EPA-600/2-76-049b
March 1976
Environmental Protection Technology Series
ELECTRICAL ENERGY AS AN ALTERNATE TO
CLEAN FUELS FOR STATIONARY SOURCES
Volume II - Appendix
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, NC 27711
-------
RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into five series. These five broad
categories were established to facilitate further development and application of
environmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The five series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
This report has been assigned to the ENVIRONMENTAL PROTECTION
TECHNOLOGY series. This series describes research performed to develop and
demonstrate instrumentation, equipment, and methodology to repair or prevent
environmental degradation from point and non-point sources of pollution. This
work provides the new or improved technology required for the control and
treatment of pollution sources to meet environmental quality standards.
EPA REVIEW NOTICE
This report has been reviewed by the U.S. Environmental
Protection Agency, and approved for publication. Approval
does not signify that the contents necessarily reflect the
views and policy of the Agency, nor does mention of trade
names or commercial products constitute endorsement or
recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EPA-600/2-76-049b
March 1976
ELECTRICAL ENERGY AS AN ALTERNATE TO
CLEAN FUELS FOR STATIONARY SOURCES
VOLUME II—APPENDIX
by
R. M. Wells and W. E. Corbett
Radian Corporation
8500 Shoal Creek Boulevard
P.O. Box 9948
Austin, Texas 78766
Contract No. 68-02-1319, Task 13
ROAP No. 21ADD-042
Program Element No. 1AB013
EPA Project Officer: Walter B. Steen
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
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APPENDIX A
BREAKDOWN OF FOSSIL
FUEL ENERGY USAGE IN
INDUSTRIAL DIRECT
HEAT CATEGORY
-------
APPENDIX A
TABLE OF CONTENTS
Page
1.0 INTRODUCTION ! A-l
2 . 0 PRIMARY METALS GROUP (SIC 33) A-3
3 . 0 CHEMICAL AND ALLIED PRODUCTS (SIC 28) A-7
4.0 PETROLEUM REFINING AND RELATED INDUSTRIES
(SIC 29) A-8
5 . 0 FOOD AND KINDRED PRODUCTS (SIC 20) A-10
6.0 PAPER AND ALLIED PRODUCTS (SIC 26) A-ll
7.0 STONE, CLAY AND GLASS (SIC 32) A-12
8.0 SUMMARY A-15
9.0 REFERENCES - APPENDIX A A-17
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1.0 INTRODUCTION
In Section 3.0 of Volume I of this report, procedures
used to obtain a detailed breakdown of the fossil fuel energy
used in the residential, commercial and industrial sectors were
discussed. This breakdown of energy usage was intended to pro-
vide a basis for the assessment of electrical substitution
possibilities in each of the three sectors considered.
Residential and commercial sector energy demands in
the years 1960 and 1968 were broken down in great detail in a
Stanford Research Institute (SRI) report (ST-186). An assess-
ment of electrical substitution possibilities could be made
in the case of both of these sectors using only the data pro-
vided in the SRI report. This was not true in the case of the
industrial sector energy breakdown provided by SRI. For this
reason, it was necessary for Radian to gather additional data
on fossil fuel consumption in that sector.
Industrial sector fossil fuel usage categories
defined by SRI included: process steam, direct heat, feed-
stock and electrical generation. Of this group, process steam
and direct heat are the only categories in which any electrical
substitution possibilities exist. Due to the inefficiencies
involved, it is not likely that electricity would ever be used
to produce significant quantities of process steam. For this
reason, the direct heat category was identified as being the
only SRI classification group having any significant potential
for electrical substitution.
In this appendix, Radian's analysis of the energy used
to supply direct heat in the industrial sector is presented.
These results are based upon information extracted from
A-l
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appropriate reference material and assumptions made by Radian
personnel. The assumptions, results, and the effects of errors
in these assumptions are discussed below. In most cases,
several sources of data are compared. In order to provide a com-
mon basis for this comparison, usage data given for years other
than 1968 were projected to 1968 using an assumed annual energy
growth rate of 4%.
Standard Industrial Classification (SIC) groups pro-
vided the basis for this survey of industrial sector energy use.
The six major SIC groups which were examined in detail included:
SIC
33 Primary Metals
28 Chemicals and Allied Products
29 Petroleum Refining and Related Industries
20 Food and Kindred Products
26 Paper and Allied Products
32 Stone, Clay and Glass Products
It will be shown in this section that these six
SIC groups accounted for about 96% of the total fossil fuel
energy consumed for direct heat in the industrial sector in
1968.
A-2
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2-0 PRIMARY METALS GROUP (SIC 33)
The primary metals group is comprised of varied metal-
related industries with the iron-steel industry and the aluminum
industry being the major energy users. These two industries
are described in detail in the following sections.
2-1 Iron-Steel Industry
Total energy used in the iron-steel industry in 1968
is given below.
10I2 Btu
Coal
Natural Gas
Petroleum
Electricity
TOTAL
Fossil fuels used to provide direct heat in the iron-
steel industry are summarized in Table 1. The SRI total fossil
fuel direct heat figure of 2,927 x 1012 Btu is comparable to the
Sansom (EN-187) value of 2,801 x 1012 Btu and the AGA (AM-095)
value of 2,260 x 1012 Btu., The AGA value is based upon 1964 data;
therefore, it is possible that the 47, growth rate was not ap-
plicable over that four-year period. Also, since the AGA report
did not break down the^ energy used in as detailed a fashion as
the other two reports, there may have been some important applica-
tions omitted.
A-3
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TABLE 1
1968 FOSSIL FUEL USAGE FOR DIRECT HEAT
IN THE IRON-STEEL INDUSTRY
(1012 Btu)
Natural Fuel Oil
Use Coal Gas (and LPG) Total
Blast Furnace 2,129 47 12 2,188
Associated Blast Furnace
Activities -62 8
Steel Mining - 102 82 184
Heating and Annealing - 304 56 360
Other 18 128 41 187
TOTAL 2,147 587 193 2,927
Total Fossil Fuel Direct Heat = 2,927 x 1012 Btu
A-4
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2.2 Aluminum Industry
Electricity is the primary source of energy in this
industry since the smelting and refining processes are largely
electrolytic in nature. An energy usage breakdown for this in-
dustry is shown in Table 2,
TABLE 2
1968 ENERGY USE IN ALUMINUM PRODUCTION
Process
Electrolytic Smelting (Net)
Melting
Process Power, Steam
Ancillary Needs
Total
Amount
10 6 Btu/t
46.7
4.7
3.6
20 A0,
75,0
Fuel Type
Electricity
Fossil Fuels
Fossil Fuels
Fossil Fuels
In 1968, there were 3.7 x 10s tons of aluminum produced.
This implies that the energy used was (3.7 x 106 tons) (75 x 106
Btu/ton) = 278 x 1012 Btu. Also, secondary aluminum refining
used 7 x 1012 Btu, and wrought aluminum processing used 45 x
1012 Btu. Therefore, according to SRI, a total of 330 x 1012 Btu
was utilized by the aluminum industry in 1968.
Since these energy figures were not broken down further
in any of the sources considered, it was assumed that all of the
energy consumed in the smelting category and half of the energy
used for ancillary needs were fossil fuel direct heat. Likewise,
A-5
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half of the secondary refining and wrought aluminum processing
energy needs were assumed to be fossil fuel direct heat. These
assumptions imply that 54 x 1012 Btu of fossil fuels were used to
supply direct heat for aluminum production and that secondary re-
covery and processing of wrought aluminum consumed 26 x 1012 Btu
of fossil fuels for direct heat in 1968. Thus, in 1968, fossil
fuels provided 80 x 1012 Btu of direct heat energy in the alumi-
num industry.
The total amount of fossil fuel energy consumed to supply
direct heat in both the iron-steel industry and the aluminum
industry in 1968 was:
Iron-Steel 2,927 x 1012
Aluminum 80 x 1012
Total 3,007 x 1012 Btu
This value, based on SRI data, compares with the San-
som value of 2,859 x 1012 Btu and the AGA value of 2,337 x 1012
Btu.
A-6
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3.0 CHEMICAL AND ALLIED PRODUCTS (SIC 28)
The chemical group includes all chemical manufacturing
activities, but excludes such industries as petroleum refining.
The energy used in 1967 was
Space Heating: 80 x 1012 Btu
Process Heat: 498 x 1012 Btu
Space heating can be provided by either steam or
fossil fuel combustion. If it is assumed that half of the space-
heating requirements in this category are supplied-by fossil
fuels then,
40 x 1012 Btu Fossil Fuel Space Heating,
498 x 1012 Btu Process Heat
538 x 1012 Btu in 1967
assuming a 4% annual grox^th rate yields
Total Fossil Fuel Direct Heat - 560 x 1012 Btu in
1968.
This agrees very well with the Sansom (698 x 1012 Btu)
and AGA (679 x 1012 Btu) values, which do not include steam
heating.
A-7
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4.0 PETROLEUM REFINING AND RELATED INDUSTRIES (SIC 29,)
This industrial grouping supplies a large share of
all energy used by the nation. The energy derived and used
internally from the input feedstocks is reported to be between
600,000 to 710,000 Btu per input barrel of crude. The bulk of
this energy is used for steam generation and direct heating.
Two methods were used to compute quantities of fossil fuels
used to provide direct heat in this group.
4.1 Method 1
In 1968, 11,740,000 barrels (42 gallons/barrel) of
crude were refined per day. For 350 refining days per year
this implies that 4,109 x 109 barrels of crude were refined.
Using a conversion factor of 7.10 x 10s Btu per barrel of crude,
the total fossil fuel energy used to refine the crude is deter-
mined to be 2,917 x 1012 Btu in 1968. If 60% of this energy
is used to provide direct heat, then 60% of 2,917 x 1012 is
Fossil Fuel Direct Heat = 1,750 x 1012 Btu.
4.2 Method 2
The second method used to compute total fossil fuel
consumption for this group involved the use of data given in the
SRI report. Total energy use reported by SRI was 2,683 x 1012
Btu. 60% of this is
Fossil Fuel Direct Heat = 1,610 x 1012 Btu.
A-8
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These two methods yielded results which were within
1070 of each other. Sansom reported a value of 1,679 x 1012
Btu and the AGA reported a value of 1,121 x 1012 Btu. The
Sansom value is in good agreement with the data given above,
while the AGA value is considerably lower. It is felt that this
number is possibly lower because the AGA may not have included
all of the energy derived from internally generated gases and
fuels.
A-9
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5.0 FOOD AND KINDRED PRODUCTS (SIC 20)
This industrial grouping includes all food processing
including meat processing, grain processing and beverage produc-
tion activities. The data available from the sources considered
were at best sketchy. The total fossil fuel energy used in this
industry was available, however. Since it was felt that most of
this energy would go into cooling or heating foods, 75% of the
total energy used by this group of industries was assumed to be
direct heat. In 1963, the following fuels were used in the
amounts given.
Coal 168 x 1012 Btu
Oil 95 x 1012 Btu
Natural Gas 359 x 1012 Btu
622 x 1012 Btu
If 75% of these were used to provide direct heat, then
Fossil Fuel Direct Heat = 467 x 1012 Btu.
This values compares favorably with data derived from
Sansom and AGA data using the same 75% assumption. These numbers
are 459 x 1012 Btu for Sansom and 538 x 1012 Btu for AGA,
respectively. This 75% factor could be off by ±20% but since
the total value of the number involved here is so small compared
to the other major groups, the impact of this error would be in-
significant.
A-10
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6.0 PAPER AND ALLIED PRODUCTS (SIC 26)
This industrial grouping includes all paper, pulp
and allied products. The amounts of fossil fuels used to
provide direct heat in this industry are minute. The pri-
mary source of direct heat is internally generated waste (pulp,
chips, and bark). The information reported below was obtained
from a diagram in the SRI report. The total heat used was 1,679 x
1012 Btu. The amount of steam heat was 1,675 x 1012 Btu. Thus
Fossil Fuel Direct Heat = 4 x 1012 Btu.
Again, even if this value is incorrect by a consider-
able factor, the overall analysis is extremely insensitive to
this small number. Sansbm provided no useful numbers and the
AGA report gave a value of .01 x 10s Btu per ton of paper.
This implies that 400 x 106 tons of paper would have to be
produced to use 4 x 1012 Btu. This is a factor of four larger
than the total production of paper and pulp in 1968.
A-ll
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7.0 STONE, CLAY AND GLASS (SIC 32)
This group consists of all industries related to the
stone industry including the cement and concrete industry.
Ceramic and glass production activities are also included.
Of this group, the cement and glassware industries are the
major energy users with these two subgroups accounting for
59% of the total energy used in this SIC group. These two
subgroups are discussed below in detail.
7.1 .Cement
The major portion of all cement produced in the U. S.
is Portland cement. This process requires direct heat in a kiln
and in fact, this is the major use of direct heat in the industry.
Sources report that approximately 600 pounds of coal
are required to produce a ton of cement. This implies that
7.86 x 106 Btu are required per ton of cement. There were
403,349,000 barrels of Portland cement (at 376 pounds per barrel)
produced in 1968 in the U. S. This means that 152 x 109 pounds
of cement (76 million tons) were produced. Therefore
Fossil Fuel Direct Heat = 597 x 1012 Btu.
Sansom reported that 502 x 1012 Btu/year and the AGA
reported that 544 x 1012 Btu were used to provide direct heat
for cement manufacturing in 1968. These values are all in good
agreement.
A-12
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7.2 • Glass
The glass industry used 10.8 x 106 tons of silica sand
in 1968 for glass making. The approximate formula for glass
(by weight) is
100 parts sand (silica)
35 parts soda
12 parts lime
10 parts niters
157 parts
If this formula is scaled up to 10.2 x 106 tons silica sand, then
10.2 x 106 sand (tons)
3.6 x 10s soda (tons)
1.2 x 106 lime (tons)
1.0 x 106 niters (tons)
16.0 x 106 tons glass material
Assuming a 10% process loss, these figures imply that,
in 1968, 13.4 x 106 tons of glass were produced. SRI reports
that 14-18 x 10s Btu of energy are required per ton of glass
produced for plates and containers. Therefore, using average of
16 x 1012 Btu per ton, 216 x 1012 Btu of energy was used. If
50% of this is fossil fuel direct heat, then
Fossil Fuel Direct Heat = 108 x 1012 Btu.
A-13
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If this 50% factor were actually 75% the calculated
direct heat value would be 162 x 1012 Btu. This would again
represent a small change in overall direct heat energy usage.
Sansom reported that 118 x 1012 Btu were used in the manufactur-
ing of glass containers. If 75% is direct heat, then 89 x 1012
Btu were used in this subgroup. The glass container industry
represents 75% of the glass industry energy use. The AGA states
that approximately 163 x 1012 Btu of fossil fuel energy were used
in this industry in 1968.
7.3 Glass and Cement
According to the SRI figures discussed above, these
two subgroups consumed 705 x 10I2 Btu of fossil fuel energy for
direct heat in 1968 while Sansom and the AGA reported the use
of 620 x 1012 Btu and 707 x 101Z Btu, respectively.
A-14
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8.0 SUMMARY
The results of this breakdown of industrial sector
direct heat requirements are summarized in Table 3. As can be
seen, data derived from the three sources used are in reason-
ably good agreement. Based on this, the numbers derived from
SRI data were presumed to be representative and were therefore
used in the body of this report. It should be noted here that,
although the six SIC groups considered accounted for only 67%
of the total fossil fuel energy consumed in the industrial
sector in 1968, these same groups accounted for 96% of the
fossil fuels consumed for direct heat. It can therefore be con-
cluded that all significant fossil fuel end uses in the in-
dustrial sector which are convertible to electricity have been
covered by this survey.
A-15
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TABLE 3
FOSSIL FUEL USAGE FOR
DIRECT HEAT
IN 1968
(1012 Btu)
Industry SRI Sansom
Primary Metals 3,007 2,859
Chemical 560 698
Refining 1,610 1,679
Food 467 459
Paper 4
Stone, Clay, Glass 705 620
SUBTOTAL OF ABOVE 6,353 (96%)
AGA
2,337
679
1,121
538
-
707
TOTAL INDUSTRIAL SECTOR
DIRECT HEAT
USAGE (ST-186)
6,604 (100%)
Other Direct Heat Uses
Not Accounted for in
Industry Groups Con-
sidered (by difference)
251 (4%)
A-16
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9.0 REFERENCES - APPENDIX A
AM-095 American Gas Assoc., Inc., A Study of Process Energy
Requirements for U.S. Industries, Arlington, Va.
EN-187 Energy and Environmental Analysis, Inc., Energy
Management in Manufacturing: 1967-1990, Vol. 1,
summary report, draft, Arlington, Va., 1974.
ST-186 Stanford Research Institute, Patterns o_f Energy
Consumption in the United States, Menlo Park, Ca.,
Stanford Research Inst., 1974
A-17
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APPENDIX B
A COMPARATIVE ANALYSIS OF THE
EFFICIENCIES OF ELECTRICAL END USE
EQUIPMENT ITEMS VERSUS DIRECT-FIRED
FOSSIL FUEL EQUIPMENT ALTERNATIVES
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APPENDIX B
TABLE OF CONTENTS
1.0 INTRODUCTION B-l
2 . 0 RESIDENTIAL SECTOR B-2
3 . 0 COMMERCIAL SECTOR B-13
4. 0 INDUSTRIAL SECTOR B-15
5.0 SUMMARY B-18
6.0 REFERENCES - APPENDIX B B-20
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1.0 INTRODUCTION
As an alternative to the direct combustion of fossil
fuels at stationary end use sites, it has been suggested that
the environmental impacts of fossil fuel use can best be mini-
mized by burning these fuels in large central power stations
where efficient emission control techniques can be effectively
applied. Electricity would then be used to satisfy the needs
of energy consumers in the stationary sectors.
The technical incentives for moving toward this type
of energy supply situation obviously depend strongly on the rela-
tive efficiencies of fossil fuel and electrical equipment items
designed to satisfy equivalent end use demands. For this reason,
an important part of this study consisted of a survey to gather
data on the thenaodynatnic efficiencies of alternative equipment
types which are presently used in the residential, commercial, and
industrial sectors. The results of this survey are summarized^.
in this appendix.
Each of the end use sectors considered in this study
is discussed separately. First, fossil fuel-powered equipment
items presently used in each sector and the energy use efficiency
of each is discussed. Then, where they exist, electrical al-
ternatives to each fossil fuel end use are identified and the
efficiency of each alternative equipment type is presented. In
the final section of this appendix, a summary table listing
all of these alternatives is presented.
B-l
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2.0 RESIDENTIAL SECTOR
The major energy end uses in the residential sector
are space heating, water heating, cooking, clothes drying,
refrigeration, and air-conditioning. For each of these
end uses, an electrical substitute exists.
2.1 Space Heating
In 1968, fossil fuels satisfied 97% of the total U.S.
space heating load. The two major types of fossil fuel-fired
hardware which are currently in use include natural gas furnaces
and fuel oil furnaces. Alternative electrical hardware items
include baseboard heaters, electric furnaces, heat pumps, and
electric heating mats.
Published data on the efficiencies of fossil fuel-fired
residential space heaters are summarized in Table 1. It is
obvious from these data that considerable variations in reported
efficiencies are observed. Some of these variations are due to
the different bases used by the various investigators. For
example, the 75% "technical efficiency" published by SRI (ST-186)
included only the efficiency of the burner or furnace whereas the
55.2% overall efficiency reported by Large (LA-144) included
other losses which occur before the end use. The two efficiencies
presented by Dunning (DU-069) provide an interesting comparison.
The utilization efficiency is defined as:
Utilization _ -,QQ . Calculated Heat Loss ^ of a House
Efficiency Annual Fuel Consumption of a House
and the furnace efficiency is defined as:
Furnace = i on •
Efficiency 1UU
Heat Losses of the House which the Furnace Replaces
Annual Fuel Consumption of the House
B-2
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TABLE 1
EFFICIENCIES OF FOSSIL FUEL-FIRED
RESIDENTIAL SPACE HEATERS
Equipment
1. Natural Gas
Furnace
Efficiency
75%
75%
67%
60-65%
65%
63%
60%
60%
55.2%
47%
45%
Comments
Technical efficiency
Combustion Efficiency
Includes 90% supply
efficiency
Utilization efficiency
Overall efficiency
Average of extremes of
reported efficiencies
Overall efficiency
92% delivery efficiency,
60% furnace efficiency
Furnace efficiency
Source
ST-186
MA-345
NA-187'
MA-345
DU-069
LE-165
HI-095
TI-026
LA- 144'
DU-069
HE -085
2.
Fuel Oil
Furnace
63%
60-65%
60%
50%
60%
Technical efficiency
Includes 90% supply
efficiency
Average of extremes of
reported efficiencies
System efficiency
ST-186
MA-345
HI-095
CO-106
TI-026
B-3
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The utilization efficiency is somewhat misleading in that it
credits the gas furnace for heating which is in reality performed
by solar radiation, lighting, and appliances. The utilization
efficiency also includes as useful energy, the heat required to
warm to room temperature the outside air which infiltrates the
house to replace the heated air escaping up the flue. In contrast,
furnace efficiency does not credit the furnace with either heat
gains or heat required to warm the infiltrated air.
Another important point to consider is the condition
of the furnace during the test. High efficiencies are generally
obtained by evaluating the performance of a clean furnace after
warm up. In actual practice, furnaces tend to be dirty and to
operate in a cycling mode. Both of these deviations from ideal
conditions tend to lower their efficiencies. Also, some of the
sources in Table 1 include losses which are incurred before the
end use in their calculations. For example, a delivery or supply
efficiency is sometimes included in the overall efficiency calcula-
tion. The delivery or supply efficiency takes into account losses
suffered during extraction, transmission, or distribution of the
fossil fuel.
A value of 60% was chosen here to represent the
efficiency of a typical natural gas-fired furnace. This efficiency
agrees approximately with results of two studies conducted by
Hittman (HI-105) and the Institute of Gas Technology (LE-165).
These studies reportedly considered all of the factors that in-
fluence the efficiency of a natural gas furnace such as air
infiltration and exfiltration, furnace cycling, and contributions
from ancillary heat sources. Furthermore, 60% is a reasonable
average of the data reported in Table 1. This efficiency is not
intended to include losses which are incurred before the gas is
consumed at the end use site. Since the efficiencies of oil-
fired furnaces are usually quoted as a few percent less than
comparable gas furnaces, an efficiency of 55% was selected as
a representative value for the efficiency of an oil-fired furnace.
B-4
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Viable electrical hardware items which could be used
in place of fossil fuel space heaters are listed in Table 2.
The electric heating mat is omitted from this list since no ef-
ficiency or cost data for this alternative could be found.
These mats are generally installed in the concrete slab of a single
level building with a layer of sand below the concrete for insula-
tion purposes. During off-peak hours, the resistive heating mats
are turned on to warm the concrete slab. This mass functions as
a large heat reservoir during the night and slowly releases heat
to the building via radiation and convection the following day.
As can be seen from Table 2, wide variations in the
efficiencies of electric baseboard heaters and electric furnaces
are observed because of the electricity supply losses which are
included in some of the end use efficiency figures shown. The
efficiency of converting electrical energy into useful heat is
usually given as 95-100%. Deviations from this range of values
.seen in Table 2 arise from the inclusion of fossil-fuel extraction
efficiencies, steam-electric generation efficiencies, and trans-
mission-distribution efficiencies in the calculation of overall
end use efficiency values. In this study, it was appropriate to
assume a 100% efficiency for the conversion of electrical energy
into useful heat.
The heat pump is a device receiving much attention from
energy conservation proponents since this energy mover can display
thermal efficiencies which are greater than 100%. As it is defined
here, an efficiency greater than 10070 means that for every Btu of
electrical energy consumed (3413 Btu/kWh) by the heat pump motor,
more than one Btu of heat is transferred from the surroundings to
the residence. Furthermore, if the motor is located inside the
residence, a portion of the electrical energy consumed by the
motor is recoverable in the form of dissipated heat. Efficiencies
B-5
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TABLE 2
EFFICIENCIES OF ELECTRICAL SPACE HEATING EQUIPMENT
Equipment
Electric
Baseboard
Efficiency
100%
95%
95%
30%
28.1%
Electric
Furnace
100%
95%
Comments Source
HE-085
CO-106
Technical efficiency ST-186
33% generation efficiency; HI-095
91% transmission and dis-
tribution efficiency; 100%
resistive heating efficiency
95% delivery efficiency; LA-144
32.5% generation efficiency;
91% transmission efficiency;
100% conversion to heat
efficiency
HE-085
CO-106'
3. Heat Pump
226%
200%
200%
120-250%
119-203%
CO-106
LA-144
HI-095
MO-135
DU-069
B-6
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of this device are reported to range from 100% to greater than
300%. A large dependence on the temperature differential be-
tween the inside and the outside environment partially accounts
for these variations in reported efficiencies. Radian used
an efficiency of 200% for heat pumps which are operating in the
space heating mode since this figure is a reasonable average of
the values reported.
2.2 Water Heating
Fossil fuels supplied 83% of all energy used for
residential water heating in 1968. The efficiencies of gas-
fired and fuel oil-fired water heaters are given in Table 3.
Based upon the range of values shown in this table, an efficiency
of 50% appears to be typical for gas-fired water heaters, whereas,
the efficiency of fuel oil-fired water heaters is closer to 55%.
The efficiency of an electric water heater is reported
to be 92% By SRI (ST-186). Other references burden the efficiency
with prior conversion losses as discussed in Section 2.1. Since
fuel supply losses are treated separately in this study, an
efficiency of 92% was chosen for electric water heaters.
2.3 Cooking
The energy supplied by direct firing of fossil fuels
represented 84% of all energy used for residential cooking in
1968. This energy was primarily consumed in gas stoves/ovens and
other stoves/ovens fired by fuel oil or liquefied petroleum gas
(LPG). The types of equipment used for cooking in the residen-
tial sector and their corresponding efficiencies are listed in
Table 4. According to SRI, the efficiency of using fossil fuels
directly for cooking is 37%. The efficiency of electric cooking
B-7
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TABLE 3
EFFICIENCIES OF RESIDENTIAL WATER HEATERS
Equipment
Efficiency
Comments
Source
1.
2.
3.
Gas -Fired
Water Heater
Oil-Fired
Water Heater
Electric Water
647o
597=
50-557o
507o
50-557o
417,
927o
Technical efficiency
Includes 9070 delivery
efficiency
Technical efficiency
Includes 9070 delivery
efficiency
Technical efficiency
ST-186
CO-106
MA-345
ST-186
MA-345
CO-106
ST-186
Heater
B-8
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TABLE 4
EFFICIENCIES OF RESIDENTIAL COOKING EQUIPMENT
Equipment Efficiency
Comments
1. Natural Gas
Stove/Oven
37% Technical efficiency
Source
ST-186
2. Fuel Oil/LPG
Stove/Oven
37% Technical efficiency
ST-186
3. Electric
Stove/Oven
75% Technical efficiency
ST-186
4. Microwave
Oven
82%
Derived
from data
published
in ST-186
B-9
-------
is 75% when only the efficiency of conversion from electricity
to cooking heat is considered, A relatively new device, the
microwave oven, exhibits efficiencies above 80%.
2.4 Other End Uses
The remaining major energy end uses in the residential
sector and the efficiencies of both fossil fuel-fired and com-
parable electrical equipment items are listed in Table 5. Sup-
posedly, none of these efficiencies are burdened by losses
which occur before the point of fuel consumption at the end use
site.
It should again be noted that the efficiency of a heat
pump is very dependent on the temperature differential between
the inside of the residence and the outside environment. As was
the case with the space heating application, two-hundred percent
was selected as a representative thermal efficiency for a heat
pump used for residential cooling.
At this point, some discussion of the apparent dis-
crepancies seen in the data presented in Table 5 is appropriate.
The end use efficiency figures used in this study are intended to
represent the amount of useful energy which can be derived from a
device as a function of the input energy required to operate the
device. On this basis, electrical resistance heaters are
assigned an efficiency of nearly 100% since nearly 3413 Btu of
thermal energy can be derived from the consumption of one kwh of
electrical energy. On this same basis, the heat pump is assigned
a representative efficiency value which is greater than 100%,
since more than 3413 Btu of thermal energy can be moved for every
kwh of electrical energy consumed.
B-10
-------
When considered in terms of this efficiency definition,
some of the SRI efficiency figures which are listed in Table 5
do not appear to be realistic. Physically, electric air
conditioners and electric heat pumps are identical devices
since conventional versions of these units-utilize the same
freon vapor compression cycle. The efficiencies of these two
devices should therefore be equivalent. Apparently, SRI ef-
ficiency figures for the four refrigeration devices shown in
Table 5 are true thermodynamic efficiency values (calculated as
the actual heat transferred divided by the theoretical heat which
could be transferred by an ideal reversible heat engine operat-
ing between the temperature limits considered). On this basis,
the thermodynamic efficiency of a typical commercial air condi-
tioning unit is on the order of 50%. As it is defined for
purposes of this study, however, it is more meaningful to assign
an efficiency figure of 200% to a residential electric air con-
ditioning unit.
According to the SRI figures in Table 5, gas air condi-
tioners are 60% as efficient as electric air conditioners. This
is probably reasonable since all of the thermal energy contained
in the gas cannot be converted to useful work for purposes of
compressing the working fluid (e.g., freon) in an air condition-
ing unit. This same relative efficiency difference would be
expected in the case of gas and electric refrigerators. This is
not seen in the data presented in Table 5 however. This dis-
crepancy is probably accounted for by the fact that the figures
for gas and electric refrigerators are not derived from the same
source. As a result, it is likely that the two efficiency figures
involved were not calculated using a consistent basis.
B-ll
-------
TABLE 5
EFFICIENCIES OF OTHER
MAJOR RESIDENTIAL EQUIPMENT
Equipment Efficiency
1.
Gas
Clothes
Dryers
Comments
47%
507,
Technical efficiency
Source
ST-186
MA-345
2. Petroleum
(LPG) Clothes
Dryers
4778 Technical efficiency
ST-186
3. Gas
Refrigerator
69%'
CO-106
4. Gas Air-
Conditioner
30%:
Technical efficiency
ST-186
5. Electric
Clothes
Dryer
57% Technical efficiency
54%
ST-186
MA-345
6. Electric
Refrigerator
50%'
Technical efficiency
ST-186
7. Electric Air-
Conditioner
50%* Technical efficiency
ST-186
8. Electric
Heat Pump
200%'v
See Table 2
These figures are not defined on a consistent basis. See discussion
in Section 2.4
B-12
-------
3-0 COMMERCIAL SECTOR
In this sector the major energy end uses are space
heating, water heating, cooking, refrigeration, and air-condition-
ing. The electrical replacement equipment is the same as that
for the residential sector.
3.1 Space Heating
At the present time, almost all commercial space heat-
ing demands are satisfied by fossil-fuel powered equipment.
Table 6 lists the efficiencies of equipment items currently used
in this application in the commercial sector. Large commercial
space heaters generally operate at slightly higher efficiencies
than their residential counterparts. Electrical replacements
for these equipment items are identical to those listed in Table
2 for the residential sector.
3.2 Other End Uses
The efficiencies of other major fossil-fuel fired
hardware items in the commercial sector are essentially the same
as their counterparts which are used in the residential sector.
This is also true in the case of the electrical replacement
equipment. As a result, Tables 3, 4, and 5 should be consulted
to obtain representative values for the energy use efficiencies
of these equipment items,
B-13
-------
TABLE 6
EFFICIENCIES OF COMMERCIAL SPACE HEATERS
Equipment Efficiency Comments
1. Coal Furnace 70% Technical efficiency
2. Natural Gas
Furnace
3. Fuel Oil
Furnace
77%
76%
Technical efficiency
Technical efficiency
Source
ST-186
ST-186
ST-186
B-14
-------
4.0 INDUSTRIAL SECTOR
The only energy end use in the industrial sector which
has a potential for conversion from direct-fired fossil fuel
equipment to electrical equipment is the "direct-heat" end use.
As reported in Appendix A, 6604 x 1012 Btu were used in 1968 to
provide direct heat in the industrial sector. In some applica-
tions, however, it is not technically feasible to change hard-
ware. For example, in the petroleum refining and chemical
industries, there exists no feasible electrical equipment to
replace large process heaters and boilers. Also, in the cement
industry, it is not technically feasible to replace direct-fired
rotary kilns with electrical hardware. As a result of Radian's
analysis of energy end uses which are convertible, it was deter-
mined that in the industrial sector, only 1679 x 1012 Btu of
energy use in 1968 could have been satisfied by electrical energy.
Table 7 lists the fossil fuel end uses in the industrial
sector which could reasonably be converted to electrical equip-
ment. Also listed are the process energy requirements or effi-
ciencies of each equipment item. Shown in Table 8 are the
electrical equipment items which could be substituted for exist-
ing industrial sector fossil fuel end uses.
In general, it can be seen that the electrical equip-
ment items listed in Table 8 require less energy per unit weight
of processed material than their fossil fuel-powered counter-
parts . These higher efficiencies and lower energy requirements
can be misleading, however, because fuel supply losses are not
included in these figures, When a steam-electric generation
efficiency of 33 to 35% is included, overall net efficiencies of
electrical equipment items are lowered by a factor of approxi-
mately 3.
B-15
-------
TABLE 7
COHVERTIBLE
FOSSIL FUEL ENERGY USED
TO SUPPLY DIRECT HEAT
IN THE INDUSTRIAL SECTOR
Industrial Sector End Use
1.
2.
3.
4.
5.
Primary Metals
a. Iron-Steel Steel Making
Heating,
Annealing
Space Heating
b. Aluminum Melting, etc.
Chemical Space Heating
Food Space Heating
Cooking
Stone, Clay, Glass Melting
Glass
Other Misc. (from Table 3
Appendix A)
Process Energy
Energy Used* Requirements
Fossil Fuel 1968 (BTU/wt) or
Type (10' ? BTU) Efficiency Comments
Natural Gas
Fuel Oil and
LPG
Natural Gas
Fuel Oil
Coal
Natural Gas
Fuel Oil
All Fossil
Fuels
All Fossil
Fuels
Coal
Fuel Oil
and LPG
Natural Gas
Natural Gas
102
82
304
56
18
128
41
80
42
126
71
270
108
251
4.3 x 10' BTU/Ton
4.3 x 10s BTU/Ton
19 x 106 BTU/Ton This is the average of
19 x 106 BTU/Ton the extremes 13 x 106
BTU/Ton and 25 x 10s BTU/
Ton.
707.
77%
76%
74% Average of coal , gas and
fuel oil furnace
efficiencies .
70%
37% Fuel oil could provide
some space heating.
