrogen 8.75%, oxygen-17.7%
100,000 gal of heated tankage (30 hours capacity)
-n
Two parallel trains with 4 PUROX converters
(2 spares) , 433 tons per day wood feed to each
train
C6H8.57°3.544
35'19502 3000°F.
42CO + 26CO + 32H + 16.55H20
0.7234 Ib 0,.,/lb wood converted, 346 tons per day
0- supplied by a high purity oxygen plant
(cryogenic air separation)
3 stages of water scrubbing
Benfield hot carbonate process, 1281 moles/hr
(dry) design feed rate to each train, 3000 ppmv
CO slippage, capacity is 120% of design rate
Water extraction from syngas converter slag;
makeup - 4.4% of catalyst feed (1.8 tons/day)
Anerobic digestion followed by activated sludge
Onsite generation
Purchased
Onsite landfill
214
-------
bottom-mounted vibrating feeders. Each bin compartment and feeder serves an
inclined belt conveyor that supplies chips to a processing unit. Conveyor ca-
pacities are 150 percent of design flow.
Wood Preparation
Five hundred tons per day of raw wood chips are processed in each wood prepara-
tion train. Wood preparation consists of drying (to 10 percent moisture) and
grinding (to minus 50 mesh), then blending the ground wood with recycle oil
from the reaction section to provide a wood/oil slurry feed to the reactor.
Each train has dryer/grinder units. Wood chips from twin surge bins are fed by
screw conveyors into the twin dryer/grinders. Hot gas (900 F) from the reactor
heater is introduced to each unit to dry the chips to 10 percent moisture con-
tent as they are being ground. The ground wood particles are carried by the
gas through the air classifier section, which permits passage of minus 50 mesh
material to a cyclone separator (one for two grinders). Plus 50 mesh particles
drop back into the grinding section. The cyclone product is discharged through
a rotary valve into the wood flour surge bin mounted above the wood/oil blend
tank. Cyclone exit gas passes through a baghouse (fabric filter collector)
which collects, as product, the fine wood dust escaping the cyclone. Part of
the baghouse exhaust gas is recycled to the dryer/grinder inlet hot gas ducts.
A portion is released to the atmosphere through the vent on the dryer/grinder
building roof. Part is also ducted to the reactor heater as dilution (cooling)
gas.
From the surge bin, wood flour is metered continuously (12.7 tons per hour de-
sign rate) to a feed hopper on the wood/oil blend tank. Wood flour is slurried
to a 30-percent concentration with hot recycle oil in a 20,000-gallon agitated
tank. Each wood/oil slurry feed pump supplies about 46 tons per hour (about
170 gpm) of slurry at 400 F and 3500 psi to its respective conversion reactor.
Reactor (Conversion) Section
Each reaction train converts about 305 tons of wood flour into 880 barrels per
day (185 tons per day) of oil. Conversion is about 80 percent per pass and
95 percent overall. Catalyst solution, 20 percent sodium carbonate in water,
and compressed CO/H reducing gas are injected into the slurry upstream of the
reactor. The resultant gas/liquid/solid mixture is charged to the two-part
reactor system.
The first part of the reactor consists of a single helical coil (about 2200 feet
of three-inch diameter, schedule 160 pipe) mounted vertically in a cylindrical
brick-lined furnace (12 feet in diameter by 50 feet high). The second part is
a four-foot diameter by 50-foot high vertical pressure vessel. The reactor feed
mixture is heated to 650 F and 2500 psia, which provides about 20 minutes hold-
up time for additional conversion.
Gas/liquid separation takes place in a two-stage flash system at liquid end con-
ditions of 515 F and about 50 psia. Flash gases (mainly CO , unreacted CO,
water vapors and light hydrocarbons) pass through a surge (knockout) drum and
into a three-stage water scrubbing system. The scrubbing system cools the gas
215
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(to 100°F), condensing water, and hydrocarbons, and removes particulate matter.
Hot flash gas enters a spray tower where the gases are water-quenched before
entering a venturi for further particulate scrubbing. The entrained water drop-
lets are coalesced and separated in a nonreversing cyclone having a flooded mesh
demister section. A surge drum is provided to dampen pressure fluctuations in
the cleaned flash gas stream.
Any condensed hydrocarbons are recovered from the scrubbing water in an oil/
water phase separation vessel. Hydrocarbons are pumped to product recovery and
most of the water is recycled. Water condensed from the gas stream yields a net
water input; so a continuous purge is required (to waste treatment).
Scrubbed flash gas (about 168 Btu/SCF) is burned with excess air in a combustion
box to provide the hot gases for heating the reactor coil. The combustion prod-
ucts at 1800°F are cooled to about 1500°F by commingling a dryer/grinder vent
gas stream prior to entering the reactor furnace. This tempering of the gas
limits the coil wall temperature, which helps to minimize fouling of the reac-
tor tube (inside) walls. About half of the furnace tail gas (35,000 SCFM at
1200 F) is used to generate process steam in a waste heat boiler. The remain-
der is used for drying in the wood preparation section.
The reactor liquid product from the low-pressure flash tank contains unreacted
wood, ash, and catalyst. About 80 percent is recycled to the wood/oil blend
tank. The remaining 20 percent (205 tons per day from each train) of the raw
product oil is pumped to the product separation section.
Product Separation
Two trains of product separation are used to recover a total of 370 tons per
day of heavy product oil.
Hot raw oil is pumped to a venturi nozzle inlet to a flash cooling tank. Sol-
vent (xylene) is injected into the venturi section, mixing with the oil and
cooling it to about 250 F by vaporization of the solvent. Solvent vapor is con-
densed in the flash tank overhead system and recovered. The cooled oil stream
is further diluted with solvent and pumped to an agitated surge tank. A 2:1
solvent-to-oil ratio is employed to reduce the oil viscosity for the subsequent
filtration step.
The diluted oil stream is fed to one of two precoat rotary vacuum drum filters
where undissolved wood and inert solids are filtered out. The 10-foot diameter
by 16-foot long filters are enclosed and nitrogen blanketed. The filters al-
ternate on a nominal 12-hour cycle. One is in operation while the other is
cleaned, precoated with diatomaceous earth, and put in standby position. Fil-
ter cake solids are steam-stripped of solvent in a countercurrent steam heated
screw conveyor. The dried solids (wood, ash, and filter aid) are collected and
transferred to the syngas furnaces for residual energy recovery. The stripped
solvent and steam are condensed and phase-separated. Solvent is recycled and
the water is sent to wastewater treatment.
The solids-free oil/solvent stream is pumped to a vacuum stripping column
(eight-foot diameter x 25 trays) where the solvent is stripped, condensed in
216
-------
the overhead system, and recycled to a solvent surge tank. A thermosiphon
reboiler heated with 250 psi, 500 F superheated steam provides stripping vapor.
The solvent-free column bottoms stream is water-washed to extract the sodium
carbonate catalyst. The oil/water mixture passes through an electrostatic
coalescer and into a phase-separation tank. The catalyst-bearing water phase
is pumped to the syngas furnace for catalyst processing. Warm product oil
(26 gpm) is pumped through steam-traced lines to 25,000-gallon heated storage
tanks.
The product tankage provides 30 hours of product storage capacity. Product oil
is loaded daily into 5000-gallon heated tank trucks for transport to local
utilities which fire the supplemental fuel in steam-generating stations.
Syngas Production
The wood conversion (reduction) reaction requires carbon monoxide as reductant.
The PUROxR process is used to partially oxidize wood, producing a synthesis
gas (syngas) containing CO, H2, C02, and water. An acid gas removal step yields
the CO-rich gas stream used in the wood conversion reaction. This section is
shown in Figure 28.
Two 50-percent capacity syngas production trains convert about 880 tons per day
of raw wood to syngas. Each train consists of two syngas shaft furnaces (one
spare), a three-stage syngas scrubbing system, a- syngas compressor, and an acid
gas removal system.
Wood chips from a surge bin are fed into the 12-foot diameter (atmospheric)
shaft furnace near the top. High purity oxygen (98 percent minimum) is intro-
duced into the bottom of the furnace where the char material is burned at about
3000 F, producing hot CO and C0? that react with the wood in the pyrolysis
zone. Drying of the wood feed occurs in the uppper zone of the furnace. Wood
(filter cake) recovered in product separation and the catalyst-bearing solution
are also injected at the top of the furnace.
A molten slag composed of wood ash and sodium carbonate is discharged from the
bottom into a quench tank.
Raw syngas at about 200 F contains some condensible hydrocarbons, tar, and
particulate matter which are removed in a dry cyclone separator and a three-
stage scrubbing train. Solids collected in the cyclone are normally returned
to the furnace, but can also be discharged to an ash bin for disposal. The
scrubbing system is similar to that used for reactor flash gas cleanup — a
spray tower, venturi, and nonreversing cyclone/demister. Soluble organics in
the scrubbing water are purged to the wastewater treatment section. There is
a net water production of about 40 gpm resulting from condensation of water
vapor in the wet syngas.
Scrubbed syngas (8340 SCFM) is compressed to 200 psig and sent to the CO re-
moval plant (Benfield Proprietary Process). Carbon dioxide is physically ab-
sorbed by a hot potassium carbonate solution in a packed absorption column.
The carbon dioxide-rich solution is stripped of CO in a packed regeneration
column, and the lean solution bottoms is returned to the top section of the
absorber. Reboiler steam (75 psig saturated) is supplied by a waste heat boiler
217
-------
recovering energy from 1200°F reactor tail gas. The acid gas (2570 SCFM),
mainly CO and water vapor, is vented to the atmosphere. CO-rich product
gas (about 6000 SCFM) is compressed to 4000 psig for injection into the wood/
oil slurry upstream of the reactor.
One 400-ton-per-day oxygen plant will supply the oxygen requirements for both
syngas trains. The two spare syngas furnaces will provide the capability for
virtually continuous two-train production. No liquid oxygen storage is pro-
vided. Oxygen is produced by conventional air separation involving air lique-
faction and fractional distillation into its separate components. The oxygen
plant is supplied as a package unit except for the air compressor and oxygen
compressor.
Catalyst Recovery
Soluble sodium carbonate is recovered from the syngas slag quench tanks by
physical separation (two recovery trains). The slag/water slurry is filtered
in a rotary vacuum filter to remove the insoluble materials (mainly wood ash
and filter aid). Part of the filtrate stream is purged to the wastewater
treatment system to prevent a buildup of soluble inorganics in the catalyst
system. The remainder is recycled to a catalyst makeup (and surge) tank. As
needed, anhydrous Na CO (light soda ash powder) and water are added to the
agitated makeup tank to maintain a 20 percent Na^CO. solution. A total of
21 tons per day of solution from each train is injected at 3500 psia into the
wood/oil slurry feed to the reactor makeup. The Na CO-quantities are expected
to be small because the wood ash should be a source of (catalyst) alkaline
material. (It may be necessary to (pulverize) grind the quench slag in order
to improve the dissolution of occluded Na CO .)
Auxiliary Facilities
The plant's main auxiliary facilities are a utility boiler to provide process
and heating steam, a raw water treatment system to supply plant water, a cir-
culating water system to provide cooling water, and a wastewater treatment
system to clean up liquid effluent streams.
Utility Boiler
Process and heating steam requirements are supplied by a 50,000 Ib/hr capacity
(250 psia, 500 F) wood-burning boiler. Normally only about 25,000 Ib/hr of
steam are required. The higher capacity was selected to meet peak demands of
wintertime operation, 120 percent plant throughput, and the failure of one
waste heat boiler (process steam supply to Benfield plant).
The boiler system consists of a traveling grate stoker with a two-drum vertical
boiler unit and an economizer. The boiler is also equipped to fire gaseous
fuel. Wood chips from the transfer house are supplied to the boiler silo by
an inclined belt conveyor. A mechanical fuel distributor feeds in wood chips
above the grate (about four tons per hour). A forced draft fan supplies combus-
tion air to the furnace. Hot combustion products pass through the radiant and
convection sections and are ducted to an electrostatic precipitator for fly ash
collection (99.5 percent removal efficiency). An induced draft fan boosts the
218
-------
flue gas to slightly above atmospheric pressure and the cleaned gas is dis-
charged to the atmosphere through a 100-foot tall steel stack. Fly ash and
bottom ash are conveyed to an ash bin and hauled off periodically for disposal.
Feedwater supplied to the boiler is composed of about 80 percent recovered con-
densate and 20 percent makeup (demineralized raw water).
Raw Water Treatment System
Figure 33 presents a summary water balance for the plant. Raw water is sup-
plied to the plant from the nearby river. The maximum demand is about 250 gpm.
A small pump house near the bank of the river pumps water through a 3000-foot
long, four-inch diameter steel pipe to the onsite raw water storage basin.
The earthen (settling and surge) basin has a 900,000-gallon capacity of a
2%-day supply, at the maximum makeup demand.' (The basin water pumps can also
supply water directly to the cooling tower for makeup.) Basin water is pumped
to the plant water treatment system, which consists of a gravity sand filter,
a chlorinator, and a filtered water storage tank. Filtered water is pumped
into the plant distribution system (utility and potable water). Water for
boiler feed makeup (three boilers) and pump system supply makeup is deminer-
alized and pumped to the boiler condensate storage tanks. The total treated
plant water demand averages about 80 gpm.
Recirculating Water System
Process auxiliary cooling duties total about 90 million Btu/hr. A recirculating
water system supplies 80 F water to all of the exchanger-coolers. A three-cell
induced-draft cooling tower (33 feet wide by 73.5 feet long) dissipates the
heat load to the atmosphere by evaporation and sensible heat transfer. Each
cell is equipped with a 168-inch diameter fan. Summer design conditions are a
o o o
70 F wet bulb, a 10 F approach, and a 30 F cooling range. Two 50-percent ca-
pacity pumps pump about 6000 gpm of cooled water from the tower basin to the
circulating water distribution system. The tower is operated at a nominal
25 cycles of concentration with river water as the makeup source (treated waste-
water is an alternate source). Evaporation and drift losses average about
128 gpm. The cooling water is shock-chlorinated for 90 minutes each day to
control fouling organisms. Sulfuric acid is added to the makeup water as a
scale (CaCO ) control measure.
Basin heaters (immersion steam coils) are used to prevent freezing during shut-
down of one or more cells in cold weather.
Wastewater Treatment System
Principal wastewater streams in the plant are:
• Boiler blowdown and regenerant brines
• Cooling tower blowdown
• Utility wastewater (yard and building drains)
• Sanitary wastewater
219
-------
1 D«f UIOOp T (13.T I (3-*aPM)
WQODCH.PS DRV/QSIHO "^^ | PRODUCT | «*« °'C PRODUCT 1
(TS GPM) But NO | I IS. 9 GPM* FLA.SH |(V&PW] i E P *N | |?4.1&Pn) SCRu
P.W-^-iGPM
CQ-i^ y£NT Qfci ( z ^ f
^J R^ (. 5.5 C-.PM) *~| p
\ilOOQ CHIPS iVMG^S 1 &fcS 1 t».-i I *.CID &fcS 1
>• s I » I • I • •
Mif tcOKID (T»aaPM) |"COMO. (1.8 6PM)
/ -3L.KC, ' CATM.YST 1
r\j /I QutNcHdo.^&Pwii v -^ MAKEUP 1
/ / P^""^ WATER (p.wj (-* >
/ / C.T, wwctup (r*oGPK) » ^' »rw") L,
/ / A.i.r. , , ' ' COOI_(N& r
3B.M4I mlt^~..itN, ^««
M'O.IGPM) A.IR
Hc«HCp°Rt7s,«J °PL"V 1
i0.0""^1.^! 1 COND (l.^SPKl
BACtWASM <- 1 *PM)
1 '*/,,",'
CiT.t Glf^l) f.NAftRO«lC 1 1 ACTtvAT to I SAND I
j. 1 CCNIBIFUSF! 1 1
DtGtsnow I ' I SLUDiit 1 FILTRATION!
DRIFT haw) lf==>«t.ltPH} ^H?E
' 1 ' ALT.- "-.I. >A*".tuP
11 TQUUtRl^y i v ' 0-I^Q &PM) <_ _ _*—
' SKINMIMO 1 r<~ ^ STORM
j I | SLOWDOWN i (MA ,-,f« .,«-)
/ , ftlOUOGlCKL 1 £s~GPM) &TORM WMtfJ
/ / SAHO ( 906PM ^ (3aPrt) ' TREMMENT| > B^SIN | (^GPH>
1 FILTRATION ^^"™ '
/ 1 1 • Bo
/ ' TREATMENT 1
/ QpjUeS I i [
I NtUTRpVLll, 1 ^
"•EHS Lt > STM^ COAIO LOSSIS
BLUWOOWH
, (1.&PM) . (~S
-------
• Compressor condensates
.• Catalyst solution purge
• Oily condensates from gas cleaning
• Storm water drainage (intermittent)
The blowdown (high total dissolved solids) streams are collected in a small
neutralization basin for blending, settling, and pH adjustment, if necessary,
and then sent to the stormwater holding basin before discharge to the river.
Utility wastewater and condensates from compressor coolers are collected in
process area sumps with oil skimming facilities before being sent to the bio-
logical treatment system. Sanitary wastewater is collected and treated in a
packaged biological treatment unit. The effluent is disinfected with chlorine
and sent to the stormwater basin.
The 3.9-million-gallon capacity earthen basin is able to impound about 50 per-
cent of the runoff from 75 acres during a 10-year, 24-hour storm. That is,
the basin provides about 12 hours of runoff holding capacity for this 10-year
event and total impoundment capacity for runoff from most rainfall events.
The basin also can serve as a final settling pond for the normal plant efflu-
ents.
Oily condensates, particularly from syngas scrubbing, are expected to contain
substantial concentrations of dissolved organics. These condensates are
treated in an 800,000-gallon capacity anaerobic digestion tank which converts
part of the dissolved and undissolved organics into-methane and carbon dioxide,
Raw digester gas is compressed and recirculated through submerged hydraulic
mixer units to mix the digester contents. Compressed raw gas product (about
570 Btu/SCF) is burned with wood in the utility boiler to generate process
steam.
Digester effluent is sent to a solid-bowl centrifuge which concentrates the
digester solids to a 15 to 20 percent weight centrifuge cake. The cake is
transported to the utility boiler and burned with the wood chip fuel. The
fuel value of the digester gas is expected to more than offset the low heating
value (high moisture content) of the sludge cake — resulting in a net energy
contribution from the digestion system.
Mother liquor from the centrifuge is sent to an activated sludge system for a
second stage of biological treatment. Utility wastewater and compressor con-
densates (ca 50 gpm) are also aerobically treated in the 250,000-gallon aera-
tion basin. Basin mixed liquor is clarified in a conventional gravity clari-
fier and the settled sludge is recycled to the aeration basin. A portion of
the recycle sludge stream is pumped to the digester to maintain the desired
mixed liquor solids concentration in the aeration basin. This sludge, gener-
ated by the biological process, is ultimately burned in the boiler.
Overflow from the clarifier is filtered in a gravity sand filter to remove
residual suspended solids. Filtered effluent is sent to the stormwater basin
for discharge to the river. Alternatively, most of this wastewater could be
221
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pumped to the cooling tower srs part or all of the makeup requirement for
the recirculating water system (ROWS). A high residual organic content or
a high dissolved solids content could limit the effective cycles of concentra-
tion attainable in the ROWS.
The total plant liquid discharge (dry weather flow) could be less than 25 gpm
if process effluent were used to supply the total cooling tower makeup demand.
Solid Waste Disposal
Plant solid wastes consist mainly of mineral residue (ash) from the syngas and
utility boiler units. This material, plus plant trash and garbage, is buried
onsite in a conventional landfill (spread, compact, and cover). About 11 acre-
feet of solid waste is generated per year. A three-acre site will be developed
initially for solid waste disposal. Additional area will be developed as the
initial site is filled.
Relief and Blowdown System
All pressurized systems handling hydrocarbons or other combustible materials
are equipped with safety and relief devices venting to the blowdown system.
Certain equipment normally has continuous vents to purge noncondensible gases
(which may also contain combustible gas). The blowdown and flare system is
designed to collect and incinerate normal process vent gases as well as handle
the largest credible release in an emergency (venting of one train — syngas,
reactor product, oil/solvent separation). The blowdown system is connected
to a knockout drum and a 16-inch diameter by 94-foot high elevated flare lo-
cated away from the process area.
Plant Energy Balance
An overall plant energy balance can be calculated in a "simple" way — the total
value of direct energy inputs (feedstock and electric power) minus the energy
value of the product oil equals the energy "lost" or dissipated to the sur-
roundings. The balance on such a basis is summarized in Table 80.
However, these energy values are not really equivalent, since they are not all
fuel heating values. If electric power consumption is converted to a fuel
basis on a 22-percent conversion efficiency (see wood-to-power), then the con-
version efficiency becomes 100 x 463.05 v 1098.4 = 42.1 percent.
222
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TABLE 80. THERMAL BALANCE ELEMENTS - WOOD TO OIL
Form
Quantity
MM Btu/hr
Total Feedstock Input 83,333 Ib/hr to reactors
72,155 Ib/hr to syngas production
8,225 Ib/hr to utility boiler
163,713 Ib/hr at 4,977 Btu/lb
Electrical Power Input 24,500 hp at 2,545.1 Btu/hr/hp
814.8
62.4
TOTAL
Product Oil Output
Heat Rejection
Direct Conversion
'Efficiency
30,870 Ib/hr at 15,000 Btu/lb
463.05/877.2 (100) = 52.8%*
877.2
463.05
414.15
* Efficiency drops to 42.1% if the fuel equivalent of electric power is
included at 22 percent conversion efficiency (15,514 Btu/kWh).
WOOD-TO-OIL PLANT COSTS
A conceptual estimate was made for the wood-to-oil plant on the hypothetical
110-acre site in New England. Table 81 summarizes major capital costs. De-
tails are presented in Appendix C. Mechanical equipment and piping are the
largest field cost items reflecting the materials handling and chemical pro-
cessing nature of the conversion plant. Pollution control equipment costs
are a little more than three percent of the direct field cost. Aqueous waste
treatment systems account for most of the pollution control costs. The
$99.1 million total investment for the 1764-barrel-per-day production
($56,000/BPD) is not directly comparable to the conventional petroleum pro-
duction and refining costs since the "oil fossil fuel" is not really "produced"
in the same sense. For a biomass comparison, SRI (11) reports an estimated
investment of about $144 million for a 5268 BPD wood liquefaction plant, or
about one-half the investment on a $/BPD basis.
Annual operating costs in Table 82 exclude the wood feedstock cost. The
utilities cost, which is nearly all electric power at 3c/kWh, is the largest
single operating expense, exceeding the combined costs of operating labor,
supervision, and maintenance labor and materials. In some situations, it may
be advantageous to produce power on site from wood. As indicated in Section 3,
the cost of electricity generation from wood would be on the order of 3c/kWh,
223
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TABLE 81. WOOD--TO -OIL CAPITAL COSTS
Element $ 1,000,000's
Site and Yard 1-6
Civil/Structural 4-8
Process Mechanical Equipment 27.6
Pollution Control Equipment 1 • 7
Piping and Instrumentation 10.5
Electrical J> •6
DIRECT FIELD COST 50.8
Indirect Field Cost 6.5
TOTAL FIELD COST 57.3
Engineering Services 6.9
64.2
Allowance for Uncertainty 12. 8
TOTAL CONSTRUCTION COST 77.0
Land 0.4
Other Oxmer Costs 1.5
Startup 7.7
Allowance for Funds During Construction 7.3
FIXED CAPITAL INVESTMENT 94.4
Working Capital 4.7
TOTAL CAPITAL COST 99.1
First Quarter 1978, Price and Wage Levels
224
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excluding wood costs. Economically there would be no advantage unless wood
were essentially free or the cost of supplying power to the plant were con-
siderably higher than 3
-------
TABLE 82. ANNUAL OPERATING AND MAINTENANCE COSTS* -
WOOD- TO OIL
Element
$l,000,000's
Supplies
Utilities
Operating Personnel
Maintenance Labor and Materials
Supervision
Administration and Overhead
Local Taxes and Insurance
TOTAL ESTIMATED ANNUAL OPERATING COST
First Quarter 1978, Price and Wage Levels
'"'Excluding wood feedstock.
TABLE 83. ANNUALIZED COST OF OIL PRODUCTION
0.6
4.3
2.0
1.1
0.4
0.7
2.0
11.1
Element
Annualized Capital Cost (9%)
Annual Operating Cost
Annual Wood Cost
(Base: $10/ton)
TOTAL ANNUALIZED COST
$l,000's
10,764
11,100
6,550
28,414
$/Bbl
18.30
18.88
11.14
48.32
$/MM Btu
2.91
3.00
1.76
7.67
226
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100,
WOOD COST, S/MMBTU
2 3
80
I
WOOD-TO-OIL
60
CQ
CD
CO
O
CJ
40
20
PRIVATE
UTILITY
10 20
WOOD COST, S/TON
30
40
Figure 34. Effect of wood cost on cost of oil with
both private and utility financing.
227
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Forest Regeneration and Stand Development—
Large quantities of forest residues can impede the germination of seeds and
the development of seedlings. Optimum amounts of residues, however, may form
desirable seedbeds for new growth. Moist, decayed organic matter may be the
ideal .environment for regeneration of the forest.
By affording nutrient supply, large residues (stumps, etc.) may protect new
saplings. Residues, however, may prevent germination of such species as red
alder and firs, which require mineral soils for seedling establishment. On
balance, removal of at least a portion of the residues would probably consti-
tute positive, rather than negative environmental impacts.
Maintenance of Soil Fertility and Erosion Control—
Excessive removal of forest residues will cause depletion of the nutrient
elements. Leaves are especially rich in nutrients and their complete removal
will obviously cause deficiencies' in such elements as nitrogen, potassium,
phosphorus, and sulfur, depending on nutritive makeup of the soil (41). Min-
eral deficiencies of this nature will have to be corrected by the incorporation
of fertilizers — an expensive alternative.
Excessive residue removal in the area will also result in soil erosion, espe-
cially on slopes. In addition to soil loss, secondary impacts such as sedi-
mentation and bank cutting of streams and loss of water quality could occur
in some areas.
Water Quality—
The presence in streams of fine residues caused by soil erosion can increase
biological oxygen demand and thus influence stream biology by reducing the
amount of dissolved oxygen for fish. Sedimentation can also impede fish mi-
gration, eliminate spawning beds, and destroy rooted aquatic vegetation.
Wildlife Habitat—
Inasmuch as forest residues generally provide habitats and cover for a variety
of biota, excessive removal may be detrimental for some species of small mam-
mals and birds. Wildlife will be disturbed by the collection activities and
will temporarily move to new habitats in the near-by forest. This displace-
ment could result in increased mortality for strongly territorial species,
especially during breeding or nesting seasons.
Recreation and Aesthetics—
Optimum levels of removal of heavy logging residues will improve recreational
and aesthetic prospects in most situations.
Transportation—
Wood chip shipments to the conversion plant will average (annual operating
basis) 100 truck loads or 40 (5000 CF) rail hopper car loads per day. Other
mobile equipment will be involved in collection of residue on forest lands by
off-road activities. The additional transportation burden on local roads,
state highways, and rail lines will be small (probably less than one percent)
compared with the current annual vehicle-mileage or ton-mileage in the col-
lection area (about 6000 square miles). Some local congestion could be ex-
pected at times in the vicinity of the plant because of chip haul traffic.
Z28
-------
Motor fuel consumption for residue collection will be on the order of 1.5 per-
cent of the conversion plant's fuel production. Vehicle pollutant emissions
will increase as a result of this fuel consumption, a small though adverse
effect on ambient air quality.
Socioeconomic—
Local income and employment will increase as a result of residue procurement
activities_, a benefit to the economy of the area. Some 30 to 50 new permanent
jobs will be created, as well as some part-time employment opportunities for
loggers. Several million dollars will be paid annually for wood delivered to
the plant. Manpower and community service resources in the area will not be
unduly strained by the demands of this new activity.
Summary—
Table 84 summarizes principal impacts -anticipated in forest residue collection.
As in the wood-to-power scenario, a considerable amount of land area will be
affected by forest residue collection. Environmental impacts will have both
positive and negative aspects. With proper management of collection activities,
forestland productivity and appearance could be improved, with economic and
perhaps recreational benefits for the community. However, some damage to
soil stability and wildlife habitats should be expected. Severe damage to
forestlands could occur through excessive removal of residues and careless
harvesting practices, resulting in soil erosion and degradation of surface
waters.
229
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TABLE 84. PROCUREMENT IMPACT SUMMARY - FOREST RESIDUE
Environmental
Factors
Residue Procurement
Impacts
Potential
Mitigating Measures
Air Quality
Surface Water
Groundwater
Quality
Land
Ecology and
Critical Habitat
Soils and
Geology
Minor adverse impact from vehicle
pollutant emissions and localized
fugitive dust emissions
Potential degradation of stream
qualities resulting from soil
erosion — secondary effects such
as increased turbidity and or-
ganic loading
No direct impact
Abundant forestland in region-
yarding areas only direct land
requirement; agreements with
land owners needed to collect
enough residue for 20 year
plant life
About 20,000 to 70,000 acres
subjected to residue collec-
tion annually; judicious col-
lection can improve forest
productivity, reduce fire,
disease and insect damage; some
damage to vegetation expected !
during collection, disturbance
of wildlife habitats and pos-
sible permanent displacement of
and loss by increased mortality
to some animal species
Nutrients in residue removed may
result in degradation of soil
fertility; complete removal may
cause serious mineral deficien-
cies; potential increase in soil
erosion on unstable terrain
Avoid or limit resi-
due collection on un-
stable soils
Develop residue col-
lection and manage-
ment to ensure supply
Wildlife surveys
needed to avoid
critical habitats;
management of col-
lection activities to
minimize damage of
vegetation and
wildlife
Soil surveys and
monitoring of col-
lection activities
to prevent damage
to soil fertility
and stability; im-
port fertilizers,
if necessary to re-
plenish nutrients
(Continued)
230
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TABLE 84. (Continued)
Environmental
Factors
Residue Procurement
Impacts
Potential
Mitigating Measures
Aesthetic and
Recreational
Resources
Community
Economy
Community Popu-
lation and
Services
Some improvement in appearance
of logged areas; potential in-
crease in recreational value of
forest land
$6.5 million annual input to local
economy through purchase of de-
livered residue-significant benefit
Little increase expected in local
population and in demands for
services
Avoid excessive re-
moval that leads to
erosion and degrades
aesthetic qualities
Labor
Availability
Local labor supply is adequate to
fill the jobs created by residue
procurement — benefit to local
work force.
Transportation
Small increase in rail and road
traffic in region; local con-
gestion may occur on principal
residue haul routes
Plant Impacts
Construction and operation of the wood-to-oil plant would have impacts on the
environment in the vicinity of the hypothetical plant site. These impacts are
broken down into physical/chemical, biological, aesthetic, and socioeconomic
categories for discussion.
Estimates of physical resources committed to operation of the plant over its
20-year life are summarized in Table 85. Table 86 presents annual chemical
requirements.
Construction of the plant will also involve the utilization of additional re-
sources —manpower, fuel, water, and all the construction materials. The total
construction period is assumed to be three years. During the peak of construc-
tion, several hundred workers will be on site.
Physical/Chemical Impacts—
Physical/chemical emissions from the plant are categorized as air, water, and
solid waste emissions. Direct impacts from these emissions on air, water,
land, and biota are discussed below.
231
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TABLE 85. RESOURCES COMMITTED TO PLANT OPERATION
Resource Category
Quantity
Normalized Quantity
(Output)*
Land
Feedstock
Auxiliary Fuel
Chemicals
Electric Power
Water
Manpower (145 employees)
110 acres
655,000 tons/yr
13,300 MM Btu/yr
2,130 tons/yr
146 MM kWh/yr
100.8 MM gal/yr
290,000 manhours/yr
0.24 acres/MM Btu/hr
(62.4 acres/MBPD)
353.7 Ib/MM Btu
3,590 Btu/MM Btu
1.15 Ib/MM Btu
39.5 kW/MM Btu/hr
27.2 gal/MM Btu
0.078 manhours/MM Btu
*Basis: 3.704 trillion Btu/yr net output.
Air Emissions—The wood-to-oil conversion plant will be equipped with pollution
controls to limit pollutant emissions to the atmosphere. Significant emission
sources and estimated emission rates are listed in Table 87. Particulate
emissions from wood chip transfer operations are controlled where practical by
the enclosure of transfer points and the use of fabric filter collectors on ex-
haust air streams. Uncontrolled emission sources are the dump hopper, the
pneumatic conveyor discharge paper, and the chip storage pile. A large fraction
of the particulate matter entrained in the air streams will probably settle out
quickly and close to the emission source. Suspended particulate matter emis-
sions are expected to be low, even from uncontrolled sources.
The dryer/grinder units will produce large amounts of fine wood dust. Bag-
houses will be used to clean the exhaust gas before it is vented (part of it)
to the atmosphere. The dryer/grinders are expected to be the largest particu-
late matter sources in the plant. Uncontrolled emissions could be several
tons per day.
Vent gases from the dryer/grinders and from the waste heat boilers originate
from combustion of reactor flash gas. As such, the combustion product gases
will contain small amounts of nitrogen oxides, carbon monoxides, and unburned
hydrocarbon pollutants that will be emitted to the atmosphere. The utility
boiler will be the other source of combustion product pollutants. The boiler
will have an electrostatic precipitator for particulate matter removal as its
only pollution control device. None of the combustion sources will emit
232
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TABLE 86. SUMMARY OF ANNUAL CHEMICAL REQUIREMENTS -
WOOD -TO- OIL
Chemical
Amount Per Year
Solvent (o-xylene)
Diatomaceous Earth
Soda Ash
Lime
Chlorine
Caustic Soda (50%)
Sulfuric Acid (66° Be)
Polymer
Misc. Water Treatment Chemicals
Benfield Solution
Ion Exchange Resins
Lube Oil
Auxiliary Fuel
Diesel
Gasoline
Natural Gas
1 MM Ib
950 tons
590 tons
40 tons
16 tons
10 tons
13 tons
2 tons
1 ton
2,000 gal
5 cu ft
3,300 gal
66,000 gal
15,000 gal
2,400 MSCF
233
-------
TABLE 87. SUMMARY OF ESTIMATED AIR EMISSIONS - WOOD -TO OIL
Source
Flow Quantity
Pollutants
Emission Rate
Chip Dump Hopper
Chip Transfer Bins
Pneumatic Chip
Conveyors
Chip Storage Pile
Transfer House Vent
Dryer/grinder
Feed Bins (4)
Syngas
Feed Bins (4)
Boiler Feed Silo
Dryer Baghouse
Vents (2)
Waste Heat Boiler
Stacks (2)
2330 tons/14-hr day,
6 days/week
2330 tons/14-hr day,
6 days/week(1200 CFM)*
2330 tons/14-hr day,
6 days/week(5600 CFM)
120,000 tons stored
9-10 acres of land
2000 tons/day chips
(600 CFM)"
1000 tons/day
(400 CFM)*
865 tons/day
(400 CFM)*
100 tons/day
(100 CFM)*
15,250 CFM exhaust
each*
17,500 SCFM each
Fugitive dust-
suspended
particulates
Fugitive dust
(.1 gr/CF)
Fugitive dust
Fugitive dust
Fugitive dust
(.lgr/CF)
Fugitive dust
(.1 gr/CF)
Fugitive dust
(-1 gr/CF)
Fugitive dust
(.1 gr/CF)
23 Ib/day
14 Ib/day
23 Ib/day
50 Ib/day
12 Ib/day
8 Ib/day
8 Ib/day
2 Ib/day
Particulate
matter (.02 gr/CF) 125 Ib/dav
NO (0.5 Ib/MM Btu)f 25 Ib/day
CO(0.05 Ib/MM Btu)f2.5 Ib/day
HC(0.05 Ib/MM Btu)f2.5 Ib/day
Particulate
matter(.004 gr/CF) 30 Ib/day
NO (0.5 Ib/MM Btu)f 35 Ib/day
CO^O.05 Ib/MM Btu)f3.5
HC(0.05 Ib/MM Btu)f3.5
Acid Gas Column
Vents (2)
2570 SCFM each
CO
H2
288 Ib/day
48 Ib/day
(Continued)
234
-------
TABLE 87. (Continued)
Source Flow Quantity
Utility Boiler Stack 13,500 SCFM
Pollutants Emission Rate
*
Particulate matter
NOX(0.5 Ib/MM Btu)1"
SOX(<0.01 Ib/MM Btu)f
C0(0.1 Ib/MM Btu)t
HC(0.1 Ib/MM Btu)f
36 Ib/day
500 Ib/day
<10 Ib/day
100 Ib/day
100 Ib/day
Oxygen Plant
Nitrogen Vent
Cooling Tower
Exhaust
Flare
21,600 SCFM of N2
354,000 SCFM
'(dry air)
Small
None
Drift(water
droplets)
Salts
HC**
CO, HC, NCi
36,000 Ib/day
60 Ib/day
Small'
^Fabric filter collector on vent stream.
tAssumed emission factors.