37% Natural gas could provide
some space heating.
16 x 106 BTU/Ton Some of 108 x 1012BTU
(about 12%) is coal and
fuel oil.
Combination of space heat
and other uses. Most is
Total
probably convertible.
1679
See Appendix A
B-16
-------
TABLE 8
ELECTRICAL EQUIPMENT FOR REPLACEMENT IN INDUSTRIAL SECTOR
Industrial Sector
End Use
Process Energy
Requirement (BtU/wt)
or Efficiency of
Electrical Equipment Electrical Equipment Comments
Source
1. Primary Metal
a. Iron-Steel Steel Making
Heating,
Annealing
Space
Heating
b . Aluminum Melting
2. Chemical Space
Heating
3 . Food Space
Heating
Cooking
Electric Arc Steel
Making
Electric Arc or Electric
Induction Furnaces
Electric Furnaces
Electric Arc or
Induction Furnaces
Electric Furnace
Electric Furnace/Ovens
Electric Stoves
Microwave Ovens
1.9 x 10' BTU/Ton
2.1 x 10s BTU/Ton
95%
2.1 x 10s BTU/Ton
95%
957.
75%
827.
AM-095
AM-095
ST-186
ST-186
ST-186
ST-186
4. Stone, Clay, Glass Melting Electric Furnaces
Glass
2.9 x 10s BTU/Ton
AM-095
B-17
-------
5.0 SUMMARY
Table 9 lists the total energy which could have been
converted from fossil fuel-fired equipment to electrically
powered equipment in each sector in the year 1968. It should
be noted that the residential and commercial sectors provide a
very high percentage of the fossil fuel energy use which is
convertible.
B-18
-------
TABLE 9
CONVERTIBLE ENERGY IN 1968
Sector
Residential
Commercial
Industrial
Total
Fossil-Fuel
Energy
Convertible
(1012 Btu)
7,798 (54%)
4,818 (34%)
1,679 (12%)
14,295 (100%)
Total Fossil
Fuel Energy
Consumed in
Sector
(1012 Btu)
7,798 (23%)
5,802 (18%)
19,438 (59%)
33,038 (100%)
Percent of
Energy Consumed
in Sector Which
is Convertible
100%
83%
9%
42%
B-19
-------
6.0 REFERENCES - APPENDIX B
AM-095 American Gas Assoc., Inc., A Study of Process Energy
Requirements for U. S_. Industries.
CO-106 Committee on Interior and Insular Affairs, U. S. Senate,
Conservation of: Energy, 98-18, 92nd Congress, 2nd
Session, Washington, GPO, 1972.
DU-069 Dunning, R. L., "Furnace Efficiency Variations Ex-
plained", Elec. World I Feb. 1974.
HE-085 "Heat-Pump Prospects Show Shart Gain", Elec. World 180
(4), 80 (1973).
HI-095 Hirst, Eric and John C. Meyers, "Efficiency of Energy
Use in the United States", Reprint, Science 179,
1299-1304 (1973).
HI-105 Hittman Associates, Inc., Residential Energy Conservation,
A Summary Report, HUD-HAI-8, Columbia, Md., July 1974.
LE-165 Lewis, Stephen A., Private Communication, AGA, 3 June 1975
LA-144 Large, David B., ed., Hidden Waste, Potentials for
Energy Conservation, Washington, D. C., Conser-
vation Foundation, 1973.
MA-345 Makhijani, A. B. and A. J. Lichtenberg, An Assessment
of Residential Energy Utilization in the U.S.A.,
ERL-M370, Berkeley, Ca., Univ. California, College
of Engineering, 1973.
B-20
-------
MO-135 "Moore Turns to the Heat Pump", Power 1973 (Nov.), 24.
NA-187 National Economic Research Associates, Inc., Electric
Heating Versus Oil Heating in the Service Territory
of Long Island Lighting Company, 2 vols., 1973.
ST-186 Stanford Research Institute, Patterns of Energy Con-
sumption in the United S tates, Menlo Park, Ca.
Stanford Research Inst., 1972.
TI-026 A Time t£ Choose America's Energy Future, Ford Energy
Policy Project, Cambridge, Mass., Ballinger, 1974.
B-21
-------
APPENDIX C
MODULE DESCRIPTIONS
-------
APPENDIX C
TABLE OF CONTENTS
Page
I. INTRODUCTION C-l
II. EXTRACTION MODULES C-4
A. COAL MINING C-5
B. OIL SHALE MINING C-24
C. OIL WELL C-32
D. GAS WELL C-43
III. PROCESS ING/CONVERSION MODULES C-53
A. PHYSICAL COAL CLEANING C-54
B. CHEMICAL COAL CLEANING C-65
C. LOW BTU COAL GASIFICATION C-80
D. HIGH BTU COAL GASIFICATION C-102
E. COAL LIQUEFACTION C-136
F. SHALE OIL PROCESSING C-201
G. LIQUEFACTION SYN-CRUDE REFINERY MODULE C-254
H. DOMESTIC CRUDE REFINERY MODULE C-284
I. FOSSIL FUEL-FIRED STEAM ELECTRIC GENERATION C-315
*
IV. TRANSPORTATION MODULES C-336
A. RAILWAY C-337
B. PIPELINE C-351
V. END USE MODULES C-363
-------
I- INTRODUCTION
In this appendix, detailed discussions of the analyti-
cal procedures used to define individual module efficiencies
and environmental impacts are presented. In this introductory
section, some comments which apply to the module analysis effort
in general are discussed.
The documents which are presented here are organized
into four general groups: Resource extraction modules, pro-
cessing and conversion modules, transportation modules and end
use modules. Resource extraction modules are presented first
in Section II. Four modules are included in this group:
(1) coal mining,
(2) oil shale mining,
(3) crude oil production, and
(4) natural gas production.
Within several of these general categories, more than one
individual module unit is described. In the coal mining
document, for example, two different mining cases are considered.
In Section III, processing and conversion modules are
presented. These modules describe all of the processing steps
needed to convert resources into end use fuels.
In Section IV, transportation modules are discussed.
Included in this group of modules are descriptions of the
original steps involved in the transportation of both energy
resource raw materials and end use fuels. Two basic transporta-
tion modes are analyzed: (1) rail and (2) pipelines.
C-l
-------
End use modules are presented in Section V.
Module Basis
In order to provide a consistent basis for comparing
different types of energy resource extraction, processing, and
transportation operations, all module calculations described
here are based on the production of 1012 Btu/day of primary fuel
products. As an example of the utility of this approach, the
use of this consistent basis makes it possible to compare the
environmental impacts of crude oil production directly with the
impacts of producing an equivalent quantity of coal.
Module Efficiencies
In the modules considered in this study, three differ-
ent process efficiency terms are used. These efficiencies are
defined as
(1) Primary Fuels Efficiency
heating value of primary fuels produced
heating value of feedstock
(2) Total Products Efficiency
heating value of all products
_ (primary fuels 4- by-products)
heating value of feedstock
(3) Overall Efficiency
heating value of all products _
heating value of feedstock + ancillary energy
input to module
C-2
-------
The overall efficiency value represents the true
energy use efficiency.of the module since it accounts for all
materials entering and leaving the module. Overall module
efficiencies are therefore used to calculate total energy use
efficiencies for entire scenarios.
LandUse
Land use values calculated for each of the modules
represent the amount of land required by process facilities only,
Quantities of land which might normally be acquired and used as
"green belts" are not included in module land use estimates.
C-3
-------
APPENDIX C
II. EXTRACTION MODULES
A. Coal Mining
B. Oil Shale Mining
C. Oil Well
D. Gas Well
C-4
-------
APPENDIX C
II-A. COAL MINING
C-5
-------
II-A. Coal Mining
1.0 INTRODUCTION
Because such a large fraction of the coal found in
the western U.S. is contained in deposits which are close to the
surface, nearly all of the coal mined in this area is produced
by surface mining methods. In 1973 for example 95% of the coal
produced in the state of Wyoming was mined by surface methods
(NI-036). For this reason, the mining module which is assumed
to be representative of the current coal mining situation in
the western states is a surface mining module.
An alternative source of coal supply which is considered
here is the coal located in the midwestern state of Illinois.
This resource is assumed to be a viable alternative to the low
sulfur coal resources of the western U.S. primarily because of
its proximity to the marketing area considered in this study
(Chicago).
Underground mining methods are widely used to extract
the coal resources of Illinois. In 1973, 53% of the coal
produced in Illinois was mined by underground methods with the
remaining 47% being produced by surface methods (NI-036). Due
to this slight majority in favor of the underground method of
mining, an underground mining module was developed for this
resource extraction case. This approach is also justified
because underground mining should account for an increasing
share of the coal mined in Illinois in future years.
Because of similarities in the methods used for the
analysis of both western and midwestern mining activities, both
of the mining modules developed for this study are documented in
this single writeup.
C-6
-------
II-A. Coal Mining
2.0 MODULE BASIS
In order to provide a consistent basis for the com-
parison of different types of resource extraction technologies,
all module calculations described here are based upon the produc-
tion of 1012 Btu/day of primary fuel product. For all of the
coal mining modules considered, the primary fuel product is
assumed to be run-of-mine coal.
Process efficiency and environmental impact data for
both mining modules studied are summarized in Tables 2-1 and 2-2,
The calculation procedures used to generate these data are dis-
cussed in Sections 3.0 and 4.0.
C-7
-------
II-A. Coal Mining
TABLE 2-1
SUMMARY OF ENVIRONMENTAL IMPACTS
WESTERN SURFACE MINING MODULE
(Module Basis: 1012 Btu/day Run-of-Mine Coal Produced)
Air (Ib/hr)
Particulates 779
S02 11.5
N0x 157
CO 95.3
HC 18.2
Water (Ib/hr)
Suspended Solids 0
Dissolved Solids 0
Organic Material 0
Thermal (Btu/hr) 0
Solid Wastes (tons/day) 0
Land Use (acres) 1700
Water Requirements (gal/day) 0
Occupational Health (per year)
Deaths 0.91
Injuries 34.1
Man-Days Lost 2252
Efficiency (7.)
Primary Fuel Efficiency 100
Total Product Efficiency 100
Overall Efficiency 99.6
Ancillary Energy (Btu/day) 4.3 x 109
C-8
-------
II-A. Coal Mining
TABLE 2-2
SUMMARY OF ENVIRONMENTAL IMPACTS
ILLINOIS UNDERGROUND MINING MODULE
(Module Basis: 1012 Btu/day Run-of-Mine Coal Produced)
Air (Ib/hr)
Particulates 0
S02 0
N0x 0
CO 0
HC 0
\
Water (Ib/hr)
Suspended Solids 0
Dissolved Solids 0
Organic Material 0
Thermal (Btu/hr) 0
Solid Wastes (tons/day) 99.3
Land Use (acres) 12900
Water Requirements (gal/day) 0
Occupational Health (per year)
Deaths 4.0
Injuries 402
Man-Days Lost 1.48 x 101*
Efficiency (%)
Primary Fuel Efficiency 100
Total Product Efficiency 100
Overall Efficiency 99
Ancillary Energy (Btu/day) 1.0 x 1010
C-9
-------
II-A. Coal Mining
3.0 MODULE DESCRIPTIONS
In this section, the process features which distinguish
the two mining modules considered here are discussed. In general,
mining methods can be broken down into two basic classes: surface
and underground methods. Each of these classes will be discussed
separately.
3.1 Surface Mining ,
Surface mining is a general term which refers to any
mining method involving the removal of surface material (over-
burden) to expose an underground resource deposit. Open-pit
mining, strip mining, and auger mining are the three basic types
of surface mining techniques.
Open-pit mining is commonly used in the metals in-
dustry to mine deep, very thick deposits of ore. Strip mining
is used to extract thin deposits of a raw material lying gen-
erally within about 100 feet of the surface (200 ft. maximum for
very thick deposits).
There are two major types of strip mining techniques
which are currently practiced in this country. Contour stripping
is a technique used to extract strippable coal resources found
in mountainous terrain. Auger mining is generally employed in
conjunction with a contour stripping operation. Since these two
mining methods are not widely used outside of the Appalachian
coal region of this country, they are not given any further con-
sideration here.
Area stripping is the name given to the mining techni-
que which is commonly used to extract the strippable coal resources
C-10
-------
II-A. Coal Mining
of the western and midwestern states. The basic steps involved
in an area stripping operations are shown in Figure 3-1.
RZCtAIMSD
WATER
Figure 3-1. STEPS INVOLVED IN AREA STRIPPING OPERATION
Topsoil and overburden are first removed and placed in
separate storage areas. After the exposed coal seam is mined,
overburden and topsoil are replaced and reclamation activities
begin.
In an established strip mine, both mining and reclama-
tion activities take place on a simultaneous, continuous basis,
as shown in Figure 3-2.
In addition to the mine site operations just described,
major facilities found at a typical strip mine will include:
haulage roads, run-off water collection and treatment facilities,
a crushing and sizing plant, and loading facilities. In this
C-ll
-------
II-A. Coal Mining
t
Direction
of Mining
Topsoil
Removal
Grading
and Topsoil
Replacement
Revegetation
Overburden
Removal
Extraction of
Coal Seam
Overburden
Replacement
Boundary of
Area to be Mined
Figure 3-2. Schematic Aerial View of Area Stripping Operation
C-12
-------
II-A. Coal Mining
study, the mining module is assumed to include all the steps
necessary to~ prepare coal for subsequent processing or trans-
portation steps.
3.2
Underground Mining
Underground mining is a term which applies to mining
methods which involve the construction of a tunnel or shaft to
access an underground resource deposit. Once this access shaft
is established, mining of' the deposit can be attempted by any
one of several means. Room and pillar and longwall mining are
the two most commonly used underground methods.
In room and pillar mining, pillars of coal are left in
place at appropriate intervals within the mine to provide roof
support. In longwall mining, a seam of coal several hundred
feet in width is mined continuously by a machine which provides
its own roof support. As this machine moves through the coal
seam, the mine roof is allowed to cave in behind the machine.
Schematic views of these two mining techniques are shown in
Figure 3-3.
ACCESS TUNNELS
COAL
PILLAR
DIRECTION OF
MINING
ROOM AND PILLAR
LONGWALL
FIGURE 3-3
UNDERGROUND MINING METHODS
C-13
-------
II-A. Coal Mining
Coal produced in underground mines is normally brought
to the surface by either rail or conveyor belt. Surface process-
ing facilities for underground mines are similar to those re-
quired by typical surface mining operations.
3-3 Ancillary Energy
The ancillary energy requirements reported by Hittman
(HI-083) for the two mining operations considered in this study
are summarized in Table 3-1.
According to Hittman, surface mining operations typically
use a mixture of diesel and electrically-powered equipment, while
underground mining operations are normally completely electrified.
It is significant to note here that the western surface mining
module requires considerably less ancillary energy than the
Illinois underground mining module.
3.4 Module Efficiencies
There are several ways to define an extraction module
efficiency. Hittman's module efficiencies are calculated in
such a way that the recovery efficiency of the mining step is
included in the overall module efficiency. On this basis, a
surface mining module efficiency of about 90% and an underground
mining module efficiency of about 65% are obtained. This
approach is proper if one seeks to compare the resource recovery
efficiencies of different types of extraction methods. In this
study, however, extraction module efficiencies are defined in a
different fashion.
C-14
-------
II-A. Coal Mining
TABLE 3-1
ANCILLARY ENERGY REQUIREMENTS OF TYPICAL WESTERN
AND MIDWESTERN MINING OPERATIONS1
(Basis: 1012 Btu Coal Extracted)
Western Surface
Operation Electricity Diesel Fuel Total'
Mining
Hauling
Crushing
Reclamation
Total 2.78 x 10s 10160
(kwhr)
,
1,
96
82
x 10s
x 10s
(gal)
6410
1400
2290
60
(Btu)
18.
1.
21.
.
7
9
8
1
x
X
X
X
10 8
108
108
108
42.5 x 103
Illinois Underground
Mining 8.2 x 10s
Crushing 1.8 x 10s
Water Treat. .2 x_105
Total 10.2 x 10s
8.3 x 109
1.9 x 109
. ,2 x 109
10.4 x 109
-Source: (HI-083)
"Diesel Fuel: 5.8 x 106 Btu/bbl; 42 gal/bbl
Electricity: Converted at three times the electrical
equivalent (3413 Btu/kwhr) of kwhr figure shown. Elec-
trical generation losses are thus charged against the
end user.
C-15
-------
II-A. Coal Mining
Mining processes are inherently inefficient from a
resource recovery point of view since it is impossible to recover
100% of any in-place resource. In one sense, it is accurate to
say that a, resource which cannot be recovered is not really a
useful resource in the first place.
Since the maximum energy available from an extraction
module is equal to the output of the module, the primary fuel
production efficiency and total product efficiency of both mining
modules considered here were defined to be 100%. This efficiency
definition is consistent with that used by Battelle (BA-230)
in a similar study of this nature.
Based on ancillary energy requirements of .4 x 1010
Btu/1012 Btu coal extracted, an overall efficiency of 99.6% is
obtained for a western surface mining operation. Ancillary
energy requirements of an Illinois underground mining operation
are shown to be 1.0 x 1010 Btu/1012 Btu coal extracted. As a
result, an overall efficiency of 99% is obtained for the Illinois
underground mining module.
3.5 Land Usage
The mining statistics shown in Table 3-2 were used to
calculate the amount of land which must be disturbed in order to
produce 1012 Btu/day of coal.
C-16
-------
II-A. Coal Mining
TABLE 3-2
HITTMAN MINING STATISTICS"
Heating Value of Coal
Mined (Btu/lb)
Coal Seam Thickness (ft)
Overburden Thickness (ft)
Average Recovery of In-
Place Coal (%)
Land Disturbed or Under-
mined During the Pro-
duction of 1012 Btu
Coal Product-^ (acres)
Western
Surface
8780
39
60
98%
0.845
Illinois
Underground
ll.OOO2
6.8
57% (85%)4
6.65 (4.46)
Source: (HI-083)
9
Calculated average of two typical coal analyses given by
Hittman
O
Assumes coal density of 81 lb/ft3
See discussion below.
These figures show that, for a typical western strip mine,
due to the thickness of the coal seam involved, less than an
acre of land is disturbed to produce 1012 Btu of run-of-mine
coal. For Illinois coal, between four and seven acres are under-
mined to produce 1012 Btu of coal product, depending on the mining
method used.
It should be noted here that different average heating
values were quoted by Hittman in certain cases where it would
be expected that the same "typical" coal analysis would apply.
C-17
-------
II-A, Coal Mining
In Hittman's analysis of coal processing operations (gasification,
liquefaction, etc.) for example, a western coal having a heating
value of 8806 Btu/lb was used as the basis for describing process
facility impacts. This value obviously differs somewhat from
the data point shown in Table 3-2 above. Discrepancies of this
nature x^ere generally ignored in subsequent phases of this
analysis because no significant changes in module impact parame-
ters would have resulted from an attempt to resolve these dis-
crepancies .
The two recovery figures shown in Table 3-2 for the
Illinois underground mining case can be explained as follows.
The 577o recovery figure is a national average value for room-
and-pillar mining. As explained in Section 3.2, this figure
applies to a situation in which significant quantities of coal
are left in place in the mine to provide roof support. For the
ideal case, negligible disturbance of surface land results from
this approach to underground mining. In practice, the amount of
subsidence which actually occurs is a complex function of a
variety of factors including:
1) the geological characteristics of the mine
itself, and
2) the specific mining procedures used in each
case.
Recovery of in-place coal in a longwall mining opera-
tion averages 85% according to Hittman. The values shown in
parentheses in the last column of Table 3-2 apply to the case
in which longwall mining methods are assumed to be used.
C-18
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II-A. Coal Mining
Because the land use figures shown in Table 3-2 for the
room-and-pillar mining case are the most conservative of the two
situations considered, the room-and-pillar figure was used in
subsequent calculations of underground mining impacts.
In addition to the mine site itself, land requirements
for a mining operation will include the space occupied by process-
ing and loading facilities. Estimated land requirements for
typical western and Illinois mining operations are summarized
in Table 3-3.
TABLE 3-3
LAND REQUIREMENTS FOR TYPICAL WESTERN AND ILLINOIS OPERATIONS
PRODUCING 1012 BTU/DAY RUN-OF-MINE COAL1
Western Illinois
Surface Underground
Mine Site:
Active Working Area 84
Land Being Reclaimed 1541
Haulage Road 10
Processing and Loading _ 75
Total 1700 12864
All figures are acres of land required.
The land area designated in Table 3-3 as the active
working area was assumed to be equal to the land disturbed or
undermined in 100 days of mining activity (based upon the figures
calculated in Table 3-2). For the surface mining case, this
implies that reclamation activities were assumed to commence
100 days after the topsoil and overburden removal steps were
C-19
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II-A. Coal Mining
initiated in any given location. Reclamation land requirements
were determined by assuming that five years are required to estab-
lish a plant cover in semi-arid western lands and three years
are required to do so on land disturbed by mining in Illinois.
Also, an additional two years were allocated to the Illinois
underground mining case to allow for subsidence prior to the
start of reclamation activities. The haulage road requirement
for surface mining was taken from Hittman (HI-083). Land allo-
cated to this usage in the underground case was assumed to be
equal to the surface mining requirement, even though trains or
conveyors would normally be used for mine-to-tipple transporta-
tion in an underground mining operation instead of trucks. The
75 acres allocated to above-ground processing facilities (crush-
ing, loading, and water treatment) in both cases was an assumed
figure.
3.6 Water Requirements
The only process water requirements of the mining
operations considered here would consist of the water used for
dust control in the crushing plant and along haulage roads. All
of the water required to satisfy these demands is assumed to be
available in the form of reclaimed water collected as mine drain-
age or surface run-off. For this reason, no water requirements
are shown for the modules in Tables 2-1 or 2-2. It should be
noted, however, that water requirements for effective reclamation
are not considered here. Particularly in the case of western
surface mining, reclamation water requirements may be significant
(NA-172).
3.7 Occupational Health
The occupational health statistics shown in Tables
2-1 and 2-2 are taken directly from Hittman (HI-083).
G-20
-------
II-A. Coal Mining
4.0 MODULE EMISSIONS
The types of emission sources considered in the mining
module analysis effort discussed here include:
1. air,
2. water, and
3. solid waste.
Each of these different emission categories will be discussed
in separate subsections below.
4.1 Air Emissions
Major sources of air emissions found within a typical
strip mining operation include:
particulate emissions from solids handling operations
topsoil and overburden removal
coal mining
coal crushing
air emissions from diesel powered mining equipment.
Particulate emissions from solids handling operations were deter-
mined from EPA emission factors for mining and quarrying opera-
tions. Emissions from diesel-powered mining equipment were also
calculated by using EPA emission factors for the diesel fuel
quantities specified in Section 3.3 of this writeup. A summary
of the air emission calculations performed for the surface
mining module, considered is presented in Table 4-1. Underground
mining module air emissions are shown to be negligible since
the use of all electric equipment is assumed
(no diesel engine emissions)
C-21
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II-A. Coal Mining
TABLE 4-1
SURFACE MINING MODULE
SUMMARY OF AIR EMISSION CALCULATIONS
Basis: 1012 Btu Coal Extracted/Day
(Emission Rates in Ib/hr)
Western Surface:
Overburden Handling
2
Wind Erosion
3
Mining Equipment
Coal Handling
Coal Hauling (trucks)
3
Storage & Crushing
Total
Part.
SO,
CO
HC
NO
460
75.
3.
238
.
1.
3
5
8
2
7.
1.
2.
3
6
6
60.
13.
21.
7
1
5
11.
2.
4.
6
5
1
99.
21.
35.
7
6
3
778.8 11.5 95.3 18.2 156.6
Calculated from:
a. EPA emission factors for quarrying operations (0.1 Ib/ton
mined) from (EN-071), and
b. data presented in Table 3-2 assuming overburden density
of 100 lb/ft3 and coal density of 81 lb/ft3.
"From (HI-083; footnote 1207) - 428 Ib particulates/ac-yr from
unreclaimed land.
From EPA emission factors for diesel-powered internal combustion
engines and diesel fuel consumption data in Table 3-1.
C-22
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II-A. Coal Mining
particulates generated during the mining and
crushing steps are assumed to be captured using
an efficient ventilation/filtering system.
4.2 Water Effluents
All mine drainage and surface runoff is assumed to be
collected, treated, and used to satisfy mining operation water
demands (dust suppression). No effluent discharge streams are,
therefore, anticipated.
Since no water effluents were assumed, thermal discharges
are also shown to be zero in Tables 2-1 and 2-2.
4.3 Solid Wastes
No solid wastes were assumed to be generated as a result
of surface mining operations since waste solids can be returned
to the mine and disposed of along with overburden material.
Mine disposal of underground mining refuse is generally not prac-
ticed. According to Hittman (HI-083; footnote 1350) solid wastes
are produced in an Illinois underground mining operation at a rate
of 99.3 tons per 1012 Btu coal extracted.
C-23
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APPENDIX C
II-B. OIL SHALE MINING
C-24
-------
.. II-B. Oil Shale Mining
1.0 INTRODUCTION
Depending upon the physical characteristics at the
particular oil shale site, oil shale may be mined by either
surface or underground methods. Most actual experience in oil
shale mining involves underground mining. Underground mining
techniques are more universally applicable to the various oil
shale deposits than surface mining, and as a result will be
extensively utilized in the development of a shale oil industry.
The Bureau of Mines has demonstrated the feasibility of roota-
and-pillar mining for oil shale at its facility near Rifle,
Colorado.
Underground extraction is capable of removing approxi-
mately 65% of the shale from a typical mine (HI-083). A typical
underground oil shale mine will supply enough shale to produce
50,000 BPD* upgraded oil. This production rate requires the
excavation of approximately 70,000 TPD of raw shale.
Due to the large quantity of solids involved with oil
shale mining, one of the major problem areas is solid waste
disposal and land requirements. Fixed land requirement for an
underground mine is only about 10 acres of surface land; however,
land must be available for disposal of both the overburden from
the mine opening and spent shale from the retort (assuming spent
shale is disposed of at the mine site). With compacting, it is
estimated that about 60% of the spent shale can be returned under-
ground. The remaining 40% must be disposed of on the surface
(US-093).
All rates in calendar days.
C-25
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II-B. Oil Shale Mining
2.0 MODULE BASIS
This module is based on a raw shale production (after
crusher) of 1012 Btu/day. Using a 30-gallon per ton grade of
shale with a heating value of 3765 Btu/lb, a module producing
132,800 TPD raw shale is defined. Calculated emissions from this
module are summarized in Table 2-1.
C-26
-------
II-B. Oil Shale Mining
TABLE 2-1
SUMMARY OF ENVIRONMENTAL IMPACTS
UNDERGROUND OIL SHALE MINING
Basis: 1012 Btu Raw Shale Produced/Day
Air (Ib/hr)
Particulates 64
S02 0
N0x 0
CO 0
HC 0
Water (Ib/hr)
Suspended Solids 0
Dissolved Solids 0
Organic Material 0
Thermal (Btu/hr) 0
Solid Wastes (tons/day) 0
Land Use (acres) 1590
Water Requirements (gal/day) 0
Occupational Health (per year)
Deaths 1.53
Injuries 70.0
Man-Days Lost N/A
Efficiency
Primary Fuels Efficiency 100.0
Total Products Efficiency 100.0
Overall Efficiency 99.5
Ancillary Energy (Btu/day) 5.35 x 109
N/A - .not available
C-27
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II-B. Oil Shale Mining
3.0 MODULE DESCRIPTIONS
The underground oil shale module described here is
assumed to utilize a room-and-pillar mining technique to ex-
tract the raw shale. The shale is transported from the mine
to the crushers by a conveyor. The crushing step consists of
primary, secondary, and tertiary crushing operations. Screen-
ing and briquetting operations are also included with the
crushing step. A 1012 Btu/day output of raw shale from
the crushers is equivalent to a production of 132,800 TPD raw
shale. Approximately 1828 TPD of rock and roughage are sep-
arated at the crushers and disposed of at the mine site.
Spent shale from the retort (164.3 x 103 TPD) is also considered
to be returned to the mine for disposal. Approximately 60%
of the spent shale can be returned to the mine. The remain-
ing shale must be 'disposed of on the surface.
3.1 Module Efficiencies
As discussed in the coal mining module description
document, the primary fuel and total product efficiencies of
all extraction modules are defined to be 100%. This defini-
tion results from the fact that the maximum energy available
from an energy supply scenario is the output of the extraction
step. Ancillary energy requirements for an oil shale mining
operation result from mining, hauling, and crushing activi-
ties. These ancillary energy requirements, shown in Table 3-1,
are adjusted from values presented in the Hittman report (HI-
083) to represent a mining module producing 1012 Btu of raw
shale (after crushing). Mining energy requirements were
determined from the following values:
mining - 4200 kwhr/hr for extracting 73,700
TPD shale
C-28
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II-B. Oil Shale Mining
conveying - 2.55 x 10s kwhr for conveying
1012 Btu shale 1 mile
crushing - 2090 kwhr/hr for crushing
73,700 TPD shale
If these values are used to calculate the ancillary
energy requirements of an underground mine producing 1012 Btu/
day of crushed shale, the results shown below are obtained.
TABLE.3-1
ANCILLARY ENERGY REQUIREMENTS .OF...AN
UNDERGROUND OIL SHALE MIMING MODULE
Operation
Mining
Hauling
Crushing
Total
ElectricjLty
7676 kwhr/hr
2.59 x 10 kwhr/ 10 12
3820 kwhr/hr
Total
(Btu)
18.4 x 108
Btu 25.9 x 108
9.17 x 108
53.5 x 108
When these ancillary energy requirements are considered, the
overall efficiency of the underground module is calculated to
be 99.5%.
3,2 Water Requirements
Water requirements for this module (exclusive of
reclamation) are zero if water used for dust or particulate
control is supplied by water collected in excavated areas.
The variable climate of the areas underlain by oil shale, and
the lack of conclusive data based on actual revegetation
efforts in these areas make it impossible to predict the
amounts of water needed for reclamation. Preliminary experience
C-29
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II-B. Oil Shale Mining
with revegetating spent shale, and the experience of the coal
industry in semi-arid regions, suggest that water requirements
for effective revegetation will be significant.
3.3 Land Requirements
Land requirements for this module were determined
from estimates for an underground mine supplying shale for a
50,000 BPD shale oil facility (US-093). An estimate of the
land impact is as follows:
(1) mine development: 20 acres
(2) solid waste disposal assuming 60% return
of processed shale underground: 51 acre/year
(3) crushing facilities: 40 acres
Assumine a thirty-vear mine life, the total land impact is
1590 acres.
3.4 Occupational Health
Occupational health information was obtained from
the Hittman Study (HI-083). The basis for the values shown
in Table 2-1 is a ten-year period of underground mining when
2919 accidents and 63.9 fatal accidents occurred. The data
presented in the table have been converted to a 1012 Btu/day
output basis.
C-30
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II-B. Oil Shale Mining
4.0 MODULE EMISSIONS
4.1 Air Emissions
The only air emissions from the underground mining
module are assumed to be particulates from the crushing
operation. From the Environmental Statement for the Prototype
Oil Shale Leasing Program (US-093), a value of 35 Ib/hr particu-
lates for a plant producing 72,700 TPD is extrapolated to 64
Ib/hr for the 1012 Btu/day output module.
4.2 Water Effluents
No water discharges should result from this module
since mine water can be used for dust or particulate control
with any excess routed to an evaporation pond.
4.3 Thermal
No thermal discharges to surrounding water bodies
result from this module since all water is contained.
4.4 Solid Wastes
Although large amounts of solid wastes are generated
by the module, none of the solid wastes leave the module
boundaries. Overburden, spent shale, and waste from the
module are disposed of within the module. As a result, the
solid waste for the module is zero. However, the area
necessary to contain the solid waste is reflected in the land
impact. The underground mine requires 1590 acres, assuming
60% disposal underground.
C-31
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APPENDIX C
II-C. OIL WELL
C-32
-------
II-C. Oil Well
1.0 INTRODUCTION
Crude oil production can result in three main hydro-
carbon products: crude oil, dry natural gas, and natural gas
liquids. The oil is composed chiefly of saturated hydrocarbons
together with small amounts of organic compounds containing
sulfur, nitrogen, and oxygen. The composition is approximately
83-87% carbon, 11-14% hydrogen, 0.05-2% sulfur, 0.1-2% nitrogen,
and 0.2% oxygen (CH-182). In 1973 there were 497,378 producing
oil wells in the United States yielding a daily average of 9.2
x 106 barrels (AM-099).
Oil wells normally utilize one of three methods to
bring oil to the surface. These methods are natural flow, gas
lifting (injection of gas into the flowing columns), and pump-
ing. Most producing wells are operated by mechanical lifting
methods using subsurface pumps of either a plunger or centri-
fugal type.
Operations typically involved with crude oil produc-
tion include the following:
(1) extraction of the oil at individual wells,
(2) combination of the oil at a gathering station,
(3) separation of the water from the oil,
(4) disposal of the water by reinjection (either
into the producing formation to maintain
reservoir pressure or into an abandoned
formation) or by routing to a containment/
evaporation pond,
C-33
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II-C. Oil Well
(5) separation of gas from the oil,
(6) transfer of the gas to a pipeline or
reinjection for pressuring,
(7) transfer of the crude oil to product
tankage.
The processing sequence used at a specific oil produc-
tion site will vary depending on a variety of factors. As an
example, gas may be separated at the well, the gathering station,
or at the refinery. Crude quality and refinery proximity have
a significant effect upon the operations that are performed at
the well site.
C-34
-------
II-C. Oil Well
2.0 MODULE BASIS
The oil well module is based on a crude production
rate of 1012 Btu/day*. Using a heating value of 5.6 x 106 Btu/
bbl for domestic crude (BA-230), a module producing 178,571 BPD
is defined. A summary of calculated emissions from the module
is presented in Table 2-1.
*
All rates in this module refer to calendar days
C-35
-------
II-C. Oil Well
TABLE 2-1
SUMMARY OF ENVIRONMENTAL IMPACTS
OIL WELL
Basis: 1012 Btu/Day Crude Oil Produced
Air (Ib/hr)
Particulates 0.144
S02 0.196
N0x 0.25
CO 0.025
HC 54.4
Water (Ib/hr)
Suspended Solids 0
Dissolved Solids 0
Organic Material 0
Thermal (Btu/hr) 0
Solid Wastes (tons/day) 0
Land Use (acres) 1000
Water Requirements (gal/day) 0
Occupational Health (per year)
Deaths 0.803
Injuries 76.7
Man-Days Lost 12800
Efficiency (%)
Primary Fuels Efficiency 100
Total Product Efficiency 100
Overall Efficiency 100
Ancillary Energy (Btu/day) 0
C-36
-------
II - C. Oil Well
3.0 MODULE DESCRIPTION
Although many operations are involved with the produc-
tion of crude oil including exploration, drilling, and production,
this module represents only the producing well. Emissions
resulting from preceding phases of oil production are not con-
sidered. This module describes an oil field producing 1012 Btu/
day of crude oil. For domestic crude averaging 5.6 x 106 Btu/bbl,
a 1012 Btu/day production is equivalent to 178,571 BPD. A
separation step for light hydrocarbons is not considered here.
Also, since gas is assumed to be reinjected, the only product
which is assumed to be obtained from the module is crude oil.
3.1 Processing Sequence
The module processing sequence considered here involves
the following steps:
(1) extraction (individual wells)
(2) gathering
(3) water separation and reinjection
(4) gas separation and reinjection
(5) transportation to storage
(floating roof tanks).
A block flow diagram of this processing sequence is shown in
Figure 3-1.
C-37
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II-C. Oil Well
OIL WELLS
GATHERING
SYSTEM
WATER
SEPARATION
CAS SEPARATION
TO STORAGE
OIL
WATER REIHJECTIOH
CAS REISJECTIOH
FIGURE 3-1
OIL WELL MODULE
C-38
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II-C. Oil Well
3.2 Module Efficiencies
As discussed in the coal mining module writeup, the
primary product and total product efficiencies of all extraction
modules developed for this study are defined to be 10070.
Since the ancillary energy requirements of a typical
oil production operation are negligible, the overall efficiency
of this module is also shown to be 100%.
3.3 Water Requirements
Due to a lack of on-site processing water needs, no
make-up water is assumed to be required by this module.
3.4 Land Use
Land use is determined from data in the Mineral
Industry Survey (US-130). Using a Texas Gulf Coast average
well production of 44.8 bbl/well-day, the number of wells
required to produce 1012 Btu (178,571 bbl) per day is 3,986
wells. Assuming 1/4 acre per well (BA-230), the land require-
ment for this module is approximately 1,000 acres.
3.5 Occupational Health
Occupational health data were derived from information
presented in a report by Battelle (BA-230).
C-39
-------
II-C. Oil Well
4.0 MODULE EMISSIONS
4.1 Air Emissions
Air emissions from this module are considered to
result from miscellaneous flaring and storage losses. Miscellan-
eous flaring is estimated to occur to an extent of about 2 x 10~5
bbl/bbl crude oil (BA-230). EPA fuel combustion factors for
residual oil were used to determine the resulting emissions (EN-
071). These factors are shown in Table 4-1.
TABLE 4-1
EMISSION FACTORS FOR RESIDUAL
OIL COMBUSTION (EN-071)
Particulate SOX CO HC N0x Aldehyde
lb/103 gal. 23 157 x S* 3 4 40 1
~v
S - wt. % sulfur in the oil
An average Gulf Coast crude sulfur content of 0.2 wt. % S was
used (NE-044) for the S02 emission rate calculation. Aldehyde
and hydrocarbon emissions were combined to give total organic
emissions. These emissions are estimated to occur approximately
fifty feet above the ground. Emissions from crude oil storage
were determined by assuming the use of floating roof tanks and
a six-day storage capacity. Using the EPA emission factor for
crude oil storage in a floating roof tank (0.029 Ib/day per 103
gal), a hydrocarbon emission rate of 54.4 Ib/hr is calculated.
A summary of calculated air emissions for the module is pre-
sented in Table 4-2.
C-40
-------
II-C. Oil Well
TABLE 4-2
AIR EMISSIONS
OIL WELL MODULE
Basis: 1012 Btu/Day Output Crude Oil
Total
Particulates SO Organics CO NO
Miscellaneous
Flaring (Ib/hr) 0.144 0.196 0.025 0.025 0.25
Crude Oil
Storage (Ib/hr) 54.4
Total (Ib/hr) 0.144 0.196 54.4 0.025 0.25
C-41
-------
II-C. Oil Well
4.2 Water Pollution
All water separated from the oil is considered to be
reinjected for pressure control or returned to an abandoned
formation for disposal. No water pollution is considered to
result from this module. An estimated 33% of the oil produced
in the United States in 1965 was extracted with the aid of water
flooding enhancement techniques. It is further estimated that
by 1980, 50% of the United States'"oil will be produced"from
formations stimulated by water flooding (CH-182).
4.3 Thermal Pollution
No thermal pollution to water bodies results from
this module.
4.4 Solid Waste
No solid wastes are generated by the oil well module.
C-42
-------
APPENDIX C
II-D. GAS WELL
C-43
-------
II-D. Gas Well
1.0 INTRODUCTION
This section describes Radian Corporation's module for
the production and processing of pipeline natural gas. The
majority of the data used to define this module is taken from
a report prepared by Hittman Associates for the Council on
Environmental Quality (HI-083). When necessary, corrections or
additions are made to Hittman's data using best available data
and engineering judgment. While Hittman's data are based on an
input of 1012 Btu of natural gas, an output basis is more appro-
priate for this study. Hittman's data were easily transformed
to an output basis by dividing by the process efficiency.
C-44
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II-D. Gas Well
2.0 MODULE BASIS
The natural gas production and processing module
described here is based on a system capable of producing 1012
Btu/day of pipeline quality natural gas. The methodology used
to calculate module emissions and impacts is the same as that
employed by Hittman (HI-083).
The only source of wellhead natural gas considered
in this module is Texas Gulf Coast gas. The important character-
istics of the raw gas are listed in Table 2-1. Table 2-2 lists
the module emissions and impacts which are expected to occur
from the production and processing of this natural gas.
TABLE 2-1
IMPORTANT CHARACTERISTICS OF THE RAW GAS
Texas Gulf Coast Gas
C02 12 mole percent
H2S 20 grains per 100 SCF
Heating Value 880 Btu/SCF
C-45
-------
II-D. Gas Well
TABLE 2-2
SUMMARY ,OF ENVIRONMENTAL IMPACTS
PRODUCTION AND PROCESSING OF NATURAL GAS FROM
TEXAS GULF COAST GAS SOURCES
Basis: Production of 1012 Btu/day of Natural Gas
Air (Ib/hr)
Particulates 52.2
S02 166
NOX 2090
CO 59.1
HC 81,700
Water (Ib/hr)
Suspended Solids 0
Dissolved Solids 0
Organic Material 0
Thermal (Btu/hr.) 0
Solid Wastes (tons/day) 0
Land Use (acres) 12,150
Water Requirements (gal/day) 0
Occupation Health (per year)
Deaths 0.81
Injuries 77
Man-Days Lost 12,700
Efficiency (%)
Primary Products Efficiency 100
Total Products Efficiency 100
Overall Efficiency 100
Ancillary Energy (Btu/day) 0
C-46
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II-D. Gas Well
3.0 MODULE DESCRIPTION
3.1 Processing Steps
There are several processing steps necessary to pro-
duce pipeline quality natural gas from a well. The first step
is production of the crude gas from the well. The output
of many wells is piped to a central treating plant where the
natural gas liquids are removed. An acid gas removal unit is
then utilized to reduce the C02 and H2S concentrations of the gas
to levels that will meet federal natural gas regulations. The
H2S removed is subsequently recovered in a Glaus plant. Finally,
the cleaned natural gas is compressed and injected into a
transmission pipeline. Figure 3-1 shows the steps involved in
a natural gas production and processing system.
3.2 Products and By-products
A natural gas processing plant will produce natural
gas liquids in addition to pipeline quality natural gas. These
liquids may contain hydrocarbon compounds from C3's to Cs's and
are usable as fuels or chemical feedstocks. The Glaus unit will
produce a saleable sulfur by-product and is assumed to have a
94% sulfur recovery efficiency.
3.3 Ancillary Energy Requirements
From Hittman (HI-083), the ancillary energy require-
ments of a natural gas plant are 1.63 x 1015 Btu per 1.95 x 1016
Btu of production. On a 1012 Btu/day output basis this gives
the ancillary energy requirements as 8.36 x 1010 Btu/day. How-
ever, since this energy would normally come from burning product
natural gas, ancillary energy requirements for this module are
considered to be zero.
C-47
-------
GAS PROCESSING PLANT
o
i
-P-
co
FUGITIVE LOSSES
GAS WELL
PUMPING
STATIONS
NATURAL GAS
LIQUIDS
REMOVAL
L.
NATURAL GAS
LIQUIDS
FLARE
SULFUR
RECOVERY
ACID GAS
REMOVAL
1
-*- SULFUR
NATURAL GAS
COMPRESSION
f
TO
IPELINE**'
M
I
t)
O
03
w
FIGURE 3-1
FLOW DIAGRAM OF NATURAL GAS PRODUCTION AND PROCESSING SYSTEM
-------
II-D. Gas Well
3.4 Efficiency
In keeping with conventions established for this
study, the primary product and total product efficiencies
of the gas well module are defined to be 100%. While Hittman
defines a production efficiency of less than 100% (based on loss
of some natural gas from the wellhead), Radian assumes that the
production step is 100% efficient. Fugitive well losses are
treated only as air emissions. Likewise, product natural gas
which is consumed as fuel for gas processing operations is
treated as a necessary loss incurred as a result of gas pro-
duction activities. Since there is no ancillary energy re-
quired for this module and no by-products with a fuel value are
produced (natural gas liquids are assumed to be part of the
primary product), all the efficiencies are equal.
3.5 Land Usage
Land requirements for the gas production and processing
module were taken from Hittman (HI-083). According to Hittman,
an average gas well requires 8.9 acre-yr/1012 Btu. This is
equivalent to 3510 acres for the production of 1.08 x 1012 Btu/
day. (All equipment must handle 1.08 x 1012 Btu/day - 8.36 x 1012
Btu/day is removed from the end product and used to meet the
process energy requirements.) Field and gathering pipelines,
including right-of-way, average 21.4 acre-yr/1012 Btu. This is
equivalent to 8440 acres for handling 1.08 x 1012 Btu/day.
Compression stations require 0.38 acre-yr/1012 Btu or 151 acres
for handling 1.08 x 1012 Btu/day. The gas processing plant re-
quires 50 acres. Therefore, total land requirements are 12,150
acres.
C-49
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II-B. Gas Well
3.6 Occupational Health
The data on injuries, deaths and man-days lost for
this module are taken directly from Battelle (BA-230). These
numbers are converted from Batelle's basis (production of 106
Btu of natural gas) to Radian's basis (production of 1012 Btu/day
of natural gas).
C-50
-------
II-D. Gas Well
4.0 MODULE EMISSIONS
4.1 Air Emissions
Air emissions from gas production and processing result
from fugitive losses at the wellhead, steam generation activities,
and the sulfur recovery unit. Wellhead losses were assumed to
be equal to 4.29% of production (HI-083). Steam generation air
emissions were calculated from the amount of natural gas burned
and emission factors from "Compilation of Air Pollutant Emission
Factors" (EN-071). Sulfur dioxide emissions from the sulfur
recovery plant were calculated assuming enough H2S is removed
from the gas to reduce the sulfur content to 2000 grains/106 ft3
and a Glaus unit sulfur recovery efficiency of 94%. Table 4-1
lists the individual sources and the quantities of air emissions
estimate to occur at each source.
In order to evaluate the effects that particulates,
S02, NO , CO and hydrocarbon emissions have on ambient air
X,
quality, it is necessary to define certain stack parameters
used in calculating ambient air conditions. Mass and volumetric
flow rates of each effluent stream were calculated from material
balances. Stoichiotnetric combustion was assumed with 25%
excess air for the steam generating facilities (75% for the sulfur
recovery flare). Volumetric flow rates were based on an assumed
exit gas temperature of 250°F. Stack heights, gas velocities
and exit temperatures were assumed, while stack diameters were
calculated from gas velocities and volumetric flow rates.
Table 4-1 lists the air emissions and stack parameters determined
for the individual emissions sources associated with this natural
gas production and processing module.
C-51
-------
TABLE 4-1
AIR EMISSION AND STACK PARAMETERS FOR GAS
PRODUCTION AND PROCESSING MODULE
BASIS: PRODUCTION OF 1012 BTU/DAY OF TEXAS GULF COAST NATURAL GAS
Source
1. Wellhead
2. Stear-
Generation
3. Acid Gas
Renoval Unit
TOTAL
Heat
Input
MMBtu/llr
3.480
45.100
Fuel
Natural
('as
Emissions Ibs/llr
Particulates
52.2
-
52.2
SOZ
2.09
164
166
Total
Organics
0.17x10*
3.48
-
8.17x10"
CO
59.1
-
59.1
NO,,
2090
-
2090
Stack Parameters
Mass
Flow
Iba/Hr
3.40x10'
7.16xl05
ACFM
1.06x10'
1.41xl05
Velocity
FPS
60
60
Height
Ft.
50
500
300
Temperature
°F
250
250
Diametei
Ft.
19.3
7.05
l-f
M
I
CO
(D
-------
APPENDIX C
III. PROCESSING/CONVERSION MODULES
A. Physical Coal Cleaning
B. Chemical Coal Cleaning
C. Low or Medium Btu Coal Gasification
D. High Btu Coal Gasification
E. Coal Liquefaction
F. Shale Oil Processing
G. Liquefaction Syn-Crude Refinery Module
H. Domestic Crude Refinery Module
I. Fossil Fuel-Fired Steam Electric
Generation
C-53
-------
APPENDIX C
III-A. PHYSICAL COAL CLEANING
C-54
-------
III-A.
Physical Coal Cleaning
1.0
INTRODUCTION
This section describes Radian Corporation's module for
the physical cleaning of Illinois coal. Physical coal cleaning
is a proven industrial technique used to remove portions of the
sulfur and ash contained in coal. While the sulfur present in
coal exists in both inorganic and organic forms, physical
cleaning is only effective in removing inorganic sulfur. In
addition to reducing the coal sulfur content, physical
cleaning results in an increase in the per pound heat content
of the coal due to the partial removal of ash.
Emissions and efficiency data for physical coal clean-
ing were prepared by Battelle (BA-230). For this study. Radian
used Battelle's method, although when necessary additions or
corrections were made using best available data and engineering
j udgment.
2.0
MODULE BASIS
The physical coal cleaning module is based on the
production of 1012 Btu/day of cleaned coal. Table 2-1 gives
the proximate and ultimate analyses of the Illinois coal
used.
C-55
-------
III-A. Physical Coal Cleaning
TABLE 2-1
PROXIMATE AND ULTIMATE ANALYSIS OF AN ILLINOIS COAL
Proximate Analysis
Ultimate Analysis
Ash
H20
Volatile Matter
Fixed Carbon
Sulfur
Heating Value
11
11
36
42
3.6
11,000
c
H2
N2
02
s
Ash
H20
61.0
5.2
1.4
6.8
3.6
11.0
11.0
100.0
Note: All numbers are wt. % except heating value which is Btu/lb coal.
C-56
-------
III-A. Physical Coal Cleaning
3.0 MODULE DESCRIPTION
Table 3-1 gives the emissions and impacts of the
physical coal cleaning module.
3.1 Processing Steps
The physical coal cleaning module in this study is
based on dense media washing. In this process, run-of-mine
coal is crushed to a top size of three inches and sent to a
dense media washing unit. In this unit the coal is separated
into two layers by washing with a liquid of 1.6 specific gravity.
The heaviest fraction, which contains the ash and refuse material,
is removed from the bottom of the unit. The "float material"
is removed and crushed to a top size of 3/8 inch. Screening
of this material yields 38 mesh x 0 and 3/8 inch x 30 mesh
fractions. The latter is sent to a dense media cyclone where
it is treated with a liquid of 1.35 specific gravity. The
float coal of density less than 1.35 from the dense media
cyclones is washed, wet ground to 30 mesh x 0 and centrifugally
dried. The 30 mesh x 0 fraction from the "float material"
screening is sent to a froth flotation unit where the fines are
frothed (after treating with alcohols, pine oil or kerosene to
render the coal particles nonwettable and to facilitate agglo-
meration) , skimmed, thickened and vacuum filtered. The two 30
mesh x 0 streams are combined to yield the physically cleaned
coal product.
Refuse from the process is collected and stored until
time of disposal. The liquid effluent streams, containing large
quantities of suspended solids, are sent to holding ponds where
the solids settle and the clear supernatant liquid is returned
to the process. Figure 3-1 is a block diagram of the physical
coal cleaning process.
C-57
-------
III-A. Physical Coal Cleaning
TABLE 3-1
SUMMARY OF ENVIRONMENTAL IMPACTS
PHYSICAL COAL CLEANING MODULE: ILLINOIS COAL
Basis: Production of 1012 Btu/Day of Physically Cleaned Coal
Air (Ib/hr)
Particulates 0
SO 2 0
N0x 0
CO 0
HC 0
Water (Ib/hr)
Suspended solids 0
Dissolved solids 0
Organic Material 0
Thermal (Btu/hr) 0
Solid Wastes (tons/day) 10,900
Land Use (acres) 170
Water Requirements (gal/day) 3.15 x 10s
Occupational Health (per year)
Deaths 1.43
Injuries 28.6
Man-Days Lost 12,700
Efficiency
Primary Product Efficiency 83.3
Total Product Efficiency 83.3
Overall Efficiency 83.1
Ancillary Energy (Btu/day) 3.06 x 10!
C-58
-------
o
Ul
vO
Run of
Coal
Mine
1
Breaker or
Crusher
,
Float Coal n»u!Lrln£8 3" x 3/8" > Impact
' Screens " '• ' ^™sner
i
Dense Media
Washer
Sp. sr. - 1.6
1
refi
,
,.. 0 Classifying
J/ 0 A U
'
Classifying
Screens
™ »..K . n , Sumo6"1"8 30 Mesh x (T Two Stage
* and Pumps ' Hydrocyclones
J I
3/8" x 30 mesh
,.. - V
Dense Media
Cyclones
sp. gr. - 1.35
,
1.6 x 1.351
sink Wet Grinding *> mesh x 0 Froth
- ' Mills * Clasiif iei Flotation
Units
-1.35 sp.gr.
Float Coal r
Centrifugal
Dryer
Vacuum
Filter
. 3/8" x 30 meoh , , 3/3
Figure 3-1
PHYSICAL COAL CLEANING PLANT PROCESSING SCHEME
> High Sulfur Rejects
M
. wTnlHrmn t— 1
W
p.
• y o Physically £,
Coal Product ^
tu
o
fD
s
-------
III-A. Physical Coal Cleaning
3.2 Ancillary Energy Requirements
The ancillary energy requirements for a coal cleaning
plant are given by Hittman (HI-083) as 2.55 x lO^tu/lO12Btu of
coal input. Converting to a 1012Btu/day output basis gives
ancillary energy requirements as 3.06 x 109Btu/day.
3.3 Products and By-Products
The composition of the physically cleaned coal product
is calculated from a mass balance around the cleaning plant and
the following assumptions:
(1) 20% of the coal is lost during cleaning (AV-003)
(2) 50% of the coal ash is removed
(3) the sulfur content of the coal is 3.6%, of
which 2.4% is inorganic sulfur and 1.2% is
organic sulfur
(4) 80% of the inorganic sulfur is removed
(5) no organic sulfur is removed
From the mass balance, it is calculated that the cleaned coal
heating value is 11,500 Btu/lb. On a 10 Btu/day output basis,
the amount of cleaned coal produced is 43,500 tons/day. No
by-products are produced from a physical coal cleaning process.
Table 3-2 shows the ultimate analysis of the physically cleaned
coal product.
C-60
-------
III-A. Physical Coal Cleaning
TABLE 3-2
ULTIMATE ANALYSIS OF A PHYSICALLY CLEANED ILLINOIS COAL
Ash 6.8
H20 11.5
E3 5.6
C ' 65.2
N3 1.1
03 7.7
S 2.1
Heating Value 11,500
Note: All numbers are wt 70 except heating value which is
Btu/lb coal.
C-61
-------
III-A. Physical Coal Cleaning
3.4 Raw Material Requirements
From Section 3.3 the amount of cleaned coal produced
is 43,500 tons/day. Based on an assumed loss of 20% of the
coal during processing, 54,400 tons/day is the coal feed rate.
The water requirements for a coal cleaning plant are
given by Battelle (BA-230) as approximately 1,750 gals/ton
of coal processed. For a 54,400 ton/day plant, 95.3 x 106 gals/
day is the water usage. Also from Battelle, approximately 3.3%
of the process water is consumed. This gives make-up water
needs as 2,190 G.P.M. or 3.15 x 106 gals/day for a plant capable
of producing 1012 Btu/day of cleaned coal.
3.5 Efficiency
In this study three different process efficiency terms
are defined for each module. These are the primary product
efficiency, the total product efficiency and the overall effi-
ciency. The primary product efficiency is defined as the energy con-
tent of the primary product divided by the energy content of the feed.
From Section 3.4 the amount of run-of-mine coal needed to pro-
duce 1012 Btu/day of physically cleaned coal is 54,400 tons/day.
At 11,000 Btu/lb of coal, this is equivalent to 1.20 x 1012 Btu/
day as feed to the plant. Thus, the primary'product efficiency
is 83.3%.
The total product efficiency is defined as the energy
content of all products and by-products divided by the energy
content of the feed. Since no by-products are formed during
physical coal cleaning, the total product efficiency is equal
to the primary product efficiency. The overall product effi-
ciency is defined as the energy content of all products and by-
products divided by the total energy input to the process, i.e.,
C-62
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III-A. Physical Goal Cleaning
feed and ancillary energy. For this process the overall
process efficiency is 83.1%.
3.6 Land Usage
From Battelle (BA-230) the land requirements for a
1000 ton/hr coal cleaning plant are 75 acres. Scaled to a
plant capable of treating 54,400 tons/day, the land requirements
are 170 acres.
3.7 Occupational Health
The data on injuries, deaths and man-days lost for
the physical coal cleaning module are taken directly from
Battelle (BA-230). These numbers are converted from Battelle's
basis of 106 Btu output to Radian's basis of 1012 Btu/day of
physically cleaned coal product.
C-63
-------
III-A. Physical Coal Cleaning
4.0 MODULE EMISSIONS
4.1 Air Emissions
Air emissions from the coal cleaning process are
limited to dust generated during coal handling. New coal
cleaning plants are assumed to be completely enclosed and to
utilize bag houses to control particulate emissions. Therefore,
negligible air emissions would be expected to result from phy-
sical coal cleaning.
4.2 Water Emissions
Water streams within the coal cleaning process may
contain high levels of suspended and dissolved solids. However,
all liquid waste streams are routed to holding ponds to allow
settling of the suspended solids. The clear supernatant liquid
is then recycled to the process. Thus, no liquid effluents
result from the cleaning process.
4.3 Solid Wastes
Solid wastes from the coal cleaning process come
from the 20% loss in process feed. For a feed of 54,400 tons/
day, 10,900 tons/day of solid wastes are generated. Since the
coal cleaning process is normally a mine mouth operation, it
should be possible to return all solid wastes to the mine for
disposal.
4.4 Thermal Discharge
Thermal discharges to water bodies are nonexistent
since no liquid streams leave the plant site.
C-64
-------
APPENDIX C
III-B. CHEMICAL COAL CLEANING
C-65
-------
III-B. Chemical Coal Cleaning
1-0 INTRODUCTION
The technology of chemically removing sulfur from
coal is still in a developmental stage. Bench and pilot scale
work has shown that almost 100% of the inorganic sulfur and up
to 50% of the organic sulfur can be removed, depending on the
type of chemical reagent employed. However, none of the process-
es has reached the commercial stage of development.
Since most of the chemical desulfurization processes
have been examined only on a small scale, the data necessary to
define this module are not readily available for many of the
processes. However, the Control Systems Laboratory of the U. S.
Environmental Protection Agency has completed bench scale work
on a chemical desulfurization process called the Meyers Process.
A preliminary design of a large pilot plant to test this pro-
cess has recently been published. Because of the availability
of this data, Radian chose to base its chemical desulfurization
of coal module on the Meyers Process.
The bench scale work on the Meyers Process was conduc-
ted on a high pyritic, low organic sulfur Appalachian coal.
Results showed high pyritic sulfur removal, but essentially no
organic sulfur removal, The developers of the process do not
claim its applicability to producing low sulfur coal from coals
with a high organic sulfur content. The feed for this module
is an Illinois bituminous coal containing 2.470 pyritic
sulfur and 1.2% organic sulfur. Therefore, the appropriate-
ness of using the Meyers Process for this particular application
may be questionable due to the high organic sulfur content of the
coal feed being considered.
C-66
-------
III-B. Chemical Coal Cleaning
2.0 MODULE BASIS
For this study the environmental impacts resulting
from the chemical desulfurization of coal are based on the
production of 1012 Btu/day of desulfurized coal. The data needed
to develop material balances for this size facility are taken
from a report on the Meyers Process by L. Lorenzi Jr. (LO-096).
Table 2-1 gives the proximate and ultimate analyses of the
Illinois coal which is assumed to be used as plant feed and
Table 2-2 gives the overall plant material balance.
C-67
-------
III-B. Chemical Coal Cleaning
TABLE 2-1
PROXIMATE AND ULTIMATE ANALYSES OF A TYPICAL ILLINOIS COAL
Proximate
Ash
H20
Volatile Matter
Fixed Carbon
Sulfur
Heating Value
Analysis
11.0
11.
36.
42.
3.6
11,000.
Ultimate
C
H2
N2
02
S
Ash
H20
Analysis
61.0
5.2
1.4
6.8
3.6
11.0
11.0
100.0
Note: All numbers are wt. % except heating value which is
Btu/lb coal.
C-68
-------
TABLE 2-2
MEYERS PROCESS MATERIAL BALANCE
MPF Coal
FeS2
S
FeSO,,
o
2 Fe(SOll)3
H2SO,(
H20
02
Binder
TOTAL
Notes: (1)
(2)
(3)
(4)
Coal Feed HzSO^ Oxygen Fuel Coal
43,716 - - 4350
1,212* - - 15
1
1
- - 5
461 - 1
5,553 8 - 175
1380
66
Product Sulfate Sulfur
Coal Wastes By-Product
39,366
136
10 - 454
16 1662
43 1272
10 434
1,581 995
_
593
50,481 469 1380 4614 41,757 4363 454
Basis is production of 10 12 Btu/day of product coal.
* - number reported as tons of sulfur.
Units are tons /day
Only important input and output streams are shown.
M
H
M
bd
Chemical Coal
0
i— •
0>
H-
3
OT
-------
III-B. Chemical Coal Cleaning
3.0 MODULE DESCRIPTION
Radian's chemical desulfurization of coal module is
based on the Meyers Process. Table 3-1 gives the emissions and
impacts of this module.
3.1 Processing Steps
The Meyers Process is based on chemically leaching
FeS2 from coal with an aqueous ferric sulfate solution. The
FeS2 is converted into free sulfur and dissolved iron sulfate.
Ground coal is slurried with recycle iron sulfate solution and
fed to the main reactor. In this vessel the pyritic sulfur
in the coal is leached out and oxidized to free sulfur and fer-
rous sulfate by the ferric sulfate solution. Oxygen is simul-
taneously added to the vessel to regenerate the spent sulfate
solution and maintain a high ferric ion concentration.
The main reactor output is sent to a concentrating hy-
droclone. The overflow from the hydroclone is recycled to the
coal slurrying area while the underflow is sent to a coal/sulfate
solution filter. The filter cake is sent to a sulfur extraction
vessel where recycle solvent dissolves the free sulfur attached
to the coal. The filtrate is recycled to the coal slurrying
area with a slip stream being treated for sulfate removal in an
evaporator.
The slurry from the sulfur extraction vessel is sent
to a coal/solvent filter. The filtrate goes to decanters while
the filter cake is further processed in a water wash vessel. The
output of this vessel is sent to a coal/water filter from which
the filtrate goes to decanters while the filter cake is sent to
dryers. The dried coal product is then put in temporary storage
or shipped directly (LO-096). Figure 3-1 shows the processing
scheme for the Meyers Process.
C-70
-------
III-B. Chemical Coal Cleaning
TABLE 3-1
SUMMARY OF ENVIRONMENTAL IMPACTS
CHEMICAL DESULFURIZATION OF COAL
Basis: Production of 10lz Btu/day of Desulfurized Coal
Air (Ib/hr)
Particulates 344
S02 1,130
NOX 3,460
CO 192
HC 58
Water (Ib/hr)
Suspended Solids 116
Dissolved Solids 18,500
Organic Material 50
Thermal (Btu/hr) 0
Solid Wastes (tons/day) 4,363
Land Use (acres) 121
Water Requirements (gal/day) 29.3xl06
Occuptational Health (per year)
Deaths 1.43
Injuries 28.6
Man-Days Lost 12,700
Efficiency
Primary Product Efficiency 90
Total Products Efficiency 90
Overall Efficiency 90
Ancillary Energy (Btu/day) 0
C-71
-------
RAW
COAL TH.B.
Chemical Coal Cleaning
IRON SULFATE SOLUTION
RECEIVING
&
PREPARATION
1.
SLURRY
PREPARATION
OXYGEN
COAL LEACHING
&
REAGENT REGENERATION
IRON
SULFATE
FIGURE 3-1 -
PROCESSED SULFUR
COAL
SIMPLIFIED FLOW DIAGRAM OF MEYERS PROCESS
C-72
-------
III-B. Chemical Coal Cleaning
3.2 Ancillary Energy Requirements
The Meyers Process requires 5682 Kw of electrical power
for a 120 ton/hr facility (LO-096). The air emissions associated
with producing this electricity should be attributed to the de-
sulfurization plant. Therefore, an onsite power plant is in-
cluded in the desulfurization facilities. This system is assumed
to have a 35% efficiency, 9750 Btu/Kw-hr, which means the heat
rate to the boilers is 5.54xl07 Btu/hr for a 120 ton/hr facility.
Based on burning 12,000 Btu/lb product coal in the boiler, 37.2
tons/hr are required to produce 1012 Btu/day of desulfurized
coal. Since all energy needs are satisfied internally by firing
product coal, the ancillary energy requirements of this module
are zero.
3.3 . Products and By-Products
The primary product of a chemical desulfurization of
coal facility is a low sulfur coal. Based on data from LO-096,
a material balance was developed for the plant (see Table 2-2).
From this calculation the heating value of the desulfurized
coal product was found to be 12,000 Btu/lb. Therefore, the pro-
duction of 1012Btu/day of product is equivalent to 41,700 tons/
day of desulfurized coal. The only saleable by-product produced
from the Meyers Process is elemental sulfur. Based on the pro-
duction of 41,700 tons/day of desulfurized coal, 454 tons/day of
sulfur is produced. Table 3-2 shows the ultimate analysis of
the chemically desulfurized coal product.
3.4 Raw Material Requirements
From Table 2-2, 50,500 tons/day of Illinois coal must
be processed to produce 1012Btu/day of desulfurized coal product.
C-73
-------
III-B. Chemical Coal Cleaning
TABLE 3-2
ULTIMATE ANALYSIS OF A CHEMICALLY DESULFURIZED
ILLINOIS COAL
Weight 7,
Ash 12.25
S 1.55
C 66.41
H2 5.66
N2 1.52
02 7.40
H20 3.79
Binder 1.42
C-74
-------
III-B. Chemical Coal Cleaning
The make-up water requirements for the Meyers Process supply
four major needs: (1) process, (2) steam plant, (3) potable
and (4) cooling tower make-up. Approximately 4990 gpm are
required for the above items based on processing of 12,900 tons
coal/day (LO-126). This is equivalent to a requirement of
2.82 x 107 gal/day for the production of 1012 Btu/day of desulfuir-
ized coal. Heat and material balance calculations for the elec-
tricity generation facilities indicate that 1.13 x 107 gal/day
of additional make-up to the cooling system are required.
Therefore, total water requirements for the chemical desulfuriza-
tion facility are 2.93 x 107 gal/day.
3.5 Module Efficiencies
The primary product efficiency of a module is defined
as the energy content of the primary product divided by the
energy content of the feed. From Section 3.4, the amount of
run-of-mine Illinois coal required to produce 1012 Btu/day of
desulfurized coal is 50,500 tons/day. At 11,000 Btu/lb of coal,
this is equivalent to 1.11 x 1012 Btu/day as feed to the facili-
ties. Thus, the primary product efficiency is 9070.
The total products efficiency is defined as the energy
content of all products and "fuel-type" by-products divided by
the energy content of the feed. Since sulfur is the only by-
product formed and it is not considered to be a fuel, the total
products efficiency is equal to the primary product efficiency.
The overall efficiency is defined as the energy content of all
products and fuel by-products divided by the total energy
input to the process, i.e., feed and ancillary energies. Since
the ancillary energy needs of this module are zero, the overall
efficiency of this module is equal to the primary product
efficiency.
C-75
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III-B. Chemical Coal Cleaning
3.6 Land Usage
The land requirements for a facility capable of han-
dling 12,900 tons/day of coal are 30.9 acres (LO-126). Linear
scaling to a basis of 1012 Btu/day of desulfurized coal product
gives land requirements of 121 acres.
3.7 Occupational Health
Since the Meyers Process is still in the developmental
stage, data concerning injuries, deaths, and man-days lost are
not available. For the purpose of this study, the occuptational
data for chemical coal cleaning is assumed equal to that given
for physical coal cleaning in Section III-A of this appendix.
C-76
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III-B. Chemical Coal Cleaning
4.0 MODULE EMISSIONS
4.1 Air Emissions
Air emissions from the Meyers Process are limited to
the flue gas from the steam and electricity production units and
miscellaneous sources. Because the Meyers Process is just now
reaching the pilot plant stage, miscellaneous air emissions
cannot be quantified. From Table 2-2, the coal rate to the
steam and electricity production units is 4610 tons/day. This
coal has a sulfur content of 1.5570 and an ash content of 11.2%.
Based on the above data and EPA emission factors for coal fired
steam generators (EN-071), air emissions were calculated.
A limestone S02 scrubber is assumed to be employed to
remove particulates (99% efficiency) and sulfur oxides (90%
efficiency) from the flue gas. This is necessitated because the
Meyers Process does not remove organic sulfur and the Illinois
coal processed has a high organic sulfur content. If a low
organic sulfur coal is treated by the Meyers Process, the need
to treat the flue gas for sulfur oxide removal should be elimi-
nated.