"""Potential hydrocarbon emission if treated wastewater used as makeup water.
significant amounts of sulfur oxides. The Benfield regeneration columns will
release acid gas streams rich in CO . Small quantities of carbon monoxide and
hydrogen will also be released. The flare system will routinely incinerate
small quantities of hydrocarbon vapors vented from process units. Only during
emergency conditions would the flare be a significant combustion source.
The air separation plant and the cooling tower will be large emission sources
in terms of flow, but their discharges will not be particularly harmful to the
air quality. Drift from the cooling tower will deposit water droplets and salts
on the ground in the vicinity of the tower. If treated wastewater were used
for cooling tower makeup, there would be some dissolved organics in the drift
loss and probably some volatile organics in the exhaust air.
Overall, the plant emissions will have a small adverse effect on ambient air
quality in the area. The plant could be considered a major new source with
respect to particulate matter, since potential emissions exceed 100 tons per
year. Air quality in the vicinity of the plant meets primary standards except
for photochemical oxidants. Hydrocarbon storage (product oil, solvent, and
vehicle fuel) tanks will be equipped with vapor control or vapor collection
systems. Total hydrocarbon storage capacity is less than 5000 barrels. Hydro-
carbon emissions from the plant will be low and will not contribute significantly
to atmospheric pollution. Combustion products from mobile sources (wood hauling)
may be the largest contributor to oxidant formation.
235
-------
Water Emissions—Total plant process wastewater will average about 150 gpm.
Table 88 summarizes estimated emissions. Oily condensates from gas scrubbing
are expected to contain high concentrations of dissolved organic materials.
Compositions of the condensed hydrocarbons cannot be easily predicted, but
they are likely to include a variety of alcohols, aldehydes, ketones, and or-
ganic acids. The two-step biological treatment (anaerobic_digestion and acti-
vated sludge) should remove most of the biologically degradable organics. Re-
sidual organic material in the treated effluent will be discharged to the
river. Most of the process effluent will be used as cooling tower makeup if
it is low in TDS and organics. The characteristics of the residual organics
are not known. In terms of gross pollutant measures, such as biochemical
oxygen demand, chemical oxygen demand, or organic carbon, the mass emission
rate of pollutants will not be large. It is possible that some toxic or car-
cinogenic materials may be generated in the" syngas or wood conversion processes
and may pass through the wastewater treatment processes. At this time there
is no information available to assess whether or not a hazardous materials
problem will exist.
Utility wastewater will also be biologically treated and will not be a signifi-
cant source of organic pollutants. Sanitary wastewater (after separate bio-
logical treatment) and blowdowns from the boiler and cooling tower will be
low-volume wastewater sources. Dissolved solids emissions in the blowdown
streams are the result of concentration of TDS in the river water, plus added
chemicals containing inorganic ions. If the coaling tower makeup water were
treated wastewater, the cooling tower blowdown would need to be biologically
treated for high concentrations of organic materials.
Storm runoff collected from process areas will average over 100 gpm on an
annual basis. It will be a large intermittent effluent source. Stormwater
will pick up wood particles and perhaps some oily material from process areas.
During wet weather periods, part of the runoff could be used as makeup to the
cooling tower. After passing through the stormwater settling basin, it will
be discharged to the river. After settling, the discharged stormwater will
contain the low concentrations of dissolved pollutants that were picked up
through contacts x^ith the various surface areas in the plant. During storm
periods, stormwater will be the largest source of pollutant emissions in the
plant by virtue of its large volumetric flow.
Although it is difficult to predict actual pollutant loads from the conversion
plant, the application of available control technology should produce effluents
low in pollutant concentrations. The residual pollutants discharged to the
river will probably have no measurable effect on river water quality, though
the addition of any pollutants would have an adverse, though minor, effect on
the river as a water resource. Plant effluents are expected to have no effect
on groundwater resources.
Solid Waste Emissions—Solid wastes generated by the processes originate from
the noncombustible portion of the wood feedstock and from materials such as
filter aid and catalyst added to the process. The nonrecoverable solid wastes
will be buried in an onsite landfill. An estimated total of 1200 cubic feet
per day (nine acre-feet per year) of waste will be produced (see Table 89).
Slag from the syngas furnaces will contain ash from the wood, diatomaceous
236
-------
TABLE 88. SUMMARY OF ESTIMATED WASTEWATER EMISSIONS - WOOD TO OIL
Source
Estimated Flow
Pollutants
Utility Water 46 gpm
(includes cond's)
(after treatment)
Boiler Slowdown 3 gpm
and Regenerant
Brines
(after neutral and
settling)
BOD (<20 mg/1)
TSS (<10 mg/1)
Oil & Grease(<10 mg/1)
pH
TSS
TDS
PH
(<30 mg/1)
(<500 mg/1)
Emission Rate
A
Oily Process 94 gpm
Condensates
(after treatment)
BOD
TSS
Oil &
PH
(<50 mg/1)
(<10 mg/1)
grease(<20 mg/1)
<60 Ib/day
<12 Ib/day
<24 Ib/day
6-9 units
<14 Ib/day
<7 Ib/day
<7 Ib/day
6-9 units
<1 Ib/day
<18 Ib/day
6-9 units
Cooling Tower
Slowdown
(after settling)
Sanitary Wastewater
(after treatment)
Storm Runoff
(30 inches
per year)
2 gpm
5 gpm
Intermittent,
116 gpm
ann . avg .
BOD
TSS
TDS
pH
BOD
TSS
pH
BOD
TSS
PH
**
(<30 mg/1)
(-1700 mg/1)
(<30 mg/1)
(<30 mg/1)
(<10 mg/1)
(<50 mg/1)
**
<1 Ib/day
40 Ib/day
6-9 units
<2 Ib/day
<2 Ib/day
6-9 units
<20 Ib/day
<100 Ib/day
6-9 units
* Most may be used as cooling tower makeup.
** Could have a high BOD concentration if treated wastewater used as cooling
tower makeup. Cooling tower blowdown then would be biologically treated.
237
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TABLE 89. SOLID WASTE DISPOSAL SUMMARY - WOOD TO OIL
Source
Estimated
Quantity
Potential
Pollutants
Disposal
Syngas Slag
Filter Cake
1,200 Ib/hr at
50% solids
Char - potential
hazardous organ-
ics, mineral ash,
trace metals
720 cu ft/day buried
in onsite landfill
Digester Cen-
trifuge Cake
Utility
Boiler Ash
Plant Trash
2,375 Ib/hr at
20% solids
320 Ib/hr at
90% solids*
650 Ib/day
Miscellaneous: Intermittent
Benfield
Filter Cake,
Water and
Wastewater
Basins
Cleanouts
Organics, min-
eral ash, trace
metals
Mineral ash,
trace metals
Decomposable
waste, oily
materials, odor
Organics, sus-
pendable solids
Burned in utility
boiler - residual
as ash
380 cu ft/day
buried in onsite
landfill
100 cu ft/day
buried in onsite
landfill
Small amounts -
buried
^'Includes ash solids from combustion of digester centrifuge cake.
238
-------
earth (filter aid), and some carbonaceous material (char). Composition of
this char is not known. It is possible that hazardous organic compounds may
be formed in the syngas partial oxidation process and may be retained in the
char. If so, it may be more desirable environmentally to burn the char filter
cake rather than to bury it, as assumed here. Burning the cake in the utility
boiler would theoretically convert organic material to carbon dioxide and water.
The fusion properties of the filter cake would need to be determined in order
to evaluate potential slagging problems. The inorganic fraction of the filter
cake — mainly wood ash and diatomaceous earth — will be predominantly mineral
forms of silica, aluminum, calcium, magnesium, sodium, potassium, and iron.
Trace quantities of nonvolatile heavy metals in the wood feed will also be
present in the filter cake.
Disposal of the wet filter cake by proper landfill techniques will help to mini-
mize contact with surface and groundwaters and prevent their pollution. Such
techniques include preparation of an impervious base, diversion of drainage,
and frequent application and compaction of cover material.
The digester centrifuge cake will contain the undigested organics and the in-
organics that primarily originated from gas scrubbing; it will also contain
bacterial cells from the digestion and activated sludge processes. This mate-
rial will be fed along with wood to the utility boiler, and the noncombustible
portion will be collected as flyash and bottom ash. The collected ash, mainly
minerals, will be moisturized for transport and buried with the syngas filter
cake and the general plant trash. The boiler ash as a solid waste will offer
the least potential for harmful pollutant emissions. As with the filter cake
and general plant trash, the burial in a landfill must be managed so that po-
tential pollutants do not contaminate ground and surface waters.
Water and wastewater treatment basins t^ill be subjected to periodic cleaning
to remove accumulated solids. These solids, removed as sludges, will be de-
posited in the landfill. A small amount of filter cake from the Benfield solu-
tion filters will also be buried.
Plant solid wastes will contain organic and inorganic pollutants that could
contaminate water resources. By proper landfill burial, these wastes are not
expected to emit significant amounts of pollutants into the air or into water
resources. The major impact of solid waste disposal will be the "consumption"
of about 10 acres of land used for landftiling the wastes. Sections of the
landfill site will be continuously stabilized and revegetated during the plant
life.
Soils and Geology—Changes in the land surface will result from construction
of the conversion plant as well as from disposal of the plant solid waste.
Approximately 110 acres will be affected. Alterations of the land surface
(during site preparation) would include removal of topsoil, changing local topog-
raphy by cut and fill, grading and excavation for basins, diversion of natural
drainage and construction of new drainage ways, and application of surfacing
materials in process areas and roadways. During operation of the plant, the
landfill disposal area will be increased in height by about 20 to 25 feet through
emplacement of solid waste. The most significant impacts then will be the per-
manent alteration of the topography and the removal of productive soils.
239
-------
However, these impacts will be minor since the loss of soil productivity will be
a small fraction of the total in the region and there is nothing unique about
the site topography.
Biological Effects—
Plant construction will disturb plant and animal life on the site itself and on
adjacent land to some extent. Site clearing will remove most of the vegetation.
Additional strips of about 110 acres of land will be cleared of vegetation for
construction of the access road and rail spur. Timber on the site will be stock-
piled for use later as plant feed. Most of the animals displaced by removal of
their habitats will resettle nearby, but may suffer increased mortality due to
overcrowding in habitats near carrying capacity. Generally, wildlife species
do adapt to increased noise levels, although some species more sensitive to hu-
man presence or plant construction noise may be driven even further away. When
the perimeter fence is completed, it will be a barrier to the movement of larger
animals, while heavy traffic on the access road will be an intermittent hazard
to all animals. Care in siting will ensure that no rare or endangered plant
or animal species are present in the vicinity. Vegetation and woodland species
are typical of those found in many areas of this region.
Secondary impacts on biological life forms will be similar to the other two
biomass scenarios. No significant offsite damage to plants and animals is antici-
pated to result from construction or plant operation air emissions. Pollutants
in the plant effluent discharge may harm aquatic organisms in the discharge mix-
ing zone, but will have little adverse effect downstream. Runoff from severe
storms could add a significant amount of suspended solids to the river when
turbidity will already be high, thus increasing the stress on sensitive species.
Intake of river water will result in damage or destruction of a small fraction
of the small aquatic organisms in the river. Hydrocarbon spills in the plant
are unlikely to result in any significant discharge. The product oil is not
fluid and the solvent is relatively insoluble in 'water and not particularly
toxic. Overall, the significant adverse impacts will be a direct result of
clearing the site: (1) removal of vegetation, (2) displacement of wildlife,
and (3) loss of productive forestland.
Aesthetic Impacts—
The hypothetical site is in an area of fairly high aesthetic quality because of
the forested hilly terrain, good air and water quality, and low evidence of
human use. The site itself is gently sloped, but visual access will be limited
by the surrounding trees. The effect will be similar to encountering a large
lumber or pulp mill by a road or river in the forest, as illustrated in Figure
35, though the conversion plant size and the general arrangement will be dif-
ferent .
The wood storage pile (covering 9 to 10 acres) will be the dominating physical
•feature, appearing as a low broad mound on an open level area. The processing
portion of the plant is a symmetrical arrangement of the two trains. Rectangu-
lar process buildings will contrast with the horizontal and vertical cylindrical
forms of exposed process equipment and storage tanks, all set on a level site.
The Benfield columns, the boiler stack, and the flare stack will be the tallest
structures at about 100 feet high.
240
-------
,
Wi'H
'1*)V A?';
'1
'W* i^uMiV4*
'; v.i*4u4AV/
i * i ' iM
Figure 35. Artist's rendering of a commercial wood to
oil plant.
-------
Nonprocess buildings will be clustered near the plant entrance. The cooling
tower plume, normally the only visible emission, may be discerned at some
distance if the air is still.
The chemical plant appearance will contrast sharply with the woodland sur-
roundings,, and will detract from the high aesthetic quality of the area, but
the low visual accessibility will help to limit the number of adverse impres-
sions .
Social and Economic Impacts—
The local economy will benefit from construction and operation of the wood-to-
oil plant. The $99 million capital cost is a significant investment, and a
portion of the construction and the annual operation funds will be expended
in local communities. The local industrial tax base will be expanded and
taxes on the facility will help to provide community services.
The plant will provide employment opportunities for local personnel — several
hundred "temporary jobs during the construction period and about 145 permanent
jobs during its operating life. Since most of the construction and operation
work forces will be obtained from the local manpower pool, little direct in-
crease in population is anticipated and increased demands on community ser-
vices by plant personnel should not strain the budgets of nearby communities.
The plant itself will need supplemental fire protection services from local
resources and about 18 MW of electrical power from local utilities. The pro-
jected generating capacity is considered adequate to supply the plant. In
turn, the product oil can potentially serve as fuel to generate about 45 MW
of electric power.
Thus, the demands of the facility can be absorbed by the local -coTnmunity without
undue strain. The economic benefits derived from spending, wages, and taxes
are expected to outweigh any adverse social impacts.
Table 90 summarizes principal impacts and potential mitigating measures antic-
ipated for the wood-to-oil plant.
242
-------
TABLE 90. SUMMARY ENVIRONMENTAL MATRIX -
WOOD- TO- OIL
Environmental
Factors
Effect of Plant
Construction and Operation
Potential
Mitigating Measures
Climatology and
Meteorology
Air Quality
Surface Water
Availability
Groundwater
Availability
Groundwater
Quality
Land
Availability
Regional Ecology
and Critical
Habitat
No discernible impact from
plant construction or operation
Potential minor short-term
impact of fugitive dust from
construction; minor adverse
impact from plant operation
Minor adverse impact on qua-
lity; potential for generation
of hazardous compounds uncer-
tain and presence in plant
effluent uncertain
No consumption, no effect
Little potential for degrada-
tion; ponds and basins lined;
proper management of landfill
site required
Requires about 100 acres of
land including 10 acres of
landfill; no significant
impact
About 100 acres of vegetation
(mainly timber) removed and
associated wildlife displaced
or destroyed during construc-
tion; minor adverse impact;
indirect impacts on vegetation
and aquatic species
Experimental work
to assess potential
problem
Careful siting to
avoid sensitive
areas
Careful siting to
avoid critical wild-
life habitats and
rare or endangered
species
(Continued)
243
-------
TABLE 90 (Continued)
Environmental
Factors
Effect of Plant
Construction and Operation
Potential
Mitigating Measures
Aesthetic
Resources
Historical,
Archaeological
Resources
Community
Economy
Significant adverse impact in
high aesthetic quality area,
but limited visual
accessibility
Insignificant impact
Significant benefit from con-
struction and operation
through local spending, wages
paid and industrial tax
revenue
Retain vegetative
boundary as screen,
landscape plant areas
Siting surveys to
protect cultural
resources
Community
Population
and Services
Labor
Availability
Power
Availability
Transportation
Availability
Small increase in population
and residential services;
little strain on ability of
community to provide services
Requirements for several
hundred construction and about
145 operation personnel; local
manpower resources adequate
Requires about 18 MW (250 kWh/
bbl) of electric power for
plant operation; projected
generating capacity adequate
Requirement for construction
of access road and rail spur;
small adverse impact on envi-
ronment from new transporta-
tion corridors
Plant to support
community in ex-
panding services
if necessary
Plant to train, un- .
skilled workers, as
necessary
Plant could generate
required power with
wood as fuel
Careful selection of
corridors to minimize
impacts on land use,
ecology, water
resources
244
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COAL LIQUEFACTION PLANT SITE DESCRIPTION
The coal liquefaction plant is located in a hypothetical rural area in an
eastern coal-producing state approximately two miles west of a major river.
Topography and Elevation
Locally the landscape is dominated by relatively high wooded hills (to
1400 feet) to the west of the fairly level upland plateau. The river val-
ley just to the east is rather deeply dissected and is about 200 feet (MWL)
below the mean site elevation of 1000 feet. No surface or underground mining
has occurred on the site.
Transportation
A network of interstate and state highways surrounds the site area. A north-
south interstate highway passes within five miles to the west. Common-
carrier rail lines are located on either side of the river, which runs north-
south. The river is navigable and heavily used for transport of bulk cargoes.
Several small towns are located nearby, and a major metropolitan area is about
40 miles north of the site. An east-west products pipeline passes three miles
south of the site.
Climate and Air Quality
The area has a typical continental type of climate with changeable temperatures,
high humidity, and frequent precipitation. Table 91 summarizes principal cli-
matic conditions at the hypothetical site. Temperatures exceed 90 F an average
of 10 to 20 days per year and reach 32 F or lower an average of about 100 days
per year. Total precipitation averages 42 inches annually, with the maximum
occurring spring and summer.
The site area is located in EPA Region III, and the site county is currently
listed as a nonattainment area for photochemical oxidants.
Land Use
The hypothetical plant site is mostly woodland and pastureland in private owner-
ship. On the eastern edge of the site nearer the river, there is a small farm
having cropland interspersed with dairy pasture.
Water Resources
River flow near the plant averages about 8000 cfs. The lowest recorded daily
flow was about 200 cfs. The water quality is fair. In the past, this river
basin has been significantly degraded by acid mine drainage, but there has been
a gradual improvement in water quality over the past 25 years. The river is
used for recreational fishing and boating. Average xvater quality characteris-
tics are listed in Table 92. All of the plant makeup will be supplied from
the river by an intake pumphouse and pipeline.
245
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TABLE 91. ASSUMED CLIMATIC CONDITIONS AT THE SITE
Elevation:
Temperature:
Annual Average
5-Percent Design
Conditions
Annual Extremes (Daily)
Median of Annual (Winter)
Extremes
Prevailing Wind:
Precipitation:
Annual Total
Annual Runoff
Annual Lake Evaporation
10-year, 24-hour Storm
Annual Frost-Free Period:
1000 feet
54 F dry bulb
49°F wet bulb
83°F dry bulb
73°F wet bulb
-18°F to 99°F
WSW at 4.2 mph
42 inches
18 inches
29 inches
4.5 inches
265 days
Soils
Soils on the plant site include the Inceptisols and Ultisols orders. Some por-
tions have developed in clayey parent materials and are generally deficient in
bases, which were removed primarily by leaching. The soils range from freely
drained to poorly drained, and most still have a forest vegetation.
Vegetation
Most of the land area in the vicinity of the plant is farmland or woodland
while the remaining, concentrated in river valleys, is industrial and munici-
pal. The vegetative community consists of various succesional stages of a mixed
forest dominated by hardwoods (primarily oak and hickory species). The area
has typical understory shrubs and herbs, none of which is categorized as rare
or endangered species.
246
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TABLE 92. ASSUMED AVERAGE RIVER WATER QUALITY
Component Value
Flow, Average (Daily) 8,089 cfs
Temperature 56°F
pH 7.0
Turbidity 13 JTU
Dissolved Oxygen 9.7 mg/1
Hardness (as CaC03) 124 mg/1
Alkalinity (as CaC03) 29 mg/1
Calcium 35 mg/1
Magnesium 9.7 mg/1
Sodium 24 mg/1
Potassium 2.7 mg/1
Iron 1.6 mg/1
Manganese 0.3 mg/1
Fluoride 0.2 mg/1
Chloride 15.3 mg/1
Sulfate 128 mg/1
Phosphate 0.4 mg/1
Nitrogen - Total 1.6 mg/1
Silica (as SiCL) 5.1 mg/1
Total Dissolved Solids 252 mg/1
247
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Wildlife
The hardwood forest and riparian woodland provide excellent habitat for birds,
mammals, and invertebrates. 'Small game such as squirrels, rabbits, and pheas-
ants are hunted locally. White-tailed deer are hunted to a lesser extent in
the area. The bald eagle is the only endangered species known to inhabit the
general area, though none has been observed on the site.
COAL PROCUREMENT
The H-Coal plant requires about nine million tons per year of coal. In this
hypothetical scenario, the production from three large underground mines will
be dedicated to supply the plant's feedstock. In this bituminous coal dis-
trict, production averages about 25 million .tons per year, nearly all by large-
scale deep mining of the Pittsburgh seam. Two counties had nearly seven billion
tons of in-place reserves as of 1970, virtually all in a seam thickness over
3h feet (21).
The seam lies at a depth of 800 to 1500 feet and is reached by shaft entries.
The mining height averages six feet. A relatively small amount of land area
is occupied by the surface facilities at each mine. The underground mining
plan is assumed to be similar for all three mines. Production and supply
shafts are driven (at low cover) near the center of the lease holding. Main
entries are driven along the center access with production headings driven
to the left and right off the main heading. Production panels are developed
parallel to the main heading and proceed outward from the main. The depth of
the panels is about 2600 feet and is based on an eight-entry system, 16 feet
wide on 95-foot centers.
Continuous mining units each produce about 350 tons of coal per shift. At
full production, 42 production shifts are averaged per day (15-15-12) from a
total of 17 mining units. The mines operate five days per week, 220 days per
year. Each loading unit consists of a continuous miner, a loading machine, two
shuttle cars, and a roof bolter. Shuttle cars dump coal into a feeder at the
end of the unit belt conveyor. Coal is transferred by a series of belt con-
veyors to the bunkers at the foot of the production shafts. Automatic skip
hoists bring the coal to the surface where it is conveyed to the preparation
area. Shiploads of mine rock are diverted to the refuse disposal system (breaker
reject bin).
The ROM coal undergoes only screening and primary crushing (plus 3-inch material)
for mine rock rejection and size control (also tramp iron removal by magnetic
separators). The 3-inch by 0 material is conveyed to 10,000-ton capacity silos
from which it is loaded into unit trains for shipment to the plant. The mines
employ floodloading of 120-car, 100-ton capacity unit trains at the rate of
3000 tons per hour. On the average, one unit trainload is shipped from each
mine five days a week. Two of the three mines ship a unit trainload on Satur-
day for a total of 17 unit train shipments per week.
Mine water in two of the three mines is acidic enough to require treatment for
iron removal before discharge. The other mine has good quality mine water and
uses much of it at the mining faces for dust control. The remainder is pumped
248
-------
to the surface and discharged after passing through a small holding basin.
Conventional acid mine drainage systems treat the acidic water — lime neutral-
ization, aeration, primary clarification, and secondary settling of solids in
a polishing pond.
At each of the three mines, mine rock and refuse from the rotary breaker are
conveyed overland to a disposal site. This coarse material is dumped, spread,
and compacted. The disposal areas are assumed to be shallow valleys that are
ultimately filled with the reject materials, and the disposal plans include
drainage control, erosion control, and revegetation schemes.
On the order of 30,000 acres of surface will be needed by the mines to produce
the required tonnage for the plant over its 20-year life.
The acres of surface land actually used by the mines for surface facilities and
reject disposal will be much less than the underground mine acreage.
COAL LIQUEFACTION PROCESS DESCRIPTION (H-COAL)
The coal liquefaction facility described in this section is based upon the use
of the H-Coal Process developed by Hydrocarbon Research, Inc.
The facility is designed to convert approximately 9.1 million tons per year of
high-sulfur Eastern coal into a low-sulfur fuel oil product as well as a low-
sulfur naphtha product.
The fuel oil production rate is 51,325 barrels per stream day. The fuel oil
sulfur content and gravity are 0.5 wt percent and -1.8 API respectively. The
naphtha production rate is 15,531 BPSD. The sulfur content and gravity of the
naphtha product are 0.02 wt percent and 38.2 API respectively.
In addition to the major products, the following byproducts are also produced:
• 1052.2 LTPSD of sulfur flakes
• 180.2 TPSD of liquid ammonia
• 17.9 TPSD of mixed phenols
• 4 MW of electrical power for export
The plant site (fenced area) occupies approximately 440 acres, but an additional
440-acre buffer zone is assumed to surround the plant. Figure 36 shows the
general plant layout. Coal is assumed to be delivered to the plant by unit
train on a contract dollars-per-ton-delivered basis.
Design Bases
The conceptual plant process design presented in this section is based upon the
design work performed by Fluor Engineers and Constructors, Inc. for the ERDA
Fossil Energy Division with only balance-of-plant (nonprocess) modifications
made to reflect the different hypothetical plant location.
249
-------
Ln
o
PLAKlf
-9-
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.
-
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/
6TORAC,C-
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-
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}
y,f
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^
- • —
/
- —
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Day
COAL
?aep
CATAL
tUNPLI
nAwtS
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STU
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Figure 36. H-coal liquefaction plant, plot plan.
-------
The specific reference material used in this evaluation is (7):
H-Coal Commercial Evaluation, Conceptual Design and Eco-
nomic Analysis for a 25,000 Ton-per-Day H-Coal Liquefaction
Plant, Case-I Fuel Oil Mode, prepared by Fluor Engineers
and Constructors, Inc., for the United States Energy Re-
search and Development Administration, under contract
No. E(49-18)-2002, March 1976, final unpublished report.
Table 93 presents the composition of the assumed coal feedstock for the plant,
which is the same as that used in the Fluor report (7).
TABLE 93. COAL FEEDSTOCK PROPERTIES (7)
Composition
Carbon, % wt
Hydrogen, % wt
Nitrogen, % wt
Oxygen, % wt
Sulfur, % wt
Moisture, % wt
Ash, % wt
Calculated HHV, Btu/lb
Calculated, LHV, Btu/lb
As Received
63.48
4.81
0.86
7.28
4.45
10.00
9.12
100.00
11,900
11,445
Ultimate
Analysis
70.50
5.40
0.95
8.10
4.90'
0.00
10.15
100.00
Table 94 presents the general design bases assumed for the conceptual plant.
The process descriptions, which follow, describe the major process facilities
which are depicted on the simplified block flow diagram, Figure 37. Table 95
presents the compositions of the major process streams identified on the block
flow diagram. Additional process details are available in the Fluor report (7)
251
-------
TABLE 94. COAL TO FUEL OIL DESIGN BASES AND ASSUMPTIONS
Plant Capacity
Coal Receiving
Onsite Coal Storage
Coal Feed Preparation
Coal Liquefaction
Product Separation
and Recovery
Gas Processing and
Recovery
Oxygen
Aqueous Effluent
Solid Waste Disposal
The design capacity of the commercial plant is
based upon the conversion of 25,000 STPD of dry
bituminous high sulfur coal into low sulfur
fuel oil
Unit train delivery and transported into the
processing facilities by conveyor belt
60 days dead,* 3 days live
Four 33% grinding, drying and classifying systems
have been provided
Six parallel-case slurry preheaters and ebullated
reactors are provided. The number of parallel
trains was set by imposing a maximum vessel dia-
meter of approximately 15 feet. This diameter
permits shop fabrication and use of rail shipping
facilities
The following number of parallel trains have
been provided for the liquid product separation
and recovery:
Liquid processing - 7
Naphtha stabilization - 1
Slurry flashing and stripping - 2
Solvent deashing - 7
The following number of parallel trains have
been provided for gas processing and recovery:
Hydrogen compression - 3
High-pressure absorption - 3
Low-pressure absorption - 3
5400 TPD of oxygen is required having a purity
of 97 volume percent. Three 1800 TPD trains
have been provided
Maximum cleanup and reuse of process wastewaters,
water treatment wastes, and contaminated storm
runoff. Excess storm runoff discharged to river.
High TDS aqueous blowdowns sent to aqueous waste
disposal system (undefined in Fluor report) -
assumed to be evaporative concentration *
Soot and slag wastes hauled by rail car to
contractor-operated landfill site for disposal
in valley fill operation *
(continued)
252
-------
TABLE 94. (Continued)
Gas Effluent All gaseous effluents from the plant will meet
the prevailing federal and state standardst
Plant Water Supply River water (pumphouse intake system*)
Onsite Water Storage 3-day storage capacity*
Plant Load Factor 91.3 percent
Plant Operating Life 20 years
* Balance-of-plant modifications different from Fluor report.
t Treated tail gas from the Glaus unit, as designed (1975), does not meet
NSPS for sulfur recovery units (Petroleum Refining, 40CFR 423, Subpart J
March, 1978)
253
-------
TABLE 95. H-COAL LIQUEFACTION PLANT
OVERALL MATERIAL BALANCE
25,000 TONS PER DAY -
t-o
t_n
-P-
Stream No. 1
Process
Description Coal
MPH
C 12,915.5
H 55,919.0
N2 715.1
09 5,285.7
S 3,228.7
Moisture 2,165.7
MPH 190,229.7
Ib/hr 1,918,290
Ash Ib/hr 211,960
TOTAL 11) /hr 2,130,250
TPSD 25,563
N4- A r
2
°2
CO
co2
H2S
NH
H20
H2
Cl
C2
C3
C4
C5-400°F
400-500°F
500-975°F
975+°F
n-C
MPH
Ib/hr
Solids Ib/hr
TOTAL Ib/hr
GPM-60°F
SCFM
2
Recycle
Hydrogen
MPH
3,819.0
—
1,642.4
621 .8
433.4
-
32.8
53,376. 7
6,678.8
971.9
334.8
98.0
43.0
-
-
-
-
68,052.6
463,650
-
463,650
-
430432
3 4
Makeup Heavy Dist.
Hydrogen Recycle
MPH MPH
577.5
— —
900.4 -
148.5
— -
—
36.9 117.3
41,572.6 -
197.4 -
— —
_
-
- -
393.6
6,166.1
0.1
-
43,433.3 6,677.1
133,656 1,346,005
- -
133,656 1,346,005
2690
274716 -
5
Hydroclone
Overhead
MPH
3.8
—
1.5
2.7
4.5
1.3
-
44.6
13.1
8.5
6.2
4.4
131.0
183.6
5,855.4
2,341.7
—
8,602.3
2,874,726
319,385
3,194,111
5614
_
678
Oxygen Slurry Naphtha
Feed Gasifier Product
MPH MPH MPH
418.9 -
13,614.3 -
_ _ _ _
- — —
0.3
— — —
7.5 0.5
_
— — —
— — — (
1.6
- - 42.2
1.1 1,764.9
1.6 4.3
174.5
403.9
26.4 16.0
14,033.2 615.0 1,829.8
451,650 328,747 189,096
331,425 -
451,640 660,172 189,096
1043 453
88761 - -
9
Heavy Fuel
Oil Product
MPH
61.4
V
p
1.2
360.6
1,821.5
550.9
0.2
2,795.8
816,203
885
817,088
1497
-------
PA.VJ Coil-
'I'-P'^TJtLfT1? p-^-Y^1-^
Ftas-p>.iiAT»o>4 k
H-CtfAL CEAdTloM
WA|feC
uATALV^T
I80.2TP6D
4MW? WET
l-.l-OkiK.-f C1II_
I MAPUTRA
^fAR>iUltATiOM
DCA-SHIM^J
Atiz.
Figure 37. H-coal liquefaction plant, simplified
block flow diagram.
-------
Coal Handling
Coal is delivered to the plant by unit train (average 100-ton capacity, 120-car
trains). Seventeen unit train deliveries per week will provide a total of
204,000 tons per week of coal. This quantity of coal is sufficient for around-
the-clock operation in the coal preparation unit. A three-day i*ve storage pile
and a 60-day dead storage pile have been provided. The car dump facility trans-
fers coal at a 3000-tph capacity to the stacking conveyors at the live storage
pile. Coal is reclaimed by the use of two parallel 48-inch conveyors.
Coal Crushing and Drying
Three operating Loesche Mills and one spare have been provided, each having a
capacity of 400 tph. The Loesche Mills are-capable of grinding, drying, and
classifying in one operation. Flue gases from fuel-gas-fired heaters dry the
coal. Cyclone collectors and wet scrubbers remove particulates from the gases
before discharge. The dried sized coal is transferred to the slurry preparation
area via Fuller-Kinyon pumps and a dense phase conveying system. Condensate
from coal drying is sent to the plant water system.
Coal Slurry Preparation and H-Coal Reaction
Coal slurrying is performed in 12 parallel trains. In each slurry vessel the
feed coal is mechanically mixed with hot slurry oil consisting of heavy distil-
late and slurry oil recycles.
The coal-oil slurry is then pumped to reactor pressure, mixed with recycle and
makeup hydrogen (about 263 MSCFM makeup), preheated, and charged to one of the
six reactors operating in parallel. Each reactor has its own slurry and hydro-
gen heaters. Four reciprocating charge pumps are required for each reactor.
The hydrogenation of the coal is accomplished in an ebullated reactor which is
designed to operate at 3000 psig and 850 F. At these conditions, more than
90 percent of the coal is liquefied. Each reactor is equipped with a pump, lo-
cated internally, providing sufficient liquid recirculation to maintain the cata-
lyst in an ebullated state and to maintain essentially isothermal conditions
across the reactor. Catalyst addition and removal facilities are provided to
permit continuous reactor operation. Each ebullated reactor has a 13-foot
10-inch ID and a 39-foot 0-inch (T-T) dimension.
The reactor vapor and liquid products containing the unreacted coal and ash are
discharged from the reactor in a common stream, passed to the reactor in a
common stream, and then passed to the reactor vapor-liquid separators.
Reactor Vapor Liquid Separation Recovery
The product separation area has two main design objectives. The first objec-
tive is to produce an intermediate-pressure hydrogen-rich stream for recycle
to the reactors. The second objective is to process the liquid product, con-
taining unreacted coal and ash, to yield a solids-free fuel oil for fraction-
ation, a slurry stream for the coal slurry operation, and a slurry stream
containing the net unreacted coal and ash.
256
-------
The slurry leaving the reactor vapor-liquid separator is subjected to a series
of cooling and pressure-reduction steps. The pressure reductions produce the
recycle hydrogen as well as a hydrocarbon distillate stream. The slurry leav-
ing the final low-pressure flash is led to a battery of hydroclones for further
solids concentration. Three trains, each containing 35 hydroclones, are em-
ployed (27 operating, seven spares). Each hydroclone is rated at approximately
130 gpm and operates with a pressure drop of 60 psig. The overhead from the
hydroclones is recycled back to the coal slurrying operation, while the hydro-
clone bottoms are sent to the solvent deashing area for further processing.
Slurry Stripping and Solvent Deashing
The feed to this process is the hydroclone bottoms. This unit separates heavy
hydrocarbon fractions from the unreacted coal and ash. The hydrocarbon frac-
tions are removed primarily by common physical methods such as flashing and
steam stripping followed by a gravitational separation of the solids by sol-
vent precipitation. The antisolvent used in this step is normal decane.
Three basic products result from this process operation. The primary product
is a heavy fuel oil which represents 80 percent of the overall facility output.
Secondary products are a light ends fraction which is further processed in the
naphtha stabilization section, and a heavy residuum fraction. The heavy re-
siduum fraction is used as the basic feedstock to the hydrogen plant.
The stripping and deashing operations are large and require multiple parallel
trains.
The stripping section consists of two trains, while the solvent deashing section
contains six trains, each train consisting of six parallel first-stage settlers.
Fractionation and Naphtha Stabilization
The feeds to the fractionation section are the distillate from the reactor vapor-
liquid separation step, and the slurry flash and light ends from the solvent
deashing step (113,864 BPSD of liquids and 15.47 MMSCFD of vapor). There are
three steps in the processing scheme. These steps include:
• Preheating of the feed to the fractionator
• Separation of the feed into naphtha (15,531 BPSD), middle
distillate (5211 BPSD), and heavy distillate (102,960 BPSD)
• Stabilization of the naphtha
The fractionation section consists of three trains, and the stabilization section
is a single train. The primary product of this unit is the production of the re-
maining 20 percent of the fuel oil product. This product is combined with the
output from the solvent deashing unit, and the combination represents the final
fuel oil product (51,325 BPSD) which is sent to storage tanks.
257
-------
Reactor Overhead Absorption and Stripping
This unit consists of a high-pressure lean oil absorption system for the re-
covery of heavy hydrocarbons and the separation of the hydrogen-rich recycle
gas (337.6 MSCFM hydrogen).