In order to evaluate the effect that particulates,
S02, NO , CO and hydrocarbon emissions have on ambient air qual-
ity, it is necessary to define certain stack parameters used
in calculating ambient pollutant concentrations. Boiler flue gas
mass flow rates were calculated by assuming stoichiqmetric combus-
tion with 25% excess air. The volumetric flow rate was based on
an exit gas temperature of 250°F. The stack diameter was deter-
mined by assuming a gas exit velocity of 60 ft/sec. The stack
height was assumed to be 500 ft.
C-77
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III-B. Chemical Coal Cleaning
4.2 Water Emissions
Water effluents were characterized by specifying flow
rates, suspended solids, organic matter and total dissolved
solids. The suspended solids and organic matter were calculated
from an emission factor of 0.036 lb/106 Btu fired. Seventy
percent of these emissions were assumed to be suspended solids
with the remaining 30% being organic matter (BA-230). Based
on a fuel rate of 4.61 x 109 Btu/hr to the steam/electricity
production facility, suspended solids and organic matter are
116 and 50 Ib/hr, respectively.
Total dissolved solids (TDS) were calculated by assum-
ing a cooling tower blowdown rate and a TDS concentration of
10,000 ppm. The amount of blowdown from the steam production
cooling tower is expected to be 5.13 x 106 gal/day (LO-126) and the
amount resulting from electricity production is 2.05 x 105 gal/
day based on mass and energy balances around its cooling system.
Therefore, total cooling tower blowdown is 5.33 x 106 gal/day
and the TDS of this stream is 18,500 Ib/hr.
4.3 Solid.Wastes
Solid wastes from the Meyers Process consist of the
bottom ash from the steam boilers, the sludge from the limestone
scrubber and iron Sulfate wastes. From Table 2-2, 4363 tons/
day of iron sulfate wastes are produced. The quantity of lime-
stone S02 scrubber sludge is calculated from the following assump-
tions:
(1) the sludge wastes are assumed to be ponded and
the settled composition is 60% sludge and 40%
water
C-78
-------
III-B. Chemical Coal Cleaning
(2) the sludge consists of CaS03'%H20,
CAS02'2H20, Ca(OH)2 and ash,
(3) the sludge, ash excluded, contains 20% sulfur,
(4) the limestone S02 scrubber removes 90% of the
flue gas sulfur and 99% of the particulate
matter.
The bottom ash from the steam boilers is assumed to be 20% of
the ash content of the coal fired.
Total solid wastes produced from the chemical coal
desulfurization facilities are 4363 tons/day. It is assumed
here that the plant is a minemouth operation and that no addi-
tional land is required for solid waste disposal if these wastes
can be returned to the mine.
4.4 Thermal Discharges
Thermal discharges to water bodies are eliminated by
utilizing wet cooling towers.
C-79
-------
APPENDIX C
III-C. LOW BTU COAL GASIFICATION
C-30
-------
III-C. Low Btu Coal Gasification
1.0 INTRODUCTION
This section describes Radian Corporation's module for
the production of low Btu fuel gas from coal. Low Btu fuel gas
is a gas having a heating value of 150-300 Btu/scf which can be
used as fuel in either a conventional boiler or a combined cycle
generating plant.
Emission and efficiency data for low Btu gasification
systems were prepared by Hittman Associates (HI-083). A con-
siderable portion of Radian's analysis is based upon data
gathered for Hittman's study.
1.1 Description of Low Btu Gasification Processes
There are several processes which have been developed
specifically for the production of low Btu gas from coal, the
Lurgi, Koppers-Totzek, Winkler, and Wellman-Galusha processes.
The major distinguishing feature of these processes is the man-
ner in which each system's gasifier operates, since the process-
ing equipment located downstream of the gasifier is similar for
each process.
1.1.1 Common Technology
Once a raw low Btu gas is produced, it must undergo
two main processing steps to make it usable as a fuel. First,
entrained solids and/or liquids must be removed by cooling and/
or washing. This may be accomplished by many methods, of which
cyclones, venturi scrubbers or direct quenches are a few examples.
Following cooling and solids removal, C02 and/or H2S must be
removed. There are many proven industrial techniques available
for removing C02 and H2S. In this module, Radian has assumed
the use of the Stretford process for H2S removal and sulfur
recovery.
C-81
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III-C. Low Btu Coal Gasification
In addition to the gas cleaning equipment just described,
facilities must also be provided for the treatment of liquid
waste streams and for the recovery of ammonia and hydrocarbon
by-products. Included in these facilities will be a primary
water treatment unit, a gas liquor treatment unit, an ammonia
still, coal and by-product storage facilities, and in the case
of medium Btu gasification, an oxygen plant.
1.1.2 Gasifiers
The major distinguishing feature of the various low
Btu gasification processes is the design of the gasification
reactor. In this vessel coal is reacted with oxygen and steam
to produce a raw gas rich in CO and H2 which can be purified
and used as a boiler fuel. The differences between the processes
are found in the operating temperatures, pressures and mechanical
characteristics of the gasifier.
The reactions taking place in the gasifier are given
by Equations 1-1 to 1-3.
coal •> CiU + char + heat (1-1)
C + H20 + heat - CO 4- H2 (1-2)
2C + 02 - 2CO + heat (1-3)
The following paragraphs briefly describe the gasifiers of the
Lurgi, Koppers-Totzek, Winkler and Wellman-Galusha processes.
C-82
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III-C. Low Btu Coal Gasification
Lurgi Process
The Lurgi gasifier is a moving bed, steam-air gasifier.
Noncaking or slightly caking coal crushed to 1/8 x 1-1/4 inch
particles is fed through a lock hopper and distributed in the
gasifier via a revolving grate. Steam and air injected at the
bottom of the gasifier are distributed through a second revolv-
ing grate which also provides bed support and regulates the
ash removal rate. Ash is removed from the gasifier via a lock
hopper and water quenched. Figure 1-1 shows the Lurgi gasifier.
The steam and oxygen from the air react with char in
the reaction zone of the gasifier according to Equations 1-2
and 1-3 to produce heat and a low Btu gas. As this hot gas
rises through the downward moving coal bed, the coal is de-
volatilized according to Equation 1-1. The temperature at the
top of the gasifier is -about 1100°F x^hile the temperature at the
bottom is about 1800°F. The gasifier operates at a pressure of
300-500 psi (FE-068).
Koppers-Totzek Proces s
The Koppers-Totzek gasifier is an entrained flow gasi-
fier capable of treating all types of coal. Coal pulverized
to 707o through a 200 mesh screen is fed to the gasifier with
steam and air through coaxial burners at each end of the gasi-
fier. Coal, oxygen and steam react according to Equations 1-1
to 1-3 at about 3300°F to produce a low Btu gas containing CO
and H2 with a small amount of CHi,. Part of the coal ash is
slagged and removed from the bottom of the gasifier. The re-
maining ash and raw gas leave the top of the gasifier and are
processed by the dox^nstream equipment described in section
1.1.1. The gasifier pressure is approximately atmospheric (BO-117).
Figure 1-2 shows the Koppers-Totzek gasifier.
C-83
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TTT-n. Low Btu Coal Gasification
HYDQAULtC
MOTOR (TVP.1
COAL
PREHEAT
ZONE
&EACTIOU
ZQUE
ASH
OXYC-EN AUD
STEAM INLET
HYDRAULIC
OPERATED
A VALVES
__COAL
BUNKER
-&- TO EXHAUST PAU
COAL LOCK
"CHAMBER
1^^__
w
/_
"
—A
CD.UDE GAS OUTLET
COAL DISTRIBUTOR
WATER JACKETED
/PRODUCER- CHAMBER
SA/ GGAT&
ASH LOCK
CHAMBER
ASH QUEMCH WATER
ASH QUEMCH
CHAM SBg
ASH
FIGURE 1-1 SCHEMATIC DIAGRAM OF LURGI GASIFIER
C-84
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o
i
co
Ln
rt
FIGURE 1-2
K~T GASIFICATION AND HEAT RECOVERY
o
pj
CO
H-
l-h
H-
O
H-
O
-------
III-C. Low Btu Coal Gasification
Winkler Process
The Winkler gasifier is a fluid bed, steam-air gasi-
fier. Coal crushed to a 3/8 inch maximum diameter is dried
and fed by screw conveyors to the gasifier. The coal undergoes
reactions 1-1 to 1-3 to yield a raw gas rich in CO and H2. The
gasifier reaction temperature is 1500-1850°F and the pressure
is about atmospheric. Thirty percent of the coal ash is removed
from the bottom of the gasifier while about 70% is carried over-
head with the raw gas. Above the fluid bed, additional steam and
air are injected to react with the remaining carbon. The result-
ant gas is processed by the equipment described in Section 1.1.1
(BO-117). Figure 1-3 shows the Winkler gasifier.
Wellman-Galusha
The Wellman-Galusha gasifier is a moving bed, steam-
air gasifier. Coal crushed and sized to 1/2 to 2 inch diameter
is fed to the gasifier through a lock hopper and distributed
over the coal bed by a rotating arm. The coal bed moves down-
ward through the gasification zone, undergoing reaction 1-1.
As the resulting char leaves the gasification zone and enters
the combustion zone, it contacts steam and oxygen from air
injected at the bottom of the gasifier and undergoes reactions
1-2 and 1-3. A revolving eccentric grate at the bottom of the
gasifier allows for bed support and ash removal. A rotating
agitator arm, located just below the coal bed, is used when
handling slightly caking coals. Strongly caking coals must
be pretreated to destroy their caking tendencies before gasi-
fication can be accomplished. The low Btu gas flows counter-
currently to the coal bed and is removed from the top of the
gasifier at approximately 1250°F. The gasifier operates at
essentially atmospheric pressure (BA-260).
C-86
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o
I
CO
FIGURE 1-3
SCHEMATIC DIAGRAM OF
V7INKLER GASIFIER
l.P.fUOBUNHtR
IOCK HOPPERS
H.P.ftlDBUNMH
ASIICONVEVOH
WASIC lltAI HKOV0Y TRAIN
ASH IUNKC8
KOIASYIOCKS
ASIICONVCYOft
cvcicnts
wn SCRUIBCS
M
I
o
w
rt
O
O
Pi
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H-
t-n
H-
o
P3
rt
H-
o
-------
III-C. Low Btu Coal Gasification
1.2 State-of-the-Art
The technology for making a low Btu gas from coal has
been commercially available for 50 years (BA-158). The gasifica-
tion process was originally developed in Europe to produce a
low Btu fuel called "toxro gas" which was used to heat homes.
In addition, this low Btu .gas was used as a chemical feedstock
for ammonia production. After the supply of natural gas to
Europe increased, low Btu gas was relegated mainly to"use as a
chemical feedstock.
Because the U.S. has generally had an adequate supply
of natural gas, little of the early development of low Btu gasi-
fication was performed in the U.S. However, with the impending
worldwide shortage of natural gas, interest in low Btu gas as a
fuel source has been renewed in both the U.S. and Europe. The
following paragraphs briefly describe the development and
present status of the Lurgi, Koppers-Totzek, Winkler and Wellman-
Galusha processes.
Lurgi
The Lurgi process was developed in Germany in 1931.
The major use of the low Btu gas produced was as "town gas" or
a synthesis gas. Lurgi gasifiers are presently being used
in the world's largest coal gasification plant located in
Sasolburg, South Africa. A demonstration scale gas turbine
power plant in Lunen, Germany utilizes the Lurgi gasifier while
in the U.S. plans are completed or being completed for construc-
tion of several synthetic natural gas plants which employ the
Lurgi process (BA-260, BA-158, EL-052).
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III-C. Low Btu Coal Gasification
Koppers-Totzek
The Koppers-Totzek process was developed in the late
1940's by Dr. F. Totzek of Koppers of Essen, Germany. In 1948
a pilot plant to test the new process was constructed at
Louisiana, Missouri for the U.S. Bureau of Mines. This was a
joint effort of Koppers of Essen, Germany and Koppers Pittsburgh.
The pilot plant operated successfully for 2 years starting in
May of 1949. With the increased use of oil and natural gas in
the U.S. in the late 1940's, the gasification of coal became
economically unattractive. However, in 1952 a commercial
Koppers-Totzek gasification plant was installed in Finland with
several more following in other parts of the world. Presently,
16 commercial plants utilizing the Koppers-Totzek gasifier have
been built or are under construction (FA-083, BA-260).
Winkler
The Winkler process for gasification of coal was
developed in 1926 by Bamag Verfahrenstechnik GmbH. This company
is a German affiliate of Davy Powergas, Inc., the American
licensor of the Winkler process. The process was originally
used to produce a low Btu "town gas" and to provide a chemical
feedstock for the manufacture of methanol, ammonia and oil by
Fischer-Tropsch synthesis. At the present time 16 commercial
plants have been built which use the Winkler process (BA-260,
BO-117).
Wellman-Galusha
The Wellman-Galusha process was developed by McDowell
Wellman of Cleveland, Ohio. The process was originally used
to produce a fuel gas suitable for industrial needs including
kiln firing in the ceramics industry and process fuel require-
ment in the metals and glass industry. Presently, two plants
in the U.S. still employ the Wellman-Galusha process in a regular
or stand-by operational mode (BA-260, BO-117).
C-89
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III-C. Low Btu Coal Gasification
2.0 MODULE BASIS
Of the four commercial low Btu gasification systems
considered in this study, the Lurgi process is the best docu-
mented. For this reason, the Radian module for low Btu gasifica-
tion is based primarily on data generated by Hittman Associates
(HI-083) for a Lurgi plant. The use of this data does not imply
advocation or approval of the Lurgi process. In fact, data from
other processes are used when necessary to generate information
which is considered to be representative of low Btu gasification
systems in general.
Hittman's data are calculated on a basis of 1012 Btu
of coal input to the gasification plant. Because of the nature
of this study, Radian feels that an output basis is more
appropriate. The Hittman data are easily transformed from an
input basis to an output basis by dividing by the process ef-
ficiency.
In Section 3.0, discussions of typical low and medium
Btu gasification facilities are presented. Module emissions
are defined in Section 4.0.
C-90
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III-C. Low Btu Coal Gasification
3.0 MODULE DESCRIPTION
Low Btu gasification module emissions and impacts
are developed using one coal feed, an Illinois coal. A general
low Btu gasification module is described. For the purpose of
this study, air is assumed to be utilized in the gasifier as
the source of oxygen for the low Btu gasification module.
Table 3-1 is a summary of the emissions and impacts of a low
Btu gasification plant which utilizes Illinois coal.
3.1 Processing Steps
The processing units for Radian's low Btu gasification
module consists of the following:
(1) coal pretreater,
(2) gasifier,
(3) solids and liquids removal,
(4) acid gas removal and sulfur recovery.
In addition, an auxiliary boiler, gas liquid treater, ammonia
recovery unit and storage facilities are included.
3.2 Raw Material Requirements
Based on a primary product efficiency of 75.870
(see Section 3.5), 1.32xl012 Btu/day of coal is required as
feed to the gasifier to produce 1012 Btu/day of low Btu fuel
gas. Table 3-2 gives the proximate and ultimate analyses of
the coal used in Radian's study. Based on these coal heating
rates, 60,000 tons/day of Illinois coal is required.
C-91
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III-C. Low Btu Coal Gasification
TABLE 3-1
SUMMARY OF ENVIRONMENTAL IMPACTS
LOW BTU GASIFICATION OF ILLINOIS COAL
Basis: Production of 1012 Btu/day of Low Btu Fuel Gas
Air (Ib/hr)
Particulates 0.86
S02 2250
N0x 1130
CO 32.3
HC 32.5
NH3 45.4
Water (Ib/hr)
Suspended Solids 0
Dissolved Solids 0
Organic Material 0
Thermal (Btu/hr) Q
Solid Wastes (tons/day) 7320
Land Use (acres) 750
Water Requirements (gal/day) 11.0 x 106
Occupational Health (per year)
Deaths 0.71
Injuries 14.2
Man-Days Lost 7500
Efficiency (%)
Primary Product Efficiency 75.8
Total Products Efficiency 83.9
Overall Efficiency 83.9
Ancillary Energy (Btu/day) 0
C-92
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III-C. Low Btu Coal Gasification
TABLE 3-2
ANALYSES OF AN ILLINOIS BITUMINOUS COAL
Proximate
Ash
H20
Volatile Matter
Fixed Carbon
Sulfur
Heating Value
Analysis
11
11
36
42
3.6
11,000
Ultimate
C
H2
N2
02
S
Ash
H20
Analysis ...
61.0
5.2
1.4
6.8
3.6
11.0
11.0
100.0
Note: All numbers are wt. % except heating value which is
Btu/lb coal.
C-93
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III-C. Low Btu Coal Gasification
Water requirements for the low Btu gasification
plant are 7900 gpm or approximately 11 x 10fi gal/day. These
numbers are calculated by summing the water requirements
for the low Btu gas from El Paso's proposed gasification plant
and adjusting to a 1012 Btu production basis (EL-052).
3.3 Ancillary Energy Needs
From the Hittman report (HI-083), the ancillary
energy needs of a low Btu gasification plant are 3.58xl06
kwhr/1012 Btu of fuel gas produced. There are several ways
in which this energy need can be satisfied. Electricity may
by purchased from a nearby power plant or it may be generated
on site by burning coal, product gas or by-product hydrocar-
bons. Radian chose to burn a portion of the tar oils formed
during gasification to satisfy the ancillary energy needs.
This method allows environmental emissions to be properly
attributed to the gasification plant and not the power plant.
The auxiliary boiler is assumed to be 377«, efficient
(9224 Btu/kwhr). Thus, the heat rate to the auxiliary boiler
is 1.375xl09 Btu/hr. Since all energy needs can be internally
satisfied by firing tar oils in the auxiliary boiler, no
ancillary energy is considered needed for the gasification
process.
3.4 Products and By-Products
Several saleable by-products are recovered from the
low Btu gasification plants. These include naphthas, tars,
tar oils, phenols, ammonia and sulfur. Table 3-3 lists the
amounts of by-products recovered from a plant producing 1012
Btu/day of gas (BA-158, EL-052). The tar oils have been
C-94
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III-C. Low Btu Coal Gasification
TABLE 3-3
BY-PRODUCTS FROM LOW BTU GASIFICATION OF COAL
By-Product
Naphtha
Tar Oils
Tar
Phenols
NH3
Sulfur
Low Btu Gasification
of Illinois Coal
42,500
189,000
23,300
24,000
45,400
16,800
Note: (1) Numbers are in Ib/hr.
(2) Basis is production of 1012 Btu/day
of primary gas product.
C-95
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III-C. Low Btu Coal Gasificatioi
reduced by 7.99x10"* Ib/hr to account for fuel used by the
auxiliary boiler. The total heat value of the saleable hydro-
carbon by-products is 4.45xl09 Btu/hr from low Btu gasification
of Illinois coal (BA-158, EL-052).
3.5 Efficiency
It is possible to express the efficiency of a process
in several different ways. In this study, three different
efficiency terms are used. These are the primary product effi-
ciency, the total product efficiency and the overall efficiency.
The primary product efficiency is defined as the energy cojntent
of the primary product divided by the energy content of the
feed. For low Btu gasification Hittman (HI-083) gives the
primary product efficiency as 75.8%.
The total product efficiency is defined as the energy
content of all products and by-products divided by the energy
content of the feed. The overall efficiency is defined as the
energy content of all products and by-products divided by the
total energy input to the process, i.e., feed and ancillary
energies. Since there are no ancillary energy requirements
for low Btu gasification, the overall and total product effi-
ciencies are equal.
3.6 Land Usage
Land requirements for a low Btu gasification plant
are based on 50.4 acres needed for a plant capable of producing
6.73xl010 Btu/day of fuel gas (HI-083, EL-052). On a 1012
Btu/day output basis, this yields a land requirement of 750
acres.
C-96
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III-C. Low Btu Coal Gasification
3.7 Occupational Health
The data on injuries, deaths and man-days lost for
the low btu gasification module are taken directly from
Battelle (BA-230). These numbers are converted from Battelle's
basis of 105 Btu of low Btu gas production to Radian's basis of
1012 Btu/day.
C-97
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III-C. Low Btu Coal Gasification
4.0 MODULE EMISSIONS
4.1 Air Emissions
Air emissions from a low Btu gasification system come
from the sulfur recovery unit, the auxiliary boiler and storage.
The Stretford process is chosen as the method used to remove
H2S from the raw fuel gas stream. This process gives 947o
sulfur removal, with 99.4% recovery of the sulfur (HI-083).
The auxiliary boiler is fired with by-product tar oils having
a sulfur content of 1.370 (BA-158). A limestone scrubber is
utilized to reduce S02 and particulate emissions. The scrubber
is 90 and 99% efficient in removing S02 and particulates,
respectively.
The sulfur emissions from the sulfur recovery unit
are calculated from a sulfur material balance. The air emis-
sions from the auxiliary boiler are calculated from "Compilation
of Air Pollutant Emissions Factors" (EN-071), tar oils feed rate
and sulfur content. Storage emissions are assumed to occur from
the ammonia and naphtha by-products. Emissions are calculated
using storage capacity data and emission factors from (EN-071).
The ability of a gasification process to limit its air emissions
to those given above will depend to a large extent on the pre-
vention of fugitive emissions from pump seals, joints, flanges,
etc.
In order to evaluate the effect that particulates,
S02, N0x, CO and hydrocarbon emissions have on ambient air
quality, it is necessary to define certain stack parameters used
in calculating ambient air pollutant concentrations. Table 4-1
lists the air emissions and stack parameters for the individual
emission sources of a low Btu gasification plant.
C-98
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TABLE 4-1
LOW BTU COAL GASIFICATION MODULE
AIR EMISSIONS AMD STACK PARAMETERS
Basis: 10" Btu of Fuel Gas Output/Day
Source
Illinois Coal
A. Auxiliary
Power
B. Sulfur
Recovery
C. Storage
TOTAL
Heat
Input
MM Btu/Hr
1,380
55.000
Fuel
Tar Oils
Emissions Ibs/hr
Particulates
0.863
_
-
0.863
S0»
220
2030
-
2250
Total
Organics
32.3
_
0.219
32.5
CO
32.3
.
-
32.3
NO*
1130
_
-
1130
NHj
.
.
45.4
45.4
Stack Parameters
Maes
Flow
Ibs/hr
1.65x10'
12.500
Volumetric
Flow
ACFM
0.502x10'
4560
Velocity
FPS
60
60
Height
Ft.
500
300
50
Temperature
OF
250
450
Dia-eter
Ft.
13.3
1.27
o
I
MD
t-4
rt
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H-
i-h
H-
O
03
rr
H-
O
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III-C. Low Btu Coal Gasification
Mass and volumetric flow rates are calculated from
material balances. Stoichiometric mass flows shown in Table 4-1
were calculated from material balances assuming Stoichiometric
combustion with 25% excess air (75% for the sulfur recovery flare) .
Volumetric flow rates were based on assumed exit gas temperatures.
Stack heights, gas velocities, and exit temperatures were assumed,
while stack diameters were calculated from the gas velocities
and volumetric flow rates.
4.2 Water Emissions
Water emissions from the low Btu gasification module
were assumed to be equal to those from SNG-from-coal processes.
These wastes are discussed in module writeup III-D.
4.3 Solid Wastes
Solid wastes from a low Btu gasification plant consist
of coal ash, primary water treatment sludge, ammonia still
wastes and limestone scrubber sludge. The scrubber sludge is
assumed to consist of 40% water and 60% solids. The solids
contain ash, CaSO^^HaO and CaS03«%H20 (solids, ash excluded, are
20% sulfur). The amount of primary treatment sludge is calcula-
ted from (1) intake water requirements, (2) the assumption that
500 ppm of suspended solids is present in the make-up water, and
(3) all suspended solids are removed by treating. The amount of
coal ash produced is calculated from coal rates and ash content.
Ammonia still wastes are calculated using ammonia recovery rates
and the following factor: 469 tons of still wastes are formed
per 416 tons of ammonia recovered (HI-083).
The low Btu gasification plant is expected to be a
mine mouth operation and hence, all solid wastes are expected
to be disposed of as mine fill.
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III-C. Low Btu Gasification
4.4 Thermal Discharges
Thermal discharges to water bodies are eliminated by
utilizing wet cooling towers. If an adequate supply of water
is not available, air cooled condensers could replace wet cool-
ing towers.
C-101
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APPENDIX C
III-D. HIGH BTU COAL GASIFICATION
C-102
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III-D. High Btu Coal Gasification
1.0 INTRODUCTION
This section describes Radian Corporation's module for
the production of substitute natural gas (SNG) from coal. Candi-
date systems for this module included:
(1) The Lurgi Process
(2) The Institute of Gas Technology HYGAS
Process
(3) The Bituminous Coal Research BI-GAS
Process
(4) The Bureau of Mines Synthane Process
(5) The Consolidation Coal Company C02
Acceptor Process
There are additional SNG-from-coal processes which
are undergoing investigation. These include: (1) the Battelle/
Union Carbide, Agglomerating Ash Process, (2) the Kellogg
Molten Salt Process, and (3) the Garrett Process and others.
These processes are less developed than the ones mentioned
above and hence were given no consideration as candidates for
the SNG-from-coal module. However, this is not to imply that
any of these less developed processes cannot become commercial
realities.
Hittman Associates, Inc., have compiled environmental
impact and efficiency data for all of the above processes (HI-
083). These data, supplemented or corrected with data from other
sources, was used to define the SNG-from-coal module described
here.
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III-D. High Btu Coal Gasification
1-1 Description of Candidate Processes
The various candidate processes for high BTU coal
gasification contain many similar processing units. The major
distinguishing feature of the processes is the gasifier section.
The various processing steps in coal gasification are explained
in the following sections.
1.1.1 Common Technology
All SNG-from-coal processes utilize .some kind of a
gasifier to produce a synthesis gas which contains CH4, CO, H20,
Ha, and C0?. After leaving the gasifier, the synthesis gas goes
through several processing steps to upgrade it to pipeline quality
gas. Figure 1-1 is a general schematic of the gasification process.
While the specific means of accomplishing the gas processing steps
may vary from process to process, the basic principles'-of each
step are common to all processes.
1;1.1.1 Solids Separation and Cooling
Synthesis gas produced during coal gasification can
contain
dus t
coal fines
carbon char
tars
• oils
phenols.
To prevent plugging of the shift reactor and poisoning of down-
stream catalysts, the synthesis gas is cleaned of all solids.
Conventional processing equipment can be used to accomplish this,
C-104
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COAL
PREPARATION
CF:JSH AND POSSIDLY
DRV ANO/OR PRETREAT
Br OXIDATION
(PRtTRUIJtKT NOT $HO«O
O
f
O
01
T - AM3ICNT
P - ATM3SPHERIC
(COAL) v
COAL HEAT RECOVERY AND
CASIf ICATIOM INITIAL GAS CLEANUP SHIFT PURIFICATION HETHANATION
(C»H20 — «-CO*H2)
(COAL«H2 — ~OVO
T
P
t
- 1. 100» -1. SCOT
• 150-1.500 PS!
k |
(CO*H20— «>C02»H2> (CO*3H2 — »CH^'HjOy
CO CO** H** M*>0 * CM* f ty »Kj ^M^w, J
•*jS,NHT/ * •
HEAT OUT (CH4.C02.CO.H2,H20.H2S) P
A ' . p
J P \ fc T - 650»-800* F T - IOO'-3CO* F ^ T - 5CO*-900' F
*l p 1 * P • I50-!.ECO PSI * P ' 150-1.500 PSI . "" * P - 150- I.5O3 PSI
*r if , ,
LIQUIDS A.VO FINES RECYaE * ^ tHz°J
^ H
*~~LTLnj • ^
KEAT IN T . TEWERATUF.E O
(C«C2 — CO,) P. PRESSURE
(T-I.900--2.«W F) ' (). COFONENTS .N STREAM
J. H-
V CT3
(STEAM. Oj)
FIGURE 1-1
SCHEMATIC REPRESENTATION OF FUNDAMENTAL GASIFICATION
STEPS FOR COAL TO PIPELINE GAS PROCESSES
rt
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Hi
H-
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rt
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III-D. High Btu Coal Gasificatioj
however, some of the commercially available treatment methods
may have to be refined to ensure essentially 100% solids re-
moval. Typical methods would include dry cyclones, wet cyclones,
venturi scrubbers, quenchers, bag filters, etc. Each SNG process
uses the kind of solids removal device best fitted to its partic-
ular processing scheme and gas contaminants.
In addition to solids removal before the shift reactor,
the synthesis gas is cooled to 550-650°F. This is necessary
to avoid excessively high temperatures in the shift re-actor due
to the exothermic water gas reaction. The use of water wash
columns, direct quenches, venturi scrubbers and/or heat exchangers
has been proposed for cooling the synthesis gas prior to its .
entering the shift reactor.
1.1.1.2 Shift Reactor
Synthesis gas is upgraded to SNG by catalytic methana-
tion via Equation (1-1).
CO + 3H2^CH4 + H20 + heat (1-1)
Optimum methane yield requires a 3:1 ratio of hydrogen to carbon
monoxide. In most raw synthesis gases, this ratio is about 1:1 or
lower. To obtain the desired ratio of H2:CO, steam is added to
the synthesis gas and the H2:CO ratio is catalytically shifted
according to the water gas reaction given by Equation (1-2) to
give the desired 3:1 ratio.
CO + H20 v * C02 + H2 + heat (1-2)
This reaction system is currently used in several
industrial applications, for example, in the production of ammonia.
However, in the ammonia system, the CO content of the gas is
much lower than that found in coal gasification synthesis gas.
Work has been done and still needs to be done to develop new
C-106
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III-D. High Btu Coal Gasification
shift reactor catalysts and methods of operating the shift
reactor.
The need to find a new catalyst arises because of
the reducing tendencies of the high CO content of the synthesis
gas. This causes the metal oxide catalysts employed to be
reduced to the elemental metal which will then catalyze the
methanation reaction, Equation (1-1). This reaction is highly
exothermic and will cause hot spots in the reactor bed and
damage the catalyst. To offset the reducing effect of CO,
large quantities of steam, which has an oxidative effect, are
added. However, steam has adverse effects on the mechanical
strength of the catalyst. A 1:1 ratio of steam to dry gas
has been recommended by catalyst manufacturers as the best
shift reactor feed (AI-013).
The shift reactor may be operated in one~of two ways .
The total gas stream can be shifted to the desired H2:CO ratio
or part of the gas stream can be shifted to a higher H2:CO ratio
which when combined with the bypass stream will yield the desired
Ha:CO ratio. Because of catalyst considerations, i.e., a 1:1
stream to dry gas ratio, the bypass method appears to be the
best procedure (AI-013). However, this method will- create a
high exit gas temperature and necessitate quenching of the
effluent stream to prevent carbon deposition from the Boudouard
Reaction, Equation (1-3).
2CO. SCO 2 + C (1-3)
C-107
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III-D. High Btu Coal Gasificatio
1.1.1.3 Acid Gas Removal
Prior to catalytic methanation, the synthesis gas
must be cleaned of sulfur compounds and COa. The sulfur will
poison the methanation catalyst, while C02 will result in
excess CO in the product SNG by lowering the H2:CO ratio by
reacting with hydrogen according to Equation (1-4).
C02+ 4H2^ CH, + 2H20 . (1-4)
The types of acid gas removal units available can be
classified as selective or nonselective. Nonselective removal
produces an acid gas stream very 'dilute in H2S which is unaccept-
able as a feed stream to a conventional Glaus unit. • Selective
acid gas removal produces a more concentrated H2S stream that
can be treated by a conventional Glaus unit and a C02 rich stream
which can be vented to the atmosphere. Selective removal systems
include (1) the Benfield activated, hot carbonate system, (2)
the HIPURE process, (3) the Rectisol cold methanol absorption
process and others. Sulfur guards are generally used to remove
any residual sulfur that escapes the acid gas removal system.
These are usually beds of ZnO which react with H2S to yield ZnS
which is then discarded.
1.1.1.4 Sulfur Recovery
The use of a selective acid gas removal system allows
sulfur to be recovered as elemental sulfur via a conventional
Glaus unit. Glaus units recover elemental sulfur by the
following reactions:
2H2S + 302 ^ 2S02 + 2H20 (1-5)
2H2S + S02 ^^ 3S + 2H20 (1-6)
C-108
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III-D. High Btu Coal Gasification
Sulfur removal efficiencies up to 97% can be obtained. If needed,
the Glaus unit tail gas can be further treated by SO2 scrubbers
to meet environmental standards.
1.1.1.5 Cat aly t. ic Me t hana t i on
Synthesis gas which has been treated for acid gas
removal and has had its H2:CO ratio adjusted to approximately
3:1 must be catalytically methanated to yield pipeline quality
SNG. The methanation reaction is given by Equation (1-1).
CO + 3H2^ CH* + H20 + heat " (1-1)
This reaction is strongly exothermic, giving off 49.3 Kcal/g-mole.
Two important considerations in the design of the methanator
are (1) a heat removal technique to limit the gas exit-: temperature
to around 850°F and .(2) a suitable catalyst to methanate a feed
stream that contains a high content of carbon monoxide.
Several possible systems for methanation have been pro-
posed. The first involves spraying the catalyst on the outside
of tubes, with cooling fluid being circulated inside the tubes.
The synthesis gas passes over the catalyst and undergoes methana-
tion. The heat of reaction liberated is carried away by the
cooling fluid. Problems have occurred in retaining catalyst
activity for sufficient periods of time. A second method em-
ploys a system of catalytic reactors with intercooling equipment.
A major drawback to this method arises because of temperature
profile shifts which occur during start-up, shutdown, and periods
of reduced gas flow. A third system utilizes a large recycle
stream of cooled product to reduce the gas stream reactant
concentrations. This method has economic ramifications due to
'the increased converter size requirement.
C-109
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III-D. High Btu Coal Gasificatio
The methanation reaction is a well-known reaction with
widespread use in the ammonia synthesis industry. However, the
coal gasification synthesis gas which must be methanated is
considerably more concentrated with CO and H2 than in any pre-
vious application. Studies need to be performed to demonstrate
the reliability of the methanation catalyst. Catalysts proposed
for use include nickel and molybdenum.
1.1.1,6 Drying
The SNG product from the methanator contains water
which must be removed to meet pipeline specifications. Technology
in this area is industrially proven and any of several methods
are acceptable, of which, glycol absorption is one example.
1.1.2 Gasifiers
The major distinguishing feature of the various
gasification processes lies in the gasifier section. In this
section raw coal is reacted to produce a synthesis gas which
can be upgraded to pipeline quality gas. The differences
between the processes are found in the operating temperatures,
pressures, mechanical characteristics of the gasifier and the
means of supplying heat for the gasification reactions, Equations
(1-7) to (1-10).
Coal - CH4 + Char + Heat (1-7)
C + 2Ha - CH4 + Heat (1_8)
C + HaO + Heat - CO + H,, (1_9)
2C + 02 - 2CO + Heat (1-10)
C-110
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III-D. High Btu Coal Gasification
The following paragraphs briefly describe the gasifiers of the
Lurgi, HYGAS, BI-GAS, Synthane and C02 Acceptor Processes.
Lurgi Process
The Lurgi gasifier is a moving bed, stream-oxygen
gasifier. Noncaking or slightly caking coal is crushed to
yield a feed of 1/8 x 1% in. particles. This coal is fed
through a lock hopper and distributed in the gasifier via a
revolving grate. Steam and oxygen injected at the bottom of
the gasifier are distributed through a second revolving grate
which also provides bed support and regulates the ash removal
rate. Ash is removed from the gasifier via a lock hopper and
water quenched.
The steam and oxygen react with char according to
Equations (1-9) and (1-10) to produce heat and synthesis gas.
This gas rises while the coal bed moves downward. As the coal
enters the top of the gasifier, it devolatilizes according to
Equation (1-7) with further methane being formed from Equation
(1-8). The temperature at the bottom of the gasifier is about
1800°F, while the temperature at the top of the gasifier is
about 1100°F. The Lurgi gasifier operates at a pressure of
300-500 psi (FE-068). Figure 1-2 shows the Lurgi gasifier.
HYGAS Process
The HYGAS gasifier section consists of:
(1) coal pretreatment,
(2) slurry preparation,
Grill
-------
COAL
HYDRAULIC
MOTOR (TYP.1~\
-0
COAL
PREHEAT
"ZONE.
REACTION
ZQUE
•HHM
ASH ZO/V£-
OXYGEN AND
STEAM INLET
__COAL
BUNKER
HYDRAULIC
OPERATED
A VALVES
s- TO EXUAUST
COAL LOCK
^CHAMBER
CD.UDE GAS OUTLET
COAL DISTRIBUTOR
V//ATE/2 JACKETED
/P&ODUCEQ CHAM5ZB
G2ATE
A5H LOCK
CHAMBER
ASH QUEVCH WATER
ASH QUEUCH
CHA M5EB
ASH
FIGURE 1-2
SCHEMATIC DIAGRAM OF LURGI GASIFIER
C-112
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III-D. High Btu Coal Gasification
(3) a fluidized bed, two stage gasifier, and
(4) hydrogen production.
The HYGAS gasifier is unique in that it utilizes a .
hot hydrogen-rich gas stream to supply heat for the endothermic
reaction of Equation (1-9) . Coal is crushed to -8 4- 100 mesh
size and fed to the pretreater where the caking tendencies of
the coal are destroyed by a hot air stream. The treated coal
is then mixed with a light oil formed in the gasifier and
injected into the top of the gasifier in a slurry form. At
the top of the gasifier the light oil evaporates and the dried coal
falls into the upper part of the gasifier. The coal reacts with
rising hot synthesis gas and undergoes reactions (1-7) and (1-8)
at a temperature of 1300-1500°F.
The hydrogen-rich gas and steam injected into the
bottom of the gasifier react with the char formed in the upper
stages of the gasifier according to Equation (1-8) to form
methane concurrently with the formation of CO and H2 from the
steam-carbon reaction, Equation (1-9). The lower portion
of the gasifier operates at 1700-1800°F. The gasifier pressure
is 1000-1500 psi.
Unreacted char from the bottom of the gasifier is
sent to a hydrogen-rich gas generator where it is reacted with
steam to yield H2 and CO. Heat for this reaction can be supplied by
electrifying the char (FE-068). Figure 1-3 is a schematic of the
HYGAS system.
C-113
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o
FUEL GAS
COAL-
HOT AIR
PIPELINE GAS
METHANAT10N
LIGHT OIL
PRETREATER
-=. — ii_=— : — :-i-i
— — — — •
_
\——/
1 »
^
SLURRY
PREPARATION
/ I '»
_ L-fr. l
i
/
—
PURIFICATION
HYDROGASIFICATION —
SUSPENSION
GASIF1ER
_; DRYING 600" F E:
ir
-1.300-1.500° F-
GASIFICATION--
HYDROGAS1FIER
(FLUID1ZED BEDS)
1.000—1,500 PSI
OXYGEN + STEAM-
2.500° F
HYDROGEN -
RICH GAS
CHAR
STEAM GAS1FIER
r
1\\ HYDROGEN -
ELECTROTHERMAL p-°-c-
RICH GAS
CHAR
CHAR
>
ELECTRIC
AND STEAM
GENERATION
ASH
FIGURE 1-3
i 1,800-1,900" F-
STEAM
SCHEMATIC DIAGRAM OF HYGAS PROCESS
ASH
H-
09
O
o
pj
CO
(-••
Hh
H-
O
P
r^
H-
O
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III-D. High Btu Coal Gasification
BI-GAS Process
The BI-GAS gasifier section consists of
(1) coal pretreatment,
(2) a two stage, high pressure gasifier, and
(3) a char separation cyclone.
i
Coal is crushed and dried until 70% is -200 mesh. This is fed,
along with steam, to the first stage of an entrained flow
gasifier. Upon contact with the hot synthesis gas rising from
Stage 2, the coal rapidly undergoes devolatilization to produce
methane and an active carbon char. This active char reacts with
steam according to Equation (1-9) to yield more synthesis gas.
The char and gas are swept out of the top of the gasifier to the
char separation cyclone where the char is removed and returned,
along with steam and oxygen, to the second stage of the gasifier.
In this lower stage of the gasifier, the carbon char reacts
according to Equations (1-9) and (1-10) to produce a hot synthesis
gas which rises to the first stage and provides heat for further
production of synthesis gas from Reaction 1-9. Molten slag is
removed from the bottom of the gasifier and water quenched. The
Stage 1 reaction temperature is about 1700°F, while, the Stage 2
temperature is 2700°F. The gasifier operates at 1000-1500 psi
(FE-068). Figure 1-4 schematically shows the BI-GAS system.
Synthane Process
The Synthane Process utilizes a two stage, fluidized
bed gasifier with a free-falling pretreatment stage. Coal
crushed to 7070 through -200 mesh is fed to the top of the gasifier,
C-115
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HYDROGAS1FICATION
COAL
STEAM -
GASIFICATION
OXYGEN
STEAM
CHAR + GAS
CYCLONE
^1,400-1,700° F
700—1,500 PSI
2 - STAGE GAS1FIER
CHAR
SLAG
FIGURE 1-4
SHIFT
CONVERTER
PURIFICATION
METHANATION
PIPELINE GAS
SCHEMATIC DIAGRAM OF THE BI-GAS PROCESS
M
O
OP
r?
rt
o
O
CO
H-
O
PJ
ft
H-
O
3
-------
III-D. High Btu Coal Gasification
Here it reacts with steam and oxygen in a free-falling manner
that destroys the caking properties of the coal in addition to
partially devolatilizing the coal. After pretreatment the coal
enters the hydrogasification stage of the gasifier and then the
gasification section. Both of these stages operate as a fluidized
bed. At the bottom of the gasifier, steam and oxygen are injected
and char and ash removed. The steam, oxygen, and char react ac-
cording to Equations (1-7) to (1-10) to produce a synthesis gas.
The gasification stage operates at 1750-1850°F and the hydrogasi-
fication stage at 1100-1450°F. :The entire gasifier is under
600-1000 psi pressure (US-109). Figure 1-5 schematically shows
the Synthane Process.
CO2 Acceptor Process
The C02 Acceptor Process is characterized by three
fluidized bed reactors and the use of calcined dolomite as the
heat supply for the carbon-steam reaction, Equation (1-9).
Lignite or subbituminous coal crushed to 1/8 in. particles is
fed with steam, calcined dolomite and synthesis gas to the
devolatilizer. The coal undergoes devolatilization and the
steam-carbon reaction, Equations (1-7) and (1-9), respectively.
Heat for Equation (1-9) is supplied by the reaction of calcined
dolomite with carbon dioxide. The lignite char formed also
reacts according to Equation (1-8) to form more methane. The
synthesis gas exiting the devolatilizer is upgraded downstream
into SNG, while the remaining lignite char is sent to the
gasifier. Here, more steam and calcined dolomite are added to
produce synthesis gas for addition to the devolatilizer. Un-
reacted char from the gasifier is burned in the regenerator and
the heat is used to recalcine the spent dolomite from the gasifier
and devolatilizer. The system pressure is 150-300 psi, the
gasifier and devolatilizer temperature is 1500°F, and the
C-117
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o
I
oo
COAL
OXYGEN -I- STEAM—>
PRETREATMENT
AMD
DEVOLATiLIZATION
HYDROGAS1FICAT10N-
GASIFICATION
RAW GAS
600-1,000 PSI
(ENTRAINED
. FLOW)
-1,100-1,450° Fr
GASIFiER
—3 ED) "^
4-OXYGENS STEAM
, CHAR +ASH
FIGURE 1-5
SCHEMATIC DIAGRAM OF THE SYNTHANE PROCESS
SHIFT
CONVERTER
v
PURIFICATION
METHANATION
PIPELINE GAS
M
M
I
o
H-
OQ
O
O
CO
H-
Mi
H-
O
P
rt
H-
o
-------
III-D. High Btu Coal Gasification
regenerator temperature is 1900°F (FE-068). Figure 1-6 schema-
tically shows the G02 Acceptor Process.
1.2 State-of-the-Art
Many of the processing units of an SNG-from-coal
plant are new technology and have yet to be industrially proven.
The Lurgi process has the only commercially proven gasifier.
In addition, the water-gas shift reactor and methanation reactor
have not been proven for handling streams with carbon monoxide
and hydrogen contents as great as those found in gasification
synthesis gases. The following paragraphs briefly describe
the state-of-the-art of the most advanced SNG-from-coal processes,
Lurgi Process
The gasifier of the Lurgi process has been commercially
used for years to produce a "town gas" or ammonia synthesis feed.
However, the methanation reactor has not been proven. Several
commercial SNG-from-coal plants which will utilize the Lurgi
Process are presently under construction--or in the planning
stage.
HYGAS Process
The Institute of Gas Technology started work on coal
gasification in 1943. From this work evolved the HYGAS Process.
A 75 ton/day pilot plant was finished in 1971, which included
an electrothermal gasifier (FE-068). A 2 ton/day fluidized bed
reactor utilizing steam and oxygen to produce a hydrogen-rich
gas has also been constructed. IGT research was originally
supported by the American Gas Association (AGA). More recent
work has been jointly supported by the AGA and the Office of
Coal Research (OCR).
C-119
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o
i
i-1
N3
O
LIGNITE *
PURIFICATION
DEVOLATiLIZER
150 PSI
1,500° F
(FLU1DIZED)
MgO-CaO
MAKEUP
DOLOMITE
'•=\F^E-7 (MgC03-CaC03)
STEAM
METHANATION
PIPELINE GAS
ASH
P.C.C.
A
GAS1FIER
REGENERATOR
1,900'° F
(FLUIDIZED)
MgO-CaO
CHAR
150 PSI
1,600° F
(FLUIDiZED)'
MgO-CaCOs
STEAM
MgO-CaC03
GAS
T
AIR
GAS
DEVOLATILIZED COAL
GAS
FIGURE 1-6 - SCHEMATIC DIAGRAM OF THE C02 ACCEPTOR PROCESS
-------
III-D. High Btu Coal Gasification
BI-GAS Process
The BI-GAS Process was developed by Bituminous Coal
Research after a literature search which started in 1963. In
1965-1966, laboratory tests were made and then a 5 Ib/hr process
and equipment development unit was constructed to test the
\j-
second stage of the gasifier. A 5 ton/hr pilot plant is presently
under construction with start-up scheduled in the fall of 1975.
Research for the BI-GAS Process was originally funded by the
OCR and recently by the AGA and OCR.
Synthane Process
The Synthane Process development work started in 1961.
At this time methods of pretreating caking coals in a fluid bed
were studied. Construction of a 72 ton/day pilot plant was
completed in the fall of 1974. Work was also done on develop-
ing a suitable methanation reactor. Two systems were studied:
(1) a hot gas recycle process, and (2) a tube wall reactor
process. The Synthane Process was developed by the U. S.
Bureau of Mines.
CO2 Acceptor Process
The C02 Acceptor Process was developed by Consolidation
Coal Company in conjunction with the OCR and the AGA. Bench-
scale studies have been completed and a 30 ton/day pilot plant
is now in operation. By 1976 the process is expected to be
nearing the point of commercial consideration.
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III-D. High Btu Coal Gasification
2.0 MODULE BASIS
Emissions and environmental impacts are developed
for the SNG-from-coal process based on an output of 1012 BTU/day
of SNG. The data from the Hittman report (HI-083) are expressed
on a basis of 1012 BTU input .to the process. Because of the
nature of this study, Radian felt that an output basis would be
more appropriate. The Hittman data are easily transformed from
an input basis to an output basis by dividing by the process
efficiency.
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III-D. High Btu Coal Gasification
3.0 MODULE DESCRIPTION
When commercialization of SNG-from-coal plants is
realized, it is anticipated that many installations will employ
a "second generation" process, i.e., the HYGAS, BI-GAS, Syn-
thane C02 Acceptor, etc. (the Lurgi process is considered "first
generation"), and that moreover, no one process will be predom-
inantly preferred over the others.
The majority of data in the following sections is
calculated for the BI-GAS process. When necessary and where
applicable, data from any of the other SNG-from-coal processes
are used. Radian Corporation, or the Environmental Protection
Agency, are not in any way implying or denying approval or
advocation of the BI-GAS process; instead, it is felt by Radian
Corporation that the BI-GAS process is representative of the
new "second generation" process.
The SNG-from-coal module emissions and impacts are
developed using one coal feed, an Illinois coal. Section 3
describes the process features while Section 4 gives the module
emissions. A general SNG-from-coal module is characterized.
Table 3-1 is a summary of the emissions and impacts of an SNG-
from-coal plant which utilizes Illinois coal.
3 .1 Processing Steps
The processing steps in Radian's SNG-from-coal module
include the following:
(1) coal pretreatment and thermal drying
(2) gasification
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III-D. High Btu Coal Gasification
TABLE 3-1
SUMMARY OF ENVIRONMENTAL IMPACT
SNG-FROM-ILLINOIS COAL
Basis: Production of 1012 Btu/day of SNG
Air (Ib/hr)
Particulates 944
S02 10,400 .
NOX 7,770
CO 414
HC 126
NHs 54.7
Water (Ib/hr)
Suspended Solids 0
Dissolved Solids 0
Organic Material 0
Thermal (Btu/hr) 0
Solid Wastes (tons/day) 7,930
Land Use (acres) 700
Water Requirements (gal/day) 25 x 106
Occupational Health (per year)
Deaths 1.8
Injuries 61
Man-Days Lost 16,600
Efficiency (%)
Primary Product Efficiency 67.9
Total Products Efficiency 67.9
Overall Efficiency 67.9
Ancillary Energy (Btu/day) 0
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III-D. High Btu Coal Gasification
(3) cooling and solids removal
(4) catalytic shifting
(5) acid gas removal
(6) sulfur recovery
(7) catalytic methanation
(8) ammonia recovery
(9) product drying and compressing
In addition to the above facilities, an auxiliary
boiler, a steam superheater, a water treatment unit, oxygen
plant and ammonia and sulfur storage facilities are included.
While specific processes are assumed for some of these processing
units, it is felt that there are other alternatives available
which could meet the process requirements. These
alternatives should exhibit environmental impacts similar to
the processes assumed by Radian however.
3-2 Raw Material Requirements
The SNG-from-coal plant requires coal for four
processing units, the gasifier, the coal dryers, the auxiliary
boiler and the steam superheater. Table 3-2 gives the proximate
and ultimate analyses of the coal used in Radian's study. Table
3-3 shows the breakdown of coal feed rates required by the above
units. Methods of calculating coal rates are taken from
Hittman's report (HI-083).
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III-D. High Btu Coal Gasification
TABLE 3-2
ANALYSES OF AN ILLINOIS BITUMINOUS COAL
Proximate Analysis
Ash
H20
Volatile Matter
Fixed Carbon
Sulfur
Heating Value
11
11
36
42
3.6
11,000
Ultimate Analysis
C
H2
N2
02
S
Ash
H20
61.0
5.2
1.4
6.8
3.6
11.0
11.0
100.0
Note: All numbers are wt. % except heating value which is
Btu/lb coal.
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III-D. High Btu Coal Gasification
TABLE 3-3
COAL RATES TO VARIOUS UNITS OF AN SNG-FROM-COAL PLANT
Basis: Plant Capacity is 1012Btu/day of SNG
Illinois Coal
Unit Rate
Gasifier 56,400
Coal Dryer 600
Auxiliary Boiler 8,200
Steam Superheater 1.700
Total 66,900
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III-D. High Btu Coal Gasification
Water requirements are 17,600 gpm or approximately
0.25xl06 gal/day based on a preliminary design for Wesco's SNG
plant utilizing the Lurgi process (US-164). In addition,
chemicals for water treatment, acid gas removal, drying, etc.,
are needed. However, these cannot be quantified at this time.
Catalyst replacement is also necessary, but the frequency and
quantity depends on the particular catalysts used.
3.3 Ancillary Energy Needs
All ancillary energy needs for the SNG-from-coal
plant are supplied internally by burning coal in an auxiliary
boiler. Therefore, no ancillary energy needs are considered.
3.4 Products and By-Products
The SNG-from-coal module is based on the production
of 1012 Btu/day of SNG. The only saleable by-products formed
and recovered from the process are ammonia and elemental sulfur.
Hydrogen sulfide removed from the synthesis gas is treated in a
Glaus plant. The Glaus tail gas is sent to a Wellman-Lord unit
where S02 is removed and recycled to the Glaus unit. In addi-
tion, a Wellman-Lord unit is utilized to treat the flue gas
from the auxiliary boiler and steam superheater. The SOa
removed in these units is also sent to the Glaus and Wellman-
Lord units, respectively. Total elemental sulfur recovered in
the Glaus unit amounts to 410 tons per day for a western coal
feed and 2,330 tons per day for an Illinois coal feed. Seventy
percent of the nitrogen in the coal feed is assumed to form
ammonia, which is washed from the synthesis gas and recovered in
an ammonia still (HI-083). Total ammonia recovered is 656 tons
per day for an Illinois coal feed with 1.37% N2.
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III-D. High Btu Coal Gasification
3.5 Efficiency
• It is conceivable to define three efficiencies for
a process. These are the primary product efficiency, the
total product efficiency and the overall efficiency. The pri-
mary product efficiency is defined as the energy content of the
primary product(s) divided by the energy content of the feed.
The total product efficiency is defined as the energy content
of all products and by-products divided by the energy content
of the feed. The overall efficiency is defined as the energy
content of all products and by-products divided by the total
energy input to the system, i.e., feed energy content and
ancillary energy requirements.
For the SNG-from-coal module there are no ancillary
energy requirements (see Section 3.3). The only by-products
recovered from the process are ammonia and sulfur. These
compounds are not normally considered as fuel or energy sources.
Therefore, the by-product energy content is zero. Thus, for
the SNG-from-coal module all three efficiency definitions give
the same numerical value. For an Illinois coal feed the
efficiency is 67.9%.
3.6 Land Usage
Land requirements for an SNG-from-coal plant include
areas for processing equipment, coal storage and water treatment
facilities. It has been estimated that 165 acres are required
for a plant capable of producing 236 x 109 Btu/day of SNG
(AI-013). Converted to a basis of 1012 Btu/day, this gives
land requirements as 700 acres.
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III-D. High Btu Coal Gasification
3.7 Occupational Health
The data on injuries, deaths and man-days lost for
the SNG-from-coal module are taken directly from Battelle
(BA-230). These numbers are converted from Battelle's basis
of production of 106 Btu of SNG to Radian's basis of production
of 1012 Btu/day of SNG.
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III-D. High Btu Coal Gasification
4.0 MODULE EMISSIONS
4-.1 Air Emissions
Air emissions for the SNG-from-coal module arise
mainly from the secondary parts of the system. The emissions
from the auxiliary boiler, steam superheater, coal dryers and
sulfur recovery system account for almost all of the emissions.
None of the gasification train units should emit any pollutants
directly to the air.
Sulfur emissions from the coal dryers are calculated
from coal rates and the coal sulfur content. N0x and particulate
emission from the dryers are calculated using Hittman data (HI-083).
The NOX factor is 0.535 Ib of N0x per 10 Btu of coal burned.
Particulate emissions are limited to 0.03 grains/DSCF, with
24,000 DSCF required to produce a ton of dry coal.
Emissions from the auxiliary boiler and steam super-
heater are calculated from coal rates, coal composition and emis-
sion factors taken from "Compilation of Air Pollutant Emission
Factors" (EN-071). For CO, hydrocarbon and NO emissions result-
X
ing from firing western subbituminous coal, the coal rate is con-
verted to equivalent tons of 12,000 Btu/lb bituminous coal (HI-083)
In order to evaluate the effect that particulates,
SOa, NOX, CO and hydrocarbon emissions have on ambient air
quality, it is necessary to define certain stack parameters
used in calculating ambient air conditions. Mass and volumetric
flow rates are calculated from material balances. Stoichiometric
combustion is assumed with 2570 excess air. Volumetric flow rates
are based on exit gas temperatures. Stack heights,gas velocities
and exit temperatures are assumed, while stack diameters are
calculated from gas velocities and volumetric flow rates.
C-131
-------
III-D. High Btu Coal Gasification
Table 4-1 lists the air emissions and stack parameters
for the individual sources of SNG-from-coal plants. Particulate
emission are reduced 99.5% by utilizing electrostatic precipi-
tators and Wellman-Lord scrubbers to treat the flue gas from
the auxiliary boiler and steam superheater. In addition, the
Wellman-Lord scrubber reduces sulfur emissions by 95%.
Sulfur emissions from the sulfur recovery unit are
calculated by performing a sulfur balance around the sulfur
recovery unit. H2S removed from the synthesis gas in the acid
gas removal unit is processed by a Glaus unit to give elemental
sulfur. A Wellman-Lord scrubber treats the Glaus tail gas~. All
S02 recovered by the Wellman-Lord unit is recycled to the Glaus
unit. Storage emissions for NH3 and hydrocarbons are calculated
using storage capacity and EPA emissions factors (EN-071), assum-
ing use of best available control techniques.
The ability of a gasification process to limit its
air emissions to those given above will depend to a large ex-
tent on the prevention of fugitive emissions from pump seals,
joints, flanges, etc. Proper maintenance should allow fugitive
wastes to be controlled.
4.2 Water Emissions
Based on data from EL-052, liquid wastes from an SNG-
from-coal plant capable of producing 275 x 109 Btu/day of SNG
are 450,000 Ib/hr or 900 gpm. On a 1012 Btu/day basis approxi-
mately 1,640,000 Ib/hr of liquid wastes are produced. These
wastes contain high levels of dissolved solids, hazardous organic
and trace inorganic compounds, and possibly carcinogenic organic
species.
C-132
-------
O
I
LO
TABLE 4-1
SHR-FROM-COAL MODULE AIR EMISSIONS AND STACK PARAHETERS
Basis: 10" Bcu of SHO Output/day
Source
A. Coal Drying
6. Auxiliary
Boiler and Steam
Superheater
C. Sulfur Recovery
Unit
D. Storage
TOTAL
Heat
Input
MM Btu/IIr
595
9,110
51.700
-•
Fuel
Illinois
Coal
i»
it
Emissions Ibs/hr
^articulates
215
729
•_
944
S02
3890
2830
3670
-
10390
Total
Organics
126
_
-
126
CO
414
„
-
414
N0,r
319
7450
__
--
7769
Stack Parameters
IIH,
-•
,. .
54.7
54 . 7
Mass
Flow
Ibs/hr
0.649x10'
10.1x10'
4.84x10'
ACFM
0.190x10'
3.06x10'
1.04x10'
Velocity
FPS
60
60
60
Height
Ft.
300
500
300
50
Temperature
- OF
250
250
250
Diameter
Ft.
8.20
32.9
19.2
P-
OP
Cd
rt
O
O
O
(^
to
P-
Hi
H-
O
rt
-------
III-D. High Btu Coal Gasification
Because of the presence of these hazardous compounds
in a gasification plant's liquid wastes, these facilities are
assumed to operate in a "zero liquid discharge" manner. There-
fore, provisions must be made to safely dispose of these wastes
or incorporate them in a total water recycle plan. At the pre-
sent time, the exact composition of these liquid wastes is
not known. Thus, possible schemes for treating and recycling
wastewater have not been devised.
For plants located in areas where a sufficient amount
of solar evaporation occurs, the use of lined evaporation ponds
could be the most cost effective means of achieving zero l-iquid
discharge. In areas where evaporation ponds are not feasible,
the liquid wastes must be treated and reused. Possible treating
methods could include:
1) ionic exchange
2) reverse osmosis
3) chemical treatment
4) biological treatment
5) forced evaporation
6) stripping.
For plants located in the Chicago area, zero liquid
discharge is assumed to be achieved by total water recycle although
the means of obtaining this goal are not ascertainable at this
time. Moreover, the impact of these treatment demands on ancillary
energy requirements and/or land use cannot be determined for
these plants and hence is not reflected in Table 3-1.
C-134
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III-D. High Btu Coal Gasification
4.3 Solid Wastes
Solid wastes from an SNG-from-coal plant include ash,
primary water treatment sludge and wastes from the ammonia
recovery unit. Any sludges resulting from biological treatment
of liquid streams can probably be used as fuel to fire the
auxiliary boiler. The amount of coal ash and slag produced is
calculated from coal rates and compositions. The amount of
particulates emitted to the air is substracted from the total
ash present in the coal feed. Ammonia still wastes are taken
as 115 tons/day for a plant capable of producing 250 x 109 Btu/
day of SNG (HI-083). This is then scaled to an output of'1012
Btu/day of SNG. The amount of primary water treatment sludge is
calculated from (1) intake water requirements, (2) the assumption
that 500 ppm of suspended solids are present in the make-up water,
and (3) all suspended solids are removed by treating.
The SNG-from-coal plant is assumed to be a mine mouth
operation and hence, all solid wastes are expected to be disposed
of as mine fill.
4.4 Thermal Discharges
Thermal discharges to water bodies are eliminated by
utilizing wet cooling towers. If an adequate supply of water
is not available, air cooled condensers could replace cooling
towers.
C-135
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APPENDIX C
III-E. COAL LIQUEFACTION
C-136
-------
III-E. Coal Liquefaction
1.0 INTRODUCTION
,Coal liquefaction is a conversion process that is
designed to produce synthetic hydrocarbon liquids from coal.
Since the hydrogen to carbon ratio of coal is 0.82 while that
of crude oil is 1.77 (SA-109), a liquefaction process must
increase the H:C ratio of the coal. The essence of coal
liquefaction is, therefore, to crack the coal molecule and
either add hydrogen or remove carbon in order to increase
the H.-C ratio. The bonds of the coal molecule may be attacked
either thermally or chemically with the use of hydrogen.
Hydrogen serves the twofold purpose of facilitating the break-
down of the coal molecule and, by partial hydrogenation, pro-
viding a higher H:C ratio in the product. Due to these advan-
tages, most liquefaction processes employ hydrogen in some
fashion. The manner in which, or if, hydrogen is utilized is
a distinguishing characteristic of the various liquefaction
processes.
C-137
-------
III-E. Coal Liquefaction
1.1 Basic Liquefaction Methods
Liquefaction processes may be separated into two
basic groups -- processes that rely solely on heat to crack
the coal molecule (carbonization processes) and processes
that provide hydrogen in some form to facilitate the dissolu-
tion of the coal. The lure of carbonization processes is the
apparent simplicity involved with just heating the coal. The
advantage of adding hydrogen is that the amount of liquid pro-
duct which can be generated is not limited by the low hydrogen
content of the coal.
Processes which utilize hydrogen can be classified
according to how the hydrogen is added. Three types of coal
liquefaction processes which utilize hydrogen are the following
(1) Direct hydrogenation processes route
a stream containing molecular hydrogen
into the reactor with the coal slurry.
(2) Solvent hydrogenation processes utilize
a hydrogen donor solvent to dissolve the
coal and subsequently regenerate the solvent
for recycle by hydrogenation in a separate
vessel.
(3) Gasification - synthesis processes produce
liquid fuels by first gasifying the coal and
then converting the gas to liquid by a
Fischer-Tropsch synthesis. The hydrogen
is introduced into the system as steam to
the gasifier.
C-138
-------
III.E - Coal Liquefaction
Figure No. 1-1 illustrates this breakdown of liquefaction
processes. Not that some overlap can exist between direct
hydrogenation and solvent hydrogenation processes since direct
hydrogenation processes use a recycle solvent to slurry the
coal to the reactor.
Coal
Liquefaction
Methods
Chemical
^(Hydrogen Assisted)
Thermal
Direct
Hydrosenation
Solvent
Hydrogenation
CONSOL
Catalytic
H-Coal
Synthoil
GCCL
Gasification-
Synthesis
SASOL
Carbonization
U.S.B.M. Entrained Bed
COED
Lurgi-Ruhrgas
Garrett Flash Pyrolysis
Non-Catalytic
SRC
FIGURE 1-1. - CLASSIFICATION OF LIQUEFACTION PROCESSES
C-139
-------
III-E. Coal Liquefaction
1. 2 Common Technology
Despite the various approaches to coal liquefaction,
much common technology is used in the different liquefaction
processes. Most coal liquefaction processes differ in the
reaction or dissolution step where the new technology
developed for coal liquefaction is involved. Apart from the
reaction step, the operations associated with coal liquefac-
tion are accomplished with existing technology. Coal processing
prior to the reaction is essentially the grinding and drying
procedures used in the coal industry, while the gas/liquid
processing after the reactor is accomplished with conventional
petroleum refining techniques. The general processing steps
involved in coal liquefaction are shown in Figure 1-2.
These processing steps are as follows:
coal preparation
reaction and solid separation
fractionation
gas recovery and treating
sulfur recovery
naphtha or light oil hydrotreating
heavy oil hydrotreating
In addition to these main processing steps, a
liquefaction plant will have many auxiliary operations such
as power generation, ammonia separation, and water treatment
facilities.
C-140
-------
Fuel Gas
O „ , Reaction
i « •. Coal anii _ .
,_, Loai i i » Preparation -> Solid * traccio
-P~ Separation
1
Solids
(Ash)
•FIGURE 1-2. GENERAL PR
nator
DCESSING
Gas Recovery
Treating
Sulfur
** Recovery
I
Sulfur By-Product
Naphtha or
Product
M
H
l-J
l
O
I-1
STEPS IN COAL LIQUEFACTION ^
1 '•
c
fD
Pi
O
rt
H-
; O
a
-------
III-E. Coal Liquefaction
Steps in coal liquefaction processes where common
processing is utilized are as follows:
(1) Coal Preparation - All processes require
some degree of coal preparation which
normally consists of grinding and drying
the coal.
(2) Gas Liquid Separation - Following dis--
solution, 'the reactor effluent must
be depressurized and the light ends
separated (flashed) from the liquid
product.
(3) Acid Gas Removal and Sulfur Recovery -
Acid gases must be removed from the fuel
gas stream and routed to a Glaus unit
for sulfur recovery. A tail gas treating
unit will usually work in conjunction
with the Glaus unit in order to reduce
SO emissions.
X
(4) Liquid Product Separation - Essentially
the same basic liquid products can be
produced from each process. These liquid
products will normally be separated by
distillation and may include naphtha,
fuel oil, and residual oil.
(5) Product Desulfurization - Liquid product
streams will require hydrotreating for
desulfurization. Depending upon the
quality of oil from the reactor (gravity,
viscosity, pour point) and the product
C-142
-------
III-E. Coal Liquefaction
required, the more severe form of
hydrocracking may be employed to
obtain the desired product.
In,addition to these similarities, processes which
add molecular hydrogen (direct hydrogenation and solvent
hydrogenation) have the same basic steps throughout the
dissolution process. Areas of similarity among these
processes are as follows:
(1) Coal preparation
(2) Slurrying coal
(3) Preheat and dissolution
(4) Cooling and removal of gases
(5) Pressure let-down and removal of vapors
(6) Separation of solids
(7) Gasification of char
(8) Hydrotreating filtrate
(9) Separation of products and solvent for recycle
An illustration of the flow through these processing steps is
shown in Figure 1-3. Note that the main difference in
direct hydrogenation and solvent hydrogenation processes is
the method of hydrogen addition. The gasifier in these processes
serves the two-fold purpose of solids utilization and hydrogen
production.
C-143
-------
III-E. Coal Liquefaction
catalyst bed. Hydrogen consumption is approximately 9000 SCF/
ton coal. A schematic flow diagram of the Synthoil process is
shown in Figure 1-7.
Successful bench-scale tests have been conducted
with a 5/16 in. I.D. by 68 ft. reactor. Currently, tests
are in progress with a 1.0 in. I.D. reactor. Test results
for the Synthoil process are good. Coals containing 1.3
to 4.6% sulfur and 10 to 17% ash have been processed to yield
oils containing 0.1 to 0..3% sulfur and 1.0 to 2.0% ash. The
liquid yield is approximately 3 bbl oil per ton of coal. The
Synthoil process is designed to produce low sulfur fuel oils.
The degree of hydrogenation determines the product charac-
teristics and uses.
1-3.1.4 Solvent Refined Coal
Pittsburg and Midway Coal Mining Company's Solvent
Refined Coal Process was originally developed to produce a de-
ashed and desulfurized solid for power plant fuel. Initial
work began in 1962 under contract to the Office of Coal Research.
Small batch and continuous flow reactor studies were the fore-
runner of a 1 TPD pilot plant, with a 50 TPD pilot plant
currently being constructed at Tacoma, Washington. Recent
work has modified the process to yield liquid products.
In this process coal is pulverized (50-200 mesh)
and mixed with a recycle solvent similar to anthracene oil.