Gas Processing
This unit processes a combined feed of the sour gases produced in various areas
of the plant. The sour gases are scrubbed in a low-pressure absorber with a
65 wt percent diglycolamine (DGA) solution. The absorber overhead gas contains
only a trace of hydrogen sulfide and carbon dioxide. The regenerator overhead
contains all of the acid gas and becomes the feed to the sulfur plant (19.0
MMSCFD).
Hydrogen Plant
This plant furnishes 396 MMSCFD of hydrogen (95.8 percent H?), which is used
in the H-coal process for the hydrogenation of coal.
The Texaco Partial Oxidation Process is used to gasify the heavy residuum from
the solvent deashing step and produce a hydrogen synthesis gas. The heavy
residuum, containing approximately 50 wt percent solids, is gasified' in the
presence of 5400 tpd of oxygen.
The resulting synthesis gas is cooled and further processed in a shift conver-
sion reactor. This is a catalytic step which converts carbon monoxide to hydro-
gen. The resulting shifted gas now contains principally hydrogen, carbon di-
oxide, water, and hydrogen sulfide.
The shifted gas is then processed in a Selexol unit. The Selexol process is
an acid gas removal process offered by the Allied Chemical Co. The product
from a Selexol unit is a high-purity, dry, hydrogen stream. The product hydro-
gen is then compressed up to 2350 psig and fed to the H-coal reactors. The
other streams produced in the Selexol unit are a carbon-dioxide-rich gas vented
to the atmosphere; a hydrogen-sulfide-rich gas, which is fed to the sulfur
plant; and sour gas, which is fed to the sour water stripping unit. The CO
vent gas will contain some hydrogen sulfide, carbonyl sulfide, and nonmethane
hydrocarbons. It is probable that this stream may need to be scrubbed or in-
cinerated before release to the atmosphere.
Sour Water Stripping
The purpose of the sour water stripping unit is to separate and recover ammonia
from sour water and to obtain a hydrogen sulfide stream suitable for feeding
to a Glaus sulfur plant.
The process employed for this application is the Chevron WWT process. This
process is offered by Chevron Research.
258
-------
The products from this unit are:
• Liquid agricultural grade ammonia
• Water effluent (1810 gpm) containing 50 ppmw ammonia,
5 ppmw hydrogen sulfide, and phenols
• Hydrogen-sulfide-rich gas containing a maximum of 50 ppmw
ammonia
Sulfur Recovery
The sulfur plant takes the hydrogen-sulfide-rich streams from the gas process-
ing, hydrogen, and sour water stripping units and produces elemental sulfur
in a conventional Glaus plant. Three 50-percent capacity sulfur plants are
provided. The total sulfur production rate is about 1052 LTPSD. A tail gas
treating process is also provided for each sulfur plant. The Glaus plant has
been designed to achieve 96 percent overall recovery of hydrogen sulfide as
elemental sulfur. The inclusion of a tail gas treating process increases the
overall recovery to 99 percent. Cleaned tail gas streams are discharged to the
atmosphere through a common stack.
Auxiliary Systems
Oxygen Plant—
The oxygen plant is a conventional air separation plant designed to supply
5400 tpd of oxygen (as 100 percent). Three 1800-tpd trains are provided. The
oxygen product is used as a gasification reactant in the hydrogen plant.
Steam and Power Generation—
The H-coal process does not recover enough high-pressure steam from the pro-
cess to satisfy all motive and process steam requirements.
Two boilers are provided with a combined generating capacity of 1.8 million
pounds per hour of 1500 psig steam. The boilers are fired with sulfur-free
process offgas delivered by the fuel gas system. Three 50-percent turbogener-
ators have been provided. The installed capacity is 90 MWe with a normal
demand of 60 MWe. Two 150-foot-high stacks discharge boiler flue gases to
the atmosphere.
Product Storage and Loading—
This unit is designed for the storage of liquid products. Naphtha, middle"dis-
tillate, and heavy fuel oil together with recovered byproducts (all produced
in the process units) are stored, before delivery to industrial customers.
Intermediate storage is provided for slops, solids-content fuel, and liquid
products (startup oil, n-decane) purchased from outside sources for startup
and makeup.
Sulfur is stored as solid flakes in silos at the railroad. Naphtha and fuel
oil are shipped by pipeline; all other material is shipped by tank cars. The
pipelines are outside the scope of this study.
259
-------
The pumpout rate for naphtha and middle distillate is 1000 gpm, while the
pumpout rate for fuel oil is 2500 gpm.
Twenty-one-day storage capacity is provided for liquid hydrocarbon product
and ammonia. For all other intermediates and byproducts, the storage capacity
is as required by the process. The sulfur silos are sized for seven days of
storage.
Flare System and Stacks—
A relief system is provided to protect the process equipment from over-pressure
in conformance with accepted practice. It is assumed that a dual relief system
would be provided for this plant. One system will be provided for high pressure
and one system for low pressure. Relief lines will carry away process fluids
from the processing areas to the elevated flare stacks, where ignition will
occur in case of release. Separator drums are provided at the base of each
stack to capture liquids which are then pumped to slops storage. Molecular
seals are provided in each stack to prevent air intrusion into the relief
system.
Water Systems—
Figure 38 presents a simplified diagram of the H-coal water system. The plant
makeup water demand is about 9100 gpm (9092 gpm design average). Maximum supply
capacity is 16,000 gpm from three 33-percent capacity pumps in the intake pump-
house. River water is pumped through a 24-inch diameter line to the onsite
storage pond. This 39-million-gallon earthen basin provides three days of
makeup (design capacity). River water is used for cooling-tower makeup, fire
water, potable water, utility water, process water, and boiler feedwater make-
up. Three pondwater pumps supply makeup water to the cooling towers (5073 gpm)
and water (3694 gpm) to granular media filters for suspended solids removal
prior to additional treatment. Additional pondwater pumps feed the potable
and utility water systems.
Pondwater is treated in a packaged system for filtration and chlorination to
produce about 125 gpm of potable quality water. An air-pressurized surge tank
is provided for distributing water throughout the plant. About 200 gpm of
pondwater is supplied to the utility distribution system. Utility water losses
from miscellaneous use are estimated at 50 gpm.
Boiler feedwater treatment consists of reverse osmosis (RO) followed by mixed-
bed ion exchange or polish demineralization. Micron filter units precede the
RO membrane modules to remove fine particulate matter, helping to minimize
membrane fouling. RO product (about 90-percent recovery) contains 40 to 50 mg/1
TDS, and 1810 gpm is used for makeup to the process units. Much of the process
water is recovered as stripped sour water.
The mixed bed units produce 1400 gpm of boiler feedwater makeup with a TDS level
of two mg/1 of less. The granular media filter and micron filter backwashes
and the RO concentrate brine are collected for treatment and reuse in the cool-
ing water system. The low TDS backwash and rinse waters from ion exchange re-
generation are fed back to the RO system ahead of the micron filters. High TDS
acid and caustic regenerant wastes are neutralized.
260
-------
COAL YARD
SETTLING
BASINS
DISCHKRGE.
(444-844)
COAL | COAL [PRODUCT' GAS [ SULFUR] o2 ! u* SOUR [PRODUCT!
~ PREP. IH-*DROG.I RE.COV. PROCESS.; PLANT , PLANT PLANT i V*>'ItR , STORAGE!
, , | , ; | ! STRIP.; 1
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D.
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|
<
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j^ •> (0-tOOO)
FIRt WLTER
(SOU) MAKEUP
a t FILTRATION
'-A-
j POT. \NAUR
~°~* TREATMENT
4>- 111
* ^ (200)
TAMINATED RUNOFF
,_.
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r (14) BACKW
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c
daio)
STRIPP
BTM
AQUEOU11
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ER
WASTE
— » ^ NAPHTHA 15,531 BPSD
— > ^> FUtL OIL 51,^25 BPSD
>•«- I .
'ARATIONI *
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sues
UfW HAKEUP
^
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1 SRIMtt
ER NEUTRAL
KIT BASIN
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LOSSES (SO)
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; t4is) i
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HDEEP BE-0 I
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T BOILER
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V
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ASIN
RUNOFF
(2IS-4I5)
1
-- (SIS)
(AU.)
r
O
EUSt
PHtNOL I (1120) E.V
RECOVERvl
COOLING 1
) • lutfJLK'j 1
(3639) 1
<>- (495
, (}244) BLO
, (104)
< - (416
LIME- SODA |
• SOFTEWFR!
(4410) EV
-------
Steam pressure levels in the plant include 1500 psig, 600 psig, 150Qpsig, and
50 psig. Two process fuel-gas-fired boilers produce 1500 psig, 900 F steam
for power generation. Saturated 1500 psig.steam from hydrogen plant steam
generation is superheated in a fuel-gas heater to provide additional steam
supply to the turbine generators. Turbine exhause steam is condensed and re-
turned to the condensate distribution system. Other process steam generators
produce 50 and 150 psig steam for process and utility use. Process and utility
steam consumption and losses total 1333 gpm. Steam generator blowdown streams
total 67 gpm; the blowdowns are collected for reuse in the cooling water sys-
tems. Boiler water conditioning chemicals include hydrazine, morpholine, and
sodium phosphates.
Two separate cooling water systems are provided, one for the power plant and
the second for the process units. The cooling systems are operated in a cas-
cade mode, with blowdown from the power-plant system softened and used as make-
up to the process cooling system.
The design circulation rate for the power-plant cooling water is 120,000 gpm.
Two six-cell induced draft cooling towers cool the hot-side condenser return
water to 85 F. Evaporation and drift losses total 3144 gpm. The towers are
operated at about seven cycles of concentration (about 1700 mg/1 TDS). Make-
up is about half river water and half treated process effluent from sour water
stripping (Chevron WWT process).
The process cooling water circulation rate is about 153,000 gpm (design). Two
seven-cell towers reject the process heat load to the atmosphere with tower
evaporation and drift losses of 4400 gpm. Makeup to this system is a lime-
soda softened combination of river water (3244 gpm), cooling tower blowdown
(495 gpm), water treatment wastes (467 gpm), and wastewaters (579 gpm) includ-
ing storm runoff. Lime-soda softening of the makeup reduces the hardness
enough to permit operation at high (up to 20) cycles of concentration' with-
out unmanageable scaling of the heat transfer surfaces. Circulating water TDS
levels on the order of 10,000 mg/1 are maintained. Blowdown is combined with
other high TDS streams for final effluent treatment. Both cooling water sys-
tems use sulfuric acid for pH control and proprietary chemicals for corrosion
inhibition, scale control, and sludge dispersion. Biological fouling is con-
trolled with chlorine.
The plant wastewater treatment systems are designed primarily to clean up
effluents for reuse.
Storm runoff from process and hydrocarbon tankage areas is collected in storm
sewers and sent to the forebay section of a 35-million-gallon storm basin.
The basin can impound about three inches of runoff from the entire plant site
(440 acres). Normally only the first portion (contaminated) of the rainfall
runoff is directed to the forebay; the remainder is diverted to the main basin.
Utility wastewaters and condensate from the coal dryer system are also directed
to the forebay section. Storm runoff from plant areas where contamination will
not occur flows directly to the main basin.
Two seven-million-gallon settling basins accept runoff from the coal storage
yard (56 acres). Runoff contacting the dead and live piles, as well as
262
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surfaces around the piles, may pick up significant amounts of coal dust. Pro-
longed contact with the coal may also result in leaching of contaminants. The
basins not only provide suspended solids settling capacity, but also can impound
a significant volume of contaminated drainage for either treatment of workoff
at a low rate through the main storm basin. At an annual runoff of 25 inches
(42 inches precipitation) over 400 acres of drained plant area, the runoff vol-
ume would average 516 gpm on a continuous basis. Up to 200 gpm can be pumped
from the main basin to the softener unit. Excess runoff is discharged to the
river.
Contaminated runoff from the forebay is treated in a gravity oil/water separa-
tor, either API or CPI (corrugated plate interceptor) type. Skimmed oil is
pumped to slop tanks for recovery. Settled sludge is pumped periodically to
a hold tank for subsequent dewatering. Effluent water from the separator is
treated in a deep bed filtration unit for additional oil and suspended solids
removal. Filter backwash is returned to the forebay of the storm basin. Fil-
tered effluent (40 gpm average) is collected in a basin with other wastes
(treated sanitary wastewater, boiler blowdown, and potable water filter back-
wash) for pumping to the lime-soda softener.
Sanitary sewage (100 gpm) is treated in a package unit which employs extended
aeration, biological treatment, clarification, tertiary filtration, and dis-
infection. __ Effluent is sent to the wastewater collection basin.
The main process effluent is 1810 gpm of wastewater from the Chevron WWT unit.
Flotable oil which may be present is recovered in an oil/water separator. This
unit is follow by a phenol recovery system to remove dissolved hydrocarbons,
principally phenols. The recovery process employs polymeric adsorbent resin.
The resin beds are regenerated with acetone and the crude (mixed) phenols are
recovered by distillation. The cleaned process effluent '(containing small
amounts of ammonia and phenol) is combined with raw water for reuse as makeup
to the power plant cooling tower.
*
The plant effluents consist of cooling tower blowdown (202 gpm), ion exchange
regenerant brines* (7 gpm), and aqueous waste" (230 gpm) from the hydrogen
plant — in addition to excess stormwater (during heavy rainfall periods). If
these normally high TDS plant effluents were free of contaminants other than
salinity, they might be discharged to the river with little impact. The aqueous
waste from the hydrogen plant could contain dissolved organics, inorganics
(including trace metals), sulfur, and nitrogen compounds. It is assumed that
an aqueous treatment system such as a multiple effect evaporator or vapor re-
compression evaporator would be used to further concentrate the wastes into a
filtrable slurry and to recover water as condensate for reuse or discharge,
perhaps with additional treatment required. The filter cake from the aqueous
treatment system could be mixed with the soot and slag for landfill disposal.
"The Fluor report assumes these high-TDS plant effluents are disposed of at
a charge of $5/1000 gallons.
263
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Miscellaneous aqueous wastes are also generated periodically and are handled
by batch treatment (with aqueous portions discharged to the forebay of the
storm basin).
Solid Waste Disposal—
The major solid*wastes produced by the plant are soot (207.6 tpd) and slag
(2543.5 tpd) from the hydrogen plant and derived from the coal feedstock.
These materials are loaded into rail hopper cars for shipment offsite to a
contractor-operated landfill under the supervision of the plant owner. The
landfill site is a typical valley fill operation similar to those in the vi-
cinity used for disposal of mine and coal preparation plant refuse. Over
the life of the plant, some 18 million tons (dry) will be deposited.
Other plant solid wastes include lime-soda softener sludge, sludges from oil
recovery operations, plant trash and garbage, and infrequent sludges resulting
'from equipment cleaning and basin cleanouts. It is assumed that items such as
waste oils and scrap metals will be salvaged and that spent catalysts will be
sent offsite for regeneration or disposal. These other solid wastes are de-
watered where necessary and hauled by truck to the soot and slag landfill site
for burial. The plant trash and garbage may be buried in a separate designated
area of the fill site.
Plant Thermal Balance
The summary energy balance shown in Table 96 indicates an overall plant thermal
efficiency of 67.7 percent (68.4 percent on an HHV basis). The Fluor report
notes also that the Texaco package (H0 plant ) is conservative with respect to
energy demands, especially steam (pernaps 50 percent less) and oxygen (8 to
10 percent less), so that the overall balance could be better than indicated.
Addition of balance-of-plant modifications such as a waiter supply system and
aqueous waste treatment facilities (high TDS waste concentration unit and
sludge dewatering facilities) would consume some additional electrical power
and perhaps steam, drawing down the improved balance somewhat.
Consumption and losses of 32.3 percent of input are represented principally
be electric power consumption (and mechanical losses), steam power consumption
(drivers), and heat rejected to the atmosphere by the process and power cooling
systems and heat in hot flue gases from fired heaters.
The clean fuel products, naphtha (5.39 MM Btu/bbl) and fuel oil (6.5 MM Btu/bbl),
represent 65.6 percent of the total energy input. Their properties are con-
siderably different and their values as products could be considered economi-
cally different. The sulfur content in each product represents less than ten
percent of that in the as-received coal on a pounds per million Btu basis.
The heavy fuel oil could theoretically be burned in a power plant without an
FGD system if the credit for fuel pretreatment were allowed. The naphtha prod-
uct could also be used as a boiler fuel though it would probably be sold as
a more valuable product.
264
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TABLE 96. SUMMARY ENERGY BALANCE - H-COAL PROCESS
Element MM Btu/hr Percent of Total
Energy Input (LHV)
, Total Coal to Process 26,542 100.0
Energy Output (LHV)
Products
Naphtha
Fuel Oil
Product Subtotal
Byproducts
Ammonia
Phenol
Sulfur
Electricity*
Subtotal (Products and
Byproducts)
Consumption and Losses
(Difference)
Total Energy Distribution
3,496
13,904
17,400
121
25
392
42
17,980
8,562
26,542
13.
52.
65.
0.
0.
1.
0.
67.
32.
100.
2
3
5
4
1
5
2
7
3
0
*Fuel Equivalent 10,000 Btu/kWh
265
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COAL LIQUEFACTION PLANT COSTS
In the Fluor commercial evaluation report (7), construction costs were sum-
marized by major process unit. That general format is retained here. Their
mid-1975 equipment and labor costs were updated to first quarter 1978 (see
Appendix C for details). Nonprocess*modification costs, such as the addition
of a water intake system and an effluent discharge system, were added to the
updated costs.
The toal capital cost of $1.64 billion shown in Table 97 represents an invest-
ment of about $24,500/BPD of oil production. Specific pollution control costs
were not identified in the Fluor report. Construction costs for the sulfur
plant, sour water treatment, a small portion of coal preparation, a portion
(ash handling) of the hydrogen plant, and a- significant portion of offsites
and utilities could be allocated as pollution control costs. These could
total five to ten percent of the total construction sosts. Additional costs
could be incurred if CO vent gas were incinerated and if the sulfur recovery
unit were to meet NSPS for SO emission concentration of 0.025 percent in
treated tail gas.
Annual operating and maintenance costs (Table 98) total $122.7 million or
$5.50/bbl of naphtha and fuel oil output. Byproduct credits for sulfur, li-
quid ammonia, and mixed phenols reduce the annual operating expenses by $13.9
million or $0.62/bbl. Catalyst and chemicals, labor, and maintenance materials
are large direct operating expenses, representing more than 60 percent of the
total.
Allowances of $1.50/ton for solid waste disposal and $7.50/M gal for aqueous
waste disposal were included as operating costs. If the major process residues
from the plant were classified as hazardous materials, the cost for an environ-
mentally secure landfill disposal might well be higher than $1.50/ton. It is
also likely that the plant would need to install treatment systems for the
aqueous waste effluent and for sludges from water and wastewater treatment.
Charges for solid and aqueous waste systems would add several millions to
the capital cost and could increase annual operating costs. A substantial
increase in the cost of synthetic oil production would probably not occur from
these changes.
The sensitivity of oil cost to the cost of coal is shown in Figure 39 for
utility and private financing. Both the naphtha and the heavy fuel oil have
been combined for simplicity. Oil production costs (zero coal cost) are about
$13.70 and $20.40 per barrel, respectively. Assuming a $25 per ton base price
for high sulfur coal, the oil costs are $24.50 and $30.88 per barrel. At
current fuel oil prices of up to $2.50/MM Btu, these synthetic oil costs of
about $3.90 and $4.90/MM Btu are not very competitive as a low-sulfur boiler
fuel. The naphtha, of course, is a more valuable product than the heavy fuel
oil. If separate pricing were considered, the relative heavy fuel oil cost
would be less (see Fluor report, Ref. (7)).
266
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TABLE 97. H-COAL CAPITAL COSTS
Element
$l,000,000's
Coal Preparation
Coal Hydrogenation
Product Recovery
Gas Processing
Sulfur Plant
Oxygen Plant
Hydrogen Plant
Sour Water Treatment
Product Storage and Loading
Offsite and Utilities
DIRECT FIELD COST
Indirect Field Cost
TOTAL FIELD COST
Engineering Services
Allowance for Uncertainty
TOTAL CONSTRUCTION COST
Land
Other Owner Costs
Startup
Allowance for Funds During Construction
FIXED CAPITAL INVESTMENT
Working Capital
TOTAL CAPITAL COST
First Quarter 1978,. Price and Wage Levels
74.0
129.0
64.0
28.0
19.0
101.0
175.0
19.0
37.0
222.9
5.9
130.0
998.9
120.0
1,118.9
168.0
1,286.9
1.0
23.7
47.3
203.8
1,562.7
77.3
1,640.0
267
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*
TABLE 98. ANNUAL OPERATING AND MAINTENANCE COSTS - H-COAL
Element $l,000,000's
Water 0.2
Catalyst and Chemicals 20.8
Operating and Maintenance Labor , 17.5
Maintenance Materials 38.9
Supplies and Materials, Allowance 2.4
Insurance 9.6
Nonincome Tax 25.7
General Overhead and Administrative 4.0
Waste Disposal Allowance, Ash' 2.0
Waste Disposal Allowance, Aqueous Effluent** 1. 6
TOTAL ANNUAL OPERATING COST 122.7
Byproduct Credits 13.9
NET ANNUAL OPERATING COST 108.8
First Quarter 1978, Price and Wage Levels
-Excluding coal feedstock.
r$1.50/ton.
*$7.50/11 gal.
268
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0.5
COAL COST, S/MMBTU
1.0 1.5
2 0
100
COAL LIQUEFACTION
(H-COAL)
PRIVATE
UTILITY
80
60
CO
CD
O
LL
O
O
O
40
20
10
Figure 39.
20 30
COAL COST, S/TON
40
Effect of coal cost on cost of oil with
both private and utility financing.
269
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COAL LIQUEFACTION ENVIRONMENTAL ASSESSMENT
Coal Procurement Impacts
About nine million tons of coal per year will be obtained from an existing
underground mine complex in the eastern U.S. Underground mines have different
impacts from surface mines since so little of the surface land area is involved.
Topography—
Construction of aboveground handling facilities will affect topography locally,
but the major impact on topography will be the disposal of mine rock. Shallow
valleys will be filled, altering the hilly character of the area and resulting
in a more regular terrain with less surface relief.
Geology and Soils—
Mine rock has a potential for erosion and, in addition, will alter the surface
characteristics of much land area. Other geological effects will include:
• Removal of the coal, a nonrenewable resource
• Potential subsidence of the area over the mine after
abandonment
Groundwater—
Mine water from the two hypothetical mines will have to be removed, treated,
and disposed of. This water is a low-quality groundwater which will not be
committed to other regional uses. The third mine has good quality water which,
while it can be used in the mining operation (dust control), does result in a
reduction in local, and possibly regional, groundwater supplies.
Leaching from mine rock will have a small potential for contamination of ground-
water, but this potential is dependent on the quality of the refuse.
Surface Water—
Disposal of acid mine water after treatment for iron and acidity reduction
could add to present water quality problems in nearby drainage sy"stems.
Air Quality—
Fugitive dust and gaseous emissions from the mine and from coal handling may
locally degrade air quality. Dust control on mine faces, coal piles, and mine
rock disposal, as well as the use of pollution controls on the conveyor dis-
charge points, screens, and primary crushers, will reduce these emissions.
Mine water may be used for this dust control, reducing discharges to surface
water as well.
Vegetation—
Only a small acreage of agricultural or woodland vegetation will be affected by
mine buildings, coal handling, or transport facilities. However, several hun-
dred acres of shallow valleys will be filled with mine rock, eliminating ri-
parian vegetation which is valuable wildlife habitat. While revegetation is
contemplated, it is not likely that the same species mix would be reestablished
and the value to wildlife would be reduced.
270
-------
Wildlife—
A total regional reduction in species dependent on riparian woodlands will
occur with ongoing mine rock disposal. This could have a particular impact
on the bald eagle, an endangered species which usually nests near water in ri-
parian woodlands.
Land Use—
Agricultural and woodland uses will be foreclosed in mine rock disposal areas.
In addition, construction over the mined area may be restricted by the poten-
tial for subsidence.
Aesthetics—
Deep underground mines do not have the visual character typical of surface
mines and tend not to have the aesthetic impact of surface mines. However;
changes in topography and vegetation due to mine rock disposal will have an
adverse aesthetic impact over a large area.
Social and Economic Effects—
The opening of three mines and the sale of more than nine million tons per
year of coal (about $230 million at $25/ton) will result in more jobs, income,
and no increases in population are likely.
Table 99 presents a brief summary of potential coal procurement impacts and
mitigating measures.
Plant Impacts
Environmental impacts of the coal liquefaction project will result from plant
construction and from operation of the plant over its 20-year life. The total
construction period from start of engineering to completion of construction is
assumed to be five years, and 3000 to 4000 workers will be on the site at the
peak of construction. Construction activities will primarily result in short-
term impacts on the physical environment, except for the permanent alteration
of the land surface. Emissions from the operating plant may have longer-term
adverse impacts on the physical and biological environment. Economic benefits
will be derived from construction and operation. The plant will produce clean
fuels and other byproducts for offsite consumption. The plant will consume
resources as summarized in Tables 100 and 101. Additional resources — fuel,
power, water, manpower, some chemicals, and all of the plant construction ma-
terials — will be used during plant construction.
This brief environmental assessment will focus on estimated impacts of the
operating plant.
Physical/Chemical Emissions and Impacts—
Air, water, and solid waste emissions were estimated for the liquefaction plant
based primarily on information contained in the Fluor report (7) and on Bechtel
estimates where no information was available.
271
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TABLE 99. PROCUREMENT IMPACT SUMMARY — COAL
Environmental Factors
Coal Mining Impacts
Mitigating Measures
Topography
Soils and Geology
Groundwater
Quality
Surface Water
Air Quality
Vegetation and
Wildlife
Land Use
Aesthetics
Community Economy
Community Population
and Services
Labor Availability
Transportation
Major local change due to
mine rock disposal
Potential for subsidence;
change in surface character
at mine rock disposal sites
Potential for disruption of
flow by dewatering; leaching
from mine rock disposal
Degradation from runoff,
erosion, mine water
discharge
Fugitive dust
Loss of large acreage of
riparian habitat at mine
rock disposal site
Change in use at mine rock
disposal site
Sharp visual effects at
mine rock site
Potential for jobs, salaries,
tax base
No change expected
Sufficient labor pool
Mine site roads and rail-
roads required
Revegetation of
mine rock site;
treatment of mine
water
Dust control
Revegetation
Revegetation
272
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TABLE 100. PRINCIPAL RESOURCES COMMITTED TO H-COAL PLANT OPERATION
Resource Category
Quantity
Normalized Quantity
(Output)*
Land
Coal (11,900 Btu/lb)
Auxiliary Fuel
(Vehicles)
Auxiliary Power (Net
Production)
Water (9,092 gpm)
Catalysts and Chemicals
Manpower (726 Employees)
440 acres
9,277,740 tons/yr
100,000 gal/yr
(32 MM kWh/yr)
4,364 MM gal/yr
37,950 tons/yr
1.53 MM manhours/yr
/
6.6 acres/MBPD
133,3 Ib/MM Btu
79 Btu/MM Btu
31.35 gal/MM Btu
0.545 Ib/MM Btu
0.011 manhours/MM Btu
*Basis: 139,200 trillion Btu/yr (LHV)
--Increases to 13.2 acres/MBPD if 440-acre buffer zone is included.
273
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TABLE 101. ESTIMATED ANNUAL CATALYSTS AND CHEMICALS MAKEUP (7)
Material
HDS-2A Catalyst
Bauxite Catalyst
Cobalt-Moly Catalyst
Shift Catalyst
n-decane, Antisolvent
Diglycolamine
Selexol Solvent-
Lime (90% CaO)
Soda Ash (98%)
Sulfuric Acid (66° Be)
Caustic Soda (100%)
Biocide
Corrosion Inhibitor (Nonchromate)
Surfactant (Polymeric)
Scale and Sludge Control Agent (Dispersant)
Hydrazine (35%)
Mo rp ho line
Disodium Phosphate (Anhydrous)
Trisodium Phosphate (Anhydrous)
Acetone
Dust Suppression Agent
Diesel and Gasoline Fuels
Quantity
4,125 tons/yr
13.2 tons/yr
51.8 tons/yr
85.1 tons/yr
24,244 tons/yr
22.4 tons/yr
67.5 tons/yr
3,505 tons/yr
2,641 tons/yr
2,160 tons/yr
150 tons/yr
50 tons/yr
60 tons/yr
30 tons/yr
118 tons/yr
65 tons/yr
12 tons/yr
8 tons/yr
10.4 tons/yr
528.4 tons/yr
3,000 gal/yr
100,000 gal/yr
274
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Air Emissions—The coal liquefaction plant will contain a significant number
of point emission sources — from coal handling, from combustion units (process
heaters and utility boilers), and from process vents. Table 102 presents esti-
mates of air pollutant emissions from the plant, categorized principally as
fugitive dust, sulfur compounds, nitrogen oxides, carbon monoxide, and hydro-
carbons.
Coal handling will result in the release of fugitive emissions (coal dust) from
both point and area sources. The quantities of dust emissions from the coal
car dump hoppers, the coal stacker discharge, the bucket wheel reclaimer, and
the storage piles will vary considerably and are difficult to estimate. Wind-
blown dust emissions can be reduced by wet" chemical suppression or enclosures
at transfer points, sealing the dead storage pile, and periodic application of
chemical dust suppressants on the live storage pile. Very rough estimates of
fugitive dust releases in Table 102 indicate the potential for high local par-
ticulate concentrations in the air. Most of the heavier windblown dust parti-
cles will settle out in the vicinity of the release points, so that fugitive
coal dust will not seriously degrade ambient air quality offsite.
Reclaimed coal will be ground in mills and dried using hot flue gases from
three process gas-fired heaters. The dust-laden flue gas will pass through
cyclone collectors and a wet scrubber before discharge to the atmosphere. The
vented gas will contain some particulates plus small quantities of combustion
product pollutants. Other process heaters, as well as the two power plant
boilers, will also burn sulfur-free process gas, emitting small quantities of
combustion product pollutants. Nitrogen oxide emissions are assumed to meet
the proposed NSPS of 0.2 Ib NO /MM Btu input for gas-fired steam-electric
generators.
A small quantity of process vent gases will be incinerated in the flare systems.
Sulfur dioxide is formed from combustion of sulfur compounds in vent gases.
Hydrocarbons are converted to carbon dioxide and water.
The acid removal systems in the hydrogen plant will have carbon-dioxide-rich
vent streams containing small quantities of hydrogen sulfide, carbon monoxide,
hydrogen, and methane. Trace quantities of other non-methane organics will
likely be present (possibly including toxic compounds) . The large vent gas
flows will result in significant pollutant releases on an annual basis, It is
possible that incineration or scrubbing may be required as additional treatment
for these vent gases.
The sulfur plant will convert more than 99 percent of the feed sulfur compounds
into elemental sulfur. The tail gas, after cleanup, will contain about
1100 ppmv of sulfur oxides. Even though a large quantity of sulfur (over
1000 tons per day) will be removed from the sulfur-laden gases, the cleaned
tail gas will still constitute a major sulfur oxide emission source of about
nine tons per day. The S0_ concentration estimated here exceeds the NSPS for
sulfur recovery units in refineries. Additional tail gas sulfur removal could
be required.
275
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TABLE 102. SUMMARY OF ESTIMATED AIR EMISSIONS - COAL- TO- OIL
Source
Flow Quantity
Pollutants
Emission Rate
Coal Car Dump Station
(8 hoppers)
(wet suppression)
Coal Pile Stacker
Discharge(l)
(wet suppression)
Coal Reclaimer(l)
(wet suppression)
Dead Storage Pile,
60 days (sealed)
Live Storage Piles,
3 days
(wet suppression)
Coal Surge Bins(3)
(bin vent collectors)
Coal Dryer Flue
Gases(3)
(after cyclones and
wet scrubbing)
Process Heater
Flue Gases(12)
Flare Gases,
H.P. and L.P. Flares
Process Heater Flue
Gases(6)
H2 Plant C
Vent Gases (2)
3,000 tph
33,000 tpd avg
(6 days/wk)
3,000 tph
33,000 tpd avg
(6 days/week)
1,200 tph
27,836 tpd
1,670,000 tons
15 acres
Fugitive coal dust
(0.05 Ib/ton)
Fugitive coal dust
(0.05 Ib/ton)
Fugitive coal dust
(0.05 Ib/ton)
Fugitive coal dust
(0.01 Ib/ton/mo)
1650 Ib/day
1650 Ib/day
1400 Ib/day
560 Ib/day
83,500 tons
6.5 acres
1,200 tph
27,836 tpd
169,800 SCFM
(486 MM Btu/hr
input)
176,700 SCFM
(832 MM Btu/hr
input)
422 SCFM
59,470 SCFM
(280 MM Btu/hr
input)
190,540 SCFM
Fugitive coal dust
(0.1 Ib/ton/mo)
Fugitive coal dust
Particulate matter
(0.08 gr/CF)*
NOX(0.2 Ib/MM Btu)*
C0(0.05 Ib/MM Btu)*
HC(0.02 Ib/MM Btu)*
N0x(0.2 Ib/MM Btu)*
C0*(0.05 Ib/MM Btu)*
HC(0.02 Ib/MM Btu)*
sox
CO
HC
NOX(0.2 Ib/MM Btu)*
CO (0.05 Ib/MM Btu)*
HC(0.02 Ib/MM Btu)*
H2S
CO
H2
CH4
280 Ib/day
130 Ib/day
116 Ib/hr
97 Ib/hr
24 Ib/hr
10 Ib/hr
166 Ib/hr
42 Ib/hr
17 Ib/hr
50 Ib/hr
trace Ib/hr
trace Ib/hr
56 Ib/hr
14 Ib/hr
6 Ib/hr
17 Ib/hr
312 Ib/hr
131 Ib/hr
114 Ib/hr
COS and other organics small amounts
(Continued)
276
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TABLE 102. (Continued)
Source
Flow Quantity
Pollutants
Emission Rate
02 Plant
Nitrogen Vent(3)
Sulfur Plant
Tail Gas(l)
Power Plant
Cooling Towers(2)
Process Cooling
Towers(2)
Boiler Flue Gases(2)
Soot and Slag
Car Loading
Hydrocarbon Storage
and Transfer
Ammonia Storage
And Transfer
293,390 SCFM
Nitrogen
66,660 SCFM
(34 MM Btu/hr
input)
3,510,000 SCFM
dry air,
1,560,000 Ib/hr
water vapor
4,480,000 SCFM
dry air
2,205,000 Ib/hr
water vapor
574,560 SCFM
(2705 MM/Btu hr
input)
3,980 tons
per day(wet)
1.9 MM bbl
storage capacity,
naphtha, fuel oil,
mid-dist., sol-
vent , phenols
46,000 cu ft
capacity
None
SOX
NOX(.2 Ib/MM Btu)-
Drift(water droplets)
TDS (salts)
Chemicals**
Thermal
768 Ib/hr
6.8 Ib/hr
12,000 Ib/hr
20.4 Ib/hr
7.4 Ib/hr
2,100 MM Btu/hr
Drift (water droplets) 15,000 Ib/hr
TDS (salts) 150 Ib/hr
Chemicals** 10.8 Ib/hr
Thermal 2,678 MM/Btu/hr
sox
NOX(0.2 Ib/MM Btu)*
C0(0.05 Ib/MM Btu)*
HC(0.02 Ib/MM Btu)*
Fugitive dust
Small amount
541 Ib/hr
135 Ib/hr
54 Ib/hr
Small amount
Fugitive hydrocarbons No estimate
Ammonia
No estimate
-'Assumed emission factors.
**Water treatment chemicals in drift.
277
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The oxygen plant nitrogen vents and the power plant and process cooling tower
will be large volumetric rate emission sources — though relatively free of
pollutants. Drift from the power plant cooling towers will carry out salts
and chemicals added to the cooling water and possibly some ammonia hydrogen
sulfide and residual phenols. These materials may also be stripped by the air/
water contact and appear in the exhaust vapor. Drift from the process unit
cooling towers will carry out about 150 Ib/hr of dissolved solids, most of
which will be deposited on the ground in the vicinity of the towers. There
is also the potential of organics and ammonia in the circulating water being
stripped into the exhaust air as well as being carried out in the drift.
The many pumps, valves, tanks, and vessels in the H-coal facility will be
sources of fugitive hydrocarbon emission because of minor leakage, storage,
and transfer losses. Total product storage capacity for the hydrocarbon li-
quids will be about 1.9 million barrels. Most of this tankage capacity is
for heavy fuel oil, and vapor losses should be small. No estimates of fugitive
hydrocarbon emissions or characteristics were made, however. The concern about
emissions of potentially harmful compounds from synthetic fuel liquids should
be noted.