Slurry mixture is typically 2 to 3 parts solvent with 1 part
by weight coal. The slurry is mixed with hydrogen and routed
to the reactor. Reactor conditions are approximately 850°F
and 1050 PSIG. The SRC process differs from the other
direct hydrogenation processes in that no catalyst is employed
in the reactor. The reactor consists of four vertical tubes
C-144
-------
1
Coal &
o
I
I—1
-p-
Ul
Prepare
Cool
—9
~b
Slurry
Coal and
Solvent
Separate
Solvent from
Product
1
Product
fh
t
I Hydrogenate t
' and I
*-{ Desulfurize ^
i Extract I
L 0- J
•f
1
! H2
Preheat
and
Dissolve
Coal
Remove
Mineral Matter
and
Organic Solids
i
/
Generate
Hydrogen
— $>
1
3 —
Cool
and
Remove
Gases
4ydrocarbon Gases
t
Let -down
Pressure and
Remove
Condensible
Vapors
3—
Ash
M
I
O
O
HI
PI
o
rt
H-
o
FIGURE 1-3
PROCESSING STEPS IN LIQUEFACTION PROCESSES ADDING MOLECULAR HYDROGEN
(KA-124)
-------
III-E. Coal Liquefaction
1.3 Liquefaction Processes
The main differences in coal liquefaction processing
occur in the dissolution or reaction step. Due to the various
conversion processes which may be utilized (direct hydro-
genation, solvent hydrogenation, gasification-synthesis, and
carbonization), the reactors may differ considerably. Reactors
which are employed in liquefaction processes include open
vessels, stirred vessels, fixed bed, and fluidized bed-.
Operating conditions change according to reaction mechanism
and reactor types. Solid handling facilities and miscellaneous
support facilities also depend upon the reaction procedure"
employed. Operating conditions and typical products for
liquefaction processes utilizing molecular hydrogen are shown
in Table 1-1.
1.3.1 Direct Hydrogenation Processes
Much of the work currently being done with coal
liquefaction involves processes which route hydrogen into the
reactor. Processes of this type include H-Coal by Hydrocarbon
Research Incorporated, Gulf Catalytic Coal Liquids by Gulf
Research and Development, Synthoil by U.S. Bureau of Mines, and
Solvent Refined Coal (modified) by Pittsburg and Midway Coal
Mining Company. The first three processes utilize a catalyst
in the reactor while the Solvent Refined Coal Process does
not require a catalyst.
1.3.1.1 H-Coal Process
The H-Coal Process was jointly developed through
the efforts of Hydrocarbon Research, Inc. (HRI) and the
Office of Coal Research (OCR). The process is carried out
C-146
-------
TABLE 1-1
n
PROCFSS
Hydrogen used
in dissolution?
Subrrquent Extract
lly.lvoi;onation?
Catilytlc Dlssol.
A]-(ir.i:«lr it..-
Ri-.icior Tfiipcrature.
Realtor Pressure.
Coa 1
S-ilfur. Ut.Z
Solvent to Coal
R.itlo (to slurry).
Percent Coal
Dissolved (MAT).
Hydrogen Consump-
tion Sr.f/ton Coal
(MM).
Sntiils Separation,
Sol Us Content In
Product .
Principal Products
1. Fuel
Yield bbl/ton
API (\ravlty
Viscosity
Sulfur, Vt.Z
Nitrogen, Wt.Z
2. Fuel
API gravity
Yield bbl/ton
Viscosity
Sulfur, Wt.Z
Nitrogen, Wt.Z
COAL LIQUEFACTION PROCESS OPERATING CONDITIONS AND TYPICAL
PRODUCTS (KA.-124)
H-COAL PARSONS MODIFIED PAMCO BUR. OF GULF CCL P^.0^
Yes
No
Yes
850*
3000 pslg
111. No. 6
5Z
l:l(by Wt.)
90%+
15,100
llylroclones
and/or
filtration
Fuel Oil
1.73 bbl/ton
-l.l'API
0.5Z
Naphtha
38.4*API
0.5'ibbl/ton
<0. 1%
PAMCO
Yes
Yes
No
B40°F
1200 pslg
111. No. 6
3.38%
2.0:l(by Wt.)
90%+
12,600
Filtration
Residual Fuel
Oil
1.43bbl/ton
-9.7°API 60/60
<0.5%
Distillate Fuel
Oil
13.9'API 60/60
0.71 bbl/ton
0.2%
(S.SERV.)
Yes
No
No
850'F
1500 pslg
__
5%
2:l(by Wt.)
90%+
-------
III-E. Coal Liquefaction
in an ebullated bed reactor in the presence of hydrogen and
a cobalt molybdate catalyst. The ebullated bed reactor,
shown in Figure 1-4, is the heart of the process. The
fluidized bed concept allows a catalyst to be used without
the plugging problems inherent with a fixed bed reactor.
A flow diagram for the H-Coal process is shown in
Figure 1-5. Ground coal (-20 mesh) is slurried with a
recycle solvent, mixed with hydrogen, and routed through a
preheater to the reactor. Upward passage of the coal and
reaction products maintains the catalyst in a fluidized state.
The coal is ground finer than the catalyst (1/32-1/16 inch)
allowing passage through the catalyst. Unreacted solids are
removed at the top of the reactor along with the liquid product,
while the coarser catalyst is retained in the reactor. Catalyst
can be added and withdrawn continuously in order to maintain
catalyst activity. Internal turbulence is insured by an
internal slurry recycle. The reactor operates at 800-900°F
and 1500-3000 PSIG. Products typically would be a naphtha
(38.4° API) and a fuel oil (-3.1° API). The estimated overall
thermal efficiency is 69.6% (KA-124).
Solids separation is accomplished by hydroclones
followed by a rotary drum filter. H-Coal yields for bitumi-
nous and subbituminous coals are shown in Table 1-2 (HE-055).
Conversion for the bituminous coal is given as 89.3 wt% with
conversion for the subbituminous coal as 81.4 wt%.
The H-Coal process was piloted in a 3 ton/day
pilot plant. Conversion of approximately 88% was obtained,
corresponding to a liquid yield of approximately 4.3 bbl per
ton of moisture and ash-free coal. The process has demonstrated
good desulfurization characteristics producing oils containing
less than 0.5% sulfur from 3.4% sulfur coal.
C-148
-------
III--E. Coal Liquefaction
Vapour
Catalyst
Liquid ond Ash Level — -
Catalyst level
Recycle Tube
Liquid—Solid
Clear Liquid
Catalyst
Plenum Chamber
Coal Slurry
Hydrogen
FIGURE 1-4
H-COAL EBULLATED BED REACTOR
C-149
-------
Water
104 T/D
Slurry
Preparation
Feed Cool
Ul
O
Vent Gases
Fuel Gas (used for
process fuel)
> Sulfur-19.5 T/D
Water
Ammonia
Let
Down
Flash
System
Mineral
Matter
119.4 T/D
NQPhth2396 8/D
•M.662B/D
H-Coal Process for Fuel Oil Production—Devolatilization Plant
(KA-124) '
o
o
HI
o
rt
H-
O
FIGURE 1-5
-------
-E. Coal Liquefaction
TABLE 1-2
YIELDS BASED ON MOISTURE AND ASH-FREE COAL (HE-055)
Illinois No. 6 bituminous coal
Light gas, C,-C,
Liquid product
Unconverted char
Hydrogen sulfide, water, ammonia
Yields.
by weight
10.2
71.0
10.7
14.0 '
Conversion =
maf cool-char
maf coal
(100) = 89.3 7, by weight
Liquid product inspections
ASTM
cut points
C4 to 400°F.
400° to 680°F.
680° to 97S°F.
975°F.+
Total
% '
by volume
31.6
39.7
15.8
12.9
100.0
Degrees,
API
49.2
21.1
0.3
-20
Liquid yield
% by weight
of moisture and
ash free coal
18.5
27.5
12.7
12.3
71.0
Liquid yield
barrels per ton
of moisture and
• ash free cool
1.35
1.70
0.67
0.55
4.27
Nitrogen,
p.p.m.
-
1,000
1,700
4.100
Sulfur,
' p.p.m.
990
1,600
1,000
Wyoming subbituminous cool
gas, C,-C,
Liquid product
Unconverted char
Hydrogen sulfide, water, ammonia
Carbon monoxide and carbon dioxide
Conversion = 81.4 % by weight
Liquid product inspections
Yields,
by weight
10.8
56.1
18.6
12.9
6.6
ASTM
cut points
C, to 400°F.
400° to 650°F.
650° to 975°F.
975°F.+
Totol
%•
by volume
39.4
27.6
18.0
15.0
100.0
Degrees,
API
50
21
4
-16
Liquid yield
% by weight
of moisture and
ash free coal
18.5
15.5
11.1
11.0
56.1
Liquid yield
barrels per ton
of moisture and
ash free coal
145
0.95
0.62
0.52
3.44
Nitrogen,
p.p.m.
2,000
3,000
6,000
Sulfur,
p.p.m*
<700
•<700
<700
-------
III-E. Coal Liquefaction
1.3.1.2 Gulf Catalyst Coal Liquids
Another direct hydrogenation process is the Gulf
Catalytic Coal Liquids process developed by Gulf R&D. Work to
date has been limited to bench-scale activity, although a 1 TPD
pilot plant is under construction. This process utilizes a fixed
bed reactor. Processing steps are similar to those used in the
H-coal process in that ground coal is slurried with a recycle
solvent, mixed with hydrogen, and routed through a preheater to
the reactor. Reactor operating conditions are 800-900°F and
3000 PSIG. Approximately 9170 of the coal (MAF)* is dissolved.
Solid separation is achieved by hydroclones followed by rotary
drum filters.
Product yield is three barrels per ton of coal
charged. Approximately 72% of the product is a heavy (9° API)
fuel oil with the remaining 28% being equilavent to a distillate
fuel cut. A flow diagram of the Gulf process is shown in
Figure 1-6. This process routes the filter cake to a coker
unit rather than a gasifier. Hydrogen production is accom-
plished with a steam-hydrocarbon reformer.
1.3.1.3 Synthoil
The Synthoil process pilot plant operated by the
U.S. Bureau of Mines is another example of a direct hydro-
genation process. In this process a slurry of coal and recycle
solvent is mixed with hydrogen, preheated, and routed into
the reactor. The reactor is a 68-foot-long tube packed with
1/8 inch pellets of a cobalt molybdate catalyst. The reactor
is normally operated at 840°F and 2000-4000 PSIG. Over 90%
of the coal (MAF) is dissolved. The turbulent flow of hydrogen
and short residence time prevents the coal from plugging the
Moisture and ash-free.
C-152
-------
Heat Recovery
Exchanger
n
Ul
u>
Fired
Preheater
Fixed
Bed
Catalytic
Reactor
Let-down
a Flash
System
I80Q°F
T
^,
Water'
Reforming
H2
j-Vlydrocarbons
Gas Separation
8 Treatment
Hydro-
gen
Recycle
-> Ammonia
-> Sulfur
Coke
> Product
a Mineral
Matter
C Disti
Distillation
o
o
a>
Hi
(U
o
rt
p-
o
3
Liquid Product
FIGURE 1-6 - GULF R&D CATALYTIC COAL LIQUIDS PROCESS
(KA-124)
-------
Recycle
Coal Oil
Slurry
Preparation
I
I-1
Ol
H2 Rich
Recycle
Gas
Gas-
Cleaning
Separator
Tubular
Catalytic
Reactor
Heater
Recycle
Oil
Centrifuge
\
Oil
Cake
Oil
to Storage
Hydrogen
Production
M
M
I
o
o
Mi
P3
O
rt
H-
O
'FIGURE 1-7 - SCHEMATIC FLOW DIAGRAM - SYNTHOIL PROCESS
-------
III-E. Coal Liquefaction
in series with upflow of both liquid and gas. Initially, the
solvent is absorbed by the coal resulting in a significant
increase in slurry viscosity. As the residence time of the
coal increases, dissolution begins to occur. Over 90% of
the coal (MAF) is dissolved. Hydrogen consumption is approxi-
mately 12,600 SCF/ton coal. Solid separation is. accomplished
by rotary drum filters. Operating conditions at the filter
are 600°F and 150 PSIG. These conditions represent a com-
promise between ease of operation and reliability of equipment.
A flow diagram of the SRC process is shown in Figure
1-8. Liquid products consist of a naphtha, fuel oil (13.9° API)
and a residual oil (-9.7° API). Thermal efficiency is approxi-
mately 62.5%. Products from a Ralph M. Parsons Company design
of a 10,000 TPD demonstration plant charging Illinois No. 6
seam coal, heating value approximately 12,800 Btu/lb, are as
follows:
(1) Two primary boiler fuels:
(a) Four billion Btu/hr (minimum) of- a -9.7° API
liquid having a maximum sulfur content of 0.570,
a flash point of 150°F and a higher heating
value of 16,600 Btu/lb.
(b) Two billion Btu/hr (minimum) of a 13.9° API,
400-870°F boiling range hydrogenated liquid
having a naximum sulfur content of 0.2%, a flash
point of 150°F and a higher heating value of
18,330 Btu/lb.
(2) A 52° API hydrogenated, C^.-400°F boiling range
light oil containing 5 ppm nitrogen and 1 ppm
sulfur.
C-155
-------
Low Purity Hydrogen
o
I
o
o
HI
o
rr
P-
O
270 T/D
.FIGURE 1-8 - PARSONS--PAMCO HYBRID DEMONSTRATION PLANT SCHEMATIC
-------
III-E. Coal Liquefaction
1.3.2 Solvent Hydrogenation
Solvent hydrogenation is another category of coal
liquefaction processes. These processes physically dissolve
coal in a recycle hydrocarbon solvent. Coal dissolution allows
removal of insoluble ash and insoluble sulfur from the extract.
Any hydrogenation that occurs during extraction also converts
soluble organic sulfur to a removable form. The coal extract is
processed to remove ash, sulfur, and other impurities; to recover
solvent; and possibly to further hydrogenate and purify the liquid
product. Extract hydrogenation technology was pioneered in Germany;
however, it did not enjoy any particular success since this tech-
nology was not developed beyond the pilot scale. OCR renewed
development activity of extract hydrogenation in the 1960's.
An outgrowth of these activities is the Consol Synthetic Fuels
process.
1.3.2.1 Consol Synthetic Fuels Process
The Consol Synthetic Fuels process has undergone de-
velopment that has included the operation of a 20 ton/day pilot
plant at Cresap, West Virginia. This development project (known
as Project Gasoline) utilized a coal liquefaction flow scheme that
was designed by the Consolidation Coal Company. Figure 1-9
presents a block diagram of the flow scheme that was employed.
The Consol process developed by Consolidation Coal
Company employs a hydrogen donor solvent to dissolve the coal.
Feed coal is dried and ground in a coal preparation step, slurried .
with the recycle solvent, and routed through the preheater to the
reactor. Only solvents capable of transferring hydrogen are
effective for dissolution of the coal. Coal derived solvents such
as Tetralin appear to offer the best hydrogen transfer capabilities.
C-157
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III-E. Coal Liquefaction
Low-TcmperntufO
Carbonization
To Gas Plant
Extract
Hydrogenation
Synthetic
Crude Oil
Tar Acids
FIGURE 1-9 - BLOCK DIAGRAM OF THE CONSOL SYNTHETIC FUELS
PROCESS (SA-109)
C-158
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III-E. Coal Liquefaction
The reaction takes place in a stirred vessel. Since turbulence
cannot be provided by the H2 gas stream as in the previous pro-
cesses, the agitation is needed to insure the presence of the
hydrogen donor solvent whenever a coal molecule is cracked. The
reactor operating conditions are 700-750°? and 400 PSIG. Approxi-
mately 80% of the coal (MAF) is dissolved.
After removal of light ends and solids from the reactor
effluent the liquid stream must be hydrotreated. The hydro-
treating step not only desulfurizes what will be the product
streams but, by partial hydrogenation,. regenerates the recycle
solvent. Hydrogenation is achieved in a fixed bed reactor con-
taining cobalt molybdate catalyst, operating at 775-850°F and
3000-4200 PSIG. The hydrotreater effluent is separated by dis-
tillation into recycle solvent and the product streams of gas,
naphtha, and fuel oil. Overall thermal efficiency is approxi-
mately 69.2%.
Product yield and characteristics are presented in
Table .1-3.
1.3.3 Gasification-Synthesis (SASOL)
The gasification-synthesis system is the only procedure
currently being used to produce liquid fuels from coal on a com-
mercial scale. The 10,000 TPD commercial plant was built by the
South African Coal, Oil and Gas Corporation (SASOL) in the
Republic of South Africa and was financed through the Industrial
Development Corporation of South Africa, a government-supported
agency.
The SASOL process is an indirect route to the production
of liquid fuels from coal. The gasification-synthesis process
consists of two main steps.
C-159
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III-E. Coal Liquefaction
TABLE 1-3
- CONSOL PRODUCTS
Typical products. Pittsburgh seam coal (Irealand
mined) yields:
Product
Product/ton of
raw coal Characteristics
Gas
Naphtha
puel Oil
3.424 Mscf HHV 933 BTU/scf
0.52 bbl
1.52 bbl
Ammonia 11.00 Ib
Sulfur 71.00 Ib
Ash 213.60 Ib
58° API, 5.2 million BTU/bbl.
0.05S wt % S
10.3° API, 6.3 million BTU/bbl,
0.123 wt % S
C-160
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III-E. Coal Liquefaction
The coal is first gasified to produce a synthesis gas containing
hydrogen, carbon monoxide, and other constituents. After purifi
cation the H2 and CO undergo a Fischer-Tropsch synthesis to
produce a desulfurized, deashed liquid product.
A block flow diagram of the SASOL process is shown
in Figure 1-10. The coal is gasified in a Lurgi reactor with.
steam and oxygen at a temperature of approximately 1500°F and a
pressure of 380 PSI. A gas consisting primarily of hydrogen,
carbon monoxide, carbor: dioxide and methane is produced. The
basic reactions are as follows:
C + H90 •» CO + H~ (1-1)
£~ £*
C + 02 •* C02 (1-2)
C + 2H2 •* CH4 (1-3)
The gas is purified by a methanol wash for removal of sulfur
compounds and carbon dioxide. The purified gas is then reformed
with high purity oxygen and steam over a nickel catalyst to re-
duce the methane content. The reforming reactions are
H20 -
1/202 -
» CO -
» CO H
h 3H2
f- 2H2
The carbon monoxide and the hydrogen from the reformer are then
converted to liquid products by means of a Fischer-Tropsch synthesis
A simplified expression for the overall reaction is :
SCO + 17 H2 -» CgH18 + 8 H20 (1-6)
C-161
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III-E. Coal Liquefaction
27 000 kw
3000V
Gas
Recovery
(Cat
oa
Polym.)
L_
" .
•"•— «P-HB_^
Sicnm
500 Ib f/in?
800'F
Synthesis
Ammonium Sulphate
110 tons
Phenol
26 BBL
Tar 12 • 1 tons
Creosotes.
TOG DDL
Wax 247
Fuel Oil. 88-6 B8L.
Diesel Oil, 224-OB BL
Kerosine. 46-2BBL.
Gasoline, 414-0 80L
Gasolino. 3GS1 BBL
Diesel Oil, 142 BBL
Waxy Oil,'IG BEL
LP.G. 24 BBL
Ethanol, 12 BBL
Acetone, 15-61 BBL
Benzol. 59-5 BBL
Toluol, 10-6 BEL
HVY Naphtha, 7 BQL
Methyl Ethyl
Ketone, 21-B BBL
Crude Naphtha
105 BBL
FIGURE 1-10 -
BLOCK DIAGRAM OF THE SASOL PROCESS
(SA-109)
C-162
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III-E. Coal Liquefaction
Two types of reactors are used in the SASOL plant, a German
"ARGE" unit and the American Kellogg process. The arge pro-
cess is a fixed bed process which primarily yields heavy fuel
oils and diesel oils. The Kellogg process is a fluidized bed
process which produces lower boiling materials such as LPG,
gasoline and furnace oils. The Fisher-Tropsch synthesis takes
place at 600°F and 350 PSI over an iron catalyst. Gas velocity
is 4-7 FPS. The reformer effluent gas is split and routed through
both Fischer-Tropsch processes to produce a full range of liquid
products.
Although there has been intense interest in the SASOL
process, this plant was built and operates under conditions that
are different than those under which this country is striving to
liquefy coal. These differences are as follows:
(1) South Africa has no oil but does have
a large supply of coal.
(2) South African coal costs less than half
what it does almost anywhere else in
the world. In October 1973, the average
pit-head cost of South African coal
was about $2.50 per ton as compared to
more than $6.00 per ton in the United
States (BR-137). The SASOL plant con-
sumes 10,000 tons of coal per day; however,
only 5,000 tons are routed to the
gasifier, while half of the coal is
used for steam generation.
C-163
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III-E. Coal Liquefaction
(3) This plant was built piece by piece
over the last fifteen years with
government support, thus defraying
the tremendous capital investment.
(4) Also, the SASOL plant is devoted to
producing a wide range of chemical
products rather than optimizing the
output of liquid fuels. The efficiency
of the plant is such that 70% of the
heat in the feed coal can be converted
into gaseous fuel. However, if the
production of gasoline is maximized
only 40-4570 of the input heat is
recovered in the product.
1.3.4 Carbonization
Carbonization refers to liquefaction of coal by thermal
pyrolysis. Coal is simply heated in reactors to produce volatile
hydrocarbons and a carbon or char residue. The hydrocarbons are
recovered as a process gas and liquid oils while char remains
a by-product of the process. Liquid yields from various carboniza-
tion processes are shown in Table 1-4.
C-164
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III-E. Coal Liquefaction
TABLE 1-4
LIQUID YIELDS FROM VARIOUS COAL
CARBONIZATION PROCESSES
Process
U.S. Bureau of Mines
F.M.C. Corporation
Lurgi-Ruhrgas
Garrett Process
Yield. Iblton of coal
250—400
' 370—470
450—570
—700
.. .
(SA-109)
The apparent simplicity of carbonization has always
intrigued process developers and many efforts have been made
to come up with an economically attractive process. Unfortu-
nately several problems exist which prevent carbonization from
being a matter of simply heating the coal.
These problem areas are as follows:
(1) Residence Time: Much of the carbonization
technology evolved from the methods of
coke production. These procedures involved
batch-type operations over long periods
of time. An economic process for coal
liquefaction requires a significantly
shorter residence time and continuous
operation. 'Also, it has been discovered
that the shorter the residence time, the
less severe the cracking, and the greater
the liquid yield. Therefore, a good
carbonization process must be fast enough
to be practical on a large-scale and achieve
enough cracking to produce liquid products
without converting a substantial amount
into gas.
C-165
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III-E. Coal Liquefaction
(2) Coking Coals: Another problem involved
with carbonization is that the coals which
more readily yield liquid products are cok-
ing coals. These coals become plastic when
heated to decomposition temperature and
adhere to the reactor walls, rapidly
fouling the process. In order to keep
the process in line their fouling must
be minimized.
(3) Heat Requirement: The carbonization process
is highly endothermic since it involves the
thermal decomposition of the coal molecule.
Approximately 500 Btu of heat per pound of
coal nrocessed must be supplied. Although
some of the coal in the reactor may be burned
to supply the heat, this approach would greatly
decrease the liquid yield.
C-166
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III-E. Coal Liquefaction
1-3.4.1 U.S.B.M. Entrained Bed Process
The United States Bureau of Mines Entrained Bed
Process avoids many of the problems associated with carboniza-
tion processes by pneumatically injecting coal into a reactor
with air. An illustration of this process is shown in Figure
1-11. The gas velocity is sufficiently high so that the i
coal moves up the reactor in plug flow. Short residence time
provides high liquid yields. Agglomeration is avoided by
contacting the coal with air during the carbonization step,
partially oxidizing the surface of the coal particles. Un-
fortunately the off gases from this process are so diluted with
nitrogen that they cannot be used for pipeline gas.
FIGURE 1-11
Coal —
U.S.B.M. entrained bed carbonization
C-167
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III-E. Coal Liquefaction
1.3.4.2 COED
The COED process developed by FMC Corporation minimizes
agglomeration by heating the coal in stages. The process con-
sists of four reactors or heating stages. A flow diagram of
the COED process is shown in Figure 1-12. Each reactor is a
fluidized bed. In the first stage the coal is dried and heated
to approximately 600°F with steam and combustion gases. This
stage heating allows the softening point of the coal to be
increased. The coal is subsequently routed to the second reactor
where it is heated to about 850°F by recycle char and gas from
the third stage. The overhead gases from the second stage-con-
tain the product gases and liquids. This overhead is scrubbed
and routed to distillation for product recovery. Meanwhile, the
char from the second stage is routed to the third reactor. The
char is heated to approximately 1000°F by a combination of oxygen
and hot gases from stage four. The char from stage three is routed
to the fourth and final stage where it is heated to 1600°F with
oxygen. The last stage produces hydrogen which is needed for
hydrotreating the product tar. Synthesis crude oil produced
from the COED process has a very high viscosity and must be hydro-
treated rather severely to allow the oil to be pumped. Approxi-
mate yields for the process are 55 wt % char, 19% oil, and 17%
gas.
The FMC Corporation has developed the COED process with
financial support from OCR. A 36 ton coal/day pilot plant is
presently testing the process at Princeton, New Jersey. Plans
to pilot a gasifier which will utilize the char by-product of
the COED process have been initiated.
C-168
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III-E. Coal Liquefaction
Vent
Finos
Coal
Steam
Finos
Votatilcs
Gas
£*,
-------
III-E. Coal Liquefaction
1.3.4.3 Lurgi-Ruhrgas
The Lurgi-Ruhrgas process uses a mechanical mixer to
intimately contact coal and recycled hot char. A flow diagram of
the Lurgi-Ruhrgas process is shown in Figure 1-13. The hot
char supplies the heat for reaction. Agglomeration is no longer
a problem since not only does the char act as a diluent but the
mixer helps break up large particles. The liquid yield is fairly
high since the residence time in the mixer is only a few seconds.
Product vapors leave overhead. Char from the mixer is super-
heated for recycle by reacting it with air in a transport
reactor. Capital investment for this process appears to be
significantly higher than those of competitors.
FIGURE 1-13
Vent gases
Coal
Char Heater
Lurgi-Ruhrgas carbonization process
(SA-109)
1.3.4.4 Garrett Carbonization Process
Garrett Research and Development is developing a
flash pyrolysis coal liquefaction process. It is estimated
that the process can produce as much as 2 bbl oil per ton coal.
This compares to 1.5 bbl oil per ton coal processed for the
COED process. Economics for Garrett's carbonization process
are also reported to be favorable.
C-170
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III-E. Coal Liquefaction
The Garrett Flash Pyrolysis process utilizes an en-
trained bed reactor. A block flow diagram is shown in Figure
1-14. Crushed, dried coal is conveyed by recycle gas to
the entrained bed reactor. The reactor is heated by recycle
char from the char heater and maintained at 1100°F. Reactor
effluent passes through cyclones to separate the char from the
gas. Some of the char is cooled as product. The remaining char
goes to a char heater where some is burned to reheat the char to
approximately 1400°F for recycle to the reactor. The gas stream
is cooled and the tar (liquids) separated. The gas is separated
into three streams. One stream is used to entrain the coal fed
to the reactor. Another stream is routed to product after"acid
gas is removed. The remaining gas is .used in the production of
hydrogen for hydrotreating the process tar. At the hydro-
treater the tar is upgraded to obtain a synthetic crude oil.
Product yields are shown in Table 1-5. .
FIGURE 1-14
Garrett's coal pyrolysis process
plont r
*
^^— L_^
Gal toolef . .... ]
.. ond itrubotr Cos-l.iiu.d j
K.S
Prod
•-53
Cher
healer, i
1.100'- ,.
1,400'F.J S"
Product (hor
Hydro- .
Syitttotk end*
CGI
0171
-------
III-E. Coal Liquefaction
TABLE 1-5
PRODUCTS FROM GARRETT FLASH PYROLYSIS
(BO-117)
Typical products. Pryolysis of a. West Kentucky coal
produces:
Products Wt % Characteristics
Char 56 7 12,100 BTU/lb
Tar 35.0 About 80% C. 7% H2. 1.5% N2, 10% 0=,
1.5% S
Gas 6.6 TOOBTU/scf
Water 1.7
Total 100.0
C-172
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III-E. Coal Liquefaction
1.4 STATE-OF-THE-ART
As previously stated, only one commercial coal lique-
faction plant, SASOL, is currently in operation. However, this
particular plant operates under unique social, political, and
economic conditions which are not duplicated in the United
States. At present the other three procedures (direct hydro-
genation, solvent hydrogenation, and carbonization) appear to
be more likely candidates for use in this country.
1.4.1 Stage of Development
The most attractive processes in these categories are
all in the pilot plant or bench-scale stage.. The present de-
velopment stages of these processes are as follows:
(1) CONSOL - 20 TPD pilot plant
(2) SRC (modified) - 50 TPD unit under
construction - 75 Ib/day bench-
scale and 1TPD pilot plant
(3) H-Coal - 3 TPD pilot plant -
600 TPD unit in planning
(4) Synthoil - 0.5 TPD pilot plant -
8 TPD unit next stage
(5) COED - 36 TPD pilot plant
Conceptual commercial size plants have been designed for several
processes. These processes are listed in Table 1-6.
C-173
-------
O
I
TABLE 1-6
CONCEPTUAL COMMERCIAL SIZE COAL LIQUEFACTION PLANTS (KA-124)
Process
Modified SCR
Consol CSF ,
H-Coal
Cult CCL
Engineering
Desiqn
P.alph M.
Parsons (17)
Fostcr-
Kheeler (18) ;
Hydrocarbon
Research,
Inc. (10)
Gulf RSD(8)
Plant Size
tons coal/day
10,000
20,000(MF)
25,000(MF)
35,211
33,000
Coals
Illinois
No. 6,
3.41S
Pittsburg
Seam 4.2»S
Illinois
No. G,
5%S
Wyodak
0.7%
Big Horn
Main Fuel Oil
Products
0.2tS 13.9«API
0.51S -9.7»API
0.056%S 58'API
0.128»S 10.3'API
O.llS 27«API
0.51S -3.1»API
<0.2% 39.3°API
<0.04»S IS.l'SVI
Plant
Capital
Cost*
Million $
270
230
299
445
423
Date of
Study
1973
1972
1973
1973
1973
KW Poten-
tial at
354 Effi-
ciency
620
*
1530
1800
2000
2300**
Cost
S/KW
43S
ISO-
166.'
222-
184.
0.54%
. 0.041S 9*API
* Does not include interest during construction
•• Not given
*•• Estimated
(MF) Moisture Free
O
O
r1
H-
C
n>
HI
03
o
rt
o
3
-------
III-E. Coal Liquefaction
In addition to these processes, several research pro-
jects on liquefaction are currently underway. These projects
include the following:
(1) "Removal of Sulfur from Coal by
Treatment with Hydrogen" - Colorado
School of Mines
*
(2) "Intermediate Coal Hydrogenation
Processes" - University of Utah
(3) "Premium Fuels from Northern Great
Plains Lignite-Project Lignite" -
University of North Dakota
(5) Various projects on solvent refining
of coal - University of Kentucky,
University of Michigan, and University
of Auburn.
1.4.2 Problem Areas
Areas in which problems exist for coal liquefaction
processes are as follows:
(1) Thermal Efficiency: The low thermal
efficiency of liquefaction processes
dictates an intensive effort to
recover energy. Most liquefaction
processes claim an efficiency between
60 and 7070. Much heat is required to
crack the coal bonds which cannot be
recovered as liquid fuel. Any processing
C-175
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III-E. Coal Liquefaction
techniques that will increase
the efficiency should boost the
potential of coal liquefaction
as a viable alternative for the
production of liquid fuels. Since
these efficiency values were deter-
mined from pilot plant runs employing .
direct heat, some improvement may be
obtained on a commercial scale where
heat exchange can be utilized to
greater extent.
(2) Water Management: Large amounts of
make-up water are required in coal
liquefaction processes for use in the
gasifier, process water, and for
cooling. A design for a SRC demonstra-
tion plant requires 522 gal/ton coal
(PA-139) while a CONSOL plant design
requires 259 gal/ton (HI-083). Due to
the trace elements and other pollutants
in coal, the low supply of water at many
potential plant sites, and the increas-
ingly stringent clean water legislation,
liquefaction plants must achieve a status
of zero water discharge with maximum water
reuse. In order to obtain this goal a
comprehensive water management program
coupled with extensive water treating
facilities must be utilized. Such
facilities include fan air coolers,
mechanical draft cooling towers,
strippers to remove NHo and HLS, API
C-176
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III-E. Coal Liquefaction
separators, biological treating facil-
ities, and containment/evaporation
ponds. It should be noted that much work
is still required in this area and that
much is still unknown about the ability
to clean up coal liquefaction water.
For instance, high concentration of cer-
tain trace elements or trace organics
may have an adverse effect on the
bacteria used in biological treating
facilities. New technical developments
may have to occur before a zero water
discharge can really be achieved.
(3) Solids Separation: One of the critical
problem areas involves solid separation
from the reactor effluent. Separation
methods include filtration, hydroclones,
centrifuges, evaporation-distillation,
carbonization, and solvent washing.
Most processes propose to use hydroclones
followed by rotary drum vacuum filters.
Experience with hydroclones at the
Cresap pilot plant was poor. Typical solids
in the overflow was 12% (7% mineral residue)
while the underflow contained approximately
17% of the feed liquid. When the Cresap
pilot plant was shut down solids separation
was still an unresolved problem. Likewise
rotary drum vacuum filters offer problems.
Filtration efficiency increases with slurry
temperature but mechanical reliability de-
creases. Under the best conditions many
C-177
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III-E. Coal Liquefaction
mechanical problems can be expected from
rotary drum filters.
(4) Solvent-to-Coal Ratio: The solvent-
to-coal ratio may be dictated by many
conditions such as pressure drop,
coking in preheaters, or filtration
rates. If no restrictions exist
a compromise between slurry viscosity •
and pumping 'capabilities should be
made. Most processes operate at a
solvent-to-coal ratio between
1.5:1 to 2.5:1.
(5) Solvent Generation: Solvent generation
and control is potentially another
problem. Most liquefaction processes
requiring a solvent plan to start up
using a petroleum fraction and generate
the anthracene solvent.
(6) Preheat: Enough preheat must be applied
to reach reaction temperature; however,
the slurry should not be preheated to
the extent that appreciable reaction
takes place in the preheater. When
dissolution occurs the slurry should
be in the reactor under the most
favorable mass transfer conditions
for hydrogenation.
C-173
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III-E. Coal Liquefaction
(7) Pressure Let-Down: Malfunctioning
of the pressure let-down systems has
occurred in pilot plant operations.
Types of pressure let-down systems
that can be used are expansion through
a control orifice, controlled volume
let-down and turbine or piston expansion.
(8) Hydrogen Production: Hydrogen production
is one of the major expense items involved
with coal liquefaction. Many liquefaction
processes operate in conjunction with
gasifiers which maximize carbon utiliza-
tion as well as producing hydrogen for
the liquefaction process.