Overall, the H-coal facility will emit a substantial tonnage per year of par-
ticulates, SO,,, NCL, CO, and hydrocarbons. These emissions will result in a
small degradation of ambient air quality in the vicinity of the plant. It is
assumed that installation of this facility will not result in significant de-
terioration of regional air quality for designated pollutants other than photo-
chemical oxidants. Emission offsets will probably be required as well as
the use of best available control technology.
Wastewater Emissions—Table 103 lists major aqueous streams identified in the
Fluor report (7). The water management scheme, as designed, includes internal
treatment and recycling of streams to minimize the plant makeup water demand
and to reduce the volume of aqueous effluent to be disposed of (assumed off-
site disposal). Characteristics of internal recycle streams were not well
defined. It is anticipated that the concentrated aqueous wastes (cooling tower
blowdown, regenerant brines, and the H plant waste) will contain a variety of
inorganic and organic constituents. Water treating chemicals, residual pollu-
tants from process effluents, and pollutant materials introduced from soot and
slag handling will be present.
An onsite waste treatment system could be used to produce an effluent acceptable
for discharge or reuse. A wastewater evaporator would concentrate nonvolatile
inorganics and organics into slurry form for dewatering and offsite landfill
disposal. Further cleanup of the condensate could be needed if ammonia or
other volatile constituents were present in concentrations too high for dis-
charge or for reuse in the plant. Upsets in internal treatment or recycle
systems could also result in the temporary discharge to the river of untreated
or partially treated wastewater. A short-term adverse effect on surface water
quality could occur. The main storm basin will probably be used for impound-
ment of contaminated water during upset periods.
278
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TABLE 103. SUMMARY OF ESTIMATED WASTEWATER EMISSIONS
COAL TO OIL
Source
Estimated Flow
Pollutants
Emission Rate
WWT Effluent
(after treatment)
Granular Media
Filter Backwash
Micron Filter
Backwash
Sanitary Wastewater
(after treatment)
Utility Wastewater
(after treatment)
ISlOgpm
(used as C.T.
makeup)
75 gpm
(intermittent)
(softened for
reuse)
37 gpm
(intermittent)
(softened for
reuse)
100 gpm
(softened for
reuse)
200 gpm
(softened for
reuse)
Phenols (4mg/l)
NH3 (50 ing/I)
H2S (5 mg/1)
PH
TSS
BOD
TSS
BOD(<20 mg/1)
TSS(<20 mg/1)
Colif orms
pH
Oil & Grease
(<10 mg/1)
TSS(<20 mg/1)
No direct emission
No direct emission'
No direct emission
No direct emission
No direct emission
Contaminated Storm
Runoff (after
treatment)
Boiler Slowdown
60 gpm annual
avg
(softened for
reuse)
67 gpm
(softened for
reuse)
Coal Dryer Condensate 200 gpm
(after treatment) (softened for
reuse)
Oil & Grease
(<10 mg/1)
TSS(<20 mg/1)
pH
TDS*
TSS
PH
Oil & Grease
(<10 mg/1)
TSS(<20 mg/1)
PH
No direct emission
No direct emission
No direct emission
(Continued)
279
-------
TABLE 103. (Continued)
Source
Estimated Flow
Pollutants
Emission Rate
Power Plant
C . T . Slowdown
495 gpm NH3
(softened for reuse) TDS**(1700 mg/1)
TSS
Phenols
pH
No direct emission
Process C.T.
Slowdown
Ion Echange
Regenerant Brines
(after
neutralization)
Aqueous Waste from
H2 Plant
(from soot and slag
handling)
Aqueous Waste Disposal 429 gpm
Effluent (To discharge
(after treatment)t or reuse)
202 gpm
7 gpm avg.
(intermittent)
230 gpm
TDS**(10,000 mg/1)
TSS
BOD
pH
TDS(up to
30,000 mg/1)
TSS
PH
TDS
TSS
BOD
NH3, sulfides
pH
BOD(<50 mg/1)
NH3(<50 mg/1)
TDS(<20 mg/1)
To aqueous waste
disposal system
To aqueous waste
disposal system
To aqueous waste
disposal system
<250 Ib/day
<250 Ib/day
<100 Ib/day
6 to 9
Coal Yard Runoff
(after settling)
Uncontaminated
Storm Runoff
(after settling)
65 gpm
annual avg
(intermittent)
350 gpm
annual avg
(intermittent)
Oil & Grease
(<10 mg/1)
TSS(<50 mg/1)
ph
Oil & Grease
(<10 mg/1)
TSS(<50 mg/1
ph
<8 Ib/day
<40 Ib/day
6 to 9
<42 Ib/day
<210 Ib/day
6 to 9
"Contains added chemicals - morpholine, hydrazine(decomposed), sodium
phosphates, corrosion products.
^"'Contains added chemicals - sulfate, biocide, dispersant, corrosion inhibitor
tAssumed onsite treatment system including evaporation.
280
-------
Storm runoff in excess of that which can be impounded and reused will be dis-
charged to the river. On an annual basis, the pollutant load contributed by
discharged plant runoff will have a minor effect on the river water quality.
The normal aqueous discharge from the plant should have little effect on the
river water quality outside of the mixing zone. The flow rate will be rela-
tively low and, with proper wastewater treatment, the pollutant load will be
low. The plant consumption of about-9100 gpm will be only about 0.25 percent
of the average river flow, s'o that a significant impact on surface water avail-
ability is not expected.
Solid Waste Emissions—Table 104 lists approximate quantities of solid wastes
that will be produced by the operating plant. Nearly all of the unreacted
coal constituents from liquefaction will be converted to synthesis gas and
soot and slag wastes in the hydrogen plant. The hydrogen plant will contain
solids thickening and dewatering facilities to prepare the soot and slag for
loading into rail hopper cars and offsite disposal.
The soot will be nearly all carbon and some 69,200 tons per year (dry basis)
will be produced. This waste material is assumed to be in the form of wet
finely divided particulates with about 40 percent surface moisture as prepared
for disposal. Slag from the Texaco gasifiers will be discharged in slurry
form and dewatered. The material is assumed to be primarily the inorganic
portion of the raw coal (ash). About 847,800 tons per year (dry basis) will
be transported offsite for disposal. Its physical characteristics should be
similar to those of boiler bottom ash (slag). The wet slag is assumed to con-
tain 30 percent moisture as loaded into rail cars.
Water treatment wastes will include dewatered sludge (42 tons per day) from
lime-soda softening of cooling tower blowdown and dewatered brine slurry (65
tons per day) from an onsite aqueous waste treatment system. Both wastes will
be produced from efforts to minimize aqueous pollutant discharges.
Plant trash and garbage will be another solid waste routinely produced during
plant operation. It is assumed that salvageable spent catalysts, lube oils,
and scrap metals will be sent offsite for recovery, if practical. Nonsalvage-
able materials will be hauled offsite for burial. Miscellaneous wastes also
will result from cleanouts during maintenance or turnaround operations. These
infrequently produced sludges and solids will presumably be disposed of offsite
in a landfill after adequate onsite treatment.
The offsite solid waste disposal area is assumed environmentally suitable for
all of the plant's wastes over its 20-year operating life (on the order of
27 million tons). In this particular region, the landfill disposal site will
be operated somewhat like a coal refuse disposal site. The plant's other solid
wastes will also be buried, and special handling could be needed to ensure pro-
per disposal, such as designated disposal sites for particular types of wastes
and special precautions to prevent contact with surface and groundwater. With
proper selection of the disposal area and good disposal practices, surface and
groundwater resources can be adequately protected. At the disposal site, pro-
vision for collection and treatment of any leachate or contaminated surface
281
-------
TABLE 104. SOLID WASTE DISPOSAL SUMMARY — COAL TO OIL
Source
Estimated
Quantity
Potential Pollutants
Disposal
Soot from 1I2 Plant
Slag from H2 Plant
Lime-soda Softener
Sludge Filter Cake
Filter Cake from
Aqueous Waste
Treatment
Plant Trash and
Garbage
Spent Catalysts (HDS,
Bauxite, CO-Mo, Shift
Catalysts)
Miscellaneous:
Oil Recovery
Sludges
Equipment Cleanout
Sludges
Basin Cleanout
Sludges
207.6 tpd solids
138.4 tpd water
2,543.5 tpd solids
1,090 tpd water
8.4 tpd solids
33.6 tpd water
26 tpd solids
39 tpd water
1,700 Ib/day
4,275 tpd
(average)
No estimates made
of quantities
Carbon, organics, sus-
pendable solids
Minerals, trace elements
and organics
Inorganics, organics,
NH3, chemical additives,
corrosion products
Inorganics, organics,
heavy metals, suspend-
able solids
Decomposable wastes, some
oily materials
Heavy metals, residual
organics
Organics, inorganics,
suspendable solids
Hauled by rail to valley
landfill - spread, com- ^
pacted, and covered
Hauled by rail to valley
landfill - spread, com-
pacted, and covered
Dewatered and hauled to
offsite landfill
Dewatered and hauled to
offsite landfill
Collected twice per week,
compacted and buried in
offsite landfill
Returned for regeneration/
disposal or buried in off-
site landfill
Dewatered and buried in
offsite landfill
-------
runoff will need to be made. A low permeability base material such as clay
could retard movement of contaminants into any groundwater resources.
There is a potential that the soot and slag residues, more than 95 percent of
the total waste, may be classified as hazardous materials rather than coal
refuse-type materials commonly disposed of in this area. A substantially more
complex and expensive disposal operation could be required.
Soils and Geology—Approximately 440 acres of land will be altered by construc-
tion activities (clearing, grading, cut-and-fill excavation, paving) and addi-
tional offsite lands will be affected by the building of access roads, rail
spurs, and pipelines. During operation, the disposal of plant solid wastes
in shallow valleys will alter topography by raising the height of the disposal
sites over time, reducing the hilly character of the area. This change will
be significant to regional topography.
Biological Effects—
Four hundred and forty acres of farmland and woodland will be cleared during
construction. While this acreage is not significant in a regional sense, the
impact will depend on the actual amount of wooded land disturbed. In an area
such as this hypothetical eastern site, which has been converted extensively
to agricultural or industrial use, little natural habitat remains. In this
type of situation, removal of even a small acreage of natural habitat could
be significant to regional ecology. Care in siting of the facility will mini-
mize this potentially adverse impact.
Secondary impacts include effects of degraded air quality and water quality:
• Increased exposure to SO and particulates, with loss of
some sensitive plants possible
• Increased salt concentrations in soil downwind from the
cooling tower, decreasing soil productivity locally
• Local minor degradation of aquatic habitat due to plant
aqueous discharge; aggravated if the water supply is cur-
rently affected by acid mine drainage or other industrial
effluents
• Potential icing and resultant vegetation damage if cooling
tower plumes increase chances of freezing rain
Operation of water intake systems can result in entrainment of smaller species
and impingement of fishes on protective screens. The entrained species will
be killed, but design and location of the intake will minimize entrainment
effects.
Aesthetic Impacts—
The presence of the H-coal facility on previously agricultural and wooded land
constitutes a change in the visual character of the area and a possible adverse
impact. Building structures, coal piles, and transportation facilities con-
stitute the major sources of visual contrast in texture, shape, and color.
283
-------
While industrial use is not uncommon in the area, conversion of a less dis-
turbed area to new industrial use could in itself be an impact since the re-
lief offered by the presence of greenbelts or open spaces would be exchanged
for the more urban character.
Layout of the plant to reduce visibility of structures from nearby roads or
residential areas is a potential mitigating measure. This could include
setting the structures well back from the highway - utilizing a 440-acre buffer
zone, placing administrative buildings between roadways and reactor trains,
and using trees as visual screens.
Social and Economic Effects—
A portion of the capital investment ($1.6 billion) will be spent locally for
equipment, construction materials, and labor. The jobs created for 3000 to
4000 temporary construction workers and for 726 permanent operations staff
will result in wages and salaries being infused into the regional economy.
The plant will also expand the tax base for local or state use and may offset
increased demands for services.
Manpower will probably be available in this more industrialized region, par-
ticularly people trained in the coal industry. Local training programs may
be used to supplement the labor pool of skilled construction and operating
workers.
The plant will consume auxiliary fuel and power, but this consumption will be
outweighed by the fuel produced. Coal, a nonrenewable resource, will be
consumed.
Table 105 summarizes the anticipated impacts of the H-coal facility in this
hypothetical location.
284
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TABLE 105. SUMMARY ENVIRONMENTAL MATRIX - H-COAL
Environmental
Factors
Effect of Plant
Construction and Operation
Potential
Mitigating Measures
Climatology and
Meteorology
Air Quality
Surface Water
Availability
Potential for fogging from cooling
tower during periods of high
humidity
Fugitive dust_ and vehicle emis-
sions during construction;
fugitive dust (coal), some par-
ticulates, HC, CO; moderate to
significant emissions of H2S,
SOx; cooling tower drift and
salt releases
31 gal/MM Btu consumed
Dust suppression, use
of low sulfur fuel for
combustion, pollution
control (scrubbers,
etc.)
Internal recycling
Surface Water
Quality
Groundwater
Availability
Groundwater
Quality
Land
Availability
Regional Ecology
and Critical
Habitat
Releases of sediment during con-
struction;- IDS, TSS, BOD'released
from, waste streams — local dis-
charge effect small (but poten-
tially important in presently
polluted system)
No consumption — no effect
Potential degradation from
leaching of coal piles, land-
fill and wasteponds
880 acres used — insignifi-
cant regional effect. Solid
waste acreage potentially
significant
440 acres of vegetation and wild-
life removed or disturbed; salt
drift and/or dust effects on
plantsf human activity disturb-
ing wildlife and water quality
degradation stressing aquatic
life. Solid waste disposal
acreage disturbed — potentially
significant impact
Construction tech-
niques to prevent
erosion; internal
recycling to reduce
pollutant discharges
Lined ponds; careful
management of land-
fill, pads or silos
for coal storage
Care in siting for
compatibility, value
of land use
Care in siting;
water recycling to
minimize consumption
and degradation
(Continued)
285
-------
TABLE 105. (Continued)
Environmental
Factors
Effect of Plant
Construction and Operation
Potential
Mitigating Measures
Aesthetic
Resources
Historical,
"Archaeological
Resources
Community
Economy
Community
Population
and Services
Labor
Availability
Power
Availability
Transportation
Availability
Massive structures, coal piles,
change in land use result in
significant visual contrast
No significant effects
Potential benefit from capital
expenditures, jobs, tax base
Minimum impact
Sufficient labor pool
34 MM kWh/yr net production
Access road, rail spurs,
pipelines
Landscaping, plant
layout
Care in siting
Training if needed
Care in siting
286
-------
SECTION 6
ECONOMIC AND ENVIRONMENTAL COMPARISONS
Sections 3,. 4, and 5 presented details of each of the six conversion cases,
paired by product and region- Each of the three biomass and coal pairs are
compared here, first on an economic and then on an envirqmnental-impact basis.
WOOD AND COAL TO ELECTRIC POWER
The 50 MWe and 500 MWe plants would produce electric power from wood residue
and coal in the South Central scenario.
Economic Comparison of Power Production — Scenario 1
As of today, one cannot expect that wood conversion" to electric power can
compete economically with large coal-fired electric generating stations.
There is no advantage of conversion efficiency for wood fuels in direct com- •
bustion-steam electric generation. Coal conversion penalties could be coal -
costs, capital and" operating costs, or environmental costs (affecting the
preceding costs) . Table 106 is a summation of pertinent economic factors
for the two plants. A tenfold capacity.difference favors the coal-fired
plant because of economy of scale.
In most of the comparison categories, the wood-fired plant suffers a consid-
erable deficit, stemming primarily from the substantial differences in plant
capacity and conversion efficiency. Capital cost, annual operating cost, and
hence base production cost are all about 50 to 60 percent higher for the wood
case based on output. For comparable capacity plants (50 MWe), these factors
would be much closer. The wood-fired plant could be more attractive than
a 500 MWe coal-fired plant with art FGD system. However, new coal-fired sta-
tions of less than 100 MWe are not likely to be constructed in the south
central region.
The base production cost of electricity (excluding fuel cost) for the wood-
fired plant is 28.5 mills/kWh versus 19 mills/kWh for the coal-fired plant.
With private financing, these costs are considerably higher in both cases.
If wood were available at a very low price, the cost of electricity would be
nearly competitive with electricity from a large coal-fired plant. Table 106
gives costs of electricity with wood at $10 per ton and coal at $25 per ton
as example fuel costs for this scenario. For utility financing, the 45.8
mills/kWh wood-to-power cost is 60 percent higher than the base production
cost and about 60 percent higher than the corresponding coal-to-power cost.
287
-------
TABLE 106. ECONOMIC COMPARISON OF WOOD AND COAL TO POWER
Element
Feedstock Input, MM Btu/yr
Power Output, MM-kWh/yr
Thermal Efficiency, I
Capital Cost
$ Million
$/kW (Net)
Wood- to Power
(45 MWe)
4,357,000
275.9
21.6
54.2
1,202
Coal to Power
(476 MWe)
27,857,000
2,913
35.1
384
807
Operating Cost*
$ Million/yr 2.2 14.8
Mills/kWh (Net) 8.0 5.1
Base Production Cost*
Utility, Mills/kWh (Net) 23.5 19.0
Private, Mills/kWh (Net) 45.5 32.0
Example Cost of Electricity**
Utility, Mills/kWh (Net) 45.8 28.2
Private, Mills/kWh (Net) 62.8 41.2
* Excludes feedstock cost.
** Includes wood residue at $10/ton ($1.10/MM Btu) and coal at
$25/ton ($0.96/MM Btu).
288
-------
Figure 40 further illustrates the importance of the wood cost with respect
to the cost of electricity; namely, high-costs for delivered wood will make
the electricity costs very unattractive compared with costs "of electricity
from new large coal-fired stations with FGD systems.
Despite these economic disadvantages, a small wood-fired power station could
be attractive in a scenario where wood is available at a low cost and there
is no demand for a large electric-generating station in the area. Co-firing
of wood and coal may also be economic where coal prices are high enough to
offset retrofit costs.
Environmental Comparison. — Scenario 1
Feedstock Procurement—
The primary sources of environmental impact in feedstock procurement are the .
actual physical activities of gathering and removing wood residue or coal.
These activities may directly affect soils, geology, topography, and land use
and indirectly affect water quality and soil productivity. The following
paragraphs compare the effects of feedstock procurement for the wood-to-power
and coal-to-power plants, and these effects are summarized in Table 107.
Air Quality—Short-term increases in particulate concentrations (resulting
from fugitive dust) are expected from both feedstock procurement activities.
The actual quantities of fugitive dust will depend on the acreage exposed to
wind action; wood refuse collection, properly.managed, will probably result
in lower windborne participates than surface mining. However, the total ,
surface area exposed in both instances will be small, regionally, and neither
activity should contribute significantly to the regional pollutant loading.
Surface Water—Wood residue procurement may result in increased sediment loads
to streams in the region since some unstable soils may be exposed and subject
to erosion. Careful management of residue collection, particularly in drain-~7~
age areas known to be susceptible to erosion, will minimize this effect. No
impact on water availability is expected.
Coal procurement, on the other hand, may affect water quality and water avail-"
.ability. In addition to sediment loading in. streams as a result of exposing
subsoils and stockpiling topsoil for revegetation and reclamation, some water
quality degradation may result from acid mine drainage. This degradation
can be controlled by using state-of-the-art reclamation procedures, but any
acid mine drainage could have potentially long-term adverse impacts downstream
of the mine.
Surface water availability could be affected during mining since drainage
systems will be affected directly. By the removal of surface materials, the
natural drainage will be altered, and some stream beds may even be removed or
channelized. In addition, the use of cofferdams and other erosion control
measures to limit the impact on water quality will reduce downstream flows.
These effects should be short-term and should cease upon reclamation and
restoration of the natural topography.
289
-------
WOOD COST. S/MMBTU
10
I
20
l
30
|
COAL COST,
40
_L_ .
S/TON
5,0 60
I L
70
I
80
!
0.50 1.00 1.50 2.00
COAL COST, S/MMBTU
2.50
3.00
Figure 40. Effect of feedstock cost on
the cost of electricity.
290
-------
TABLE 107. IMPACT SUMMARY FOR SITE SPECIFIC FACTORS - FEEDSTOCK PROCUREMENT
Site Specific Factors
FOREST RESIDUE PROCUREMENT
SOUTH CENTRAL U.S.
Climatology and Meteorology
Air Quality
Surface Water Availability
Surface Watar Quality
Groundwacar Availability x
Groundwacer Qualicy X
Soils and Geology ,
Land Availability
Regional Ecology and Critical Habitats
Aesthetic Resources
Historical, Archaeological Resources X
CommuniCy Economy
Cotanunity Population and Services X
Labor Availability
' Power Availability X
Transportation Availability
COAL PROCUREMENT, SOUTH CENTRAL U.S.
Climatology and Meteorology X
Air Qualicy
Surface Water Availability
Surface Water Quality
Groundwater Availability
Groundwater Quality
5oils and Geology
Land Availability
Regional Ecology and Critical Habitats
Aesthetic Resources
Historical , Archaeological Resources
Community Economy
Community Population and Services
Labor Availability
?ow«r Availability X
Transportation Availability
I-M X X
IX X
X
X
x(d)
X
I - - X X
IX X
: x • — x
I XX
I-St X X
I-M X X
M-5 X X
IX X
I-M X .<
Si XX
I-M X X
W
X
I XX
IX X
I XX
A
A
A
A
A
A
A
A
A
(a) Key for symbols used in adverse iapacc racings:
S » Potentially significant
M " Moderate
I - Potentially insignificant
(b) Key for symbols used in mitigating measures ratings:
A - Mitigating measures described in text assumed to be implemented
(c) Assumes no other large scale development in the area coincident with power plant development or
synthetic fuel.
(d) Assumes cooperation between plant and government agencies to promote reasonable, economically
(e) Hslel^over production or fuel production is a benefit to the community outweighing ainor power
consumption during construction or during operation.
291
-------
Groundwater—Wood residue procurement should have no impact on groundwater
supplies. However, coal procurement could affect long-term availability and
quality of groundwater. The magnitude of the impact depends on the aquifers
in the region of the mine, their location, recharge and discharge areas, and
quality.
The quantity of groundwater could be affected by interrupting recharge areas
during mining; the alterations to recharge areas could persist after reclama-
tion, since stratigraphy and the physical interaction of soil/subsoil horizons
will be permanently altered. Discharge of groundwater could be significantly
affected, at least on the short term, if dewatering were necessary in the
mine pit. In this instance, quantities of groundwater could be pumped out
upstream of the discharge area, depleting the aquifer downstream.- In addi-
tion, shallow aquifers could be cut (if above the coal seam) or removed (if
in the coal seam horizon), resulting in an interruption of flow to the dis-
charge area downstream. Depending on the regional use of water from these
aquifers, potential long-term adverse impacts on groundwater availability
could result.
Groundwater quality could be altered by surface mining activities. In addi-
tion to affecting recharge rates and locations, changes in stratigraphy could
affect the chemical composition of the water by altering the sources of chem-
icals and their proportions (rock and soil composition may be affected).
Also, changes in stratigraphy which resulted in the cutting of more than one
shallow aquifier could result in mixing of groundwater supplies. If one
aquifer were of lesser quality, it could significantly affect the quality,
and therefore the usefulness, of others.
Soils and Geology—Both wood residue and coal procurement can adversely affect
soils productivity, and mitigation of this impact requires extensive use of
fertilizers and soil conditioners after procurement. Wood residue contributes
to the organic content of forest soils; removal of a portion of this residue
limits this contribution and, in time, contributes to decreased productivity.
Forestry practice would probably have to include the addition of expensive
fertilizers and soil conditioners to maintain yields at present levels.
Coal procurement involves removal of topsoils which, when stockpiled for use
in reclamation, may be lowered in. productivity. For example, richer topsoils
may be mixed with less fertile subsoils. Organic materials which normally
contribute to organic content are usually removed, and then natural soil
bacteria and fungi may die, resulting in sterile soil after long periods of
stockpiling. Upon reclamation, fertilizers and soil conditioners must be
applied before planting to ensure yields. In some instances, subsoils may
contain minerals or salts toxic to plant growth, but normally they are below
the root zone. In reclamation, some of these undesirable materials may be
brought to the surface, further reducing productivity. Special soil separa-
tion techniques may be necessary to prevent this type of problem.
Both wood and coal procurement increase the potential for erosion and loss of
valuable topsoil. In addition, coal procurement alters soil and geology struc-
ture by altering soil horizons and stratification of beds, resulting in "bulk-
ing" of the overburden with potential for settling after reclamation, and
292
-------
changing topography. On a long-term basis, the overall impact on geology
and soils is potentially greater from coal surface mining because of the
extent of surface disruption, the depth disturbed, and the physical changes
which occur.
Land Availability—Wood residue collection will require between 30,000 a&d
100,000 acres per year; acreage committed to coal mining will depend on the
richness of the deposit and the surface area necessary to obtain one million
tons per year. Wood residue removal does not foreclose any other land use,
although the acreage used in any given year will not be suitable for wood
residue collection for a long period after removal. Similarly, after coal
mining and reclamation, no other land use will be prohibited although coal
mining will be permanently foreclosed. Therefore, given adequate wood and
coal resources,, feedstock procurement should: not have a significant impact
on land availability.
Ecology—Removal of forest residue may disturb or eliminate wildlife habitat
in up to 100,000 acres a year. Repopulation of the cleared area will depend
on rate of accumulation of forest floor debris as well as regrowth of any
cut-over stands of trees. Total acreage disturbed over the life of the proj-
ect may be significant. However, the disturbance itself will be minor and
could be beneficial if residue collection is coordinated with fire management
in the region. For example, pine flatwoods are a "fire climax" ecosystem;
hardwoods such as oaks and underbrush invade if occasional fires do not occur.
When hardwood and underbrush do occur, any fire may have serious wide-ranging
impact on the environment, since the normally resistant pines cannot survive
the heat of a fire fueled by all that residue. Keeping the forest floor
cleared and controlled use of fire can maintain a healthy pinewood against
this potential fire danger (42, 43).
Coal mining will remove an undefined number of acres of wildlife habitat per
year. Reclamation and revegetation may, if pursued immediately upon comple-
tion of mining in an area, minimize the overall adverse impact of removal by
reestablishing wildlife habitat. Hox^ever, if the mine is located in a mature
pine flatwoods ecosystem, the wildlife typical of that system cannot return
until a mature pine flatwood is reestablished. This could take between 25
and 100 years (43) and could be particularly significant to populations of
species- dependent on mature pinewoods, such as the endangered red cockaded
woodpecker. Over the life of the mine, a significant acreage of woodpecker
habitat could be removed in this region.
Aesthetics—The open park-like appearance resulting from wood residue collec-
tion in a pine woods could enhance the aesthetic appeal of the woods, if
careful management of the collection prevented erosion, displacement of
wildlife, and damage to mature vegetation. However, the contrasts in color,
line, and texture resulting from surface mining of coal are adverse impacts
on aesthetics. Reclamation will reduce this effect over time, but, for the
life of the mine, the area will be adversely affected.
Historic and Archaeological Resources—Wood residue collection should not
affect any historic ar archaeological resources. Coal surface mining could
uncover such resources, and care in locating, retrieving, and protecting
293
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subsurface artifacts would be required. Mining might be prohibited in an
area designated as a historic landmark.
Social and Economic Effects—Approximately 30 to 50 full-time jobs, associated
wages and spending, and several million dollars per year paid for wood residue
will benefit the community. No adverse effects on population, services, or
power consumption are anticipated.
Coal mining will provide full-time employment, wages, and money paid for the
coal ($20 to 25 million per year) to the community. However, if the mine is
in a previously undeveloped area, labor may need to be imported, labor train-
ing programs may need to be implemented, and expanded services and housing
may be required. These requirements are expected to produce insignificant
impacts on a regional basis, but could produce moderate impacts on local
communities.
Conversion Plants—
Air, water, and solid waste emissions are the major sources of environmental
impact from wood-to-power and coal-to-power plants. These emissions directly
affect physical and chemical aspects of the environment (air quality, surface
and groundwater quality) and indirectly affect biological and aesthetic
resources. Section 3 discussed the typical pollutants and expected levels
of emissions with respect to site quality and environmental standards. The
following paragraphs compare the two facilities with respect to these emis-
sions and their potential effects on the environment. The impacts are sum-
marized in Table 108.
Climatology and Meteorology—Both wood-burning and coal-burning power plants
are assumed to use cooling towers which will release heat and water vapor
to the atmosphere. The wood-burning plant cooling towers will release
250,000 Ib/hr of water vapor, while the coal-fired plant will release about
1,750,000 Ib/hr. Both could cause local fogging on cool, humid days, with
the coal-fired plant having the greater potential. On a MWe basis, the wood-
burning plant (50 MWe) releases more water vapor than the coal-fired plant
(500 MWe). Similar impacts are expected from plants of similar sizes, regard-
less of feedtsock.
Air Quality—Low nitrogen and sulfur content in the wood residue will result
in low emissions of NO^ and 50^ from the wood-burning plant. New source
particulate standards could be met by using mechanical collectors and elec-
trostatic precipitators. However, an estimated 1000 tons/year of NOX, 200
tons/year of CO, and 200 tons/year of HC will constitute major new source
emissions, and some measurable adverse effects could occur. In addition,
15 tons/year of salts will be distributed downwind of the cooling tower.
The coal-fired power plant is expected to meet NSPS particulate, NOX, and
SOX standards. However, the total emissions from the plant may be as much
as 11,700 tons/year of NOX, 4400 tons/year of SOX, 1000 tons/year of CO, and
400 tons/year of HC, as well as trace amounts of volatile materials. On a
MWe basis, these emissions are less than or equivalent to wood-burning emis-
sions with the exception of SOX and the trace volatile materials. About
120 tons per day of salts will also be distributed downwind from cooling
294
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TABLE 108. IMPACT SUl'E-IARY FOR SITE SPECIFIC FACTORS - WOOD AND COAL
TO POWER
Mo
Site Specific Factors Discernible
Impact
WOOD-fO-POWER, 50 MWa WOOD-FIRED POWER
PLANT, SOOTH CENTRAL U.S.
Climatology and Meteorology
Air Qualicy
Surface Water Availability
Surface Water- Qualicy
Groundvacar Availability X
Groundvacer Quality
Soils and Geology
Land Availability
Regional Ecology and Critical Habitats
Aesthetic Resources
Historical, Archaeological Resources
Community Economy
Community Population and Services
Labor Availability
Power Availability
7
COAL-TO-POWES, 500 MWe COAL-FIRED POWER
SLANT, SOOTH CENTRAL II. S.
Climatology and Meteorology
Air Quality
Surface tfatar Availability
Surface Water Quality
Groundwacer Availability X
Groundwater Quality
Soils and Geology
Land Availability
Regional Ecology and Critical Habitats
Aesthetic Resources
Historical, Archaeological Resources
Community Economy
ConHBunity Population and Services
Labor Availability
Potwr Availability
Transportation Availability
Beneficial "Ver3a
Impact In^a«
I
r(c)
I
I
I
I
j(0
I
I-M
I
x(d)
I
I
XCe>
L
i
.i(c)
r
i
L
M
T(c)
I
M
I
vCd)
X
I-M
I
xta)
I
Short Long „
Term Term Olre« Indlrs<:t:
X X
X X
X X
X X
X X
X X
X X
X X
X X
X X
X X
X X
~
X X
X X
X X
X X
:c x
X X
X 'C
X X
X X
X X
X X
X X
X X
Mitigating
Measures
(b)
A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
(a) Key for symbols used in adverse iinpact ratings:
S » Potentially significant
M - Moderate
I - Potentially insignificant
(b) Key for symbols used in mitigating aeasures ratings:
A » Mitigating aieasures described in text assumed Co be inplemented
(c) Assumes no other large scale development in the area coincident uith power plant development or
synthetic fuel.
(d) Assumes cooperation between plant and government agencies to promote reasonable, economically
sound growth.
(e) Assumes power production or fuel production is a benefit Co Che community outweighing minor power
consumption during construction or during operation.
295
-------
towers, roughly equivalent to salts from the wood-burning plant on a MWe
basis. Some local adverse effects on air quality are expected, although,
as with wood-burning plants, the significance of the effect will depend on
ambient air quality and the existence of other point sources in the region.
For example, the plant site is in a nonattainment area for photochemical
oxidants, and emission offsets may be required for both plants.
't
Surface Water—The wood-burning plant will require about 0.8 gal/kWh for
boiler feed and cooling water makeup, while" the coal-fired plant will require
about 0.5 gal/kWh. Neither should significantly affect surface water supply
availability.
Discharges from the wood-burning plant include IDS, TSS, residual chlorine,
small amounts of oil and grease, BOD, and caliform bacteria. The quantities
discharged (about 100 gpm) and the concentrations of material in the effluent
are not expected to significantly degrade water quality..
The coal-fired plant will discharge larger quantities of effluent of similar
quality. Runoff from plant-site coal piles and sludge landfills could pose
a problem to surface waters, but proper management of landfills and use of
sedimentation basins for plant-site runoff will reduce this effect.
Groundwater—Neither facility is expected to use groundwater as a makeup or
potable supply. However, both could affect groundwater quality through
leachates from ash and sludge disposal sites. The composition of such
leachates is not known, but any change in groundwater quality is long-term
and possible cumulative, so particular care in landfill disposal of solid
wastes will be necessary to minimize this potential adverse impact.
Soils and Geology—About 50 acres of surface will be altered for the wood-
burning plant and about 365 for the coal-fired plant. Although these are
roughly proportional on a per-MWe basis, coal plant acreage is not linearly
related to energ3^ generated. Similarly, about five acres will be committed
to a landfill for solid waste disposal for the wood-burning plant and 230
acres for the coal-fired plant. Either plant may result in locally signifi-
cant impacts on topsoil and topography. This alteration may or may not be
regionally significant, depending on other changes to regional topography
and other developments.
Land Availability—Commitment of 50 acres to a wood-burning plant and 365
acres to a coal-fired plant should not constitute a constraint on land avail-
ability. The use of buffer zones, say, 365 acres for the coal-fired plant,
might be a problem in land acquisition; but agricultural, grazing, or
forestry land uses would be compatible with use as a buffer zone. Therefore,
depending on siting and on planned' development in the area, land availability
should not be significantly affected.
Ecology—Approximately 50 acres of wildlife habitat will be removed or dis-
turbed during construction of a wood-burning power plant. Care in siting
could minimize the regional effect of this loss by avoidance of critical
habitats, known nesting or feeding areas of important species, or other eco-
logically .sensitive areas. Similarly, the 365 acres disturbed by construc-
tion of a coal-fired power plant can be minimized by care in siting.
296
-------
Impacts on vegetation and wildlife resulting from degradation of air or
water quality will be similar for each facility, although losses due to salt
deposition on vegetation from cooling-tower drift may be greater for the
coal-fired plant.
Aesthetics—Both facilities will impose an industrial character on their
sites; the magnitude of impact will essentially be proportional to the mag-
nitude of the facility. Color contrast from coal piles and.landfills will
be greater for the coal-fired plant than for the wood-burning facility, and
because of the required acreage, the coal-fired plant will constitute a
greater impact on aesthetics than the wood-burning plant. However, land-
scaping, plant layout, and the use of the buffer zone can reduce the local
impact of the plant itself,
Historic and Archaeological Resources—Care in siting will reduce the impact
on historical or archaeological resources, as will salvage .and protection
should any subsurface relics be discovered.
Social and Economic Effects—Approximately 200 to 300 construction jobs and
300 full-time operational positions will be created by the 50 MWe wood-burn-
ing plant. The coal-fired plant will require a. larger labor pool both for
construction (up to 1000) and for plant operation (95 employees). .Therefore,
both will benefit the community in employment, wages, and local spending.
Per MWe, these benefits are likely to be equivalent, and demands for services,
housing, and labor training are expected to be equivalent. However, the
coal-fired plant, as a larger unit, has a potentially greater effect on
local growth.
Both plants will produce electric power for the region. The coal-fired plant,
being more efficient, will produce more energy per ton of feedstock and
will produce cheaper electricity. The costs of feedstock do not generally
take into account that wood residue, over time, is renewable, while coal is
a nonrenewable fuel source.