C-179
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III-E. Coal Liquefaction
2.0 MODULE BASIS
The module calculations discussed here are based on a
coal liquefaction plant producing 1012 Btu/day*of primary liquid
fuels. For a coal liquefaction plant these primary fuels in-
clude naphtha, fuel oil, and residual oil. The thermal ef-
ficiency** selected for this module is 62.5% (PA-139). This
value is the efficiency given for the modified Solvent Refined
Coal process by Pittsburgh and Midway Mining Company. The ef-
ficiency is chosen since the SRC process appears to be under
serious consideration for commercial operation, with a 50 TPD
pilot plant under construction and the design of a 10,000 TPD
demonstration plant completed. In addition, the demonstration
plant design by Ralph M. Parsons Co. (PA-139) provides a good
source for checking the heat and mass flows associated with a
liquefaction process. Using a thermal efficiency of 62.570 the
required coal feed is determined. A liquefaction module is an-
alyzed for an Illinois coal with a heating value of 10,820 Btu/lb,
Table 2-1 summarizes the emissions from the liquefaction module.
* All flow rates are based on calendar days
** Heating Value of Primary Fuels x i QQ
Heating Value of Coal Feed
C-180
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III-E. Coal Liquefaction
TABLE 2-1
SUMMARY OF ENVIRONMENTAL IMPACTS
COAL LIQUEFACTION MODULE
FEED: ILLINOIS GOAL (10,820 BTU/LB)
BASIS: 1012 BTU/DAY OUTPUT LIQUID FUEL
Air (Ib/hr)
Participates 612
S02 1957.7
NOX 8507.5
CO 340
HC 2607.6
Water (Ib/hr)
Suspended Solids 0
Dissolved Solids 0
Organic Material 0
Thermal (Btu/hr) 0
Solid Wastes (tons/day) 8423
Land Use (acres) 3254
Water Requirements 33.3 x 106
Occupational Health (per year)
Deaths 0.511
Injuries 9.9
Man-Days Lost 2372
Efficiency (%)
Primary Fuels Efficiency 62.5
Total Products Efficiency 62.5
Overall Efficiency 62.5
Ancillary Energy (Btu/day) 0
C-181
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III-E. Coal Liquefaction
3.0 MODULE DESCRIPTION
The coal liquefaction module which is described here
is assumed to utilize an Illinois coal with a heating value of
10,820 Btu/lb. An analysis of this coal is shown in Table 3-1.
For a 1012 Btu/day output with a 62.5% primary efficiency,
approximately 73,900 TPD of Illinois coal is required. From
Table 1-6 the average commercial size plant will charge approx-
imately 25,000 TPD coal.
3.1 Processing Steps
The processing facilities considered to be part of
the liquefaction module are as follows:
Coal stockpiling facilities
Coal preparation facilities
Coal slurry tank
Coal preheater and reactor
Flash System
Filtration System
Fractionation
Naphtha hydrotreater
Fuel oil hydrotreater
Char gasifier
Acid gas removal unit
Shift conversion unit
Methanation unit
Oxygen plant
Glaus plant
Tail gas treating unit
Ammonia separation facilities
Power generation unit
Steam generation boiler
Water treating facilities
Product tankage.
C-132
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III-E. Coal Liquefaction
TABLE 3-1
TYPICAL ILLINOIS COAL ANALYSIS
Heating Value Btu/lb 10,820
Sulfur Wt % 3.7
Ash Wt % 11.3
Water Wt % 14.4
Volatile Matter Wt % 33.4
Fixed Carbon Wt % 40.9
C-133
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III-E. Coal Liquefaction
The major processing steps are coal dissolution, pro-
duct fractionation, naphtha hydrotreating, fuel oil hydrotreating,
char gasification, acid gas removal, shift conversion, methanation,
oxygen plant, and sulfur recovery.
3.2 Flow Rates
Module flow rates are shown in Figure 3-1. Using the
SRC product distribution, the product yields are determined as
12,830 BPD distillate fuel and 89,920 BPD heavy oil. For a
1012 Btu/day output with a 62.5% primary efficiency, the coal
requirement is 73,900 TPD Illinois coal.
3.3 Heat Requirement
Typical liquefaction process heat demands are obtained
from the Parson SRC design (PA-139). The fuel gas heat require-
ments for the 10,000 TPD SRC plant are shown in Table 3.2. The
total heat requirement for this plant is given as 76.3 x 109
Btu/day or 3179 x 106 Btu/hr. Fuel gas is to supply 70.0 x 109
Btu/day with the difference being made up with residual fuel oil.
In order to determine emissions at specific sources fuel oil is
considered used as the product fractionation, fuel oil HDS,
naphtha HDS, and shift converter. These units are selected to
reflect the appropriate percentage of fuel oil being burned for
process heat.
For the Radian module, the difference in unit heat
requirements as shown in Table 3-2 (69.6 x 109 Btu/day) and the
total SRC heat requirement of 76.3 x 109 Btu/hr is used for power
generation and steam generation. Therefore, the heating require-
ments for these two demands are altered to show 1051.9 x 106
Btu/hr for power generation and 683.9 x 10s Btu/hr for steam
generation. Extrapolating to a 1012 Btu/day product basis the
total module heat requirement is determined to be 4.87 x 10ll
Btu/day. Process unit heat requirements are shown in Table 3-3.
C-184
-------
High Purity
Hydrogen Co -
Hydrotreacers
Methanator
O
i
co
01
73.900 TPD
Coal"
Feed
Coal''
Preparatiori
Slurry
Preparation
Shift
Conversion
Reaccor
To Acid Gas -«j-
Removal
Low Purity Hydrogen
I
Gas Flashing
and Solid
Separation
Gasifier
Char
8423 TPD
Acid Gas
Removal and
HI Separation
Fractionator
Sulfur
Recovery
-*>- Fuel Gas
Naphtha
Hydrocreater
Fuel Oil
Hydrotreater
89.420 BPD
Residual Oil
FIGURE 3-1 - LIQUEFACTION MODULE
-------
TABLE 3-2
Unit
Description
Fuel
(106 Btu/hr)
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
30
31
32
33
35
36
37
Coal Preparation
Coal Slurrying and Pumping
Coal Liquefaction and Filtration
Dissolver Acid Gas Removal
Coal Liquefaction Product Distillation
Fuel Oil Hydrogenation
Naphtha Hydrogenation
Fuel Gas Sulfur Removal
Gasification
Acid Gas Removal
Shift Conversion
C02 Removal
Methanation
Sulfur Plant
Oxygen Plant
Instrument and Plant Air
Raw Water Treatment
Process Waste Water Treatment
Power Generation
Product Storage
Slag Removal System
Steam Generation
Total Fuel Gas Consumption
1039.5
92.3
57.0
11.6
41.1
96.3
78.3
926.0
558.0
2900.1
C-186
-------
III-E. Coal Liquefaction
TABLE 3-3
MODULE HEAT REQUIREMENT .
BASIS,: 1012BTU/Day Product
HEAT REQUIREMENT
UNIT (1Q9 BTU/Day)
Coal Dissolution/Reaction 159.2
Distillation 14.2
Fuel Oil Hydrotreater 8.7
Naphtha Hydrotreater 1.8
Gasifier 10.5
Shift Conversion 14.7
Sulfur Recovery 12.0
Power Generation 161.1
Steam Generation 104.7
486.9
C-137
-------
III-E. Coal Liquefaction
3.4 Module Efficiency
Three different efficiency terms are defined for each
of the modules considered in this study. These three efficiencies
are defined as follows:
(1) Primary fuels efficiency:
Primary liquid fuels from the
liquefaction module are naphtha,
distillate oil, and residual oil.
The primary fuels efficiency is the
heating value of these three products
divided by the heating value of the
coal feed: This value is 62.5% for
this module (HI-083).
(2) Total products efficiency:
This efficiency credits any other hydro-
carbon products made. Sulfur and ammonia
are not included. Total products ef-
ficiency is the heating value of all
hydrocarbon products divided by the
heating value of the coal feed. Since all
the fuel gas produced by the module is
consumed and no other hydrocarbon by-products
are made, the total products efficiency is
equivalent to the primary fuels efficiency.
(3) Overall Efficiency:
This efficiency takes into account any
ancillary energy such as electricity that
may be supplied to a module. This efficiency
C-188
-------
III-E. Coal Liquefaction
is equal to the heating value of all hydro-
carbon products divided by the heating
value of the coal feed plus any ancillary
energy input to the module. Since the
coal liquefaction module generates its
own power, this efficiency is also equal
to the primary fuels efficiency.
The determination of the primary fuel efficiency for the
Illinois coal liquefaction module is shown in Table 3-4.
3.5 Water Requirements
The make-up water requirement for this module is
33.3 x 106 gal/day. This rate is determined from the SRC
design requirement of 5.2 x 106 gal/day (3626 gpm) for a
10,000 TPD plant producing 1.57 x 10M Btu/day.
3.6 Land Use
Based on a land requirement of 510 acres for a plant
producing 1.57 x 1011 Btu/day (HI-083), a land use figure of
3254 acres for a 1012 Btu/day module is determined.
3.7 Occupational Health
Occupational health data for this module is obtained
from the Battelle study (BA-230). This information, based on
10s Btu output, is as follows:
C-139
-------
III-E. Coal Liquefaction
deaths:
total injuries:
man-days lost:
1.4 x 10"9
2.7 x 10"8
6.5 x 10"6
Data for injuries and man-days lost due to injuries are from
the chemical industry. Assumptions which are made include a
death rate equivalent to 5% of total injuries and 6,000 man-
days lost/death. The values as presented in the Battelle re-
port are adjusted to a 1012 Btu output basis for this module.
TABLE 3-4
PRIMARY FUELS EFFICIENCY
Stream
Rate
Coal
Naphtha
Fuel Oil
Residual Oil
90,800 TPD
12,830 BPD
54,050 BPD
89,420 BPD
Heating Value
8806 Btu/lb
5.37xl09 Btu/BBL
6.10xl09 Btu/BBL
6.72xl09 Btu/BBL
Total Heating Value
1600xl09 Btu/day
68.9xl09 Btu/day
330.5xl09 Btu/day
600.9xl09 Btu/day
1012 Btu/day
PRIMARY FUELS EFFICIENCY = 10'2/l.6x1012 = 0.625
C-190
-------
III-E. Coal Liquefaction
4.0 MODULE EMISSIONS
Environmental effects resulting from air emissions,
water effluents, and solid wastes are discussed in separate
subsections below.
4.1 Air Emissions
Air emissions from the module result from fuels com-
bustion, coal preparation, sulfur recovery, ammonia storage,
petroleum storage and miscellaneous hydrocarbon losses. Air
emissions and stack parameters for the module are shown in
Table 4-1.
4.1-1 Fuels Combustion
Fuel combustion emissions sources are determined to
be the following:
liquefaction reactor preheater
product fractionator
fuel oil hydrotreater
naphtha hydrotreater
char gasifier
shift converter
power generation
steam generation
From information in the Parsons SRC design (PA-139) emission
sources at a particular unit are specified if more than one
potential source exists (naphtha HDS: reactor heater and
reboiler heater). Emissions from these sources are calculated
by use of the EPA fuel combustion factors for fuel gas and re-
sidual fuel oil. These factors are shown in Table 4r2. Power
C-191
-------
TABLE 4-1
AIR EMISSIONS AND STACK PARAMETERS
LIQUEFACTION MODULE - ILLINOIS COAL
BASIS: 1012 BTU OUTPUT/DAY
III-E, Coal Liquefaction
Source
1. Coal
preparation
2. Liquefac-
tion Re-
actors
(6 pre-
heaters)
TOTAL
3. Distil-
lation
(2 stacks)
TOTAL
4. Fuel Oil
HDS
A. Reactor
Heater
B. Reboiler
Heater
TOTAL
Heat
Input
mm Btu/Hr
1105
6633
295
590
209
155
.364
Fuel
1.07xlO*SCFl
6.44xlO*SCF!
1.835x10'
gal/Hr
3.67xlO'gal/
Hr
1.30xlO'gal/
Hr
963 gal/Hr
2.263x10'
3al/Hr
Emissions Ibs/Hr
Particulates
92.4
19.3
115.8
42.1
84.2
29.9
22.2
52.1
SO,
28.8
L73.2
L06.(
>13.:
75.:
56.1
LSI.:
Total
Organics
3.22
19.3
7.34
14.7
5.2
3.85
9.05
CO
18.2
109. 2
7.3*
14.7
5.2
3.85
9.05
NO
257.5
1545
73.4
146.8
52.0
38.5
90,5
Stack Parameters
Haas
Flow
Ibs/Hr
975x10'
5.85x10*
254.7x10'
509.3x10'
180.4x10'
133.5x10'
313.9x10'
i
ACFM
;
388x10'
97.5x10'
69.0x10'
51.1x10'
Velocity
FPS
60
60
60
60
Height
Ft.
200
200
200
200
Temperature
°F
450
450
450
450
Diameter
Ft.
11.72
5.37
4.94
4.25
-------
Table 4-1 (Cont.)
III-E. Coal Liquefaction
Source
5. Naphtha
HDS
A. Reactor
Heater
B. P.cbotlcr
Heater
TOTAL
6. Gasifier
A. Oxygen
Treheater
B. Steam
Super-
heater
C. Recycle
Char Iltr 1
D. Recycle
Char Htr I
TOTAL
1
Heat
Input
trra Btu'/Hr
50
24.6
74.6
94.2
85.4
140.4
115.8
435.8
Fuel
311 gal/Hr
153 gal/Hr
464 gal/hr
91.3x10*
SCFH
82.9x10*
SCFH
136.3x10*
SCFH
112.5x10'
SCFH
423x10 'SCFH
Emissions Ibs/Hr
Partlculates
7.16
3.52
10.68
1.64
1.49
2.45
2.03
7.61 .
SO*
18.0
8.9
26.9
2.46
2.23
3.67
3.03
11.4
Total
Orf»anlca
1.24
0.61
1.85
0.27
0.25
0.41
0.34
1.27
CO
1.24
0.61
1.85
1.55
1.41
2.32
1.92
7.20
N0^_
12. /.
6.12
18.5
21.9
19.8
32.7
•
27.0
101.4
Stack Parameters
Mass
Flow
Iba/Hr
43.2x10'
21.2x10*
64.4x10'
83.1x10'
75.5x10'
123.8x10'
102.4x10'
384.8x10*
I*
ACFM
16.6x10'
8.12x10'
33.1x10*
30.0x10*
49.2x10'
40.7x10*
Velocity
FPS
60
60
60
60
60
60
Height
Ft.
200
200
200
200
200
200
Temperature
oF
450
450
450
450
450
450
Diameter
Ft.
2.42
1.70
3.42
3.26
A. 17
3.80
o
I
-------
Table 4-1 (Cont.)
III-E, Coal Liquefaction
Source
7. ShifC
Conversion
A. Boiler I
B. Boiler II
C. Hot Shift
Her
TOTAL
8. Sulfur
Recovery
TGTU (/.
c cocks)
TOTAL
9. Power Gen-
eration
(6 units)
TOTAL
10. Steam
Genera-
tion (6
units)
TOTAL
Heat
Input
nm Utu/Hr
281.3
212.1
120.8
614.2
1118.7
6712
727.1
4362.5
Fuel
1.75xlO'gal/
llr
1.32xlO'gnl/
llr
0.75xlO»gal/
Ilr
3.82xl03gal/
llr
1.09xlO*SCFI!
6.52xlO'SCFli
0.706x10"
SCFH
4.24xlO*SCFl
Emissions Ibs/Hr
Particulates
40.25
30.38
17.25.
87.88.
16.3
97.77
10.6
63.5
SO*
.01.5
76. C
43.8
!21.9
222.5
890
29.:
175. <
19. (
114. (
Total
Organieo
7
5.28
3
15.28
1.09
6.52
0.71
4.25
CO
7
5.28
3
15.28
18.46
110.7!
12
72
NOV
70
52.8
30
152.8
i51.7
3910
423.0
2542.5
Stack Parameters
Masai
Flow
Ibs/Hr
242.9x10'
183.3x10'
104.0x10'
530.2x10'
l.OSxlO1
2.16x10*
988.3x10*
5.93xlO«
641.7x10'
3850x10*
ACFM
92.8x10'
70.1x10*
39.8x10'
403.3x10'
806.6x10'
392.9x10'
2.36x10*
255.3x10'
1532x10*
Velocity
FPS
60
60
60
60
60
60
Height
Ft.
200
200
200
200
200
200
Temperature
OF
450
450
450
450
450
450
Diameter
Ft.
5.73
3.77
3.75
11.95
11.79
9.50
o
I
-------
III-E, Coal Liquefaction
Table 4-1 (Cont.)
Source
1. Refining
Misc.
2. • Storage
TOTAL
0
i
vO
Heat
Input
nra Dtu/Hr
Fuel
Emissions Ibs/Hr
Particulntes
-
611.9
•
SO*
957.7
Total
Orpanics
2525
10.4
2607.6
CO
340.0
N0r
J507.5
NHJ
40.6
40.6
Stack Parameters
'Ha'a is
Flow
Iba/Hr
ACFM
Velocity
FPS
leight
Ft.
5
50
renperature
oF
Diataetei
Ft.
-------
III-E. Coal Liquefaction
TABLE 4-2
EPA EMISSION FACTORS (EN-071)
Fuel Combustion
Resid Oil
Fuel Gas lb/106ft3 lb/103gal
Emissions Power Plant Process Boiler Process Boiler
Particulates 15 13 23
S02 0.6 0.6 157 S*
HC 1 3 3
CO 17 17 4
NO 600 230 40
X
Aldehydes 1
*wt % sulfur in the fuel oil.
C-196
-------
III-E. Coal Liquefaction
plant emission factors for fuel gas combustion are used for
the power and steam generation sources. Process boiler emission
factors for residual oil are used for.fractionation, fuel oil
HDS, naphtha HDS, and shift conversion. Process boiler emission
factors for fuel gas combustion are used at the remaining
sources. Aldehyde emissions from fuel oil combustion are
combined with hydrocarbon- to give total organic emission.
Sulfur dioxide emissions from these sources are determined by
considering the fuel oil contains 0.3 wt 70 S and using the
refinery emission standard of 0.10 gr H2S/dSCF fuel gas.
Flue gas rates resulting from fuel combustion are
calculated by assuming stoichiometric combustion and 2070
excess oxygen. Combustion of one SCF of fuel gas results in
12.4 SCF of flue gas. Combustion of one gallon of fuel oil
results in 1820 SCF of flue gas. A stack velocity of 60 FPS
and a temperature of 450°F are assumed for dispersion modeling.
4-1.2 Coal Preparation
Entrained particulates are considered to be the only
emissions from coal preparation. A particulate emission factor
for a fluidized bed dryer of 20 Ib/ton coal is used to determine
the particulate emission rate (EN-071). This emission rate
is reduced 857, considering the use of cyclones and another 9570
by use of a bag filter (HI-083).
4.1.3 Sulfur Recovery
Sulfur dioxide 'is considered to be the only signi-
ficant emission from this source. The sulfur dioxide emission
is calculated by determining the following:
C-197
-------
III-E. Coal Liquefaction
(1) %HzS in the Glaus plant charge.
This value is approximately 55%
for Illinois coal (HI-083).
(2) Glaus plant efficiency. The
efficiency of the Glaus plant
is estimated from the equivalent
sulfur in the charge. Glaus plant
recovery efficiency is assumed to
be 96% for the Illinois•coal module
(BA-166).
(3) Sulfur dioxide in the tail gas
treating unit charge.
(4) Sulfur dioxide in the stack gas
assuming a 95% removal efficiency
in the tail gas treating unit (HI-083)
The Illinois coal module recovers 2,640 TPD sulfur with a
sulfur plant emission of 890 Ibs/hr S02.
Stack parameters are assumed to be 60 FPS and 450°F.
A flow rate is calculated using literature information on inlet -
and outlet gas compositions from a tail gas treating unit and
making a nitrogen balance (BE-148).
4.1.4 Ammonia Storage
The EPA emission iractor (EN-071) for the storage and
loading of ammonia (200 Ib/ton NHs) is used to determine ammonia
emissions. This factor is reduced by 99% considering the use
C-198
-------
III-E. Coal Liquefaction
of a packed tower scrubber. The amount of ammonia is calculated
assuming that 40% of the nitrogen in the coal forms ammonia.
Ammonia produced from the module is 487 TPD.
4.1.5 Petroleum Storage
The following assumptions based on literature data
and experience are formulated to calculate the hydrocarbon
emissions from petroleum storage:
(1) All feed and product storage is in
floating roof tanks.
(2) Storage capacity is two weeks (HI-083).
(3) Only naphtha storage will result in
significant emissions. Residual and
distillate fuel oil storage create
negligible emissions due to low vapor
pressures.
Using petroleum storage emission factors for storing gasoline
in floating roof tanks (0.033 Ib/day - 103 gal) hydrocarbon
emissions from storage are calculated to be 10.4 Ib/hr. These
emissions are assumed to occur at a height of fifty feet.
4.1.6 Miscellaneous Hydrocarbons
There can be numerous miscellaneous hydrocarbon
emissions in the liquefaction upgrading facilities which
escape from sources such as valve stems, flanges, loading
racks, equipment leaks, pump seals, sumps, and API separators.
These losses are discussed in Radian's Refinery Siting
Report (RA-119). Based on literature data, Radian found
that the miscellaneous hydrocarbon emissions amount to about
C-199
-------
III-E. Coal Liquefaction
0.1 wt % of refinery capacity for a new well-designed, well-
maintained refinery. This value of 0.1 wt % is used to deter-
mine miscellaneous emissions from the liquefaction upgrading
facilities. The composition of these hydrocarbons can be
expected to be a composite of all volatile intermediate and
refined products. The emissions are assumed to occur at a
height of five feet.
4.2 Water Effluents
Water effluents are nonexistent since the module is
assumed to operate with zero discharge (HI-083).
4.3 Thermal
Thermal discharge to water bodies is zero since no
water is discharged from the module.
4.4 Solid Wastes
Solid wastes are determined from the amount of ash
in the coal and solids in the make-up water. Radian assumed
500 ppm solids in the make-up water. Solid wastes resulting
from silt in the make-up water is 70 TPD. Ash produced by the
module is 8,353 TPD for Illinois coal. Total solid waste
from the module is 8,423 TPD.
C-200
-------
APPENDIX C
III-F. OIL SHALE PROCESSING
C-201
-------
III-F. Oil Shale Processing
1.0 INTRODUCTION
Oil shale is a naturally occurring deposit consisting
of a mixture of several minerals and kerogen, a solid organic
constituent which may be converted to conventional petroleum
products. Oil shale may normally contain anywhere from 4.0 -
28.7 wt. 7o kerogen. A typical oil shale will contain approxi-
mately 12 wt. % kerogen or about 30 gallons of oil per ton of
shale. Fischer assay data for various grades of oil shale are
shown in Table 1-1. Typical organic and mineral matter contents
for a 25 gallon of oil (per ton) shale is shown in Table 1-2.
In order to decompose the kerogen and obtain the
hydrocarbon products, the shale must be heated to approximately
900°F. This heating step, which is a basic requirement of all
shale oil processes, is normally accomplished in a retorting
vessel; however, some processes propose to retort the oil shale
underground (in situ). The manner in which the shale is re-
torted and the mechanism by which the necessary heat is supplied,
characterize the various shale oil processes.
1-1 Basic Retorting Methods
Shale oil processes can basically be divided into two
groups depending on whether the retorting is accomplished above
or below ground (ex situ or in situ). Ex situ processes deal
with more familiar technology and consequently are much more
advanced. The intriguing advantage of in situ processing is
the elimination of the massive solids handling and disposal
problems associated with ex situ processes. A comparison of
these two approaches to oil shale processing is shown in Figure
1-1.
C-202
-------
III-F. Oil Shale Processing
TABLE 1-1
DATA OBTAINABLE FROM THE MODIFIED FISCHER ASSAY
Typical Values
for Very~ for"Very"
Low For Medium For High High
Grade Grade Grade Grade
Shale Shale Shale Jnale
Oil, gal/ton 10.5 26.7 36.3 61.8
Oil, weight percent 4.0 10.4 13.8 23.6
Hater, weigh: percent 0.5 1.4 1.5 1.)
Spent shale, weight percent 94.4 85.7 82.1' 70.4
Gas, weight percent I.I 2.0 2.2 4.2
Loss, weight percent - 0.5 0.4 0.7
Source: GA-107
TABLE 1-2
TYPICAL COMPOSITION OF OIL SHALE SECTIONS AVERAGING
25 GALLONS OF OIL PER TON IN THE MAHOGANY ZONE OF
COLORADO AND UTAH
Weight-percent
Organic matter:
Content of raw shale 13.8
Ultimate composition:
Carbon 80.5
Hydrogen 10.3
Nitrogen 2.4
Sulfur 1.0
Oxygen. 5.8
Total 100.0
Mineral matter:
Content of raw shale 36.2
Estimated mineral constitutents:
Carbonates; principally dolomite 48
Feldspars 21
Quartz , 13
Clays, principally illite 13
Analcite 4
Pyrite 1
Total 100
(Source: US-093)
-------
(3A) NATURAL
(2C) HYDRAULIC
{2O ELECTRO-
(2C) CHEM. EXPLOSIVE
(38) NUCLEAR
IN-SITU (2-3)
OIL SHALE DEPOSIT
_l, ,l_
J
CONVENT/WAL (2)
FRACTURING
(2C) GAS DRIVE
(2C) ARTIFICIAL LIFT
f3cA) £ST«.) LUTING ««"GASESt2A)
PRODUCT
RECOVERY
o
ro
MINING j
CRUSHING
'RETORTING [
•"•"•""""'"''""X
[Room aPiitof (lA)
fUNDERGROUM) Cut and Fill (38)
CODE-
StaH of knosviedge cpplicoble to a'l shale
I. Reownobly well demonstrated
2. Seme expe'imcrrtol knowlwige
3. Ljltk; known
4. Conceptual
- wilh knowledge stenvning from :
A. Stale experience
B. Petroleum or other industry
experience
C. Bolh
(1C)
'GAS COMBUSTION {
UtJION (IA) l
TOSCO (I A)
HYDROGEN ATMOSPHERE (3A)
Bureou (IA)
Petrosix (2 A)
(UTILIZE
IDISPOSE
(2A)
[Mine fill (3B)
RewKjotate (2 A)
iDump
(1C)
GASOI.INE
DIESEL FUEL
JET FUEL
DISTILLATE FUEL OIL
RESIDUAL FUEL OIL
LIQUEFIED PETROLEUM GAS
AMMONIA (1C)
SULFUR (1C)
AROMATICS(2A)
SPECIALTIES (3 A)
COKE (1C)
PITCH (1C)
ASPHALT (1C)
WAX (2A)
August 1972
FIGURE 1-1 - RELATIVE STATE OF KNOWLEDGE OF VARIOUS OPERATIONS REQUIRED IN OIL SHALE PROCESSING
(Source: US-093)
o
H-
05
h-«
(D
O
O
tt>
CO
co
H-
d
CP
-------
III-F. Oil Shale Processing
In situ processing involves fracturing the shale to
allow injection of retorting fluids and the subsequent recovery
of the oil through wells. Proposed methods for fracturing the
shale include hydraulic, electric, chemical explosive and nuclear
methods. Possibilities for retorting include underground com-
bustion and injection of hot gases or steam. The products may
be recovered by using either the pressure from retorting fluids
or by applying artificial lift methods. Since in situ processes
are still in the conceptual stage (US-093.) , they do not repre-
sent a viable alternative for shale oil recovery at this time.
Ex situ processes basically contain a retort, solids
handling, and shale oil upgrading facilities. A flow diagram
for a typical shale oil process is shown in Figure 1-2. Of the
eight units shown, only the pyrolysis step (retorting) repre-
sents new technology. Shale oil upgrading is accomplished
with conventional petroleum refining techniques. All shale oil
processes can utilize the same shale oil upgrading facilities;
however, the manner in which the retorting is accomplished and
in particular the manner in which the necessary heat is supplied
distinguishes the various process.
Current ex situ processes involve either solid-solid
or solid-gas heat transfer. Processes which utilize solid-
solid heat transfer rely on heated solids such as ceramic balls,
sand, or spent shale particles to supply the retorting heat.
Such processes heat the particles in an external heater and then
mix them with the raw shale in the retort. After retorting,
the heat-carrying solids must be separated for recycle from the
spent shale. Ex situ processes which involve gas-solid heat
transfer use either internal gas combustion or external heat
generation. Processes utilizing internal gas combustion inject
air directly into the retort. The heat liberated by the result-
ing combustion of fuel gas and carbon residue provides the
C-205
-------
n
o
Raw
Shale J>"1"'
Ret
Spent
ort
: Shale
>
Pro
Separ
duct
ation
1
r*««
das
& fi
'o PI
To
Trea
|m-_.
Tre
£CO\
I
ant
Gas
:ing
i
%
Cok
.
:aL
rer
Fu
t
ing
Y
el
t
1
i*-"
r
Sulfur
Recovery
Hydrogen
Unit
To Gas
Treating
t
Naphtha
HDS
To Gas
Treating
1
Gas Oil
HDS
C*1 Hydrogen
To Plant
Fuel
t
' " tt" Gas Oil
[
Coke
FIGURE 1-2 -TYPICAL SHALE OIL PROCESS
0
0)
w
to
OP
-------
III-F. Oil Shale Processing
retorting temperature. Processes utilizing external heat
generation normally rely on external heaters to provide a high
temperature recycle gas which may be routed into the retort.
The recycle gas increases the shale temperature to the required
value of approximately 900°F.
These basic retorting methods are shown in Figure 1-3.
1.2 Common Technology
Many common features exist in the various shale oil
processes. These common features result from the fact that
certain basic processing steps must be performed in order to
obtain a marketable hydrocarbon product from oil shale. These
steps include retorting, oil recovery and fractionation, gas
recovery and treating, sulfur recovery, heavy oil cracking,
hydrotreating, ammonia separation, and water treating. Dif-
ferent shale oil processes use the same established technology
for all of these operations except the retorting step. Although
the effluent stream from each retort type differs, the same
upgrading processes can be used.
A typical shale oil upgrading sequence is as follows.
(1) Effluent from the retort is cooled, allowing
separation of light gases overhead and removal
of water by use of knockout drums. The crude
shale oil is routed to a fractionator for product
separation. A typical fractionator separates
the feed stream into gas, sour water, naphthas
or light oil, and a heavy bottoms oil. A series
of parallel operations follow the fractionation
as product streams are upgraded and by-products
recovered.
C-207
-------
Gas:Solid
Heat Transfer
o
O
CO
Internal
Gas Combustion
External
Heat Generation
U.S.B.M. Gas Combustion
Union Oil *
Paraho
Petrosix
OIL SHALE
RETORTING METHODS
Ex Situ
Solid:Solid
Heat Transfer
In Situ
TOSCO II
Lurgi-Ruhrgas
Occidental Petroleum'
o
H-
FIGURE 1-3 - CLASSIFICATION OF RETORTING METHODS
Both Union Oil and Paraho have plans or capabilities to use external heating of
recycle gas to provide the retorting heat (PF-003, LI-094).
o
o
ro
CO
CO
H-
3
OQ
-------
III-F. Oil Shale Processing
(2) All gas streams produced in oil shale refining
are routed to a gas recovery and treating unit.
In this unit, heavy hydrocarbons (C5 ) are re-
covered and returned to the light oil stream from
the fractionator for processing. The gas is
treated in an amine or other similar unit for re-
moval of hydrogen sulfide and carbon dioxide.
The clean gas may then be routed to boilers for
power generation or to a methane/steam reformer
for hydrogen generation. The acid gas is stripped
from the amine sorbent and routed to a sulfur
recovery unit.
(3) The sulfur recovery unit normally consists of a
Glaus plant working in conjunction with a tail
gas treating unit. This unit should be capable of
99% sulfur recovery (HI-083). If the hydrogen
sulfide concentration in the Glaus feed is main-
tained at 40 vol 7o or higher, a three-stage Glaus
plant should recover approximately 95% of the
equivalent sulfur in the charge. The gas stream
containing approximately 5% of the original sulfur
is routed to a tail gas treating unit. Perfor-
mances of tail gas treating units vary; however,
approximately 95% of the remaining sulfur should
be removed. Some tail gas units reduce sulfur to
the level of 250 ppm S02 in the effluent gas stream.
(4) Light distillate from the fractionator requires
hydrotreating to remove impurities and to improve
pour point and viscosity. Since hydrogen is
required, a hydrogen generation unit is normally
located on site. Hydrogen is produced from
C-209
-------
III-F. Oil Shale Processing
plant fuel gas and steam in a conventional
steam reforming process. Hydrotreated oil is
routed to product tankage. Sour gas from the
hydrotreater is routed to the gas recovery
facilities.
(5) Fractionator bottoms are routed to a delayed
coker for recovery of additional oil by thermal
cracking. Oil from the delayed coker is routed
to a gas oil hydrotreater. Gas produced from
the thermal cracking is routed to the gas re-
covery facilities. A large percentage of the
charge to the delayed coker is produced as coke.
This coke may be either marketed as a by-product
or used for process heat.
(6) An ammonia separation unit is used to remove
ammonia from the hydrotreater wash water.
The water is first stripped of any light hydro-
carbons which are routed to the gas treating
facilities. The ammonia is then removed in an
ammonia stripper and compressed to form liquid
ammonia.
(7) Not included in Figure 1-2, but necessary to all
shale oil processing units, are extensive water-
treating facilities. Process water requirements
are expected to be a major problem, since many of
the potential sites for shale oil development are
located in water deficient areas. Careful water
management and coordinated water-treating facilities
are required to reduce make-up water requirements
and to prevent water pollution. Maximum reuse is
C-210
-------
III-F. Oil Shale Processing
anticipated if a goal of zero wastewater dis-
charge is to be obtained. Water-treating facilities
include mechanical draft cooling towers, strippers
to remove NH3 and H2S, API separators, biological
treating facilities, and containment/evaporation
ponds.
1.3 Shale Oil Processes
The retort is the heart of the shale oil process.
Most of the differences that exist between processes are a
result of the retorting procedure. Specific retorts dictate
how fine the ore must be crushed. The TOSCO retort requires
ore ground to less than 0.5 inches while Union and Gas Combus-
tion retorts can receive ore up to 3.5 inches in diameter.
Operating conditions of the different retorts vary and this
affects the product streams. A comparison of the effluent
oil streams from three different retorts is shown in Table 1-3.
Gases produced in shale oil processes also vary signifi-
cantly, depending on retort type. .Gases from internal combustion
retorts are diluted with combustion products and the inert com-
ponents of the air. As a result, the gas has a low heating
value (100 Btu/scf), and cannot be economically transported any
significant distance. Gas produced from retorts which utilize
indirect heating has a substantially higher heating value
(~800 Btu/scf). A comparison of gases from internal combustion
and indirect heat retorts is shown in Table 1-4.