Consumption of Resources—Table 109 shows the natural resource consumption
rates expected from each plant. The two facilities consume roughly equiva-
lent quantities with three notable exceptions:
• The wood-burning plant, using a lower-Btu fuel, consumes
more feedstock (Ib/kWh) of a renewable resource, while the
coal-fired plant consumes lesser quantities of a higher-Btu,
'nonrenewable fuel
• The coal-burning plant consumes more chemicals (particularly
lime) in total than the wood-burning plant
• The coal-fired plant requires less manpower per kWh of output
(due more to economy of scale than to superior conversion
efficiency)
Summary of Scenario 1—
If the qualitative assessments summarized in Tables 107 and 108 were assigned
numerical values using the scale shown in Table 110 and summed without
297
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TABLE 109. RESOURCES COMMITTED TO THE POWER PLANTS''
Wood- to Power Coal- to- -Power
Resource 50 MWe 500 MWe
Land 1.11 acre/MWe 0.77 acre/MWe**
Feedstock 3.46 Ib/kWh 0.734 Ib/kWh
Auxiliary Fuels 188 Btu/kWh 169 Btu/kWh
Chemicals 0.00046 Ib/kWh 0.022 Ib/kWh
Auxiliary Power 0.109 kW/kW 0.06 kW/kW
Water 0.82 gal/kWh 0.51 gal/kWh
Manpower 0.67 men/MWe 0.2 men/MWe
*From Tables 25 and 38.
**Increases to 1.54 if a 365 acre buffer zone is included.
weighting environmental aspects according to value to the site and region,
feedstock procurement for coal-fired plants would potentially have signifi-
cantly higher impact than wood-residue collection (Table 111). The regional
impacts of the two power plants, on a MWe (relative) basis, however, would
be similar. The biomass conversion facility would be more environmentally
acceptable in this scenario largely because of the lower overall impact of
feedstock procurement (forest residue) compared with coal mining.
298
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TABLE 110. SAMPLE NUMERICAL RATINGS FOR QUALITATIVE ASSESSMENTS
Scale Environmental Qualitative Assessment
+10 Significant benefit
9
8
7
6
5 Moderate benefit
4
3
2
+1 Insignificant benefit
0 No discernible impact
-1 Insignificant adverse short-term impact
-I
£.
3 Moderate adverse short-term impact
4
5 Significant adverse short-term impact
6 Insignificant adverse long-term impact
7
8 Moderate adverse long-term impact
9
-LO Significant adverse long-term impact
299
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TABLE 111. SUMMARY OF WOOD AND COAL TO POWER IMPACTS
Site Specific
Factors
Climatology and
Meteorology
Air Quality
Surf ace, Water
Availability
Surface Water
Quality
Ground water
Availability
Groundwater
Quality
Soils, Geology
Land
Availability
Ecology
Aesthetic
Resources
Historical,
Archaeological
Resources
Community
Economy
Community
Population
and Services
Labor
Availability
Power
Availability
Transportation
Availability
TOTAL
Feedstock Procurement
Wood Residue
0
-L
0
-1
0
0
-7
-1
1
1
0
5
0
1
0
-6
-8
Coal
0
-L
-1
-6
-7
-7
-9
-1
-7
-8
-7
5
-6
-1
0
-6
-62
Conversion
Plants
Wood
-1
-6
-1
-1
0
-6
-6
-6
-6
-7
/-
-o
5
-1
-1
5
-6
-44
Coal
-1
-6
-1
-1
0
-6
-8
-6
-6
-8
-6
5
_2
-1
10'
-6
-43
300
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STRAW/MANURE AND COAL TO SYNTHETIC PIPELINE GAS
The hypothetical biogas and HYGAS conversion plants would produce SPG in the
midwest region. The large difference in plant capacities should be kept in
mind in this comparison of their economics and environmental impacts.
Economic Comparison of SPG Production — Scenario 2
Both conversion plants can be considered advanced processes for production of
SPG. HYGAS is a second-generation gasification process not yet in the com-
mercial stage. Anaerobic digestion is an old process, but this conceptual
commercial-scale plant is not yet demonstrated technology. The steam-oxygen
HYGAS process was the best economic case of the six gasification processes
evaluated in the 1976 C. F. Braun report (6). Anaerobic digestion of Biomass
residues is considered by some a promising route to low-cost methane gas.
Economic factors of the two conceptual conversion plants are compared in
Table 112 for both private and utility financing. The 250 MMM Btu/day capac-
ity plant is generally considered a reasonable commercial scale for high-Btu
gasification processes. The biogas plant, at nearly one-fortieth the capac-
ity, might suffer in the comparison, but a much larger facility could not be
envisioned in this scenario. Plane thermal efficiency certainly favors the
HYGAS facility by a factor of two, a difference primarily related to the con-
version processes themselves.
A. comparison of the cost items in Table 112 on the basis of energy output
indicates unfavorable cost ratios from 2.5 to 4 or more for SPG from straw
and manure. A portion of' the difference can be attributed to the low biogas
plant capacity compared with the HYGAS capacity, but the low conversion effi-
ciency is a more critical difference. The biogas annual operating cost
(excluding feedstock) of 32.97/MM 3tu is, by itself, higher than current prices
for most fuels. If the biogas plant's undigested residue could be sold as
cattle feed, for example, a large byproduct credit could improve the biogas
economics considerably.
Without including the cost of feedstock, the SPG production cost for the bio-
gas plant is about three times that for the HYGAS facility wish either utility
or private financing as used in this study. Compared with first-generation
coal gasification technology (Lurgi), biogas-derived SPG may be only twice
as costly, however. It should be noted that other estimates (9, 10, 11, 12)
of SNG costs by digestion and gasification of biomass are more optimistic
($3 to $5/MM Btu, excluding feedstock costs). The gas cost examples shown in
Table 112 include the costs of delivered feedstocks at prices which might be
reasonable in this midwest scenario today. Sensitivity of gas costs to
feedstock costs is shown in Figure 41. Various relative feedstock cost
scenarios can be considered for the future, but it seems clear that the
cost of SPG diverges in favor of coal gasification (or at least HYGAS) at
increasing feedstock prices.
It isjiot apparent how biogas-derived SPG can be competitive economically with
coal gasification on a large commercial scale, since conversion efficiencies
are relatively low and practical plant capacities are limited. This comparison,
301
-------
TABLE 112. ECONOMIC COMPARISON OF STRAW/MANURE AND COAL TO SPG
Straw/Manure to SPG
Element (6_66 ^^ Btu/Day)
Feedstock Input, MM Btu/yr
SPG Output, MM Btu/yr
Thermal Efficiency, %
Capital Cost
$ Million
$/MM Btu Per Day (Net)
Operating Cost*
$ Million/yr
S/MM Btu
5,670,000
2,188,600
31.9
85.2
12,800
6.5
2.97
Coal to SPG (HYGAS)
(250 MMM Btu/Day)
118,360,000
82, 125, -000
69.7
1,213.2
4,850
53.6
0.65
Base Production Cost"
Utility, $/}fM Btu 7.68 2.42
Private, $/MM Btu 10.63 3.37
Example Cost of SPG**
Utility, $/MM Btu 9.48 3.66
Private, $/MM Btu 12.43 5.02
* Excludes feedstock cost.
** Includes straw at $10/ton. ($.70/MM Btu), manure at $2/ton ($.68/MM Btu),
and coal at $15/ton ($.85/MM Btu).
302
-------
0.50
1
1.00
I
STRAW OR MANURE COST, S/MMBTU
1.50
2.00
2.50
3.00
STRAW- 10
20-
30
40 STRAW
20
3
CD
I1'
C0~
O
u.
° 10
MANURE 246
STRAW AND MANURE COST, S/TON
10
COAL COST, S/TON
20 30 40
8 MANURE
PRIVATE —
UTILITY
iO 60
0.50
1.00
1.50 2.00
COAL COST, S/MMBTU
2.50
3.00
Figure 41. Effect of feedstock cost on the cost
of synthetic pipeline gas (SPG).
303
-------
at least, would suggest a different direction for this intrinsically wet
conversion process; namely, small-scale plants using wet biomass materials
available in high local concentrations. Using fresh cattle manure from a
large (100,000 head) confined feedlot in an onsite biogas plant is an example.
The product could be medium-Btu gas for local industrial fuel or gas-turbine
power generation. Improvement in the conversion efficiency to methane is
also needed.
Environmental Comparison — Scenario 2
Feedstock Procurement—
As in Scenario 1, the actual collection of feedstock materials will be the
major source of environmental impact. These surface activities will'alter
soil's, geology, topography, and land use directly. In turn, these direct
impacts affect air and water quality, ecology, and future uses. The impacts
of collection of straw/manure and coal are discussed below and are summarized
in Table 113.
Air Quality—Short-term increases in particulate concentrations (resulting
from fugitive dust) are expected from both feedstock procurement activities.
The actual quantities of fugitive dust will depend on the acreage exposed to
wind erosion. Straw collection, if carefully managed, will probably result
in less fugitive dust even though the acreage affected will probably be much
greater than the 100 acres per year disturbed by s.urface coal mining. On a
regional scale, neither activity is likely to affect air quality significantly.
Surface Water—Straw procurement may expose highly erodible soils to water
erosion, so careful analysis of the area will be necessary to determine in
which fields partial collection should be practiced. No -impacts on water
availability are anticipated.
Coal mining may remove or redirect surface runoff, altering downstream flows.
This alteration may be partially mitigated by reclamation, but any topograph-
ical change in the mine area could indirectly affect water availability.
Erosion from stockpiled soils and subsoils, from strip-mined land, and from
coal piles could affect water quality. Uses of erosion control methods,
settling ponds, and prompt reclamation/revegetation will minimize this adverse
impact.
Groundwater—Little or no discernible impact on groundwater is expected from
straw or manure collection. Coal mining, as in Scenario 1, could affect
groundwater availability by:
• Interrupting recharge
* Dewatering the mine site
• Cutting or removing shallow aquifers
Groundwater quality could be adversely affected by changing the composition
of the overburden, thereby affecting the sources of groundwater chemicals
304
-------
TABLE 113. IMPACT SUMMARY FOR SITE SPECIFIC FACTORS — FEEDSTOCK PROCUREMENT
^^ a - Adve rse Mi tisatiniz
Site Specific Factors Discernible oenericial Impacc Short Long Direcc indirect Measures
Impact npact ^^ Term Term ^j
WHEAT STRAW AND MANURE PROCUREMENT
MIDWESTERN U.S.
1 Climatology and Meceorology x
Air Quality I X X A
Surface Water Availability c
Surface- Wacer Quaiicy I X X A
Groundwacer Availability X
Groundwacer Quaiicy X—— —-———_______^^^____
Soils and Geology I-M X X A
Land Availability
Regional Ecology and Critical Habitats
Aesthetic Resources
Historical, Archaeological Resources X
Community Economy '<
Comnunicy Population and Services X
Labor Availability X
Power Availability X
COAL PROCUREMENT, 'JESTERN U.S.
Climatology and Meceorology
Air Quaiicy
Surface Wacer Availability
Surface Water Quality
Grounawatar Availability
I
X
I-M
I
I
I-M
X (
X X
X X
X X I
:c x
Groundwacer Qualify
Soils and Geology
Land Availaoiiicy
Regional icology and Crzcical Habicacs
Aesthetic Resources
Historical, Archaeological Resources
Cotnmunity Economy
Comaainicy Populacion and Services
Labor Availability
Power Availability —.
Transportation Availability
(a) Key for symbols used in adverse impact ratings:
S - Potentially significant
M - Moderate
I - Pocencially insignificant
(b) Key for symbols used in aiicigacing measures racings:
A » Mltigacing measures described in cexc assumed Co be implemented
(c) Assumes no other Large scale development in Che area coincident with power plant development or
synthetic fuel.
(d) Assumes cooperation becveen plant and government agencies CO promote reasonable, economically
sound growth.
(e) Assumes power production or fuel production is a benefit to Che community outweighing minor power
consumption during conscruccion or during operacion.
305
-------
and minerals, and by allowing one or more lower-quality aquifers to connect
with a better-quality supply. Detailed studies on the area would be necessary
to determine whether or not these long-term impacts can occur, and whether or
not such impacts would be important to regional water use.
Soils and Geology—In addition to the potential for increased wind and-^ater
erosion, removal of straw could contribute to decreased soil productivity.
Since the straw is commonly plowed into the ground at planting time, it
contributes to topsoil stability and organic content. Some or all of this
contribution will be eliminated. The use of organic sludges (residue) from
anaerobic digestion as soil amendments may compensate partially for this loss,
but the nutritive content of the sludges will be less than the straw and
additional fertilizers may be necessary.
Manure is usually used as a soil amendment, although not at the collection
sites. Use of manure as feedstock, therefore, reduces Ghe availability of
soil amendments and could force local reliance on chemical fertilizers and
conditioners.
As in Scenario 1, coal mining can affect soil productivity, stratification,
concentrations of toxic materials, density, and topography. While 100 acres
a year is not significant on a regional scale, in context with other mining
activities the regional impact could be important and long-term.
Land Availability—Straw and manure collection will not affect land availa-
bility or use; sufficient acreage must be available to supply the necessary
feedstock but, with proper management and with use of soil conditioners, -the
wheat fields could continue is use.
Coal raining will commit 100 acres per year, which will be reclaimed immediately
after use. This constitutes a small land commitment regionally, and restora-
tion to agricultural use is technically and economically feasible. .Future
use of the area for coal mining, however, will be foreclosed, since the
mineral will have been consumed.
Ecology—Since the straw/manure collection is. restricted to agricultural
lands, no discernible environmental impacts on wildlife are expected. Coal
mining, however, could result in a. reduction of grassland vegetation and its
associated animal populations. Even after revegetation, this habitat may not
be as productive as wildlife habitat. Reclamation for wildlife use may require
inclusion of more varieties of plant species, adding significantly to technical
difficulties (plant propagation, proper watering, and fertilizers) as well as
costs. Since native prairie species are not common, loss of such habitat
could constitute an important impact.
Aesthetics—Straw and manure collection should have no discernible effect on
the visual quality of the collection sites. Coal mining, on the other hand,
will result in contrasts in color, land form, and texture on 100 acres each
year. Although reclamation will be a continuing process, there will always
be one or more areas at the mine site which are being worked. These contrasts
will be aesthetically displeasing and may persist for a period following the
cessation of mining.
306
-------
Historic and Archaeological Resources—Straw and manure collection will not
affect any historic or archaeological resources, since no physical disrup-
tion of land surface or structures will result. The coal mine could uncover
subsurface relics, and premining surveys may be used to locate, preserve,
or salvage resources. The presence of a historic landmark on the mine site
might prohibit mining activity in that area, a possible constraint to feed-
stock procurement.
Social and Economic Effects—Both feedstock procurement activities will create
jobs '(30 to 50 for straw/manure collection, for example) and infuse new money
into the regional economies. The local labor pools are expected to be suf-
ficient to supply all needed employees, and little growth is anticipated
nearby as a result of these activities alone.. Development of several other
large strip mines lit- the same western mine area could stress the labor pool
and induce significant community growth.
Conversion Plants—
Air, water, and solid waste emissions are expected to be the major sources of
environmental impact for synthetic gas plants. These emissions could directly
affect air and surface water quality and land use, and indirectly affect
groundwater quality. Section 4 described the potential emission concentra-
tions. In this section, straw/manure-to-gas (biogas) and coal-to-gas (HYGAS)
plants are environmentally compared assuming the same site in midwestern U.S.
Table. 114 summarizes- this comparison.
Climatology and Meteorology—About 8200 Ib/hr of water vapor will be released
by the biogas plant cooling tower, while 405,000 Ib/hr will be released by
HYGAS. On a MMSCFD basis, the biogas plant (7 MMSCFD) will release somewhat
less water vapor than the HYGAS plant (274 MMSCFD). Maximum use of air cool-
ing will keep the HYGAS cooling water demand low, although total heat rejec-
tion to the atmosphere is considerably greater for HYGAS on a relative gas
output basis. On cool humid days, local fogging could occur for either
plant. In addition, icing could occur on days when the plume came to the
ground and the temperature was below freezing. The relative impact from the
HYGAS plant will be larger.
Mr Quality—The biogas plant will release NOX (104 tons/year), SOX (398 tons/
year), CO (less tharr 21 tons/year), and HC (less than. 21 tons/year) as well
as fugitive dust and potential odors from the manure stockpile. This facil-
ity will probably meet standards in the area, although new source tradeoffs
may be necessary. In addition, 20 tons per year of salts will be deposited
downwind of the cooling tower.
The HYGAS plant may release NOX (1900 tons/year), SOX (4600 tons/year), CO
(3500 tons/year), miscellaneous hydrocarbons (including methane, ethane),
COS, and hydrogen sulfide as well as trace quantities of potentially toxic
organic materials. On a MMSCFD basis, these emissions are similar to biogas
emissions except for the potentially hazardous organic and reduced sulfur
compounds. Local adverse impacts may not be significantly different from
those of biogas, but additional pollution controls may have to be implemented
to control vapor emissions. In the HYGAS plant, about 40 tons per year of
307
-------
TABLE 114. IMPACT SUMMARY FOR SITE SPECIFIC FACTORS - STRAW/MANURE AND
COAL TO SYNTHETIC PIPELINE GAS
No
Sice Specific Factors Discernible e, c
Imoact
Impact v
BIOGAS, 7 MMSCFD METHANE GAS PLANT,
MIDWESTERN U.S.
Climatology and Meteorology
Air Quality
Surface -Water Availability
Surface tfacer Quality
Groundvater Availability
Groundwacer Quality
Soils and Geology
Land Availability
Regional Ecology and Critical Habitat
Aesthetic Resources
Historical, Archaeological Resources
Community Economy X
Community Population and Services
Labor Availability
Power Availability X
Transportation Availability
STEAM-OXYGEN HYGAS, 250 MMSCFD COAL
GASIFICATION PLANT, MIDWESTERN U.S.
Climatology and Meteorology
Air Quality
Surface Water Availability
Surface Vatar Quality
Groundwacer Availability
Groundwater Quality
Soils and Geology
Land Availability
Regional Ecology and Critical Habitat
Aesthetic Resources
Historical, Archaeological Resources
Coammlcy Economy X
Comnlcy Population- and Services _
Labor Availability
Power Availability x'e'
Transportation Availability
(a) Key for symbols used in adverse impact ratings:
S • Potentially significant
M - Moderate
I • Potentially insignificant
Cb) Key for symbols used in mitigating measures ratings:
A - Mitigating measures described in text assumed to
\d
ll Impact S*°™ £°ng
(a) e erm
I X
I(c) X
I X
. I X
I X
I X
I-M X
Itc> X
I X
I-M X
I X
I X
I X
I ' X
I X
ICc) X
I X
I X
: v
I X
I-M 7.
I(c) X
I \
I-M X
I X
I-M X
I-M X
I X
be implemented
(c) Assumes no other large scale developoent in the area coincident with power plant
synthetic fuel.
(d) Aasuoes cooperation betveen plant and government agencies
to promote reasonable.
Direct Indirect
X
X
X
X
X
X
x:
X
X
X
X
X
X
X
X
X
X
X
X
X
c
X
X
X
X
X
X
X
development or
economically
Mitigating
Measures
(b)
A
A
A
A
A
A
A
A
A
A
~
A
A
A
A
A
A
A
A
A
A
\ ,
A
sound growth.
(a) Assumes power production or fuel production is a benefit to the community outweighing minor power
consumption during construction or during operation.
308
-------
salts will be deposited downwind of the cooling tower. Cooling-tower drift
will probably contain organics resulting from recycling of process effluents
to the cooling system.
Surface Water—The biogas facility will require about 43 gallons of water per
million Btu production (or 40 gallons of surface water per 1000 SCF of product
gas). Treatment and internal recycling will reduce the consumption rate.
The water consumption by HYGAS will be about 11 gallons per million Btu.
As noted earlier, the HYGAS plant utilizes air cooling to lower water consump-
tion, and internal recycling further reduces consumptive use. Neither facil-
ity should seriously affect sur.face water availability/
Discharges from the biogas plant will contain. TDS, TSS, residual chlorine,
small amounts of oil and grease, BOD, nitrogen, and phosphorus. The quanti-
ties discharged (about 150 gpm process effluent and 50 gpm storm runoff) and
the concentrations of material in the effluent are not expected to be signi-
ficant unless hazardous compounds are present. The HYGAS plant will discharge
no process wastewater, but will discharge about 150 gpm (average annual flow)
of storm runoff containing TSS and oil and grease. Upsets in the closed pro-
cess water recycle systems could result in discharge of dissolved and sus-
pended pollutants and pose a problem to surface water quality. Proper manage-
ment of runoff from coal storage, the onsite landfill and process areas,
including containment and treatment, if necessary, will minimize the potential
for serious degradation of surface receiving water-.
Groundwater—About three gallons of groundwater per MSCF product gas will be_
used in' the biogas plant, while the HYGAS plant will use no groundwater. The
impact of this consumption will depend on other uses of the supply but the
effect is"expected to be minor.
At this time, sludges from biogas are assumed to be applied as a soil amend-
ment to the fields from which straw is collected. While these organic sludges
may leach during interim storage and after spreading, the contamination poten-
tial for groundwater is expected to be small. Interim storage sites (offsite)
will probably have to be diked and lined to prevent percolation of nitrates
and trace organics to the groundwater.
HIGAS solid wastes will have potentially toxic materials such as heavy metals,
trace organics, and other matter which could contaminate groundwater through
leaching. If the western mine site is used for disposal prior to reclama-
tion, the area may need special preparation to minimize groundwater contact.
The onsite plant solid waste landfill area will be clay.lined, and the coal
storage sites should be lined to prevent groundwater contamination.
jpils and Geology—Construction will affect the landform and surface of 140
acres for the biogas plant and 440 acres for the HYGAS plant. Again, the
HYGAS facility demonstrates an economy of scale with much less land committed
per MMSCFD of gas production. Onsite, the changes will be significant and
permanent, particularly the solid waste landfill for HYGAS. The overall
regional impact will be low.
30!9
-------
Land Availability—Commitment of 140 acres to the biogas plant and 440 acres
to the HYGAS plant constitutes a limit on developable lands in the vicinity
of the site. The use of a 440-acre buffer zone for HYGAS will not be incom-
patible with agricultural, grazing, or other low-intensity uses, but con-
straints on land acquisition could arise. On a regional basis, land availa-
bility should not be significantly affected.
Ecology—Assuming the site to be primarily agricultural-, ecological effects
should be minimal regardless of the process used. However, some wildlife
habitat (a maximum of 140 acres for the biogas plant and 400 acres for the
HYGAS plant) would, be removed if the area were used for grazing, or if wood-
lots or fence rows were affected. Care in siting should further reduce this
impact.
Impacts on nearby wildlife and vegetation from air or water quality degrada-
tion, salt deposition from cooling-tower drift, or entrainment in intake
water systems may be greater for HYGAS because this plant has greater total
emissions. But per Btu, the biogas plant may have the greater relative impact.
Aesthetics—Both facilities will impose an industrial appearance on a rural
site, and the magnitude of visual contact will be proportional to the size
of the structures (stacks, reaction vessel trains, cooling towers, rail
yards, etc.). In addition, live coal piles and wastewater ponds will affect
the appearance of the HYGAS site, while a possible odor problem from manure
storage could affect the biogas plant site. Use of landscaping and buffer
zones (440 acres for HYGAS) as well as plant layout could reduce the local
impact on aesthetics.
Historic and Archaeological Resources—Care in siting will reduce the poten-
tial for adverse impact on historic or cultural resources. Should any sub-
surface relics be discovered during siting or construction, salvage and
protection measures will be implemented.
Social and Economic Effects—Approximately 100 full-time operation jobs will
be provided by the biogas plant, while the HYGAS plant will required more
than 700 permanent employees. These facilities will also require several
hundred (biogas) to 300 (HYGAS) construction workers. These jobs and their
resultant wages will benefit the local economy as will local spending, capital
expenditures, and expanded tax base. Some small increases in population and
demand for services may result in this rural area, and labor training programs
and recruitment may be necessary to staff the jobs for both plants.
Both plants will produce synthetic pipeline gas which can be used to generate
energy. While coal conversion consumes a nonrenewable resource, it is more
efficient than biogas conversion (less feedstock used per Btu produced).
Therefore, the return would be a cheaper synthetic gas from HYGAS than bio-
gas which, in turn, would result in less cost for energy generation.
Consumption of Resources—Table 115 shows the natural resource consumption
expected from each plant. The HYGAS process and the economy of scale result
in less materials consumed per million Btu of output than the biogas plant.
310
-------
TABLE 115. RESOURCES COMMITTED TO THE SYNTHETIC GAS PLANTS "
Resource
Straw/Manure to Gas
7 MMSCFD
Coal to Gas
274 MMSCFD
Land
Feedstock
Auxiliary Fuels
Chemicals
Auxiliary Power
Water
Manpower
0.5 acre/MM Btu/hr
600.4 Ib/MM Btu
544 Btu/MM Btu
5.6- Ib/MM Btu
19.6 kW/MM Btu/hr
42.9 gal/MM Btu
0.09 mh/MM Btu
0.07 acre/MM Btu/hr
163.8 Ib/MM Btu
134 Btu/MM Btu
0.071 Ib/MM Btu
0
11.1 gal/MM Btu
0.019 mh/MM Btu
-*Froni Tables 56 and 70.
**Increases- to 0.14 acre/MM Btu if a 440 acre buffer zone is included.
Summary of Scenario 2—
If the qualitative assessments summarized in Tables 113 and 114 were assigned
the numerical values in Table 110 and summed with.out weighting environmental
aspects of the site, the biogas plant and the HYGAS plant would have similar
regional impacts per volume (or Btu) of product gas. Feedstock procurement
for the HYGAS plant, however, would potentially have significantly greater
impact than straw and manure collection for the biogas plant (Table 116).
Mitigation of surface raining impacts would be critical if the two gas produc-
tion cycles were to be made environmentally comparable. In other words, the
biogas facility would be more environmentally suitable in this scenario region,
principally because of lower feedstock, procurement impacts. Additional study
is needed on the nature of air,, water, and solid waste emissions from the
HYGAS process to determine if hazardous substances are a problem.
311
-------
TABLE 116. SUMMARY OF STRAW/MANURE AND COAL TO
SYNTHETIC GAS IMPACTS
Site Specific Feedstock Procurement
Factors
Straw/Manure
Climatology and
Meteorology 0
Air Quality
Surface Water
Availability
Surface Water
Quality
Groundwater
Availability
Groundwater
Quality
Soils, Geology
Land
Availability
Ecology
Aesthetic
Resources
Historical,
Archaelogical
Resources
Community
Economy
Community
Population
and Services
Labor
Availability
Power
Availability
Transportation
Availability
TOTAL
-6
0
-1
0
-. . .0
-7
0
0
0
0
5
0
1
0
-6
-14
Coal
0
-2
-1
-6
-7
-7
-8
-1
-7
-8
-7
5
0
1
0
-6
-54
Conversion
Plants
Straw /Manure
-1
-6
-1
-1
-6
-6
-7
-6
-6
-7
-6
5
-1
-1
5
-6
-51
Coal
-2
-6
-1
-1
-6
-7
-6
-6
-6
-7
-7
5
-2
-2
10
-6
-48
312
-------
WOOD AND COAL TO SYNTHETIC FUEL OIL
The hypothetical wood and H-Coal liquefaction plants would produce low sulfur
synthetic fuel oil in the northeastern region of the U.S. Boiler fuel is
assumed to be the most likely product use in this region. Section 5 presented
details of the two conversion cases.
Economic Comparison of Fuel Oil Production — Scenario 3
The production capacity of the H-Coal plant is nearly 40 times that of the
wood-to-oil plant. Table 117 summarizes economic factors for the two similar
conversion processes with a large capacity difference. Capital investment
for wood-to-oil is more than twice that for H-Coal on a BPD production basis.
A larger biomass conversion plant would look, better economically, but wood
residue availability limits the practical plant capacity in this scenario.
The lower conversion efficiency is also a penalty. Annual operating costs
differ by a factor of nearly four, and the $18.88 per barrel annual cost for
the wood-to-oil plant reflects large labor and purchased power expenses.
Base production costs in Table 117 exclude the feedstock costs. For both
private and utility financing, wood-derived fuel oil is 2.5 to 3 times more
costly to produce, at least in this comparison. The example fuel oil costs
reflect the inclusion of forest residue at $10 per ton and high sulfur coal
at $25 per ton. Neither plant appears to produce an economically competitive
boiler fuel, if these feedstock costs can be considered reasonable estimates
for early 1978. The wood-derived oil is about twice as expensive as the
coal-derived oil on both financing bases. For comparison, a recent SRI
report (11) gives an oil cost (utility financing) of about $31.20 per barrel
(S5.37/MM Btu) for a 5268 BPD wood liquefaction plant using the same wood
cost of Sl.OO/MM Btu. This SRI example shows the effects of an economy of
scale and a higher conversion efficiency (52 percent versus 42.1 percent).
The relative impacts of wood and coal costs on the cost of synthetic fuel oil
are illustrated in Figure 42. On an equivalent $/MM Btu feedstock basis, the
roughly parallel lines indicate that an increase in feedstock cost results
in about the same percentage increase in oil cost for both cases. In absolute
costst the wood-derived oil is much more sensitive to wood cost. Again, the
effect is noted that the cost of the feedstock is very important in small-
capacity plants. Biomass conversion, is- unlikely to be competitive with large-
scale coal conversion unless biomass feedstocks are relatively much lower in
cost and biomass conversion efficiencies are improved.
As noted in Section 5, nearly half of the plant wood feedstock is consumed in
the production of synthesis gas for the liquefaction reaction. Conversion
efficiency improvements are certainly possible in this liquefaction process.
A larger scale plant might be possible in an area with greater residue re-
sources (at a low cost). However, many favorable circumstances would be
needed to overcome the apparent economic advantage of a large coal lique-
faction facility.
313
-------
TABLE 117. ECONOMIC COMPARISON OF WOOD AND COAL
TO SYNTHETIC FUEL OIL
Wood to Oil Coal to Oil (H-Coal)
Element (1,764 BPD) (66,856 BPD)
Ca\
Feedstock input, MM Btu/yr 6,550,000 (HHV) 220,810,000 (HHV)^ '
Fuel till Output,. MM Btu/yr 3^704,000 (HHV) 139,186,000 (LHV)(b)
Thermal Efficiency, % 42.1 6'5.5^b)
Capital Cost
$ Million
$/BPD (Net)
(c)
Operating Cost
$ Million/yr
$/bbl(d)
Base Oil Production Cost
Utility, 5/bbl(d)
Private, $/bbl
(e)
Sample Fuel Oil Cost
Utility, $/bbl(d)
Private, $/bbl(d)
99.1
56,180
11.1
18.88
39.23
51.99
.50.37
63.13
1,640
24,530
108.8
4.. 88
13.72
20.37
24.19
30.88
(a) 212,367,000 MM Btu/yr (LHV).
(b) Sum of naphtha and heavy fuel oil.
(c) Excludes feedstock cost.
(d) For a $/MM Btu basis, use 6.3 MM Btu/bbl for wood-derived oil and
6.246 MM Btu/bbl (LHV) for coal-derived oil (naphtha plus fuel oil).
(e) Includes wood residue at $10/ton ($1.00/MM Btu) and coal at $25/ton
($1.05/MM Btu).
314
-------
100
80
03
SSQ
j
O
u.
O
w 40
O
CJ
20
0.50
T
5
T.OO
!
* WOOD COST. S/MMBTLt
r.scr 2.00 * zscr
3.00
10 15 20
WOOD COST, S/TON
"T"
25
COAL COST, S/TON
10
I
20.
I
30
I
40
I
50-
1
60
30
PRIVATE
UTILITY _
70
I
30
I
0.50
1.00
1.50
ZOO-
Z50
COAL COST, S/MMBTU
3.00
Figure 42. Effect of feedstock cost on the
cost of synthetic fuel oil.
315
-------
Environmental Comparison — Scenario 3
Feedstock Procurement—
Mining of coal and gathering of wood residue require certain physical activ-
ities which will affect the environment. In general, soils, geology, topog-
raphy, and water are affected by deep coal mining while wood residue collec-
tion, as in Scenario 1, may affect soil productivity, erosion, and water
quality. In the following paragraphs and in Table 118, the potential impacts
of feedstock procurement for wood and coal liquefaction are summarized.
Air Quality—Short-term increases in fugitive dust concentration may result
from both feedstock procurement operations. Wind erosion of exposed soils
may result from-excess wood residue removal, while stockpiling and transport
of coal and disposal of mine rock will contribute to fugitive dusts as well.
Use' of dust control measures and care in residue collection, coal storage,
and transport can mitigate potential impacts.
Surface Water—Increased erosion in areas stripped of forest residues could
result in increased sediment loads in streams. 'Slopes are particularly
susceptible to erosion. Careful management of residue collection will mini-
mize this effect.
In deep mines, it may be necessary to dewater the mine area. This water, if
discharged directly to surface waters, could degrade water quality signifi-
cantly. Acid mine drainage is of particular concern in the eastern U.S.
which already has- water quality significantly affected by mine and industrial
waste discharges. In addition, disposal of mine rock wastes in shallow val-
leys may contribute to increased sediments in surface waters. Pollutants in
runoff and leachate from the waste piles can degrade water quality. Since
shallow valleys may be direct conduits to surface water bodies, dikes and
other protective measures may have to be implemented to protect downstream
water quality.
No impacts on surface water availability are expected from either procedure,
although coal waste disposal in shallow valleys could affect flow patterns in
small tributaries.
Groundwater—Wood residue collection should not affect the quality or quan-
tity of groundwater.. Mina. water is; a groundwater supply, however,, and dewa-
tering- of the coal mines may interrupt flow in some aquifers, Of particular
concern would be the good-quality water expected in one of the three proposed
mines.
Soils and Geology—Since wood refuse contributes over time to soil stability
and organic content, removal of the residues could reduce soil productivity
and contribute to the loss of topsoil through wind and water erosion. A
loss of nutrients such as nitrogen, potassium, phosphorus, and sulfur may
require use of chemical fertilizers or alternative soil conditioners to
ensure continued productivity of the forest-land soil.
Deep mining may affect soils through mine rock disposal by altering the sur-
face composition, texture, and topography in the shallow valleys. In addition,
extraction of coal could contribute to future subsidence over the mine itself.
316
-------
TABLE 118. IMPACT SUMMARY FOR SITE SPECIFIC FACTORS - FEEDSTOCK PROCUREMENT
No Adverse
Specific Factors Discernible 3eneiicial [mpacc Short Long
Impact Impact ^ Term Term
FOREST RESIDUE PROCUREMENT, NEW ENGLAND
Climatology and Meteorology x
Air Quality IX X
Surface Water Availability x
Surface Water Quality -IX X A
Groundwater Availability I
Groundwiter Quality- X. , - ,,.....
Soils and Geology " I_H- j j A
Land Availability I X X A
Regional Ecology and Critical Habitats. X
Aesthetic Resources X
Historical, Archaeological Resources X
Community Economy X
Community Population and Services \
Labor Availability '.
Power Availability X
Transportation Availability I XX
COAL PRDCDREMEST, EASTERH U.S.
Climatology and Meteorology X
Air Quality I X X A
Surface Water Availability X
Groundwater Availability
Groundwater Quality
Soils and Geology
Land Availability
Regional Ecology and Critical Habicacs
Aesthetic Resources
;-n
I
H
T
M-S
M
X
X
X
\
X
X
X
.<
X
c
X
X
A
A
A
Siscorical^ Archaeological Resources
Community Economy
Community Population and Services
Labor Availability
Power Availabilitr
transportation Avmilability
(a) Key for symbols used in adverse impact ratings:
S - Potentially significant
M • Moderate
t - potentially insignificant
(b) Key for symbols used in mitigating measures ratings:
A - Mitigating aeasures described in next assumed no be ioplemented
(c) Assumes ao other large scale development in the area coincident with power plant development or
synthetic fuel.
(d) Assumes cooperation between plant and government agencies to promote reasonable, economically
sound growth.
(e) Assuaws power production or c'uel production is a benefit to che community outweighing minor power
consumption during construction or during operation.
317
-------
Land Availability—Between 20,000 and 70,000 acres per year will be required
for forest residue collection. Since regrowth of forests in cutover areas is
necessary before a collected area can be used again, it is not likely that the
acreage used in. any given year will be used again during the life of the wood
liquefaction facility. Therefore, many thousands of acres of suitable land _
must be available for feedstock procurement, but use of this land, if avail-
able, should not affect alternative land use or development.
The deep mine itself does not commit a large amount of surface area. However,
mine rock disposal may require large areas and alternative uses of these areas
may be restricted after disposal is complete. Therefore, use of disposal
sites might have some impact on land availability, particularly in highly
developed areas- like, the coal-mining-portions of the eastern U..S.
Ecology—As in Scenario I,, removal of forest residues may physically disturb
forest floor communities of animals, alter the rate of forest regeneration by
altering forest floor soils, and displace wildlife due to the presence of
man in the area. Because of the acreage- committed to residue collection,
this disturbance will be widespread regionally although its significance will
be small because a site will be used only once, followed by the natural (or
man-assisted) recovery of that system.
Removal of forest floor debris may benefit the forest by eliminating forest
fire fuels and by removing the habitat of known insect pests or disease
organisms. A. long-term benefit to forest productivity could then result.
A regional reduction in habitat and wildlife could result from mine rock dis-
posal from the coal mines. Since the shallow valley disposal sites may also
be riparian vegetation types, and since industrial development in the eastern
U.S. has reduced wildlife habitat acreage (particularly riparian habitats),
this disposal could cause significant adverse impacts on regional ecology.
Aesthetics—Forest residue collection will result in a change in the visual
appearance of the woodland affected (about 20,000 to 70,000 acres a year).
This change could be positive, particularly in a fir or pinewoods where an
open parklike appearance would result. The change might be less noticeable
in a hardwood or mixed forest* where underbrush normally conceals the forest
floor:.
The deep mines should not affect the aesthetics beyond the actual mine shaft
and associated buildings. However, mine rock disposal will result in a loss
of vegetation, a contrast in color and texture, and changes in topography
which on a regional scale may be important. The further reduction of open
space and forested vistas in a heavily developed region such as the eastern
U.S. coal province could constitute a moderate to significant long-term
adverse effect. This impact would be moderated over time by reclamation
and revegetation of the disposal sites.
Historic and Archaeological Resources—Neither forest residue collection nor
deep mine operation should affect historic or archaeological sites.. Mine
rock disposal would be constrained by the existence of known sites; however,
surveys prior to selection of disposal sites will permit avoidance of such
resources.
318
-------
Social and Economic Effects—Between 30 and 50 jobs will be created by forest
residue collection, as in Scenario 1. Associated wages and spending as well
as several million dollars per year paid for the wood residues will benefit
the community. No adverse impacts on community services or labor availability
are expected.
Coal mining will provide full-time employment as well. In the eastern U.S.
coal province, skilled labor should be -readily available, and no drains on
services or population are expected. On the order of $200 million per year
will be paid for the coal, a benefit to the local economy.
Conversion Plants—
Construetiou and operatioti of wood or coal liquefaction, plants will affect the
hypothetical plant site and vicinity,, primarily through generation of air and
water emissions and solid wastes. As in Scenarios 1 and 2, the emissions
will directly affect air and surface water quality, soils, topography, and
land use and indirectly affect ecology and groundwater quality. Section 5
detailed the emissions expected; the following paragraphs and Table 119 sum-
marize these impacts assuming similar (but not. the same) plant sites. The.
wood-to-oil site is in New England, while the coal-to-oil (H-Coal) site is
in the eastern U.S. coal province.
Climatology and Meteorology—The wood liquefaction,plant cooling tower will
release, approximately 62^500 Ib/hr of water vapor to the atmosphere,., while
H-Coal plane towers will release about 2.2 MM Ib/hrv The 25,000 TPD coal
facility has a slight economy of scale in this respect over the 2000 TPD
wood-to-oil plant. While impacts will be short-term and localized, both
facilities have the potential to increase fogging on-cool, humid days; and,
when the temperatures are below freezing, icing could occur. The absolute
magnitude of impact for the H-Coal plant is much greater, of course.
Air Quality—The wood-to-oil conversion plant is expected to produce over
100 tons per year of particulate emissions and could be subject to new source
tradeoff (offset) conditions. Other potential air problems could result from
hydrocarbon vapors released from product storage which could aggravate an
existing photochemical oxidant problem. Small quantities of NOx, SOX, CO,
and H2 will also be released,_ and cooling-tower drift will contain small.
amounts of hydrocarbons- if process- wastewater is. recycled to the cooling
water system. About 10 tons- per year of salt will be deposited in the area
from cooling-tower drift losses.
The H-Coal plant will release significant quantities of fugitive dust from
coal handling. Other emissions will include NOX, SOX, CO, hydrocarbons such
as methane, I^S, COS, and also NH3. Trace organic compounds which could be
toxic, carcinogenic, or mutagenic might be released from product storage,
vent gas stacks, and cooling towers. Salt emissions in cooling^tower drift
will be about 600 tons per year. Some H-Coal vent gas streams might require
special treatment to reduce- toxic trace materials and hydrocarbon emissions.
In a relatively developed area. such, as the industrial eastern U.S., new
sources of SOX, NOX, and HC could be. significant in nonattainment areas, and
could make implementation of emission offsets by the plant necessary.
319
-------
TABLE 119. IMPACT SUMMARY FOR SITE SPECIFIC FACTORS - WOOD AND COAL
TO FUEL OIL
No
Site Specific Factors Discernible
Impact
WOOD-TO-OIL. 2000 TPD PLANT IN MEW ENGLAND
Climatology and Meteorology
Air Quality
Surface Water Availability X
Surface Water Quality
Groundwacer Availability X
Groundvacar- Quality
Soils and Geology ,
Land Availability
Regional Ecology and Critical Habitats
Aesthetic Resource*
Historical* Archaeological Resources
Community Economy
Community Population and Services
Labor Availability
Power Availability-
Transportation Availability
H-COAU. 25,000 TPD- PLAHTV EASTERN D.S-
Climatology and Meteorology
Air Quality
Surface Water Availability X
Surface- Water Quality
Groundwater Availability X
Groundvater Quality
Soils and Geology
Land Availability
Regional Ecology and Critical Habitats
Aesthetic Resources
Historical, Archaeological Resources
Community Economy
Community Population and Services
Labor Availability _
?ow«r Availabilitr
TrajuportatioB- Availability-
Beneficial *?v«"
Impact :m<^"
I
r(c)
I
.
L
I
r(c)
I
S
I
xCd)
I
I
x(e)
I
I
M-S
I
I
I
jCc)
j(c)
M-S
I
X
r
I
£('>
t
Short Long
Tern Term
X
X
X
t
X
X
X
X
X
X
X
X
x:
X
X
X
X
X
X
X
X
X
X
r
Direct
X
X
X
X
X
X
X
X
i.
X
X
I
X
X
X
X
X
X
X
X
X
X
Mitigating
Indirect Measures
(b)
,
A
X A
A
A
A
A
A
A
A
A
A
X A
A
A
A
A
A
A
(a) Kay for symbols used la adverse impact racings:
5 - Potentially significant
M - Moderate
~ " Potentially Insignificant
Key for symbols used in mitigating measures ratings:
A » Mitigating measures described in text assumed co be implemented
(b)
(c)
(d)
Assustes no other large scale development in the area coincident with power plant development or
synthetic fuel.
Assumes cooperation between plane and government agencies to promote reasonable, economically
sound growth.
(a) Asanaes power production or fuel production is a benefit to the community outweighing minor power
consumption during construction or during operation.
320
-------
Surface Water—The wood-to-oil plant will require about 27 gallons of water
for each million Btu of product oil, while the H-Coal plant will require
about 31 gallons per million Btu. The wood-to-oil conversion demand is about
210 gpm, which would not restrict availability in the river supply (this flow
ranges from 780,000 to two million gpm). The H-Coal plant demand of about
9100 gpm also should not restrict available supplies (this flow ranges from
75,000 to three million gpm), although at low flow some problems could arise
if other demands exist on the supply.
Aqueous discharges from the wood-to-oil plant will contain BOD (organics),
TSS, TDS, and oil and grease. It is possible that residual organic substances
which might be toxic or carcinogenic could be released from syngas or wood
conversion, processes and pass through treatment unaffected. Additional treat-
ment (such, as activated carfoort adsorption for dissolved organics) might be.
needed. If this water were reused as cooling- water as proposed, some of
these materials could be released with cooling tower drift, as dicussed above.
The H-Coal plant aqueous process effluents contain TDS, TSS, and BOD. Reuse
of wastewater minimizes plant makeup and reduces the impacts on surface water
quality. Slowdown from the cooling tower could contain trace organics (poten-
tially toxic), corrosion products, and chemicals used to control scaling and
corrosion. High TDS blowdowns from other sources, such as the H£ plant ash
system, could also contain significant quantities of pollutants. Additional
treatment may be needed before the process effluent"can be safely discharged.
After adequate treatment and recycling, the process .effluent streams from both
plants are small (150 and 430 gpm) and should not significantly affect water
quality. Storm runoff flows will be large (116 and 475 gpm) on an annual
average basis. Containment and treatment of runoff will help to limit degra-
dation of surface waters for both plants.
Groundwater—Neither facility consumes groundwater, and therefore neither
facility will affect groundwater availability. Disposal of solid wastes
(char, soot, slag) in wet cake form, however, could present a contamination
problem to groundwater supplies. Since these wastes could contain potentially
hazardous materials (nonvolatile heavy metals or hazardous organic compounds),
the. landfill sites used for each plant must be managed to prevent contamina-
tion of groundwater and surface water supplies.
Soils and Geology—About 110 acres of land for the wood-to-oil plant and 440
acres for the H-Coal plant will be alfcered by construction activities. The
H.-Co.al_ plant, uses proportionally less acreager and neither facility is expected
to have significant impacts on topography or soils.
Solid wastes will be disposed of by onsite burial for the wood-to-oil plant.
Offsite disposal of H-Coal solid wastes from the process and from water/waste-
water treatment in shallow valleys, however, will cause topographical changes.
In additionv the types of wastes for both plants could significantly affect
surface texture and soil quality. Particular care in reclamation of these
sites will be necessary in order to insure productivity of the area.
321
-------
Land Availability—Commitment of 110 acres to the wood-to-oil plant does not
constitute a significant constraint on land availability. The 880 acres (in-
cluding 440 acres of buffer zone) for the-H-Coal plant could be a problem in
a heavily developed area, but buffer zone uses such as agriculture, forestry,
grazing, or other industry could be encouraged, reducing the constraints on
land use.
Ecology—About 110 acres of wildlife habitat will be disturbed by construction
of the wood-to-oil plant, while the H-Coal plant would disturb up to 440 acres.
These impacts will be insignificant regionally if care is used in siting the
plant to avoid critical habitat, riparian woodlands (in the case of H-Coal),
or other important or unique vegetation. In the H-Coal case, ecological im-
pacts and their significance: in the region would depend also on the degree of
existing and planned development: and, therefore,, the rarity of natural habitats.
Impacts on vegetation, wildlife, and aquatic life from degradation of air and
water quality and deposition of cooling-tower drift will be similar for both
facilities, with a greater area being affected by the large H-Coal facility..
Aesthetics—In the relatively undeveloped New England site area, the plant,
feedstock woodpile, flare stack, and cooling-tower plume will present strong
contrasts in shape, color, and texture to the wooded surroundings. In addi-
tion, the potential odors from processing- and the general industrial character
imparted by.the.coming, and going of supply vehicles, human activity, equip-
ment noise, and air emissions will be- in sharp contrast to present uses.
Visual accessibility may be limited by use of the- surrounding woods as a
screen and by implementing landscaping. However, the facility will have a
significant local adverse impact on aesthetics.
The H-Coal plant will also affect aesthetics locally, but the significance
may be moderated by the present uses of land in the region for industry.
Care should be used in siting to avoid breaking up open space vistas. The
use of landscaping, the layout of the plant to reduce visibility, and the
revegetation of solid waste disposal sites offsite will also serve to modify
the adverse impact.
Historic or Archaeological Resources—Care in siting either plant will mini-
mize the potential for impact on. historic or archaeological sites-. If any
subsurface- relics are discovered during construcCiorty salvage and protection.
may be necessary. Solid waste disposal sites for H-Coal will also have to
be surveyed in order to ensure that no resources are buried with the wastes.
Social and Economic Effects—Approximately 145 permanent jobs will be created
by wood-to-oil plant operation, while H-Coal will create 726 full-time jobs.
Each facility will also generate temporary construction jobs (from several
hundred for wood-to-oil to 300 to 400 for H-Coal). This employment, the
wages and spending resulting from it, the capital spending by the plants,
and the expanded tax bases will benefit local economies. Benefits will prob-
ably be proportionally greater in rural New England, but demands for trained
labor, housing, and services will partially offset these benefits there.
Little affect on labor pools, housing, or services is expected from construc-
tion and operation of the H-Coal facility.
322
-------
Consumption of Resources—Table 120 shows the natural resources consumed by
each facility. A wood-to-oil facility would consume relatively more land,
auxiliary fuels, chemicals, and manpower as well as feedstock because of the
low efficiency of conversion. The H-Coal plant would consume slightly more
water per Btu. of product output.
TABLE 120. RESOURCES COMMITTED TO SYNTHETIC FUEL OIL PLANTS*
Resource
Wood to Oil
1,965 tpd
Coal to Oil
27,836 tpd
Land
Feedstock.
Auxiliary Fuels
Chemicals
Auxiliary Power
Water
Manpower
0.24 acre/MM Btu/hr
353.7 Ib/MM Btu
3,590 Btu/MM Btu
1.15 Ib/MM Btu
39.5 kW/MM Btu/hr
27.2 gal/MM.Btu.
0.078 mh/MM Btu
0'.024 acre/MM Btu/hr**
133.3 Ib/MM Btu
79 Btu/MM Btu
0.545 Ib/MM Btu
+
31.35 gal/MM Btu
0.011 mh/MM Btu
*From Tables 85 and 100.
**Increases to 0.098 if a 440 acre buffer zone is included.
Summary of Scenario 3—
If the qualitative assessments summarized in T.ables 118 and 119 are assigned
numerical values- shown in Table 110,. it can be seen that coal procurement for
H-Coal has- a, potential for posing, significantly greater environmental prob-
lems than, woodt procurement, for wood-to-oil. There is no- clear difference
between: the environmental effects- of the H-Coal or wood-to-oil processes
(Table 121). The important aspects of coal procurement for H-Coal are coal
refuse disposal sites and methods of disposal.. Disposal of H-Coal process
wastes, similarly, could be important. Isolation of potentially hazardous
compounds from the air, water, soils, and biota is an important area for
future study.
323
-------
TABLE 121. SUMMARY OF WOOD AND COAL TO OIL IMPACTS
Site Specific
Factors
Feedstock
Procurement
Wood Residue Coal
Climatology and
Meteorology
Air Quality
Surface Water
Availability
Surface Water
Quality
Groundwater
Availability
Groundwater
Quality
^ivi-1 Q - (Z&f\~\ n-ffv
Jv^cr^0r y. vTCvivg y
Land
Availability-—
Ecology
Aesthetic
Resources
Historical,
Archaeological
Resources
Community
Economy
Community
Population:
and Services
Labor
Availability
Power
Availability
Transportation
Availability
TOTAL
0
-1
0
-1
0
0
1
r
-I
1
1
0
5
0
1
0
-6
-8
0
-1
1
0
-7
-7
-6
— .*£•
— - — • O —
-6-
-9
-3
0
5
0
0
0
-6
-48
Conversion
Plants
Wood
-1
-6
0
-1
0
-6 ~
-6-
-6
-6
-10
-6
5
-1
-1
5
-6
-46
Coal
-1
-9
0
-1
0
-6
-6
-6
-6
-9
-6
5
-1
-1
10
-6
-43
324
-------
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PACHEC '77 Proceedings. Denver, Colorado. August 23-31, 1977.
pp. 765-768.
2. t ScoHon,, tv Reed, "Ait Assessment of Coal Jlesources," Chemical Engi-
: neertng Progress, VoiU 73 Na. 6v June, 1977. pp. 25-30,
3. D'Novo, S. T-, et al., Preliminary Environmental Assessment of Biomass
Conversion-'to Synthetic Fuels. Battelle - Columbus Laboratories.
Draft, final report prepared for U.S. Environmental Protection Agency,
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March 1, 1976- 145 pp.
6. Detman, Roger, Factored Estimates far Western Coal Commercial Concepts.
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ERDA Report No. FE-2240-5. October, 1976. 77 pp.
7. Fluor Engineers and Constructors, Inc., E-Coal Commercial Evaluation,,
Conceptual Design and Economic Analysis for a 25,, 000 Ton-Per-Day
I E-Coat Liquefaction Plant,. Case, I — Fuet Oil Mode. Final report pre—
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8. Skamser, Robert, Coal Gasification Commercial Concepts, Gas Cost
Guidelines'- C, F_ Braun and Co., prepared for ERDA and AGA. ERDA
Report No. FE-I235-1. January.. 1976. 37 pp.
9- Alien, Jr., John A., et al., An Evaluation of the Use of Agricultural
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No. TID-27904/1.. July, 1977. 88 pp.
325; .
-------
10. Bliss, C., and D. 0. Blake, "Silvicultural Biomass Farms," Volume V —
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Report No. 7347, Vol. V. May, 1977.. 246 pp.
11. Schooley, Fred A., et al., M-iss-ion Analysis fop the Federal Fuels
from Biomass Program. SRI, International quarterly progress report
prepared for U.S. Department of Energy, Solar Energy Division.
June 12, 1978. 50 pp.
12. Alich,. Jr. , John A. y et al. , "An Evaluation of the Use of Agricultural
Residues as an Energy Feedstock — A Ten Site Survey," Volume 2 —Study
Area. Analysis^ Stanford Research Institute,, prepared for U.S. Depart-
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July, 19-77. pp.. Til 1-36.
13. Austin,. M. E., "Land. Resource Regions and Major Land Resources Areas
of the United- States." U.S. Department of Agriculture, Soils Con-
servation Service. Agriculture' Handbook No. 296. 1965.
14. USDA, Soil. The learbook of Agriculture. U.S. Government Printing
Office. 1957.
15. Buol. , S. W. (ed.), Soils of the Southern. States and Puerto Rico.
Southern: Coop. Series Bull. No. 174. Reg. Pub. USDA/SCS. 1973.
16. Garrison,. G. A., et al. ,. Vegetation and Environmental Features of
Forest and. Range Ecosystems. U.S.. Department of Agriculture, U.S.
Forest Service.-•Agriculture Handbook No. 475. 1977. 68 pp.
17. Braun,-E. L., Deciduous Forests of Eastern North America. Collier
MacMillan Publishers. New York. " 1974.
18. Stanford Research Institute. An Evaluation of the Use of Agricultural
Residues as an Energy Feedstock, Volume I. NTIS Report No.- PB-260 763,
prepared for National Science Foundation. July, 1976. 174 pp.
19.. "Utilities, Put the Sun to Work," EPEI Journal, Vol. 3, No-. 2.
Marcfe, 197£~ pp. 26-32-. ~~
20. Hall, E. H., et al. , Comparison of Fossil and Wood Fuels. Battelle -
Columbus Laboratories, prepared for U.S. Environmental Protection
Agency. Report No. EPA-600/2-76-056. March, 1976.
21.. 2377 Keystone Coal Industry Manual- Mining Information Services,
The McGraw-Hill Mining Publications. New York. 1977. 1184 pp.
22. The National Atlas of the United States of America. U.S. Department
of the Interior, Geological Survey. Washington, D.C. 1970. 417 pp. •
326
-------
23. Soils of the North Central Region of the United States. Bull. No. 544,
Agricultural Experimental Station, University of Wisconsin, Madison.
North Central Region Pub. No. 76. June, 1960.
24. Kuchler, A. W., Manual to Accompany the Map, Potential Natural
-Vegetation of the Conterminous United States. American Geographical
Society. New York. 1964.
25. Kuchler, A. W. , Map - Potential Natural Vegetation of the Conterminous
United States. American Geographic Society. New York. 1975.
26.. Missouri Basin Interagency Committee,-The Missouri- River- Basin Compre-
hensive Framework Study. Volumes; 1-7. 1971.
27. USDA,. Soil Classification, A Comprehensive System, 7th Approximation.
1960. 265 pp. (Supplement, issued in March,. L967 and September, 1968).
28. USDAr Soil Survey of Harper County, Kansas. 1971.
29. Farm Facts 1972-73. Kansas State Board of Agriculture. Topeka, Kansas.
30. Skidmore, E. L. and F. H. Siddoway, Crop Residue Requirements to Con-
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31. Black, A. L., F. H. Siddoway, and P. L. Brown, "Summer Fallow in the
Western- United States,Ir Chapter 3, USDA, ARS Conservation Research
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32. Stanford Research Institute, An Evaluation of the Use of Agricultural
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prepared for National Science Foundation. July, 1976. 608 pp.
33. Lyles, Leon, "Wind Patterns and Soil Erosion on the Great Plains,"
Proceedings of the Symposium on Shelterbelts on the Great Plains.
Greaf Plains- Agriculture Publication No. 78. 1976. pp. 27-30.
3'4. Eylesv Leonv "Fassible- Effects-of-Wind' Erosion: on- Soil Productivity,""
Journal of Soil and Water- Conservation, Volume 30. 1975. pp. 279-283.
35. Aldrich, S. A. and Earl R. Leng, "Modern Corn Production," The Farm
Quarterly., Ohio. 1966.
36. The Changing Fertility of New England Soils, USDA Agriculture Infor-
mation Bulletin No. 133. 1954.
37. Shelford, V. E., The Ecology of North America. University of Illinois
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-------
38. McEwen, Bryce W. , Soil Survey of Androscoggin and Sagadahoc Counties.,
Maine. USDA. Soil Conservation Service. 1970.
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Conservation Service. 1974.
40. Hewlett, K. and A. Gamache, "Silvicultural Biomass Farms," Volume VI —
Forest and Mill, Residues as Potential Sources of Biomass. The Mitre
Corporation, Metrek Division, prepared for ERDA, Division of Solar
Energy. Mitre Technical Report No. 7347, Vol. VI. May, 1977. 124 pp.
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the Paa-ifia Northwest, USDA,. Forest Service General Technical Report
"PNW-24. Pacific Northwest Forest and Range Experimental Station,
•Portland, Ore. 1974.
42. Odum, E. P., Ecology. Holt, Rinehart and Winston. New York. 1963.
pp. 73-75.
43. Odum, E. P., Fundamentals of Ecology. Third Edition. N. B. Saunders
Company. Philadelphia. 1971. pp. 131-137, 261.
44- Fernandesr J. H. , "Why Not Burn Wood," Chemical Engineering. Vol. 84,
No.. 12. May 23, 1977. pp. 159-164.
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tion. Washington, D.C. January, 1976. 112 pp.
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East Gillette Mine. U.S. Department of the Interior, USGS. 1976.
438 pp.
328
-------
Appendix A
PLANT EQUIPMENT LISTS
The equipment lists for four of the plant types are presented here in the
following subappendices.
A-L Wood-to-Power Plant
A-2 Straw and Manure-to-Gas Plant
A-3 Wood-to-Oil Plant
A-4 Coal-to-Power Plant
329-
-------
TABLE A-l. MAJOR EQUIPMENT SUMMARY — WOOD-TO-POWER PLANT
SERVICE
DESCRIPTION
Chip dump hopper
Hopper conveyor
Transfer conveyor
(inclined)
Chip bins
Chip blowers
Hydraulic dump platform
Auger conveyors
Chip reclaim conveyors
Transfer conveyor
(inclined)
WOOD RECEIVING AND STORAGE
1 - 14,000 cu ft under track hopper, 20 ft
wide by 60 ft long by 14 ft deep
1-420 tph chain conveyor, 120 in. wide by
70 ft long,. 15 hp
I - 420 tph belt conveyor,. 48 in., wide by
300 ft long, 60 hp
Z - 10,000 cu ft bins, 20 ft dia fay 35 ft
high (with dust collectors*)
2 - 7,000 cfm rotary blowers, 6 psi static,
pressure, 350 hp
1-50 ton capacity tilt platform, 20 hp
compressor and hydraulic system
4-60 tph"twin-screw conveyors, 12 in. dia
flight by 12 ft long, 5 hp
2 - 100 tph belt conveyors, 30 in. wide by
250 ft long, 5 hp
1 - 100 tph belt conveyor, 30 in. wide by
500 ft long, 20 hp
Boiler feed, silo
•Fuel distribution system
Power boiler system
BOILER (AIRSIDE)
1. - 5000 ctt ft bin with 0-100- tph vibrating
feeder (vent dust collector)
1 — 100 tph system - includes distribution
conveyor, 4 supply lines, 4 air lock
feeders and 4 rotary blowers, 30 hp
1 - 484,000 Ib/hr, 1250 psia, 900°F (TST)
boiler — includes water wall furnace
with traveling grate, tangential fuel
firing system, combustion controls, two
(continued)
330
-------
TABLE A-l (Continued)
SERVICE
DESCRIPTION
Power boiler system
Forced-draft fan
Induced-draft fan
Electrostatic precipitator
Exhaust stack
BOILER (AIRSIDE)
drum baffleless tube bank boiler, super-
heater and desuperheater, economizer,
mechanical dust collector, Ljungstrom
air heater, ash reinjection system, ash
hopper, soot blowers, ductwork, and com-
plete structural steel ~" ~
1 - 155,000 cfm at 80°F F.D. fan, S.P- =
11 in. wg, 900 hp
1 - 291,000 cfm at 312°F I.D. fan, S.P. =
12 in. wg, 1800 hp
1 - unit', 52 ft wide by 73.5 ft high by 60
ft deep, 6.0 ducts at 9 in. plate spac-
ing, 98,820, sq ft plate area, 99.5%
removal efficiency. 302,000 cfm at
300°F, 160 kVA
1 - 10 ft I.D. (at tip) by 175 ft high stack
Steam turbine
Generator
STEAM CYCLE (WATERSIDE)
1 - 50,000 kW condensing turbine, nonreheat
singlecase, single flow, 3600 rpm,
3d), 60 Hz
1 - 60,000 kW hydrogen cooled generator with
exciter and auxiliaries,. 13.8 kV, 3^>_,
6d Hzv 0.85 pf
Main transformer
Unit auxiliary transformer
Startup transformer
1 - 55 MVA, FOA, 65 C, 13.8/115 kV. 3cb, 60 Hz
1 - 4000/5400/6600 kVA, 65°C, OA/FA/FOA, 36,
60 Hz, 13.8/4.16 kV
1 - 3600/4800/6000 kVA, 65°C, OA/FA/FOA, 3,
60 Hz, 115/4.16 kV
(continued)
331
-------
TABLE A-l (Continued)
SERVICE
DESCRIPTION
STEAM CYCLE (WATERSIDE)
Miscellaneous transformers
Emergency diesel generator
Surface condenser
L.F- feedwater heater
Deaerating heater and tank
H.P. feedwater heater
Hot well pumps
Booster pump
Boiler feed pumps
L.P. drain pump
H.P- drain pumps-
C.W.. circulating pumps
S.W. supply pumps
Cooling tower
3 - 350 kVA, OA, 65 C, 4.16 kV/489/277 V,
3, 60 Hz
1 - 250 kW,~3cf>, 60 Hz, 480 V, 0.8 pf
1 — Z-pass single shell condenser, 50,000 •
sq; ft H.T. area, 340,000 Ib/hr at Z in..
Hga
1 - 4-pass horizontal exchanger, 1750 sq ft
H.T. area,. 14.5 psia steam, 353,000 lb/
hr waterside flow
1 - 435,000 Ib/hr at 3Q7°F tray type daera-
tor 165 psia shell, 44,000 Ib/hr steam
at 75 psia, 5000 gal tank
1 - 4-pass horizontal exchanger, 2250 sq ft,
H.T. area, 311 psia steam, 435,000 Ib/hr
waterside flow
2 - 780 gpm at 340 ft TDH pumps, 125 hp
1 - 1150 gpm at 1900 ft TDH pump, 800 hp
2 - 1250 gpm at 1900 ft TDH pumps, 800 hp
1-89 gpm at 260 ft TDH pump, 10 hp
1 - 116 gpm at 3290 ft TDH pump, 175 hp
AUXILIARY
3 - 23,270 gpm at 95 ft TDH pumps, 900 hp
2 - 2420 gpm at 55 ft TDH pumps, 75 hp
1 - 4-cell induced draft tower, 333 MM Btu/
hr heat load, 18.5°F approach (61.5°?
wet bulb), 15° range, 73 ft wide by
128 ft long by 60 ft overall height, 4 -
24 ft dia fans, 100 hp
(continued)
33Z
-------
TABLE A-L (Continued)
SERVICE
DESCRIPTION
C.W. chlorinator
River water' intake pumps
Pond, water supply pumps
Fire water booster pumps
Gravity sand filter
Filtered water storage tank
Feed pumps
Automatic chlorinator
Demineralizer system
Demineralizer water storage
tank
Acid (H2 S04)
Caustic storage tank
Regenerant feed pumps
Demineralizer water feed
pumps
Sanitary waste treatment
AUXILIARY
1 - 2000 Ib/day automatic chlorinator with
analyzer-controller
2 - 385 gpm at 120 ft TDH pumps, 20 hp
2. - 385 gpm. at 45 ft TDH pumps, 10 hp
2 - 350 gpm at 230 ft TDH pumps, 40 hp
1 - 5 ft. dia filter,. 3 gpm/sq ft loading,
30 in. bed depth
1 - 8000 gal tank, 12 ft dia by 10 ft high
2-60 gpm at 95 ft TDH, 3 hp
1 - LO Ib/day chlorine injector and con-
troller unit (150 Ib Cl2 cylinders)
1 - package system - includes 2-2 ft-dia by
8-5 ft high cation vessels (50 in. bed),
1-2 ft dia by 6 ft high vacuum deaerator
with vacuum'pump, 2-2 ft dia by 8.5 ft
high anion vessels (50 in. bed)
1 - 8000 gal tank, 12 ft dia by 10 ft high
1 - 350 gal tank with 10 gph metering pump
1 — 350: gal tank with. 25 gph metering, pump
2-20 gpm at 60 ft TDH pumps, 1 hp
2-37 gpm at 70 ft TDH pumps, 2 hp
1 - 7200 gal per day package unit - includes
biological reactor, clarifier, filter
and chlorinator
(continued)
331
-------
TABLE A-l (Continued)
SERVICE
DESCRIPTION
River water storage pond
Neutralization pit
Slowdown settling pond
Stormwater holding pond
Phosphate storage tank
Hydrazine solution: tank
Morpholine solution tank
Dispersant solution tank
AUXILIARY
1 - 3,000,000 gal basin, 120 ft wide by 240
ft long by 20 ft deep (17 ft SWD), clay-
lined
1 - 12,000 gal concrete basin, 15 ft wide
by- 15 ft'long by 8 ft deep
1 - 100,000 gal gunnited basin, 36 ft wide
by 36 ft long by 12 ft deep
1 - 3,000,000 gal clay-lined basin, 180 ft
wide by 220 ft long by 12 ft deep
1 - 350 gal atmospheric tank with 3 gpm
metering pump
1 - 350 gal atmospheric tank with 1 gpm
metering pump
1 — 350 gal atmospheric tank with 1 gph
metering pump
1 - 350 gal atmospheric tank with 2 gph
metering pump
^Pollution control equipment.
Horsepower listed is motor drive rating.
334
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TABLE A-2. MAJOR EQUIPMENT SUMMARY - STRAW AND MANURE-TO-GAS PLANT
SERVICE.
DESCRIPTION
FEEDSTOCK RECEIVING AND PREPARATION
Straw dump pit
Baled straw conveyor
Bale- diverter
Straw conveyor system
Portable belt conveyors
Baled straw conveyor
Straw unbalers
Primary crushers
Pneumatic conveyor (straw)
Pneumatic conveyors (straw)
Straw storage bins
Pneumatic conveyor (straw)
Secondary crushers
Pneumatic conveyors (straw)
1 - 6000 cu ft concrete pit, 50 ft long by
12 ft wide by 10 ft deep
1 — 100 tph pan conveyor, 54 in. wide by 60
ft long, 20 hp
L, — transfer chute diverter, 8- ft wide by
S ft long by 20 ft high
1 - 200 tph reversible belt conveyor system,
42 in.- wide by 4000 ft long (4 sections)
200 hp (total)
2 - 200 tph portable conveyors, 42 in. wide
by 100 ft long, 10 hp
Z — 100 tph pair -conveyors , 54 in. wide by
30 ft long,, 10 hp
2 — automatic bale breakers, 2 hp
2-40 tph hammermill crushers, 3/4 in.
screen, 600 rpm, 350 hp
1-80 tph pneumatic conveyor, 10tin. dia
by 450 ft long, 100 hp blower"
2-80 tph conveyor sections, 10 in. dia by
50 ft long, 50 hp blower'
8 - 50,000 cu ft bins, 40 ft dia by 40 ft
high
1-80 tph conveyor, 8 in. dia by 350 ft
long, 100 hp blower"
2-22 tph hammermill crushers, 1/8 in. dis-
charge screen, 200 hp
2-30 tph conveyors, 2 in. dia by 75 ft
long, 50 hp blowers
(continued)
335
-------
TABLE A-2 (Continued)
SERVICE
DESCRIPTION
FEEDSTOCK RECEIVING AND PREPARATION
Straw- pulping tank
Pulp sump
Cyclone feed pumps
Primary cyclones
Secondary cyclones
Manure receiving bin
Manure tube conveyors
Manure pulping, tank
Pulp sump
Cyclone feed pumps
Primary cyclones
Secondary cyclones
Manure reclaim bin
Hydraulic dump platforms
Lime storage silo
Lime weigh feeder
1 - hydropulper, 20 ft dia, 20 hp (2% solids
slurry)
1 - 8500 gal concrete sump, 12 ft wide by
12 ft long by 8 ft deep
.2 - 8400 gpm at 115 ft TDK pumps, 500 hp
24- - & in. dia hydrocyclones (2.65 S.G.)
12 - 16 in. dia hydrocyclones (1.1 S.G.)
1 - 12,000 cu ft bin (live center) with 12
screw conveyors, 50 hp
2-50 tph tube flow conveyors, 8. in. dia
by 1350 ft long (chain pull with discs),
15 hp
1 - hydropulper, 12 ft dia, 5 hp (2% solids
slurry)
1. - 1500 gal concrete sump, 6 ft wide by
6 ft long by 6 ft deep
2 - 1500 gpm at 115 ft TDH pumps, 100 hp
8-6 in. dia hydrocyclones (2.65 S.G.)
4-16 in. dia hydroclones (1.1 S.G.)
1 - 6000 cu- ft bin (live center) with 6
screw conveyors, 33 hp
5 - 50-ton capacity tilt platforms, 20 hp
ANAEROBIC DIGESTION
1 - 7000 cu ft silo, 15 ft dia by 40 ft high
(with collector and fan)
1 - 0-5 tph weigh belt feeder
(continued)
336
-------
TABLE A-2 (Continued)
SERVICE
DESCRIPTION
Lime slaker unit
Lime slurry storage tank
Lime slurry surge tank
•WASTEWATER TREATMENT
1 - 1600 Ib/hr slaker package unit - includes
slaker and agitator, grit screw, trans-
fer tank and agitator, controls
1 - 17,200 gal tank, 14 ft dia by 15 ft high,
10 hp agitator
Lime slurry transfer pumps
Lime slurry storage pumps
Lime slurry surge pumps
Polymer feed system.
Straw feed storage tank
Manure feed storage tank
Straw slurry feed pumps
Mamira slurry feed: pumps
Anaerobic digesters
Mixer-heater units
Recycle gas compressors
1 - 17,200 gal tank, 14 ft dia by 15 ft high,
10 hp agitator
2-35 gpm at 30 ft TDK pumps, 1 hp
2-35 gpm at 40 ft TDK pumps, 1 hp
2-70 gpm at 40 ft TDH pumps, 2 hp
1 — 250 Ib/day -package system - includes
1—16 cu'-ft polymer storage bin-, feeder
and disperser, 1 - 4280 gal mixing
aging tank, with 5 hp agitator, 1 -
470 gal feed tank with 1 hp. agitator.,
2 - 1 to 5 gpm metering pumps, 1 hp
1 - 480,000 gal tank, 55 ft dia by 27 ft
high, 150 hp agitator
1 - 81,000 gal tank, 24 ft dia by 24 ft
high, 25 hp agitator
2 - 2000 gpm at 50 ft. TDH pumps, 50 hp
Z. ~ 350- gpm at 50 ft TDH pumps-, 10 hp
6 - 5,640,000 gal fixed roof tanks, 200 ft
dia by 24- ft deep (21 ft SWD)
588 - 12 in. dia gas mixing guns, hot water
jacketed
7 - 3500 scfm single-stage compressors,
14.5/27 psia, 250 hp
(continued)
337
-------
TABLE A-2 (Continued)
SERVICE
DESCRIPTION
Digester effluent pumps
Sludge centrifuges
Sludge cake coaveyor
4
Sludge bucket elevator
*
Sludge cake conveyor
Sludge cake hopper
*
Primary clarifier
Sludge recycle pumps
*
Aeration basin
*
Aerators
*•
Secondary clarifiers
*
Sludge recycle pumps
*
Effluent polishing pond
Polishing pond recycle
pumps
ANAEROBIC DIGESTION
8 - 375 gpm at- 50 ft TDK pumps, 25 hp
5-36 in. dia solid bowl horizontal solid
bowl centrifuges, 250 hp
1 - 100 tph.belt conveyor, 20 in. wide by
200 ft' long, 5 hp
1 - 100 tph bucket elevator 75 ft long, 20 hp
1 - 100 tph belt conveyor with plow dis-
chargers, 24 in. wide by 260 ft long,
10 hp
1 - 432,000 cu ft hopper, 6 bin compartments,
256 ft long by 42 ft wide by 50 ft high,
slide gate bottoms and bin vibrators
L - 7'4,000 gal gravity clarifier, 34 ft dia
by 12 ft SWD, 5 hp. drive
2 - 110 gpm at 70 ft TDH pumps, 5 hp
1 - 400,000 gal basin, 90 ft wide by 90 ft
long by 10 ft SWD, 2 ft freeboard,
plastic-lined
4 - floating mechanical turbine aerators,
25 hp
2 - 52,000 gal gravity clarif iers:, 28. ft dia
by 12 ft SWD, 5 hp drive
4 - 200 gpm at 70 ft TDH pumps, 10 hp
1 - 10,000,000 gal clay-lined basin, 260 ft
wide by 495 ft long by 12 ft SWD
1 - 250 gpm at 70 ft TDH pumps, 10 hp
(continued)
338
-------
TABLE A-2 (Continued)
SERVICE
DESCRIPTION
Raw gas compressor
Acid gas removal system.
Glycol dehydration system
Acid gas incinerator unit
GAS'CLEANING ^
1 - 5920 cfm (outlet) two-stage compressor,
27/325 psia, 2200 hp, with 275 sq ft
precooler, 750 sq ft intercooler, 375
sq ft aftercooler
1 — Benfield hot potassium carbonate plant
(proprietary)» 13.6 MM scfd (dry) feed
gas - includes absorption and regenera-
tion columns, exchangers, pumps, re-
boiler filter, piping,, instruments and
controls
1 - Smith Industries glycol dehydration
plant (proprietary), 8.7 MM scfd (dry)
feed gas — includes absorber, regener-
ator, exchangers, pump, heater, piping,
instruments and controls
1 - John. Zink thermal oxidizer, waste heat
boiler unit, 4.9 MM scfd'(dry) acid
gas feed - includes horizontal thermal
oxidizer, firetube boiler, stack duct-
ing, refractory, combustion air fan,
controls
River water intake pumps
River water- storage pond
Storage pond pumps
Potable water well pumps
Potable water storage tank
AUXILIARIES
2-310 gpm at 70 ft TLH pumps, 10 hp
1 - I,200,000 gal clay-lined basin, 110 ft
wide by 200 ft long by 12 ft SWD
2-310 gpm at 70 ft TDK pumps, 10 hp
2-20 gpm at 140 ft TDH vertical turbine
pumps, 2 hp (6 in. dia casing)
1 - 34,000 gal tank, 18 ft dia by 20 ft
high (0-5 Ib/day chlorinator)
(continued)
339
-------
TABLE A-2 (Continued)
SERVICE
DESCRIPTION
Potable water supply pumps
Utility boiler
Feedwater treatment unit
Cooling tower
Circulating water pumps
Sanitary waste treatment
unit*
AUXILIARIES
2-20 gpm at 70 ft TDK pumps, 1 hp
1 - 50,000 Ib/hr at 75 psig package boiler -
includes combustion box, burner, fire-
tube boiler, stack, combustion air fan,
" J_ducting, and. controls
1 - 340 gph unit - includes- cartridge filter,
zeolite softener, 1000 gal feedwater
storage tank,, 5 gpm feedwater pump
1-2 cell induced draft tower, 3000 gpm,
25°F range, 30°F approach (50°F wet
bulb) with 2-96 in. dia fans, 25 hp
2 - 3000 gpm at 45 ft TDK pumps, 75 hp
1 — 15,000 gal per day package unit — in-
cludes biological reactor, clarifier,
filter,, chlorine injector and controls
^Pollution control equipment.
Horsepower listed is motor drive rating.
340
-------
TABLE A-3. MAJOR EQUIPMENT SUMMARY - WOOD-TO-OIL PLANT
SERVICE DESCRIPTION
WOOD RECEIVING AND STORAGE
Chip dump hopper 1 - 18,000 cu ft under-track hopper, 20 ft
wide by 80 ft long by 14 ft deep
Hopper conveyor 1 - 420 tph chain conveyor, 120 in. wide by
90 ft long,. 20 hp
Transfer conveyor (inclined) I - 420 tph belt conveyor, 48 in. wide by
280 ft long, 75 hp --
Chip bins 2 - 10,000 cu ft bins, 20 ft dia by 35 ft
high (with dust collectors)"
Chip blowers 2 - 7,000 cfm rotary blowers, 7 psi static
pressure, 350 hp
Hydraulic dump platforms Z - 50 ton capacity tilt platforms, 20 hp
Auger conveyors 4-60 tph twin-screw conveyors, 12 in. dia
flights by 12 ft long, 5 hp
Chip reclaim conveyors 2 - 100 tph belt conveyors, 30 in. wide by
430 ft long, 10 hp
Transfer conveyors (inclined) 2 - 100 tph belt conveyors, 30 in. wide by
700 ft long, 20 hp
Chip distribution system 1 - transfer house - including 2-magnetic
separators, belt trippers, 1-5 com-
partment bin, 16 ft wide by 50 ft long
by 20 ft high,. 5 - 0 to 30 tph vibrat-
ing; feeders,. 1 - filter dust collector
and 1000 cfm fan*"
Dryer bin feed conveyors 2-46 tph inclined belt conveyors, 20 in.
wide by 260 ft long, 7% hp
Cross conveyors 2-46 tph belt conveyors, 20 in. wide by
65 ft long with trippers, 2 hp
Svnsas bin feed conveyors 2-46 tph inclined belt conveyors, 20 in.
y * wide by 380 ft long, 10 hp
(continued)
34L
-------
-TABLE A-3 (Continued)
SERVICE
DESCRIPTION
WOOD RECEIVING AND STORAGE
Cross conveyors
Boiler silo feed conveyor
2-46 tph belt conveyors, 20 in. wide by
75 ft long with trippers, 2 hp
1-13 tph inclined belt conveyor, 14 in.
wide by 160 ft long, 1 hp
Wood chip dryer/grinders
Wood flour metering units
Wood/oil blending tanks
Wood/oil slurry feed pumps
WOOD PREPARATION
2 - 500 tpd package systems - includes 2 -
12 ft dia by 40 ft high feed bins with
screw feed conveyors, 2 - dryer/grinder
units (125 hp) with air classifiers,
1 — cyclone separator, 1 - baghouse
filter collector (50,000 cfm, 99% effi-
cient)*,. 2 —"50,000 cfm fans, 12 in.
wg static pressure, 125 hp, 1 - wood
flour surge bin, 12 ft dia by 40 ft high
2 - 350 tpd package systems - includes star
valves, metering scale, screw conveyor
and 8 ft dia by 16 ft high feed bin
2 - 10,000 gal tanks, 12 ft dia by 12 ft
high, 150 hp agitator
4 - 270 gpm at 8070 ft TDK diaphragm pumps,
750 hp
Wood/oil slurry recycle pumps 4- - 200 gpm at 460 ft IDE diaphragm pumps.,
5(1 hp
Helical coil reactors
REACTION
2 - reactor/furnace units - includes 2300
ft of 3 in., Sch 160 pipe wound into
10 ft dia by 35 ft high helical coil
in' 12 ft dia by 60 ft high furnace shell
and hollow cone center, refractory lined
J.5 MM Btu/hr H.T. duty
(continued)
-------
TABLE A-3 (Continued)
SERVICE
DESCRIPTION
Hold (soak) vessels
H.P. 'flash tanks
L.P1., flash tanks-
Flash gas surge drums-
Flash gas spray towers
Venturi scrubbers
Nonreversing cyclones
Scrubbed gas surge drums
Oil/water separators
Water draw pumps
Oil draw pumps
Water surge tanfc
Spray water supply pumps
Flash gas blowers
Combustion air fans
REACTION
2 - 4 ft dia by 50 ft high pressure vessels,
2600 psig at 650°F
2 - 6 ft dia by 18 ft (T-T) long horizontal
drums (with internals), 175 psig at 600°F
2 — 6. ft dia by IS ft long horizontal drums
(with internals), 50 psig at 515°F
2 - 6 ft dia by 18 ft long vertical drums,
50 psig at 500°F
2 - 6 ft dia by 30 ft high towers, 8000 cfm
gas loading, L/G ~3
2 - venturi tubes, 0.6 sq ft throat area,
10 inv wg pressure drop
2 — 66 in. dia nonreversing cyclones with
demister pads (25 sq ft)
2 - 6 ft dia by 18 ft high horizontal drums,
10 psig at' 100°F
2 - 2000 gal horizontal tanks, 6 ft dia by
10 ft long (with chemical addition)
2 - 100 gpm at 95 ft TDK pumps, lh hp
2 - 10 gpm at 115 ft TDK pumps, 1 hp
2 - 20,000 gal tanks, 16 ft dia by 13.5 ft
high
2 - 130 gpm at 75 ft TDH pumps, 5 hp
2 - 7000 scfm rotary blowers, 15/30 psia,
500 hp
2 - 20,000 scfm forced draft fans, 15 in.
wg static pressure, 75 hp
(continued)
343
-------
TABLE A-3 (Continued)
SERVICE
DESCRIPTION
Flash gas combustors
Syngas feed compressors
REACTION
2 - 11.5 ft dia by 25 ft long combustion
boxes with burners, controls, refrac-
tories and ducting, 70 MM Btu/hr duty
2 - 7300 scfm three-stage compressors with
intercoolers (4 MM Btu/hr duty) r
198/4000 psia at 420°F, 3000 hp
Raw oil pumps
Cooling flash drums
Flash gas condensers
Overhead receivers
Flash drum pumps
Raw oil surge tanks
Surge tank pumps
Oil/solvent mixing tanks
Filter feed pumps
Rotary vacuum filter
systems
PRODUCT SEPARATION
4-50 gpm at 450 ft TDH diaphragm pumps,
15 hp
2 - 6 ft dia by 12 ft high vertical drums
with venturi_inlet sections, 800 scfm
vapor loading-
2 - shell and tube exchangers (250 sq ft),
2.5 MM Btu/hr duty
2 - 4 ft dia by 8 ft long horizontal drums
4-50 gpm at 230 ft TDH diaphragm pumps,
lh hp
2 - 20,000 gal tanks, 15 ft dia by 16 ft
high, heated and insulated
2 - 150 gpm at 330 ft TDH diaphragm pumps,
25 hp.
2 - 6000 gal tanks, 8 ft dia by 16 ft high,
15 hp agitators
4 - 120 gpm at 115 ft TDH pumps, 7% hp
2 - package units - includes 2 - 10 ft dia
by 16 ft long rotary vacuum precoat
filters, 2 - 1200 gal filtrate receivers,
2 — 50 hp vacuum pumps, 1 - 1000 gal
precoat mix tank with 5 hp agitator and
1—50 gpm precoat slurry pump
(continued)
344
-------
TABLE A-3 (Continued)
SERVICE
DESCRIPTION
PRODUCT SEPARATION
Filter vent gas condensers 2
Vent gas knock-out drums 2 -
Oil/water separators Z -
Filter cake bins with 4 -
conveyors
Stream stripper-conveyors 2 -
Filter solids surge- bins 2 -
Tube-flow solids conveyors 2 -
Solvent surge tanks 2 -
Surge tank pumps 4 -
Filtrate pumps 4 -
Strlppet feed- surge- drums 21 —
Oil/solvent stripping columns 2 -
Stripper reboilers
2 -
150 sq ft shell and tube exchangers,
1 MM Btu/hr duty
3 ft dia by 9 ft high, vertical drums
500 gal 'tanks-,. 3.5 ft dia, by 8- ft long
with chemical addition unit
4 ft wide by 4 ft deep by 12 ft long
bins with 2-2 tph screw conveyors,
9 in. dia flights by 60 ft long, 1 hp
2 tph screw conveyors (live steam injec-
tion), 9 in. dia flights by 30 ft long,
1 hp-
25 ton capacity bins, 12 ft dia by 25 ft
high with screw bottom, 1 hp
4 in. dia by 1500 ft long tube-flow
conveyors with chain pull and discs,
20 hp
20,000 gal tanks, 16 ft dia by 13.5 ft
high
100 gpm at 65 ft TDH pumps, 3 hp
120 gpm at 65 ft TDH pumps, 5 hp
ia,000; gal drums „ 11 ft dia, by 12 ft
high
8 ft dia by 85 ft high (T-T) (vacuum)
columns, 25 trays at 24 in. spacing
thermosiphon reboilers, 2000 sq ft H.T.
area, 250 psia at 500°F steam 10 MM
Btu/hr duty
(continued)
345
-------
TABLE A-3 (Continued)
SERVICE
DESCRIPTION
Overhead condensers
Overhead receivers
Condensate" subcoolers,
Reflux pumps
Stripper vacuum pumps
Knock-out drums
Product oil transfer pumps
PRODUCT SEPARATION
2
Electrostatic coalescers
- shell and tube exchangers,. 800 sq ft
H.T. area, 6.5 MM Btu/hr duty
2 - 1000 gal drums, 4 ft dia by 10 ft long
2 — shell and tube- exchangers, 250 sq ft
H.r.. area, 1.5 MM Btu/hr duty.
2 - 100 gpm at 40 ft TDH pumps, 2 hp
2 — 2000 scfm rotary vacuum pumps, 50 hp
2 - 2 ft dia by 6 ft high drums (pump
exhaust)
4-35 gpm at 350 .ft TDH pumps, 7^ hp
2 - 500 gal horizontal drums, 3 ft dia by
10 ft long with transformer and elec-
trode plate package.
Product oil/water separators 2
Product oil draw pumps 4
Catalyst solution pumps 2
Product, oil storage tanks 4
Product loading; pumps, 4
Solvent storage tanks- 2
Solvent truck unloading pumps 2
Solvent transfer pumps 2
- 1000 gal horizontal drums, 4 ft dia by
10 ft long (with chemical addition)
- 35 gpm at 230 ft TDH pumps, 5 hp
- 10 gpm at 170 ft TDH pumps, 1 hp
- 25,000 gal tanks, 16 ft dia by 18 ft
high.,, heated and. insulated
- 200. gpnr at 115 ft TDH~ pumps-, 15 hp
- 5000 gal tanks, 8.5 ft dia by 12 ft high
- 200 gpm at 45 ft TDH pumps, 5 hp
- 50 gpm at 95 ft TDH pumps, 2 hp
(continued)
346
-------
TABLE A-3 (Continued)
SERVICE
DESCRIPTION
Wood surge bins
shaft furnaces
SYNGAS PRODUCTION
2 - 4000 cu ft bins, 12 ft dia by 40 ft
high (with dust collector)
4 - 500 tpd units, 12 ft dia by 40 ft high -
includes 4 feed hoppers and 2 - high ef-
ficiency cyclone separators, 2 - 1000
ctt ft cyclone solids hoppers
Slag quench tanks 4
Quench tank pumps 4
Raw syngas spray towers 2
Venturi scrubbers 2
Nonreversing cyclones 2
Syngas surge drums 2
Scrubber water surge tanks 2
- 4000 gal tanks, 8 ft dia by 12 ft high
— 20 gpm at 70 ft TDK pumpsr 1 hp
- 6 ft dia by 30 ft high towers, 17,000
cfm gas loading, L/G -3
- venturi tubes, 1.2 sq ft throat area,
10 in. wg pressure drop
- 96 in. d'ia nonreversing cyclones with
demister pads (50 sq ft)
- 12 ft dia by 24 ft long (T-T) horizontal
drums, 5 psig at 100°F
- 2000 gal tanks, 5.5 ft dia by 12 ft high
with 2 hp agitator
Surge tank pumps 2 - 300 gpm at 60 ft TDK pumps, 10 hp
Raw syngas compressors 4
Benfield hot carbonate
plants
- 10 ,.000 scfm three-stage compressors
with intercoolers (4.7 MM Btu/hr duty)
14.7A200' psia. at 298°F,. 3000 hp
2 - CO^ removal plants (proprietary), 14.4
scfd design feed — includes absorption
and regeneration columns, exchangers,
pumps, reboiler, filter, piping, in-
struments , and controls
(continued)
347
-------
TABLE A-3 (Continued)
SERVICE
DESCRIPTION
Waste heat boiler units
Oxygen plant
SYNGAS PRODUCTION
2 - 8.5 ft dia by 22 ft long horizontal
fire-tube boilers, 20,000 Ib/hr steam
at 75 psig (saturated), 2 - 50,000 cfm
I.D. fans, 12 in. wg static pressure,
L50 hp,. 2 - 3.5 ft dia by 50 ft _high
stacks^, ducting,,_refractories, and
controls ~~
1 - 400 tpd capacity 02 plant (98%) - in-
cludes cold box, air compressor, oxygen
compressor, auxiliaries, superstruc-
tures, piping-, electrical, controls, and
control house
CATALYST RECOVERY, _ - -
Rotary vacuum filter systems 2 — package filter units — includes 1 - 4 ft
dia by 8 ft long rotary vacuum filter
drum, 1 - 300 gal filtrate receiver,
1 - vacuum pump (7% hp), 2 - 8 cu yd
cake bins
Filtrate pumps
Catalyst solution tanks
Catalyst hoppers
'Catalyst solution Teed
pumps
2-10 gpm at 65 ft TDK pumps, 1 hp
2 - 10,000 gal tanks, 12 ft dia by 12 ft
high with 10 hp agitator
2 - 170 cu ft bins, 6 ft dia by 10 ft high
(with dust collector)*
4- - 5T gpm: at 3500 psi TDH diaphragm pumps,
20 hp
Utility boiler
AUXILIARIES
1 - 50,000 Ib/hr, 250 psia, 500°F traveling
grate stoker boiler unit - includes
furnace, fuel distributor, burners, grate,
ash hopper, 2-drum boiler, economizer,
drives, superstructure, and controls
(continued)
348
-------
TABLE A-3 (Continued)
SERVICE
DESCRIPTION
AUXILIARIES
Forced draft fan
Induced draft fan
Electrostatic precipitator*
Boiler stack
Utility steam condenser
Boiler feedwater pumps
Condensate storage tanks;
Feedwater treatment system
Cooling tower
1 -
1 -
1 -
Circulating water pumps
19,000 cfm at 80°F fan, 13 in. wg static
pressure, 75 hp
42,000 cfm at 500° fan, 10 in. wg static
pressure,. 100 hp
unit 22 ft wide by 42 ft deep by 58 ft
high, 13,248 sq ft plate area, 99.5%
removal efficiency, 42,000 cfm at 500°F,
25 kVA
1 - 4 ft I.D. by 100 ft high stack
1 - single pass condenser, 100 sq ft H.T.
area, 300 psig shell
4-50 gpm- @ 690 ft TDH pumps, 20 hp
3 - 12,000 gal tanks, 12 ft dia by 14 ft high
1-20 gpm package system - includes 1 - 2 ft
dia by 8 ft high vessel (cation), 1 -
2 ft dia by 6 ft high vacuum deaerator
with 3 hp vacuum pump, 1 - 2 ft dia by
8 ft high vessel (anion), 1 - 8000 gal
demineralized water storage tank, 2 -
20 gpm demineralized water supply pumps
(1-2 hp) , 1 - 300-gal acid storage tank
with 10 gph metering pump, 1 - 300 gal
caustic storage tank with 25 gph meter-
ings pumpv 2. — 20> gptit regenerant feed
pumps (1 hp)
1 — induced draft cooling tower, 90 MM
Btu/hr heat load, 10°F approach (70°F
wet bulb), 30°F range, 3-cells, 33 ft
wide by 73.5 ft long (total) by 18.5
ft high with 3-14 ft dia fans, 75 hp
2 - 3700 gpm at 95 ft TDH pumps, 150 hp
(continued)
34-9- .
-------
TABLE A-3 (Continued)
SERVICE
DESCRIPTION
AUXILIARIES
Automatic chlorinator
River water intake pumps
River water storage basin
Plant water supply pumps
Gravity sand filter
Filtered water storage tank
Filtered water tank pumps
Automatic chlorinator
Sanitary waste treatment
unit
Slowdown neutralization
basin'
Storm water settling basin
Anaerobic: digester
Digester gas compressors
Digester effluent pumps
*•
Solid bowl centrifuges
1 - 800 Ib/day automatic chlorinator with
residual analyzer-controller
2 - 130 gpm at 90 ft TDK pumps, 74 hp
1 - 900,000 gal clay-lined basin, 94 ft
wide by 164 ft long by 10 ft SWD (plus-
2 ft freeboard)
2 - 130 gpm at 65 ft TDH pumps, 5 hp
1 - 6 ft dia automatic backwash filter,
85 gpm loading, 30 in. bed
1 - 20,000 gal tank, 15 ft dia by 16 ft high
2-80 gpm at 130 ft TDH pumps, 5 hp
1-10 Ib/day.chlorine injector and con-
troller unit (150 Ib Cl2 cylinder)
1 - 7200 gal per day package unit - includes
biological reactor, clarifier, filter,
chlorine injector, and controls
1 — 20,000 gal concrete basin, 15 ft wide
by 15 ft long by 12 ft deep
1 - 3,900,000 gal clay-lined basin, 154
wide by 274 ft long by 15 ft SWD (plus
2 ft freeboard)
E, - SOOvOOQf gal fixed-roof tank,. 75 ft
by 2.4 ft deep (21 ft SWD), with 14 -
12 in. dia mixer-heater units
2 - 500 scfm rotary compressors, 15/30 psia,
25 hp
2 - 120 gpm at 60 ft TDH pumps, 5 hp
2 - 30 in. dia horizontal solid bowl centri-
fuges , 150 hp
(continued)
350
-------
TABLE A-3 (Continued)
SERVICE
DESCRIPTION
Centrifuge cake bins
Aeration basin"
Aerators
*
Secondary clarifier
Sludge recycle pumps
•f,
Clarifier effluent wet well
Effluent pump
Gravity sand filters-
Main transformer
4.16 kV LCC transformers
480 V LCC transformers
AUXILIARIES
2 - 8 cu yd dumpster-type bins
1 - 250,000 gal clay-lined basin, 60 ft wide
by 100 ft long by 8 ft SWD (plus 2 ft
freeboard)
4 - floating mechanical turbine aerators,.
20 hp
1 - 24,000 gal gravity clarifier (concrete),
18 ft dia by 13 ft SWD, 5 hp drive
2 - 80 gpm at 45 ft TDK pumps, 2 hp
1 - 1600 gal concrete sump, 6 ft wide by
_6 ft.. long. byj^S ft- deep
1 - 160 gpm at 45 ft TDH pump,. 5 hp
2 - 7 ft dia automatic backwash filters,
150 gpm loading, 30 in. bed
1 - 17/23/29 MVA, 65°C, OA/FA/FOA, 115/13.8
kV, 3, 60 Hz
2 - 2400 kVA, OA, 65°C, 13.8/4.16 kV, 3,
60 Hz
4 - 1200 kVA, OA, 65°C, 13.8 kV/489V/277V,.
3£, 6.0 Hz:
Emergency-diesel generator- 1 - 500 kW, 3
-------
TABLE A-4. MAJOR EQUIPMENT SUMMARY — COAL-TO-POWER PLANT
SERVICE
DESCRIPTION
COAL HANDLING
Barge unloading system 1
Transfer conveyor (elevated) 1 -
Rail car unloading system
Coal reclaim system.
1500 tph inclined boom unloading struc-
ture, 87 ft long, 3 rows of 6 ft wide
buckets on chain conveyors, 50 ton surge
bin with 1000 tph apron feeder, 100 hp
1000 tph belt conveyor•„ 42 in. wide by
3000 ft longv 3000 hp
Transfer and sample house
Stacker conveyor (inclined) 1 -
Stacker conveyor- (elevated) '. 1 —
Transfer conveyor (inclined) 1 -
1 - transfer house with magnetic separators,
transfer chute and 2-stage coal sample
system with dust collection (ductsr
fabric filter collector, and fan)
1000 tph inclined belt conveyor, 42 in.
wide by 1000 ft long with belt tripper
and telescopic chute, 260 hp
1000 tph belt conveyor,. 42 in. wide by
140 ft long with belt tripper and tele-
scopic chute, 25 hp
12,000 cu ft under-track dump hopper;
8 - 100 tph vibrating feeders; 1000
tph belt conveyor, 42 in. wide by 80 ft
long, 100 hp
1000 tph belt conveyor, 42 in. wide by
260 ft long, 100 tph
50 tph vibrating feeders; 2 - 355 tph
belt conveyors„ 30 in~ wide by 240 ft
long:,,, 70 hp (reclaim tunnel)
1 -
1Z -
Reclaim conveyors (inclined) 2 -
Transfer house
1 -
Bin feed conveyors (inclined) 2 -
355 tph belt conveyors, 30 in. wide by
240" ft long, 50 hp
transfer house with split discharge
transfer chute, fabric filter collector
and fan (dust collection)'
355 tph belt conveyors, 30 in. wide by
360 ft long, 75 hp
(continued)
352
-------
TABLE A-4 (Continued)
SERVICE
DESCRIPTION
Surge bin
Silo feed, cascade system
Coal silos
Gravity feeders
COAL HANDLING
I - 100 ton capacity bin with 2 - 350 tph
vibrating feeders, 4000 cfm fabric
filter collector
2. — 355 tph belt conveyors, 30 in. wide by
5& ft long-, 4- - 355 tph belt conveyors,
3ff in., wide by 45 ft long with belt
trippers, 60 hp; 1 - 13,000 cfm fabric-
filter collector and fan
5 - 300 ton capacity bins,. 16 ft dia by
60 ft high with 60° slope bottom
5-50 tph feeders, 7 ft long, 2 hp
Coal pulverizers
Pulverized coal-fired
boiler
Forced draft fans
Primary air fans
BOILER (AIRSIDE)"
5 - 100,000 Ib/hr capacity bowl- roller-tye
pulverizers, 600°F,. 500 hp
1 - 3,980,000 Ib/hr, 2650 psig, 1005°F
capacity balanced draft, controlled
circulation, radiant heat drum-type
boiler - includes water-wall furnace,
tangential fuel-firing system, combus-
tion controls, ash hoppers, steam drums,
5-stage superheater, 2-stage reheater,
economizer, 4-boiler circulation pumps
(900. hp) , soot blowers, 2. — regenera—
tiver air preheaters^ 2- — steam air
heaters, duct work and complete struc-
tural steel
2 - 366,400 cfm at 80°F F.D. fans, S.P. =
14 in. wg, 1000 hp
2 - 88,800 cfm at 80°F P.A. fans, S.P. =
28 in. wgr 1000 hp
(continued)
353
-------
TABLE A-4 (Continued)
SERVICE
DESCRIPTION
Induced draft fans
Electrostatic precipitators
Chimney
BOILER (AIRSIDE)
2 - 655,.000 cfm at 262°F I.D. fans, S.P. =
25 in. wg, 5000 hp
u
2 - precipitators, each 99 ft wide by 78 ft
deep- by 73.5 ft high,. 2 units in. each,
53 ducts/unit, 116,640 sq ft plate
area/unit, 99.5£ efficiency, 655,000
cfm at 250°F
1 - 18 ft I.D. (at tip) by 300 ft high con-
crete chimney with guided steel liner
to breeching
FGD SYSTEM"
SO- absorbers
Absorber delay tanks
Absorber slurry recycle
pumps
Thickener: feed tank.
Absorber slurry bleed pumps
Slurry thickener
Wash tray recycle tanks
3 - 32 ft dia by 100 ft high spray towers
(lined), each with horizontal presatu—
ration section, wash tray, mist elimi-
nator, spray headers and full-cone
spray nozzles
3 - 228,000 gal capacity atmospheric tanks
(lined), 36 ft dia by 30 ft high, with
125 hp top-mounted agitator
18 - 6200 gpm at 150 ft TDH pumps, 500 hp
1 — 37*600 gal capacity atmospheric tank
(lirtedK 20 ft dia by 16 ft high,, with
40 hp top-mounted agitator
.3 - 150 gpm at 60 ft TDH pumps, 7.5 hp
1 - 95 ft dia by 13 ft SWD gravity thick-
ener with sludge rake mechanism, 25 hp
3 - 15,800 gal capacity atmospheric tanks
(lined), 15 ft dia by 12 ft high, with
10 hp top-mounted agitator
(continued)
354-
-------
TABLE A-4 (Continued)
SERVICE
DESCRIPTION
Wash Cray recycle pumps
Wash tray clarifier
Clarifier overflow- tank
Overflow tank, pump
Clarifier underflow pump
Thickener overflow tank
Overflow tank pump
Thickener underflow tanks
Thickener underflow pump
Vacuum filter feed pumps
Vacuum filters (package)
Filtrate storage tank
Filtrate storage tank pump
FGD SYSTEM
3 - 2500 gpm at 150 ft TDH pumps, 200 hp
1 - 65 ft dia by 14 ft SWD gravity clarifier
with skimmer and sludge rake mechanism,
15 hp.
1 — 845tt gal capacity atmospheric tank
(lined), 12 ft dia by LO ft high, with
5 hp top-mounted agitator
1 - 1980 gpm at 170 ft TDH pump, 150 hp
1-17 gpm at 50 ft TDH pump, 1 hp
1 - 4700 gal. capacity atmospheric tank
(lined), 10 ft. dia by 8 ft high, with
5 hp- top-mounted agitator
1 - 385 gpm at 160 ft TDH pump, 30 hp
2 - 338,000 gal capacity atmosphere tanks
(lined), 46 ft dia by 36 ft high, with
150 hp top-mounted agitator
1 175 gpm at 60 ft TDH pump, 7.5 hp
3 - 240 gpm at 65 ft TDH pumps, 10 hp
3 - 12 ft dia by 22 ft long rotary vacuum
belt filters,. 330 sq ft filtration
area. — unit includes trough,, filtrate
receivers, vacuum pump (370 hp),. pip-
ing and controls
1 - 338,000 gal capacity atmospheric tank
(lined), 40 ft dia by 36 ft high, with
75 hp top-mounted agitator
1-75 gpm at 100 ft TDH pump, 5 hp
(continued)
355
-------
TABLE A-4 (Continued)
SERVICE DESCRIPTION
FGD SYSTEM*
Vacuum filtrate overflow 3 - 8460 gal capacity atmospheric tanks
tanks (lined), 12 ft dia by 10 ft high, with
7.5 hp top-mounted agitator
Filtrate overflow tank pumps 3 - 240 gpm at 30 ft TDK pumps, 5 hp
Filtrate cake conveyor L - 140 tpti belt conveyor, 20 in.- wide by
300 ft long, 15 hp
Lime storage bin 1 - 130 ton capacity bin, 15 ft. dia fay 30
ft high, with cyclone product separator
and 30 hp fan
Lime weigh feeder 1 - 0 to 10 tph weigh feeder belt conveyor
Lime weigh feeder 1 - 0 to 10 tph weigh feeder belt conveyor
Lime transfer conveyor 1-10 tph belt conveyor,. 10 in. wide by
1.00 ft long,. 2 hp
Fly ash volumetric feeders 2 — 50 tph screw conveyors, 18 in. dia
flights by 20 ft long, 5 hp
Fly ash transport air blowers 2 - 2800 cfm centrifugal blowers, 2.5 psig
S.P., 50 hp
Pug blending mills 2 - 200 tph capacity mills, 75 hp
Stablized sludge conveyor 1 - 200 tph belt conveyor, 24 in. wide by
100 ft long, 7.5 hp
Load bin feed- conveyor I - 200" tph belt conveyor,. 24 in. wide by
100 ft long with tripper, 10 hp
Sludge loadout bins 2 - 150' ton capacity cone bottom bins, 13
ft dia by 30 ft high
Lime storage silos 2 - 1000 ton capacity silos, 30 ft dia by
70 ft high with cyclone product sepa-
rator and fan (30 hp), 2500 cfm fabric
filter collector
(continued)
356
-------
TABLE A-4 (Continued)
SERVICE
DESCRIPTION
FGD SYSTEM'
Lime weigh feeder (package)
Lime slaker (package)
Slurry transfer tank
(package)
Slurry transfer pump
Slurry storage tank
Slurry storage tank pump
Lime- slurry- surge tank
1 - 0 to 10 tph weigh feeder belt, 1 hp
1 - 150 tpd lime slaker unit, with 10 hp
agitator, 1 hp grit removal screw,
piping and controls
1 - 1690 gal capacity atmospheric tank
(lined) j. 6 ft dia by 8 ft high,, with
3 hp top-mounted agitator
1 - 120 gpm at 40 ft TDH pump, 3.5 hp
1 - 74,500 gal capacity atmospheric tank
(lined), 23 ft dia by 24 ft high, with
50 hp top-mounted agitator
1 - 120 gpm at 50 ft TDH pump, 5 hp
1 — 74,500 gal capacity atmospheric tank
(lined), 23 ft dia by 24 ft high, with
50 hp top-mounted agitator
Slurry surge tank pumps
Steam turbine
Generator
2 - 240 gpm at 100 ft TDH pumps, 15 hp
STEAM CYCLE (WATER-SIDE)
1 - 508,000 kW tandem compound, 4-flow,
condensing, single reheat turbine,
2400 psig/11000°F/1000°F reheat, 7 un-
controlled extraction stages, 3600
rpm, 3<(>, 60 Hz, 0.95 pf
I - 590 MVA. H/j-cooled generator with exciter
and auxiliaries, 22 kV, 3600 rpm, 3$,
60 Hz, 0.95 pf
Main transformer
Unit auxiliary transformer
Startup transformer
1 - 561 MVA, FOA, 65 C, 22/345 kV, 3$, 60 Hz
1 - 37/49.2/61.8 MVA, OA/FA/FOA, 65°C,
21 kV delta, 7.2/4.16 kV, 3$, 60 Hz
1 - 37/49.2/61.8 MVA, OA/FA/FOA, 65°C,
21 kV delta, 7.2/4.16 kV, 3, 60 Hz
(continued)
357
-------
SERVICE
TABLE A-4 (Continued)
DESCRIPTION
Auto transformer
Misc. 480 V transformers
STEAM CYCLE (WATER-SIDE)
1 - 200 MVA, FOA, 65°C, 345/230-34.5 kV
3, 60 Hz .
4 - 1725 kVA, 4-1333 kVA, 4-1150 kVA, 4-
750 kVA, OA, 65°C, 7.2 kV/480/277 V,
3$, 60 Hz
Emergency- diesei generator 1. - 1000 kffi. 0.8 pf „ 480/277 V, 3*, 60 Hz
Surface condenser I - twin shell, 2-pass divided waterbox
condenser, 234,000 sq ft H.T. area,
2480 MM Btu/hr, 2,462-,000 Ib/hr steam
at 3.85 in. Hga, with air ejector and
exhauster condensers
L.P. feedwater heater
L.P. feedwater heater
L.P. feedwater heater
Deaerating heater and tank
I.P. feedwater heater
I.P. feedwater heater
1 - U-tube horizontal 2-pass exchanger,
585.0 sq ft H.T. area, 89 MM Btu/hr,
1,311,800 Ib/hr water-side flow (design),
50 psig- shell
1 - U-tube horizontal Z-pass exchanger,
3750 sq ft E.T. area, 44 MM Btu/hr,
1,311,800 Ib/hr water-side flow,
50 psig shell
1 - U-tube horizontal 2-pass exchanger,
6730 sq ft H.T. area, 84 MM Btu/hr,
2,623,600 Ib/hr water-side flow,
50 psig shell
1 - 3,727,000 Ib/hr (outlet) at 311°F tray
deaerator with internal vent condenser,
S ft dia_by 26 ft higfav 258,850 Ib/hr
steam flow at~"66>~5' psia',, 12' ft dia" by
63 ft long storage tank '
1 - U-tufae horizontal 2-pass exchanger,
11,660 sq ft H.T. area, 249 MM Btu/hr,
3,370,200 Ib/hr water-side flow, 225
psig shell
1 - U-tube horizontal 2-pass exchanger,
10,480 sq ft H.T. area, 127 MM Btu/hr,
3,370,.200 Ib/hr water-side flow,
350 psig shell
(continued)
358.
-------
TABLE A-4 (Continued)
SERVICE
DESCRIPTION
H.P. feedwater heater
Bailer feed. pumps-
Booster pumps
Condensate pumps
Condensate storage tank
Condensate transfer pump
Auxiliary boiler
STEAM CYCLE (WATER-SIDE)
"1 - U-tube horizontal 2-pass exchanger,
14,590 sq ft.H.T. area, 259 MM Btu/hr,
3,370,200 Ib/hr water-side flow, 725
psig shell
2 - 4900 gpm (407°F) at 8264 ft TDH 5-stage
pumps, 9615 bhp, with steam turbine
drives, 174.7 psig/720°F inlet, 3.85 in.
Hga exhaust
2 - 4800 gpm (297°F) at 950 ft TDH pumps,
1500 hp
3 - 3600 gpm (124°F) at 600 ft TDH 5-stage
pumps,- 750 hp
1 - 175,000' gal capacity atmospheric tank,
43 ft dia by 16 ft high
1 - 1000 gpm at 40 ft TDH pump, 15 hp
1 - 150,000 Ib/hr, 250 psig (saturated)
package steam boiler, natural gas-fired
Circulating water pumps
Service water pumps
Condenser waterbox drain
pump
Cooling towers
AUXILIARIES
2 - 90,000 gpm at 85 ft TDH pumps, 2500 hp
2 - 12,000 gpm at 60 ft TDH pumps, 250 hp
I - 1000' gpm CH8°F) at 70 ft TLH pumpr
25 hp
2-8 cell induced draft towers, each 71 ft
wide by 288 ft long by 59.5 ft high,
8 - 28 ft dia fans, 200 hp, 2700 MM
Btu/hr total heat load, 30°F range,
9°F approach
(continued)
359
-------
TABLE A-4 (Continued)
SERVICE
DESCRIPTION
Chlorination (package)
Chlorine injector* water-
booster pump
Sulfuric acid storage tank
Dispersant storage tank
Corrosion inhibitor storage
tank.
Demineralizer feed pumps
Cation exchange units
Anion exchange units
Mixed-bed exchange units
Sulfuric acid storage tank
(66° Be)
AUXILIARIES
1 - 8,000 Ib/day capacity unit, includes
V-notch chlorinator, injector analyzer
and controls, electric evaporator unit,
expansion tank, and tank car air pad-
ding unit • _ _
L - 300 gpm at 370 ft TDH 2-stage pump,
50 hp
1 - 10,000 gal capacity atmospheric tankr
12 ft dia by 12 ft high, with 2-acid
metering pumps, 30 gph, 1/3 hp
1 - 4,000 gal capacity horizontal tank,
7 ft dia by 14 ft long, with. 2 dispers-
ant metering--pumps, 1 gph, 1/4 hp
1 — 4000 gal capacity horizontal tank,
7 ft dia by 14 ft long
2 - 150 gpm at 240 ft TDH pumps, 20 hp
2 - 120 gpm at 9.5 gpm/sq ft cation ex-
change vessels, 4 ft dia by 9 ft high,
52.5 in. bed depth (55 cu ft resin)
2 - 120 gpm at 9.5 gpm/sq ft anion ex-
change vessels, 4 ft dia by 5 ft 2 in.
high, 30.5 in. bed depth (32 cu ft
resinO
2 — 120 gpm at 17 gpm/sq ft mixed-bed ves-
sels, 3 ft dia by 13 ft 7 in. high,
34- in. bed of cation resin (20 cu ft)
and 47.5 in. bed of anion resin (28 cu
ft)
1 - 5000 gal capacity atmospheric tank,
8 ft dia by 13 ft long, with 1 acid
transfer pumpr 4 gpm,. 1 hp
(continued)
-------
TABLE A-4 (Continued)
SERVICE
DESCRIPTION
AUXILIARIES
Caustic storage tank
(50% NaOH)
Hydrasine solution tank
(35% solution)
Phosphate solution tank
Ammonia storage tank
Ammonia solution tank
(10% solution)
Potable water pump
Potable water storage tank
Raw water booster pump
Dual media gravity filters
Filtered water" clearwelX
Filter backwash pumps
*
Spent backwash tank
Main firewater pumps
1 - 5000 gal capacity atmospheric tank, 8 ft
dia by 13 ft long, with caustic trans-
fer pump, 6 gpm, 1.5 hp
1 - 1000 gal capacity skid-mounted tank,
6 ft dia by 5 high, with 2-hydrazine
metering pumps, 6 gph,. 1/3 hp
1 - 5000" gal capacity skid-mounted tank,. 10
ft high, with 3 hp side-mounted agitator
and Z-metering pumps f 25 gph, 3 hp
1 - 5000 gal capacity horizontal tank, 8 ft
dia by 12 ft long, 45 psig/120°F shell
with vent condenser
1 - 1000 gal capacity tank, 5 ft dia by 8 ft
high,. 45. ps.ig/120°F shell with vent con-
denser, 2 - metering pumps, 6 gph, 1/3 hp
1-35 gpm at-250 ft TDK 2-stage pump, 7.5 hp
1 - 11,500 gal capacity atmospheric tank,
15 ft dia by 9 ft high, with hypochlor-
ite solution feed system
1 - 1000 gpm at 55 ft TDK pump, 20 hp
2 - 500 gpm at 3 gpm/sq ft gravity filters,
15 ft dia by 16 ft high, 3 ft bed of
anthrafilt o'ver sand
L - tOGvOQO: gal capacity concrete pit,.
30 ft wd.de by 30 ft long by 16 ft deep
2 - 1700 gpta at 165 ft TDH pumps, 100 hp
1 - 20,000 gal capacity atmospheric tank,
15 ft dia by 16 ft high, with 25 gpm
sludge pump, 2.5 hp
2 - 750 gpm at 288 ft TDH pumps, 100 hp
(continued)
361
-------
TABLE A-4 (Continued)
SERVICE
DESCRIPTION
Jockey pump
Scrubber water supply pumps
Sealwater booster pumps
Pond water pumps
River water intake pumps
River water storage pond
AUXILIARIES
1-60 gpm at 288 ft TDH pump, 10 hp
2 - 350 gpm at 165 ft TDH pumps, 25 hp
. 2 - 50 gpm at 165 ft TDH pumps^ 5 hp
3 - 2200 gpm at 55 ft TDH pumps, 50 hp
3 - 2200 gpm at 150 ft TDH wet pit pumps,.
125 hp
1 - 18,200,000 gal earthen basin, 305 ft
wide by 520 ft long by 22 ft deep
(20 ft SWD), 2:1 sloped sides
(compacted)
Demineralizer waste
neutralization tank*
Boiler blowdown
collection tank*
Slowdown settling basin
Sanitary wastewater treat-
ment unit"
Coal pile run-off pond
Stormwater holding pond
1 - 25,000 gal capacity atmospheric tank,
19 ft dia by 12 ft high
1 - 5000 gal capacity tank, 10 ft dia by
9 ft high, 5 psig/185°F shell
1 - 750,000 gal capacity concrete basin,
60 ft wide by 120 ft long by 15 ft
deep, with 50 gpm sludge pump, 5 hp
1 - 25,000 gal per day package unit, in-
cludes biological reactor, clarifier,
gravity filter, and chlorinator
(hypochlorite)
1 - 1', 150,000 gal earthen basin (plastic-
lined) , 112 ft wide by 184 ft long by
10 ft deep, 2:1 sloped sides
1 - 7,800,000 gal earthen basin (clay-
lined) , 200 ft wide by 362 ft long
by 18 feet deep (15 ft SWD), 2:1
sloped slides
(continued)
362
-------
TABLE A-4 (Continued)
SERVICE
DESCRIPTION
Ash sluice water surge bin*
L.P. ash circulating pumps
E.P; asfar sluice pumps*
Coal mill rejects sluice
pumps*
Surge- tank sludge pumps*
Bottom ash ponds
Ash pond recycle pumps"
Slowdown basin recycle pump'
Switchyard CPI separator"
Precipitator flyash
fludizing blowers*
Elyasb trans-port blowers
Flyash storage silos
Flyash silo fluidizing
blowers'
AUXILIARIES
1 - 25,000 gal bin, 15 ft wide by 15 ft
long by 16 ft deep (sloped bottom)
4 - 500 gpm at 200 ft TDH pumps, 50 hp
2 - 500 gpm- at 200 ft IDE pumps, 50 hp-
2 - 100 gpm at 250 ft TDH. pumps, 20 hp
2-50 gpm at 95 ft TDH pumps, 5 hp
3 - 460,000 cu ft capacity earthen basins
(clay-lined), 160 ft wide by 320 ft
long by 14 ft deep (12 ft SWD), 2:1
sloped. sides> decant section with 12 ft
high weir, across width
3 - 500 gpm at 95 ft TDH wet-pit pumps, 20 hp-
1 - 500 gpm at 90 ft TDH pump, 20 hp
1 - 500 gpm capacity 2-plate pack unit
(1000 sq ft), with 5 gpm oil sump
pump, 1 hp
3 - 300 cfm centrifugal blowers, 3.5 psi
diff. pressure, 15 hp
3 - 1400 cfm. positive displacement blowersr
It.S psi~diff. pressure", 125 hp~"
2 - 475 ton capacity silos, 24 ft dia by 60
ft high,, with cyclone product separator
and 6000 cfm filter collector (1500 sq
ft)
2 — 900 cfm positive displacement blowers,
6 psi diff. pressure, 50 hp
*Indicates pollution control equipment
Horsepower listed is motor drive rating.
363
-------
APPENDIX B
BIOMASS AND COAL FEEDSTOCK AVAILABILITIES
Biomass and. coal resources- are. not uniformly distributed throughout the United
States. In fact,, high concentrations of both biomass residues- and coal in
the same local area are not very common. The low b'ulk densities and the rela-
tively low concentrations of most types of biomass residues tend to militate
against biomass conversion facilities on the same large scale as the proposed
commercial coal conversion facilities. This appendix briefly discusses both
biomass and coal resource availabilities in relation to the hypothetical bio-
mass and coal conversion plants described in the regional scenarios.
FOREST RESIDUE IN THE SOUTH CENTRAL REGIONAL SCENARIO
Availab-ility- of- sufficient forestry residue within a reasonable haul distance
to a biomass conversion plant would be an important consideration in plant
siting. The influence of wood cost on the cost of electricity was shown in
Section 3. In the south central region indicated in the scenario, SRI re-
ported forestry waste (logging, mill bark, and mill wood) for three of the
states as (32):
Alabama 5,381,990 dry tons per year
Georgia 5,623,474 dry tons per year
Mississippi 4,380,302 dry tons per year
The 50 MWe hypothetical plan would consume about 250,000 dry tons per year
of forest residue, so that each state could potentially support a number of
wood-to-power plants. Seasonal availability is estimated as 20 percent —
first quarter*. 30 percent — second, quarter, 30 percent. — third quarter,, and
20 percent — fourth quarter (18) .
As an example of residue resources available on a more local level, SRI also
indicates that there are potentially about 1.7 million dry tons of logging
waste and collected forestry waste within 36 mean transport miles of Demopolis,
Alabama (18). County totals near Demopolis are listed as:
Alabama County Wasted Forestry Residue
(dry tons/year)
Choctaw 218,800
Clark 307,000
Greene 62,400
Marengo 135,000
364-
-------
Alabama County Wasted Forestry Residue
(dry tons/year)
Monroe 152 ,.000
Sumpter 151,600
— Washington 145,300
Wilcox 163,700
Total 1,335,800
It is likely that enough residue could be collected in this area at a reason-
able cost for one or more 50 MWe size units. Other localities such as south-
eastern. Mississippi may also be capable of supporting a wood-fired power plant.
or a co—fired wood/coal plane,
The residue is anticipated to be primarily tops, branches, stumps, and mill
bark of such species as longleaf, shortleaf, slash, and loblolly pines. Com-
positions and heating values of various species (woods and bark) are reported
elsewhere (3, 40, 44). Heating values for southern pine wood and bark are
on the order_of 8j60_0_t_o_9400 Btu/lb (oven dried). Collection costs vary
with the specific situation. Twenty dollars a dry ton was used as a base
delivered price for chipped forest residue plus mill bark. A MITRE Corp.
report indicates a delivered cost of about $23 per ton in the South (40).
COAL IN THE'SOUTH'CENTRAL REGIONAL SCENARIO-
Alabama is the only major coal producing state in this region. The deposits
are divided into four fields. In 1968, estimated strippable reserves were
about 164 million tons. More than 65 percent of the 1975 production (over
22 million tons) was strip mined (21). Three counties (Jefferson, Tuscaloosa,
and Walker) produced about 9-1/2 million tons of strip-mined coal in 1975 (21).
The rank is primarily high-volatile A and B bituminous, and sulfur content
is on the order of 1 to 2 percent. Production would be more than sufficient
to support a 500 MWe plant in the region over a 30-year life (about 22 mil-
lion tons). In 1974, Alabama had more than 9000 megawatts of coal-fired
power plant capacity, though most of the coal used was not produced in the
state- A similar situation exists in Georgia where, coal production is vir-
tually nil- Delivered coal cost also varies widely. In 1974r the averages,
for- Alabama- and. Georgia, were about $16 and $17 per ton,, respectively (45) .
A range of 20 to 50 dollars per ton is likely today.
STRAW AND MANURE IN THE MIDWEST REGIONAL SCENARIO
The midwest region indicated .in Figure 1 is a large source of crop residue
and animal residues. Most of the crop residues are returned to the land (32).
Wheat straw residues for three of the States listed as returned are (32):
Kansas 15,453,557 dry tons per year
Nebraska 4,442,278 dry tons per year
Missouri 1,169,578 dry tons per year
1&5.
-------
The hypothetical biogas plant would consume about 290,000 dry tons per year
of wheat straw. Potentially, Kansas and Nebraska could support a number of
plants were residue judiciously collected. Seasonal availability is 100 per-
cent — third quarter. Storage of collected straw for long periods could be
a drawback.
On a local level, the crop residues (mostly wheat straw) in five Kansas coun-
ties indicate the resource potential for support of one or more,biogas
plants (32):
Kansas County Returned Crop Residue
(dry tons/year)
Butler 171 ,.800
McPherson 360,000
Reno ' 507,100
Sedgwick 389,000
Sumner 666,000
Total 2,093,900
Other localities in the region with high wheat straw densities could poten-
tially support a biogas plant also. The amount of material that can be
removed from the fields without unacceptable soil damage may limit the number
and.size of'biogas plants.
The wheat composition used for the conceptual design is primarily from a
Battalia report (31). Collection, costs will vary with the specific situation.
SRI estimated costs at roadside of, say, 6 to 20 dollars per ton for crop
residue (18). In a separate site survey analysis for the Weld, Colorado
area, SRI estimated the delivered cost to a hypothetical conversion plant
ranged from 12 to 26 dollars per dry ton (12).
Cattle manure resources in the scenario region are substantial, but much of
the waste is returned to the land.
For cattle on. feed,, state totals given by SRC are (32) :
Stater Manure- Returned Wasted
dry tons/yr dry tons/yr
Kansas 775,866 77,703
Nebraska 686,219 343,089
Iowa 885,577 239,309
Missouri 140,548 61,721
The hypothetical plant would consume about 50,000 dry tons per year, and the
above statewide totals indicate that a number of biogas plants could poten-
tially be supported in this region. Seasonal availability is approximately
uniform throughout the year.
366 .
-------
Plant locations would probably be limited to areas with high concentrations
of cattle confined on feed: i.e., large feedlots. For a two-feedstock type
of biogas plant, sufficient quantities of both wheat straw and manure should
be available in the same locality. As an example, the five Kansas counties
cited above have returned and wasted manure totals of (32):
Kansas County Returned and Wasted Manure
(dry tons/year)
Butler 22,470
McPherson 14,270
Reno 15,550
Sedgwick. 15,070
Sumner -10, .940:
Total 78,300
Although 50,000 tons per year from this area could theoretically be available
to a biogas plant, collection of manure from a wider area might be necessary
in order to ensure an adequate supply. Other localities in Iowa and Nebraska
could also be candidates for a biogas plant with manure as a feedstock. Large
feedlot operations could possible be induced in a locality by the biogas plant
developer.
Composition.' of the cattle manure used in the conceptual design was based on
data reported by Battelle (3). SRI estimated collection costs at roadside
for manure in the-WeldT Colorado study area at $0.75 to $1.50 per wet ton (12),
Transportation costs would have to be added to arrive at a delivered price
per ton. Location of a biogas plant near large feedlot operations would be
desirable to minimize the delivered cost of manure.
COAL IN THE MIDWEST REGIONAL SCENARIO
The hypothetical coal gasification plant would consume about 6.7 million tons
per year of western coal shipped by train to the plant. Although Kansas,
Missouri, and Iowa have strippable reserves sufficient to support more than
one commercial gasification plant, the 1975 annual production from strip
mines was less than, seven, million, tons in. total (28). Use of a low-sulfur
western: coaL is a. more likely scenario- for a large gasification plant because
of the much larger current production. Statewide production- in both Montana
and Wyoming exceeds 20 million tons annually and strippable reserves of
sub-bituminous and lignite coals exceed 70 billion tons (21).
In Wyoming, for example, about two-thirds of the steam coal production is
shipped to power plants in other states including Nebraska, Kansas, Iowa,
and Missouri, Some of the large strip mines planned in Wyoming could produce
more than 10 million tons annually. Campbell County in the Powder River Coal
Basin, for example, has a potential for producing about 120 million tons per
year from 12 to 15 mines in the county (46). One large strip mine there
could supply all the coal requirements for the gasification plant.
The cost of western coal delivered by unit train to the midwest region in
1978 could range from $10 to $25 per ton.
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FOREST RESIDUE IN THE NORTHEAST REGIONAL SCENARIO
Total logging residues in the New England region were estimated in an ERDA
report as more than 30 million dry tons for the year 1970 (46). SRI estimates
of forestry waste for three New England states were (32) :
Maine 2,033,000 dry tons per year*
New Hampshire 310,000 dry tons per year
Vermont 218,700 dry tons per year
The wood-to-oil plant would consume about 360,000 dry tons per year. Maine
could support at least potentially one or more 2000-ton-per-day wood-to-oil
plants operated on forestry waste alone- Seasonal availability is estimated
(18) as 20 percent — first quarter, 30 percent — second quarter, 30 percent —
third quarter,, and 20 percent — fourth quarter^ In the- study area report,
SRI's availabilities were 28, 16, 28, and 28 percent, respectively (12).
As an example of localized residue resources, SRI reported that there is
about 350,000 dry tons per year of logging and collected forestry waste
within 32 mean transport miles of the W.F. Wyman steam electric station at
Yarmouth, Maine (18). County totals in western Maine are summarized
below (32):
Maine County Wasted Forestiry' Residue
(dry tons/year)
Somerset 241,000
Franklin 168,000
Oxford 612,000
Cumberland 56,000
Androscoggin 51,000
Sagadahoc 40,000
Lincoln 65,000
Kennebec 58,000
Waldo 59,000
Total 900,000
This areav fa a. likely candidate for a; biomass- conversion- plant in terms of
resources available,. Residual fuel oil use by industry in Maine is more than
half of the total energy use (12), so that a wood-to-oil plant is a possible
candidate for this area.
The average composition of wood feedstock for the conceptual plant was cal-
culated as a mixture of 80 percent pine and 20 percent spruce bark from com-
position data presented by Battelle (3). Costs for delivered wood residues
in Maine were estimated by SRI as $20 to $60 per dry ton for logging residue
and $4 to $8 per dry ton for mill bark (12).
*Reported as about 3.4 million tons in a DOE report (Ref. 12, pp. Vll-1 to 35).
363
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COAL IN THE NORTHEAST REGIONAL SCENARIO
In the coal-to-fuel oil region, Pennsylvania and West Virginia are the only
major coal producing states. In 1975, these two states produced about 44
and 88 million tons, respectively, of deep-mined bituminous coal (21)-
The conversion scenario assumed the hypothetical H-Coal plant is located
fairly near underground coal mines with enough capacity to supply about
9.3 million tons per year. As an example, Green and Washington counties in
southwestern Pennsylvania produced about 18 million tons of deep-mined coal
in 1975, nearly all from the Pittsburgh seam (21). In-place reserves of
Pittsburgh coal were about 7 billion tons in 1970, so that the reserves would
be more than adequate to support one or more commercial coal liquefaction
plants over a 10-year operating life.
Fluor bas-ed their conceptual H-Coal plant design on an Illinois No. 6 coal.
Braun's example of an eastern coal (Pittsburgh No. 8) as indicated in
Table B-l is somewhat similar in composition to the Illinois coal. For the
northeast scenario, it could be considered as the hypothetical plant feed-
stock with roughly similar gross outputs of products. The cost of high-sul-
fur coal delivered to the nearby hypothetical plant in this region would
probably be in the range of $20 to $40 per ton in 1978. Cost of delivered
coal to power plants in Pennsylvania averaged about $18 per ton in 1974 (45) .
369.
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Table B-l. COMPARISON OF EASTERN COAL COMPOSITIONS - COAL LIQUEFACTION
SCENARIO
CoaL Analysis
Carbon
Hydrogen
Nitrogen
Oxygen
Sulfur
Ash
- Moisture
Illinois No.
As received
63.48'
4.81
0.86
7.28
4.45
9.12
— 10-. Off- -
100.00
6, % wt*
Ultimate- -
70.50
5.40
0.95
8.10
4.90
10.15
. . — _
100.00
Pittsburgh No
As received
67.21
4.72
1.15
5.14
4.16
10.62
6.00
100.00
. 8, % wt**
Ultimate
71.50- •
5.02
1.23
6.52
4.42
11.30
—
100.00
Heating value
(HHV) Btu/lb 11,900 13,222 12,400 13,190
*Fluor report (Ref. 6)
**Braun report (Ref. 7)
370 .-
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APPENDIX C
COST ESTIMATION AND ECONOMIC EVALUATION- METHODS
Capital, operating^ and. produce cost estimates were performed for one coal
and three biomass conversion concepts-- The concepts evaluated are:
• Coal— to— Power: direct combustion of coal to generate elec-
trical power (Section 3)
* Wood— to— Power: direct combustion of wood chips (forest resi-
due) to generate electrical power (Section 3)
* Wheat Straw and Manure-to-Gas : anaerobic digestion of the
biomass feedstock to product pipeline quality gas (Section 4)
* Wood-to-Oili based on the Pittsburgh Energy Research Center
(PEB.C) process, conversion of wood chips to a heavy fuel oil
(Section 5)
Previously published capital and operating costs were updated and the product
costs estimated for two coal conversion concepts. The concepts evaluated
are:
gasification of coal with steam and oxygen to produce
pipeline-quality fuel gas (Section 4)
catalytic hydrogenation of coal to produce synthetic
fuel oil (Section 5)
The following- areas of the United States were specified for each biomass and
coal conversion plant site:
». Wood-to-Power: South Central (Alabama)
#• Straw and Manure-to-Gas: Midwest (Kansas)
• Wood-to-Oil: Northeast (Maine)
» Coal-to-Power: South Central (Alabama)
* HIGAS: Midwest (Kansas)
•• H-Coal: Northeast (Pennsylvania)
371
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CAPITAL COSTS
The above three biomass conversion processes and one coal conversion process.
were estimated based on the conceptual design and engineering information
prepared for the study in the form of engineering drawings, outline speci-
fications, and equipment lists. Estimating methods consistent with the con-
ceptual nature of the design information were employed based on informal
vendor contact and extrapolation from Bechtel historical information.
The construction cost estimate is composed of field costs, engineering ser-
vices, and allowance for uncertainty. The largest (dollar) category, field
costs, comprises the direct cost of permanent plant equipment and the indi-
rect cost of temporary construction materials, supervision, etc- The esti-
mate anticipates an engineer-constructor direct-hire operation employing
field construction labor forces.
The capital costs of the other two coal conversion processes were updated
for comparison with the other four processes. Capital costs were originally
estimated by others:
Process: HYGAS (steam-oxygen)
Estimation Date: First Quarter, 1976
Reference: Factored Estimates for Western Coal Commercial Concepts,
prepared by C.F. Braun and Co., for the United States
Energy Reserach and Development Administration and the
American Gas Association under Contract No. E(49-18)-2240
March 1, 1976 (Reference 6)
Process: H-Coal
Estimation Date: Second Quarter, 1975
Reference: H-Coal Commercial Evaluation, Conceptual Design and
Economic Analysis for a 25,000 Ton-per-Day H-Coal
Liquefaction Plant, Case — I Fuel Oil Mode, prepared
by Fluor Engineers and Constructors, Inc., for the
United. States Energy Research and Development Admin-
istration under Contract No. E(49-18)-2002, March 1976,
final unpublished report (Reference 7)
In order to obtain consistency with the other four processes, the two coal
processes were updated to first quarter, 1978, prices based on Nelson refin-
ery and operating labor indices.
Indices used for HYGAS are:
Nelson Nelson
Refinery Index Operating Labor Index
1st Quarter, 1978 680.0 158.0
1st Quarter, 1976 605.0 145.0
"372T-
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Indices used for H-Coal are:
Nelson Nelson
Refinery Index Operating Labor Index
1st Quarter, 1978 680.0 158.0
2nd Quarter, 1975" 575.5 133.0
Certain nonprocess modifications were made to the HYGAS and H-Coal base con-
ceptual designs to reflect different site-related assumptions (see starred
items in Tables 63 and 94). For HYGAS, these changes resulted in a net addi-
tion to the updated total capital cost of $13.7 million. For H-Coal, the
changes resulted in a net addition to the updated total capital cost of
$12.* million. '
Pricing Levels
The estimate is at first quarter, 1978, price and wage levels. No allowance
has been made for future escalation. " "" " ~
Field Construction Costs
Elements shown in capital cost Tables 21, 35, 52, and 81 were estimated on
the basis of the following discussion:
••• Site and Yard—includes- the cost of clearing, grubbing, and
mass excavation. It also includes domestic water piping,
fire water facilities, sewer and storm drainage, fences
and gates
* Civil/Structural—includes buildings (administration building,
shops, warehouse, auxiliary service buildings and garage)
river intake structure, river water storage pond, railroad
spurs, and access roads
• Process Mechanical Equipment—includes all mechanical equip-
ment necessary to operate the plant
•» Pollution. Control Equipment—includes civil items such as
pondsv basins,- wastewater treatment, solid" waste disposal
and equipment required for gas cleanup, such as dust col-
lectors, precipitators, incinerators, and FGD systems
•» Piping and Instrumentation—includes all process and inter-
connecting piping, auxiliary piping, and necessary elec-
trical, pneumatic and mechanical instrumentation
* Electrical—includes the main transformers, unit auxiliary
transformers, start-up transformers, auto-transformers,
and emergency diesel generators. Wire and cable, conduits,
and plant lighting are also included
371
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Equipment—
Budgetary suppliers' estimates based on conceptual designs and specifications
were obtained verbally or in writing for approximately '80 percent of the
major items. Other equipment was estimated using Bechtel data derived from
recent purchase orders and vendor contacts.
Material—
Quantity evaluations were made from the drawings for the identifiable mate-
rials of concrete, steel, piping, wire and cable and these quantities were
priced using current unit prices from Bechtel sources. Other materials that
would be delineated on the final engineering drawings have been evaluated
by experience as a percentage of the installed cost of the identified materials
Subcontracts—
Subcontracts for equipment and materials commonly installed by subcontractors
were estimated and priced in accordance with Bechtel experience from current
sources.
Construction Labor—
The direct construction labor costs for the installation of the plant equip-
ment and material were estimated using recent productivity experience .and
a wage rate based on labor contracts and fringe benefits for areas of the
country specified for each conversion concept. These wage rates are based
on. a craft mix appropriate to the type of construction together with a
five percent allowance for casual overtime and one percent for craft-furnished
supervision. Sufficient manual labor to complete the project is assumed to
be- available in the project vicinity.
Indirect Field Costs—
The indirect field costs are those items of construction cost that cannot be
ascribed to direct portions of the facility and thus are accounted separately.
They were estimated by modifying the experience on plants of a similar nature
resulting in an assessment of 70 percent of direct labor costs. The items
covered by indirect field costs are as follows:
• Temporary Construction Facilities—Temporary buildings, work-
ing areas, roads, parking areas^ utility system and general-
purpose scaffolding; —
•• Miscellaneous- Construction Services—General job cleanup,
maintenance of construction equipment and tools, material
handling and surveying
*• Construction Equipment and Supplies—Construction equipment,
small tools, consumable supplies, and purchased utilities
* Field Office—Field labor of craft supervision, engineering,
procurementv scheduling, personnel administration, ware-
housing, first aid, and the costs of operating the field
office
•" Preliminary Check-Out and Acceptance Testing—Testing of
materials and equipment to insure that components and
systems are operable
" 374 "
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Engineering Services
The engineering services include engineering costs, other home office costs,
and fee. Engineering includes preliminary engineering, optimization studies,
specifications, detail engineering vendor-drawing review, site investigation,
and; support to vendors. Other home office costs comprise"procurement, esti-
mating and scheduling services, quality assurance, acceptance testing, and
construction and project management. Fee is included as a function of the
total project cost. The sum of these three categories falls into histor-
ically consistent percentages in the range of 10-20 percent depending on the
complexity of the project. For this study, a figure of 12 percent of field
construction costs has been used as typical for plants that, while new in
concept, do not depart radically•from basic engineering principles,
Allowance- for Uncertainty
Included in the estimate is an allowance for the uncertainty that exists
within the conceptual design in quantity, pricing or productivity and that
is under the control of the constructor and within the scope of the project
as defined. Implicitly the allowance will be expended during the design and
construction of the project and it cannot be considered as a source of funds
for overruns or additions to the project scope. However, experience shows
that is is- quite difficult to assess the degree to which future processes
are understood in the hardware sense. Thus, if the" conceptual arrangement
of the plant components proves to be more severe than anticipated, or if addi-
tional major subsystems are ultimately found to be necessary, then the scope
of the project is deemed to have been inadequately defined and this then
would not be covered by the allowance. This allowance was included at 20 per-
cent for the four Bechtel estimated plants and at 15 percent for HYGAS and
H-Coal.
Other Costs
Land—
The cost of land for each plant is based on an allowance of approximately
$2,000 per care (fenced plant site).
Other Owner Costs—
This? item; includes costs to- the owner to conceive, planr and execute the
project. It generally includes the expenses for process evaluation study,
planning, site surveying and selection, contractor selection, government's
permit fees and other legal costs. Also included are initial chemicals and
catalyst cost. For these estimates other owner costs were estimated at two
percent of total construction cost.
Startup—
This item covers the expenses occurring before the full operation. It includes
costs for recruiting operators, training, modification of processes to correct
deficiencies, etc. Five percent of total construction cost was allowed for
this expense for the biomass process and the coal-fired power plant.
375
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Allowance for Funds During Construction—
In accordance with usual procedures, the interest on the capital cost of the
plant during the construction period is allowed as a depreciable capital in-
vestment over the life of the plant. Nine percent per annum was used as the
interest rate, and three-year and five-year construction periods were used
for the three biomass and three coal conversion processes, respectively. It
is assumed that the center of gravity of the capital spending is located at
a point two-thirds from the beginning.
Working Capital—
The working capital of the plant represents the amount of money invested in
the following categories:
£„. Feedstock,, supplies,, and materials in storage
2. Final products in stock and semi-finished products in the
process of being manufactured
3. Cash required on hand to pay monthly expenses, such as
salaries, wages, and raw material purchase
4. Accounts payable
5.__ Taxes payable
A minimum of five percent of fixed capital investment was allowed for this
purpose.
Design Assumptions
The following are the major assumptions for which design data were not avail-
able when the estimate was prepared.
•- Site specific items which affect civil/structural costs
• Piping, instrumentation and electrical layouts
Qualifications-
The following are the major qualifications in the estimate:
» Any emission offsets required are excluded
* Feedstock delivery is by others and the cost is included in
the cost of feedstock
» Major utilities, such as power, are available at the plant
fence line from others
+• Solid sludge from the wheat straw and manure-rto-gas process
is disposed of at no cost. Its value as a soil conditioner
is assumed to equal the cost of disposal by others. Ash
residues are insignificant and are disposed of on site
37&
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• Disposal of solid wastes (ash and wastewater evaporator sludge)
from HYGAS is assumed to be in the source coal mine. Disposal
cost is included in the cost of delivered coal
• Costs of product distribution are excluded
Estimate Tables
The above discussion of pricing levels, field construction cost, engineering
services,- allowance for uncertainty, qualifications and exclusions form the
basis of the estimates contained in the following tables:
•» Table 21. Wood-to-Power Capital Costs (Section 3)
* Table- 35.. Coal-to-Power Capital Costs (Section. 3)
* Table 52. Straw/Manure-to-Gas Capital Costs (Section 4)
* Table 81. Wood-to-Oil Capital Costs (Section 5)
The.following two tables were updated to the same time period as the above
four processes:
•- Table 67. _ HYGAS Capital Costs (Section 4)'
*> Table 97. H-Cbal Capital Costs (Section 5)
ANNUAL OPERATING AND MAINTENANCE COSTS
The materials, supplies, and labor for plant operation and maintenance were
estimated to reflect first quarter, 1978, price and wage levels. They have
been included in the estimate on the basis of the following descriptions.
Supplies
The annual costs for chemicals, diesel oil, gasoline, and other supplies con-
sumed, in the operation of the plant are included on the following basis:
»• Chemicals; were? priced: using, recent supplier quotes
» Petroleum, products and natural gas were priced on an average
cose per gallon or MSCF
Utilities
Power was priced at $0.03 per kWh with the annual requirements calculated
from the installed equipment load. Plant makeup water was priced at $0.05
per thousand gallons as an allowance for water rights.
Operating Personnel
Operating personnel costs were estimated based on manning charts and average
cost, per manhour for a typical operator.
37T
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Maintenance Labor and Materials
The costs of labor for plant maintenance were estimated from the manning
charts and average costs per manhour for a typical maintenance person. Mate-
rial was priced as being 40 percent of total maintenance, given labor as
60 percent of the total.
Supervision
The supervision costs were assumed at 15 percent of operating and maintenance
labor.
Administration and Overhead
Administration and overhead costs were estimated from the manning charts with
a nominal cost included for other overhead.
Local Taxes and Insurance
Property and other recurring taxes and insurance were estimated at two percent
of total plant capital cost. This is a typical rate for the types of plant
under consideration.
Operating Cost Tables
The above discussion of annual operating and maintenance items forms the
basis of the estimates contained in the following tables:
• Table 22. Annual Operating and Maintenance Costs
Wood-to-Power (Section 3)
• Table 36. Annual Operating and Maintenance Costs
Coal-to-Power (Section 3)
• Table 53. Annual Operating and Maintenance Costs
Wheat Straw/Manure-to-Gas (Section 4)
* Table 82^ Annual Operating and Maintenance Costs
Wbod-to-Oil (Section. 5)
The following two Annual Operating and Maintenance Cost tables were obtained
from References 6 and 7. They were updated to reflect first quarter, 1978,
prices and wages using the same indices that were used for capital costs.
• Table 68. Annual Operating and Maintenance Costs
HYGAS (Section 4)
* Table 98. Annual Operating and Maintenance Costs
H-Coal (Section 5)
375
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PRODUCT COSTS
The product costs of energy produced by each of the three biomass and three
coal conversion processes were computed by two different financial methods.
They are:
• Utility financing method
* Private financing method
The procedures to calculate the production costs using these methods were
obtained from the reference listed below:
Coal gasification Commercial Concepts' Gas Cost Guidelines
by Robert Skamser, C.F. Braun and Co., Alhambra, CA 91802,
January, 1-9-76. Prepared for the United States Energy Admin-
istration and the American Gas Association, Under Contract
No. E(49-18)-1235 (Reference 8).
Utility Financing Method
The average product costs of energy produced from six different plants were
computed on the following basis:
* 20-year project life (except two electric power plants,
wood-to-power and coal-to-power — 30 years were used
instead)
•- Straight line depreciation on total capital cost excluding
working capital
• 48 percent federal income tax rate
• 75 percent debt
• 9 percent per year interest on debt
* 15 percent return on equity
Private^ Financing- Method
The constant product costs of energy produced from six different plants were
computed on the following basis:
•- 20-year project life (except two electric power plants,
wood-to-power and coal-to-power — 30 years were used
instead)
» 16 year sum-of-the-yearsT-digits depreciation on total capital
investment excluding startup, allowance for funds during con-
struction, and working capital. (For two electric power
plants, 24 years were used.)
379
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• 100 percent equity capital _
• 12 percent Discounted Cash Flow (DCF) rate of return
•> Total construction cost, land, owner's cost, allowance for
funds during construction and working capital are treated
as capital costs in Year 0
• Startup costs are treated as an expense in Year 0
Production Cost Tables and Figures
The results of calculation to compute the production cost of energy for six
different processes by utilizing- the two different financial analyses des-
cribed above were tabulated using the feedstock cost as the parameter in -the
following two tables:
• Table 8. Economic Comparison Summary for Biomass and Coal
Conversion Processes (based on feedstock cost,
dollars per ton). (Section 2)
• Table 9. Economic Comparison Summary for Biomass and Coal
Conversion Processes (based on feedstock cost,
dollars per million Btu). (Section 2.)
The effect of feedstock prices (dollars per ton and dollars per million Btu)
on product costs are graphically displayed in Figures 40, 41, and 42. Also
shown on the graphs is the effect of two different financial methods on
product cost.
• Figure 40. Effect of Feedstock Cost on the Cost of Elec-
tricity (Section 6)
• Figure 41. Effect of Feedstock Cost on the Cost of Synthetic
Pipeline Gas (Section 6)
» Figure 42. Effect of Feedstock Cost on the Cost of Synthetic
Fuel Oil (Section; S)
380"
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