Physical properties and quality of the spent shale
also change with the retort. The amount of carbonaceous
material remaining on the shale is an inverse function of the
retort temperature. The spent shale from a TOSCO retort
C-211
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III-F. Oil Shale Processing
TABLE 1-2
CHARACTERISTICS
OF CRUDE SHALE
OILS
Retorting process
Gas Combustion Union — '
Gravity, °API
Sulfur, wt —pet
Nitrogen, do.,
Pour Point, F
Viscosity, SUS (§100 °F
Reference Source
19.7 20.7
0.7^ 0.77
2.18 2.01
80 90
256 223
(i°) (ft2)
TOSCO -f
28.0
0.80
1.70
75
120
(28)
I/ Typical of product froc original Union process,
2_/ Unpublished information submitted by Colony Development Operation
indicates TOSCO crude shale oil may have gravity as low as 21°API
and sulfur content of 0.75 wt-pct
(Source: US-093)
C-212
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III-F. Oil Shale Processing
TABLE 1-3
CHARACTERISTICS AND YIELDS OF UNTREATED RETORT GASES
Type of Retorting Process
Internal Combustion
Composition, vol. pet
Nitrogen -/
Carbon monoxide
Carbon dioxide
Hydrogen Sulf ide
Hydrogen
Hydrocarbons
Gross Heating Value,
Btu/scf
Molecular Weight
Yield, scf/bb: oil I/
£/
60.1
4.7
29.7
0.1
2.2
3.2
83
32
20,560
§/
62.1
2.3
2^.5
0.1
5.7
5.3
100
30
10,900
Indirectly Heated -
As
Produced
•• «•
4.0
23.6
4.7
2U,8
42.9
775
25
923
After
Desulfurization
....
4.2
24.8
(0.02)
26.0
45.0
815
24.7
880
I/ Includes oxygen of less than 1.0 volume percent.
2/ First analysis reflects relatively high-temperature
retorting in comparison with second, promoting higher yield
of carbon oxides from shale carbonate and relatively high
yield of total gas.
3/ Oil from the retort.
(Source: US-093)
C-213
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III-F. Oil Shale Processing
(low temperature) contains 5-6% carbonaceous residue; spent shale
from the Union retort (high temperature) contains essentially
no carbon.
Regardless of the retort type, all processes can
utilize cracking and hydrotreating processes to upgrade the
retort oil to distillate fuel quality. Properties of an
upgraded shale oil are as follows.
Gravity ° API 46.2
Sulfur wt. % 0.005
Nitrogen wt. % 0.035
Pour Point °F <50.
Viscosity, SUS
at 100°F 40.
1.3.1 TOSCO II
The TOSCO II process features a rotary-type retort
which utilizes ceramic balls to supply the retorting heat by
solid-solid heat transfer. A simplified flow diagram of the
TOSCO retorting step is shown in Figure 1-4. Raw shale feed of
minus 0.5 inches is fed from a surge hopper to a raw shale
preheater. The incoming shale is preheated to approximately
500°F by contact with hot flue gas from the ceramic ball
heater. The preheating is accomplished in a fluidized bed with
the crushed shale being entrained by the hot flue gas. The
preheater effluent is routed to settling chambers and cyclones
in order to separate the preheated shale from the flue gas.
Following shale separation the cooler flue gas, which has been
incinerated within the preheat system to reduce trace hydro-
carbons, is passed through a high energy venturi to remove shale
dust before being vented to the atmosphere at a temperature of
125-130°F.
C-214
-------
riuE GAS TO
i
ho
Ln
o
H-
(D
FIGURE 1-4 - TOSCO II RETORTING PROCEDURE
O
O
(D
CA
W
H-
D
CQ
-------
III-F. Oil Shale Processing
Preheated raw shale from the cyclone separators is
routed to the rotary drum retort. High-alumina content ceramic
balls of one-half inch diameter are combined with the raw
shale in the retort. The balls are heated to approximately
1200°F in a furnace fired by product fuel gas. The retort
temperature is maintained at 900° by combining two tons of
ceramic balls with every ton of feed shale. An internal pressure
of 5 psig is maintained to prevent the entrance of air. The
rotating retort is essentially a ball mill. As the kerogen
decomposes, the shale oil loses strength and is pulverized by
the ceramic balls. Approximately 5-6% carbonaceous material
remains on the shale. An advantage of utilizing indirect heat-
ing rather than direct gas combustion is that the fuel gas
produced is not diluted by combustion products and consequently
has a higher heating value. Approximately 900 scf of fuel gas
with a heating value of 800 Btu is produced per bbl of oil
recovered from the retort.
Retort products are routed to an accumulator where
the solids are passed over a trommel screen to separate the
balls from the spent shale. The ceramic balls are recycled to
the vertical ball heater by means of a bucket elevator. In the
ball heater fuel gas is combusted to heat the balls to 1200°F.
The spent shale is cooled in a rotating drum steam
generator. After cooling, the processed shale is moisturized
to approximately 14% moisture content in a rotating drum
moisturizer. Steam and shale dust produced during the moistur-
izing step are routed through a venturi scrubber to remove the
dust. Following moisturizing, the spent shale and dust collected
from the various venturi scrubbers is conveyed to a disposal
site.
C-216
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III-F. Oil Shale Processing
Hydrocarbon vapors are routed overhead from the
accumulator to a distillation tower. The retort products are
normally separated into gas, sour water, naphtha, gas oil and
bottom oil streams. A series of parallel operations follow the
fractionation step as product streams are upgraded and by-products
recovered.
A flow diagram of the shale oil upgrading procedure
is shown in Figure 1-5. Units shown include gas recovery and
treating facilities, naphtha and gas oil hydrotreaters, delayed
coker, hydrogen generation unit, water treating facilities,
sulfur recovery unit, ammonia separation unit and steam arid
electric power generation facilities. Gas from the accumulator
is either routed to gas recovery and treating and then recycled
to the ball heater for combustion or sent to the hydrogen genera-
tion unit. The naphtha is normally stabilized and then hydro-
treated. The gas oil streams are also hydrotreated. Bottoms
oil from the fractionator is thermally cracked by use of a
delayed coker to recover additional oil. This produces a coke
by-product. All H2S rich gas streams are routed to the sulfur
recovery unit. Wash water from the hydrotreaters is stripped
at an ammonia separation unit. Water removed from gas streams
is routed to a foul water stripper to remove ammonia and hydrogen
sulfide. The stripped water is used for moisturizing the spent
shale.
Air emission sources for this process are the preheat
system, steam superheaters, moisturizing system, process heaters,
sulfur recovery unit, crushing and conveying, power generation,
hydrocarbon storage and fugitive losses. Air emissions for a
50,000 BPCD TOSCO II process are presented in an Air Quality
Assessment of the Oil Shale Development Program (EN-204).
These emissions are shown in Table 1-5. Hydrocarbon storage and
fugitive hydrocarbon losses are not included.
C-217
-------
o
CO
FIGURE 1-5 - UPGRADING AND BY-PRODUCT RECOVERY FACILITIES
O
O
fl>
CO
co
H-
D
CQ
-------
TABLE 1-5
O
i
AIR POLLUTION EMISSIONS FROM THE TOSCO II PROCESS
PROCESS
Pyrolysis and Oil Recovery Unit
Preheat Systems-6 stacks
Steam Superheaters-Ball
Moisturizing Systeras-6 stacks
Hydrogen Unit
Reforming Furnaces-2 stacks
Gas Oil Hydrogenation Unit
Reactor Heaters-2 stacVs
Reboiler Heater
Naptha Hydrogenation Unit
Reactor Heater
Sulfur Recovery Unit
Sulfur Plants with common
Tail Gas Plant
Crushing and Conveying
Delayed Coker
Heater
Utilities
TOTAL
(50,000 bbl/cd)
Emission Rates (tons/year)3
SO. Particular KO 1HC
2 x
2,873
552
NG
372
88
276
31
460
NG
307
876
5,835
526
1,051
1,183
50
9
28
3
NG
276
31
88
3,245
3,460 1,314
661 17
NG NG
399 8
105 3
333 8
35 1
NG NG
NG NG
368 9
1,051 26
6,412 1,386
Total
Exhaust Flow
(acfm)
1,272,000
265,800
226,400
296,420
21,000
• 53,000
5,250
64,900
630,000
42,000
NG
Stack Paraa^ters
Exit Tenp Radius Height
(°F) (ft) (ft)
130 4.6
150 2.7
184 2.7
184 2.9
900 1.2
700 2.6
800 1.2
125 2.0
60 3.0
350 (3.0)
NG NG
275
300
50
100
100
100
100
250
50
200
NG
aData reflect Mode 1 operation, expected.2/3 of the time
(Source: EN-204)
M
M
M
o
H-
in
CD
o
o
fD
CO
co
p-
3
GO
-------
III-F. Oil Shale Processing
1-3.2 Lurgi-Ruhrgas
The retorting step of the Lurgi-Ruhrgas process is
shown in Figure 1-6. The Lurgi-Ruhrgas process utilizes
small solids such as sand grains, coke particles, or spent
shale to convey heat to the incoming oil shale. The solids are
preheated and mixed with raw shale in the retort. The retort
is a sealed screw-type conveyor. The effluent from the retort
is discharged into a bin for separation. Solids are removed
from the lower part of the bin for recycle. Product vapors
are removed overhead for dust removal, condensation, and product
upgrading.
1-3.3 U.S.B.M. Gas Combustion
The U.S.B.M. Gas Combustion retort is a vertical,
refractory-lined vessel. Coarsely ground shale oil is intro-
duced at the top and flows by gravity downward through the
retort. Although no physical barriers are present in the vessel,
the retort may be considered to consist of four sections. These
four zones are shale preheating, retorting, combustion, and
cooling.
Combustion air and recycle gas are injected into the
combustion zone, approximately one-third of the way up the
retort. Combusion of the gases with residual carbon on the
spent shale liberates the heat necessary for retorting. Com-
bustion temperature is approximately 1200-1400°F. Retorting
occurs above the combustion zone. Product vapors from the
retorting section are cooled by the incoming shale and removed
overhead. Heat exchange between product vapors and the raw
shale serves to preheat the shale prior to retorting. Follow-
ing combustion, spent shale is cooled and removed from the
C-220
-------
O
I
to
ho
Caseous fc Liquid Product*
Solids Surge Din
Dust Rc.tnov.il Cyclone
Oil Condenser
Lift Fife
Gas/Solids Separation Din
Hiking Screw Typo Retort
Oust Cyclone
Wacto Heat Hecovery
Air * Fuel
(If Hcquirud)
FIGURE 1-6 _ THE LURGI-RUHRGAS OIL SHALE REPORTING PROCESS
(Source: GA-107)
CO
CD
o
o
ro
en
OP
-------
III-F. Oil Shale Processing
bottom of the retort. Recycle gas entering at the bottom of the
retort is used to cool the spent shale. The Gas Combustion re-
torting process is shown in Figure 1-7 along with a typical
temperature profile through the retort.
Performance data for the 150 tpd gas combustion retort
at Anvil Points, Colorado, are shown in Table 1-6.
1.3.4 Union Oil
The Union Oil process utilizes internal gas combustion
to provide the retorting heat. The retort is a vertical re-
fractory-lined vessel in the shape of an inverted cone. The top
of the retort is open to the atmosphere. Air enters from the top
while the shale is charged from the bottom by a "rock pump."
Combustion of the organic matter remaining on the shale heats the
shale by direct gas-to-solids exchange. Maximum shale temperature
in this process is approximately 1800°F. Spent shale solids over-
flow the vessel at the top. The product oil is cooled by the
incoming shale and removed through an outlet at the bottom of
the retort. The Union Oil Retort is shown in Figure 1-8.
Operating conditions and yields for this process are shown in
Table 1-7.. Union Oil is currently testing modifications of the
process, such as external heating of recycle gas, on a 3 tpd
pilot plant (LI-094).
1.3.5 Paraho Process
The Paraho retort has the capability of using either
direct gas combustion or externally heated recycle gas to achieve -
the required 900°F temperature (PF-003). Coarsely ground shale
oil is introduced at the top of a vertical retort and flows by
gravity downward through the vessel. Combustion air and recycle
gas (or heated recycle gas) are introduced at several points
-------
o
I
K3
N>
OJ
GAS COMBUSTION RETORTING PROCESS
SriNT SHAtE SOLIDS
O
f.
C-.
X
R
in
o
H-
cn
FIGURE 1-7 - GAS COMBUSTION RETORTING PROCESS
(Source: GA-107)
O
O
(D
CO
CO
H-
3
(W
-------
III-F. Oil Shale Processing
TABLE 1-6
PERFORMANCE DATA FROM OPERATION OF THE REBUILT AND
MODERNIZED 150 TPD GAS COMBUSTION RETORT AT ANVIL POINTS, COLORADO
(data source: USBM Report of Investigations 7540)
Dice
Shale (ced propercies:
Avenge Fischer assay. ..(al/con.
Cpericl.ij conditions:
Kas« feed race lb/0>r)(Eca).
Air static pressure in H,0.
Ree/cU ;as temperature ' F.
Dllucton en ceaocrature....' F.
Retort offgas pressure. .. in H,0.
Ke:arc effgis temperature...' F.
Vent jas temperature * F.
Spent jhale temperature * F.
ftetect cop pressure in H,0.
letar: bottom pressure. ..in H:0.
Slaver ouclec pressure. ..in HjO.
Oil recovery (water -free):
Ue pet of Fischer assay....;....
?ra^'.c properties:
C-1023-6
4/14 '6'
li
6
ESP
No
25.3
9 6
1-2-1/2
1J 5
27.665
501
4 710
12;
138
12 913
' 230
0
0
140
7 291
2'0
392
0
10.3
71
2X.O
85.2
6 0
19 7
o
o
C-1023-7
4/14/57
12
6
£S?
No
25.1
10 0
X-2-1/2
12 5
27 632
501
4 736
123
150
12 929
250
0
-0.07
139
7 315
243
394
-0.07
10.7
69
21.8
85.0
5 1
19 7
0
0
C-1028-8
4/15/67
12
6
ES?
Mo
26.4
10.0
1-2-1/2
12.5
27,742
502
4,693
125
147
12 944
242
0
0
139
7,253
232
331
0
10.2
69
21.5
83.6
3.8
19.3
0
0
C-1023-9
4/15/6'
12
6
ES?
So
24.4
9.3
1-2-1/2
12.5
27.713
502
4,755
123
143
12,593
231
0
-0.03
U7
7.051
227
379
-0.03
10. 1
71
20.2
84.7
3.9
19.8
g
a
C-1023-10
4/16/47
U
6
ESP
No
23.6
9.0
1-2-1/2
12.5
27,332
495
4 657
107
140
12,795
232
0
0.02
138
7.003
240
396
0.02
8.9
67
18.6
80.7
2.3
19.7
0
0
C-1029-1
4/19/67
U
6
ES?
No
26.5
10. I
1-2-1/2
12.5
27,448
497
4.765
120
143
12.533
215
0
-0.10
139
7.265
213
357
-0.10
11.1
69
23.3
90.1
4.3
19.4
0 2
0.1
C-1029-2
4/19/67
12
6
ESP
No
26.7
10. 1
1-2-1/2
12.5
27,267
494
4 £01
129
143
12 323
215
0
-0.06
138
7,202
231
364
-0.06
10.3
69
22.6
87.1
6.6
19.7
0 2
0.1
C-1031-1
4/73M7
i;
6
ESP
No
"25.7
9.8
3/4-2-1/2
10 5
27,574
499
4 722
114
135
12,524
213
0
0.11
137
7,246
241
363
fl.tl
9.9
68
21.5
65.7
10.0
19.5
o
0
C-1031-1
4,/25/i;
U
6
ES?
No
25.8
9.8
3/4-2-1/2
10.5
27,623
500
4 717
103
135
12.479
219
0
-O.C8
139
7.559
250
333
•0.03
10.2
71
21.7
86.1
5.8
19.6
0 4
O.l'
(Source: GA-107)
C-224
-------
III-F. Oil Shale Processing
Oil outlet
UNION OIL RETORT
Shale is introduced near bottom of retort
and forced upward. Air enters at the top
and flows downward.
FIGURE 1-8 - UNION OIL RETORT
(Source: US-093)
C-225
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III-F. Oil Shale Processing
TABLE 1-7
OPERATING CONDITIONS AND YIELDS
.UNION OIL RETORT""
Shale feed «—
Fischer assay-——-—*-—«»* ;.•.]./ton--*—•——— 37.9
Total feed (wet)" tons * IS?!;
Feed fat* (dry)-"..— .— t:ns/day— ... 25.44
Retorting conditions
lUtoriing rats.
1b. shale/hr./sq. ft. bed area ' 138
Air requirements — --s.c.f./tar. shale———.._... 10,700
Superficial linear 555 velocity, ft./sec. 0.32
Retort pressure (tap) ————. ——„— Jtra-
Pressure drop across bed inches t^O——-——..- 7.5
Teitaeratures, "r.
Cortustian :ona ...........—— „._— „ 2200
A«h out ............—..——..—..„„„_„„„„.. jug
Products out—.-.--..———.——————-,—. 125
Oil production
Light oil (Cs-Cs)——. -gal./ton feed————— 2.5
Hist-..-.*-——-————--.-.da—--——.—•-——• 1 4
Oil In sludge -.—.——~ ft...-.—-__— j]j
Liquid 0(1 collected > da — — 23.6
ToUl oil produced—-— ........ .—...—. 27,3
Total oil— vol. I Fischer assay—.—~—— 99.5
•
01V recovery
Oil collected gal.ton feed ~ — 23.5
Oil collected— —wt. ' Fischer assay————. 8S.2
011 collected————vol. ' Fischer assay———.— 84.4
Oil ^leld surrary
Oil yield find, mist and sludge)
gal ./ton— — 2S.2
Oil yield (da) -wt. I Fischer assay — 92.3
Oil yield (da)— "vol. '. Fischer assay —— 90.4
fuel 938 production,
Wet jai s.c.f./ton feed- ~ 17.350
Dry gas—-—— — da — 14,430
Product properties flr».»rtt-i of on
(jcjvir.y — ~—••A.P.I. •*«••«—---..»----*--•---**—-•»••-----«•-»••«-.»,—«—-—«. 55 9
A-- a'.?
CO 4.6
C02 — 30.3
HZ -. 2.2
KM 0.1
C, 0.9
Cj 0.6
Cj 0.4
C.3 0.4
C, 0.2
C4 0.3
C« 0.1
C5 -- 0.1
Properties of »h
Organic residue content----——-....——Wt. :——---—- 0.08
Klneral carsonate content ut. : 0)3 0.49
("Source: GA 107)
C-226
-------
III-F. Oil Shale Processing
in the retort, flowing upward (countercurrent) to the shale.
Combustion of these gases with the residual carbon on the
shale liberates the heat necessary for retorting. If heated
recycle gas is utilized, then steaia will provide the heat
necessary for retorting. Spent shale is removed from the bottom
of the retort. Shale oil vapors leave overhead, passing through
an electrostatic precipitator and then to a gas recovery unit.
A portion of the noncondensible gas is returned to the retort as
combustion gas with the remainder routed to a waste heat boiler.
The Paraho retort is shown in Figure 1-9.
1.3.6 Petrosix
The Petrosix process is similar to the gas combustion
process used by the Bureau of Mines except that in the Petrosix
process, externally heated recycle gas is injected into the
retort rather than combustion air. A vertical kiln retort is
used. Crushed shale enters at the top and moves down through
zones of preheating, retorting, and cooling. The heat is supplied
by a recycle gas stream which is heated in a separate furnace.
The heated recycle gas is injected into the retorting area of
the vessel. Since heat generation is external, a combustion
zone is not present in this retort. Retorting products moving
upward in the vessel are cooled by incoming raw shale prior to
leaving the retort. An unheated recycle gas stream is injected
at the bottom of the retort to recover sensible heat and to
cool the spent shale. Spent shale is removed at the bottom of
the vessel and slurried to a disposal area. A flow diagram of
the Petrosix process is shown in Figure 1-10.
C-227
-------
III-F. Oil Shale Processing
ATMOSPHERE
SHALE ROCK
SHALE VAPORS
TO OIL
RECOVERY UNIT
ELECTROSTATIC
PRECIPITATOR
RETORTED SHALE TO
DISPOSAL BEDS
RECIRCULATED GAS
1
WASTE HEAT I
I *
i Dn T t CO I
L.—_ _ ______ .j
I
GAS I
RECOVERY I
SULFUR
I PLANT ,
I , 1
r
FIGURE 1-9 - THE PARAHO RETORT PROCESS
(Source: EN-2 04)
C-228
-------
III-F. Oil Shale Processing
SMAll ft(g
MICH »;u CAS
MOOUCT(Ol
'ETGITCO SH»K SIU»r
TO OlSfOSAl
FIGURE 1-10- PETRO-SIX PROCESS FLOW DIAGRAM
(Source: GA-107)
C-229
-------
III-F. Oil Shale Processing
1-4 State of the Art
Of the two general approaches to shale oil processing,
only ex situ processes have advanced to the stage where commercial
production may be achieved in the near future. In situ pro-
cessing is still in the experimental stage. Although both
laboratory and field research has been undertaken, an in situ
technique has not been successfully developed or demonstrated.
However, demonstration or pilot plants have been operated for
a number of the ex situ processes. Among these are the following:
1 U. S. B. M. Gas Combustion - tested on 150 tpd
unit,
Union - tested on 350 tpd unit, variation tested
on 3 tpd pilot plant,
TOSCO II - tested on 1000 tpd unit, constructing
66,000 tpd commercial plants,
Lurgi-Ruhrgas - tested on 12 tpd unit, and
Petrosix - 2200 tpd demonstration plant, in operation
Colony Development Operation, comprised of Atlantic
Richfield, Standard Oil of Ohio, TOSCO, and Cleveland Cliffs
Iron Company, has plans for a commercial plant at Parachute
Creek, Colorado. This plant will consist of six TOSCO II re-
torts, each capable of processing 11,000 tpd of raw shale. Ap-
proximately 50,000 bpd of synthetic crude will be produced.
Development Engineering, Inc., is in the process of
engineering a full-scale demonstration unit of the Paraho pro-
cess at the Anvil Points facility in Colorado. The capacity
of this demonstration plant will be 500 tpd (SH-157).
C-230
-------
III-F. Oil Shale Processing
1.5 Problem-Areas
Areas in which problems exist for oil shale processes
are as follows:
(1) ThermalEfficiency - The low thermal efficiency of
oil shale processes dictates an intensive effort
to recover energy. Most oil shale processes claim
an efficiency between 60 and 70% (heating value
liquid products x 100/heating value raw shale).
Much heat is required to decompose the kerogen
which cannot be recovered as liquid fuel. Any ~
processing techniques that will increase the
efficiency should boost the potential of oil
shale processing as a viable alternative for the
production of liquid fuels.
(2) Water Management - Large amounts of makeup water
are required in oil shale processes for use in
steam generation, as process water, and for cooling,
shale disposal, and revegetation. Design for the
TOSCO II plant estimates a water demand of 4970-
5600 gpm depending on water requirements for
revegetation. Due to the trace elements and other
pollutants in oil shale, the scarcity of water at
many potential plant sites, and increasingly strin-
gent clean water legislation, shale processing
plants will probably be required to achieve zero
water discharge status. In order to obtain this
goal a comprehensive water management program coupled
with extensive water treating facilities will be
required. Such facilities will include fan air
coolers, mechanical draft cooling towers, strippers
to remove NH3 and H2S, API separators, biological
C-231
-------
III-F. Oil Shale Processing
treating facilities, and containment/evaporation
ponds. It should be noted that much work is still
required in this area and that much is still unknown
about the ability to clean up shale oil processing
water. For instance, high concentrations of certain
trace elements or trace organics may have an adverse
effect on the bacteria used in biological treating
facilities. New technical developments may have
to occur before a zero water discharge can really be
achieved.
(3) Solids Handling - Another major problem area is -
connected with solids handling and disposal. An
immense solids handling problem results from
commercial scale oil shale processing due to the
low concentration of oil in the shale (30-
40 gal/ton). A typical oil shale plant charging
72,700 tpd of 30 gal/ton shale is estimated to
produce 60,000 tpd of spent shale (US-093). In
addition, the spent shale is less compact and is
approximately 12 vol % larger than the raw shale.
Current designs call for disposal at the mine site;
however, even underground mines can only accommodate
60% of the spent shale below the surface. Therefore,
surface area for containment must be provided.
(4) Land Reclamation - Due to the land impact resulting
from spent shale disposal and raw shale mining, oil
shale processing operations will require land
reclamation. However, procedures required to properly
revegetate this land have not been adequately defined.
Total cost, time, and water involved are not accurately
established.
C-232
-------
III-F. Oil Shale Processing
2.0 MODULE BASIS
The module calculations discussed here are based on
an oil shale processing plant producing 1012 Btu per calendar
day* of primary liquid fuels. For an oil shale processing
facility these primary fuels include naphtha, distillate oil
and/or residual oil. The thermal efficiency ** selected for
this module is 66.7%. This value is the efficiency assigned
by Kittman (HI-083) to the TOSCO II process. This particular
efficiency is used here since the TOSCO II process appears to
be the most advanced process and the first one likely to reach
commercial operation. In addition, the environmental impae-t
analysis for the TOSCO II plant at Parachute Creek, Colorado,
provides a good source of information on emission sources and
fuel requirements. Using a 66.7% primary efficiency, a charge
rate of approximately 199,100 tpd of raw shale (3765 Btu/lb) is
determined. A summary of emissions from the oil shale plant is
presented in Table 2-1.
* All rates presented for this module are on a calendar day
basis.
** Heating value of primary fuels divided by heating value of
raw shale feed times 100.
C-233
-------
III-F. Oil Shale Processing
TABLE 2-1
SUMMARY OF ENVIRONMENTAL IMPACTS
SHALE OIL RETORTING AND UPGRADING MODULE
(Basis: 1012 Btu Output Liquid Fuel)
Air (Ib/hr):
Particulates 453.6
S02 5324.1
NOX 1966.7
CO 174.5
HC 2652.3
Water (Ib/hr):
Suspended Solids 0.
Dissolved Solids 0.
Organic Material 0.
Thermal (Btu/hr): 0.
Solid Wastes (tons/day): 164.3 x 103
Land Use (acres): 2000.
Water Requirements (gal/day): 21.1 x 106
Occupational Health (per year):
Deaths 0.755
Injuries 79.2
Man-Days Lost 77.0
Efficiency (%):
Primary Fuels Efficiency 66.7
Total Fuels Efficiency 79.7
Overall Efficiency 76.9
Ancillary Energy (Btu/day): 5.59 x 10
10
C-234
-------
III-F. Oil Shale Processing
3.0 MODULE DESCRIPTION
This oil shale module is concerned with the retorting
and shale oil upgrading steps. Raw shale extraction and crush-
ing are not included in this module. The primary fuels from
this module are naphtha and fuel oil. The raw shale required
by a 1012 Btu/day (output) facility with a primary efficiency
of 66.7% is 199,100 tpd. The TOSCO II plant at Parachute Creek,
Colorado, is designed for raw shale feed of 66,000 tpd. This
represents the size of a typical oil shale facility associated
with an underground mine.
3.1 Processing Steps
The main processing steps involved with the shale
oil module are as follows:
retorting,
gas recovery and treating,
sulfur recovery,
delayed coking,
hydrogen generation,
naphtha hydrotreating,
gas oil hydrotreating,
ammonia separation unit.
This processing sequence is shown in Figure 3-1. In addition
to the major processing units, listed above, support facilities
such as utility boilers and water treating facilities are also
required.
C-235
-------
0
Raw
Shale" >
199,100 TPD
Retort
Product
Separation
182,900 BPD
Spent Shale
164,300 TPD
Gas Treating
&
Recovery
To Plant
Fuel
91,500 BPD To Gas
' Treating
Coker'
Sulfur
Recovery
Hydrogen
Unit
To Gas
Treating
A
Naphtha
HPS
To Gas
Treating
Gas Oil
HDS
-O- Sulfur
117.76 TPD
>-Hydrogen
1,475,000 SCFD
-t>- Naphtha
38,700 BPD
To Plant Fuel
" Gas Oil
133,000 BPD
H
I
o
H-
n>
o
o
7,012 TPD ;
Coke
co
H-
d
OP
FIGURE 3-1 - SHALE OIL MODULE
-------
III-F. Oil Shale Processing
3.2 Flow Rates
Module flow rates were calculated from data published
by Hittman (HI-083) for the TOSCO II process. These rates are
as follows:
Raw Shale to Retort 199,100 tpd
Crude Shale Oil to Distillation 182,900 bpd
Delayed Coker Feed 91,500 bpd
H2 Plant Production 1,475,000 scfd
Hydrotreater Charge 166,400 bpd
Liquid Product 171,700 bpd
This module was assumed to separate product liquids into naphtha
and distillate oil streams. This split was determined using
heating values of 5.248 x 106 Btu/bbl for naphtha and 6.0 x 106
Btu/bbl for distillate fuel. These product stream flows were
calculated to be 133,000 bpd distillate fuel and 38,700 bpd naphth.
3.3 Heat Requirements
Heat requirements for this module were based on Colony
Development Operation data (CO-175). Heat requirements and
fuel mix for the TOSCO II Parachute Creek plant are shown in
Table 3-1. The module heat requirements and fuel mix were based
on Mode 1 operation. Assumed heating values of the fuels are
as follows:
Retort Gas 815 Btu/scf
C* Liquid 21,200 Btu/lb
Distillate Fuel 6 x 106 Btu/bbl
C-237
-------
TABLE 3-1
PRELIMINARY FUEL BALANCE FOR COMMERCIAL SHALE OIL COMPLEX
MM BTU/HR
Mode I (3)
Mode
Source (2)
Pyro lysis and Oil Recovery Unit
Preheat Systems (6)
Steam Superheaters (6)
Hydrogen Unit
Reforming Furnaces (2)
Gas Oil Hydrogenation Unit
Reactor Heaters (2)
Reboi ler Heater
(4)
Fuel Gas Fuel Oil
708 755
632
— —
C,, Liquid
384
144
47
40
Fuel Gas
330.
632
Fuel Oil
945
55
C4 Liquid
307
120
48
o
i
to
u>
CD
Naphtha Hydrogenation Unit
Reactor Heater
Sulfur Recovery Unit
Sulfur Plants (2) and Common
10
II
Tall Gas Plant
Delayed Cokar Unit
Heater
Utilities
Boilers (2)
TOTALS
(I) It should be emphasized
to
88
1448
that white
revisions, the allocation of fuels
to substantial revision
(2) Where multiple sources
(3) Complex is expected to
(4) Complex is expected to
* ' — \
femvrr.f*: CO- 17 5)
, but will
— —
___ ___
93
10
96
150
M
M
M
1
fri
848 615 1079 1150 475
estimates of total fuel consumption are
to various sources is quite preliminary
be variable during plant operations.
subject to only minor
, and is not only subject
O
H-
M
to
03
h-i
are Indicated, consumption Is for all sources.
1 • t-pl
operate In
operate In
"Mode I" approximately two-Thirds of the
"Mode II" approximately one-third of the
time.
time.
0
0
n>
lA
co
H-
3
09
-------
III-F. Oil Shale Processing
The values presented in Table 3-1 are adjusted to a 10I2 Btu/day
output basis. The heat requirements for the various module units
are shown in Table 3-2.
TABLE 3-2
MODULE HEAT REQUIREMENT
(Basis: 101Z Btu/Day Product)
Heat Requirement
Unit (MM Btu/hr)
Pyrolysis and Recovery
Preheat System 5596.2
Steam Superheaters 436.2
Hydrogen Unit 1915.
Gas Oil Hydrogenation
Reactor Heater 142.4
Reboiler Heater 121.2
Naphtha Hydrogenation 30.3
Delayed Coker 266.6
Utility Boilers 281.8
Sulfur Recovery 30.3
C-239
-------
III-F. Oil Shale Processing
3.4 Module Efficiencies
These different efficiency terms are defined for each
of the modules considered in this study. These three efficiencies
are defined as follows:
(1) Primary Fuels Efficiency - Primary liquid fuels
from the oil shale module are naphtha and distillate
oil. The primary fuels efficiency is the heating
value of these products divided by the heating value
of the raw shale feed. This value is 66.7% for this
module (HI-083).
(2) Total Products Efficiency - This efficiency credits
any other hydrocarbon products made. Sulfur and
ammonia are not included. Total products efficiency
is the heating value of all hydrocarbon products
divided by the heating value of the raw shale feed.
Coke from the delayed coker is considered in this
efficiency. For this module, the total products
efficiency is 79.7%.
(3) Overall Efficiency - This efficiency takes into
account any ancillary energy such as electricity that
may be supplied to a module. This efficiency is equal
to the heating value of all hydrocarbon products
divided by the heating value of the raw shale feed
plus any ancillary energy needs of the module. The
overall efficiency for this module is 76.9%.
Determinations of these efficiencies are shown in
Table 3-3.
C-240
-------
III-F. Oil Shale Processing
TABLE 3-3
EFFICIENCY CALCULATIONS FOR OIL SHALE PROCESSING MODULE
Stream Rate Heating Value Total Heating Value
Raw Shale 199,100 tpd 3765 Btu/lb 1.5xl012 Btu
Naphtha 38,700 bpd 5.248xl06 Btu/bbl 2.02x10M Btu
Distillate Oil 133,000 bpd 6.0xl05 Btu/bbl 7.98X1Q11 Btu
Primary Fuels Efficiency = 1012/1.5xl012 = 0.667
Coke 7,012 tpd 14,000 Btu/lb 1.96xl011 Btu
i i Qfivi n* 2
Total Product Efficiency = i e iMa - 0.797
J. *
Ancillary Energy = 5.59x1010 Btu
Overall Efficiency = 1.'"556x10 ^ = °'769
C-241
-------
III-F. Oil Shale Processing
3.5 Water Requirements
Water requirements for this module are based on TOSCO
II estimates (CO-175). Estimated water requirements are shown in
Figure 3-2. Water demands associated with the oil shale industry
cannot be accurately defined due to the uncertainty of water
requirements for revegetation. TOSCO II water demands range
between 4970 gptn and 5600 gpm depending upon the amount of water
allocated for revegetation. Water requirement for this module
were calculated using the following TOSCO II demands as a basis:
Make-Up to Water Treatment 3055 gpm
Make-Up to Pyrolysis Unit 820 gpm
Dust Control for Processed Shale 250 gpm
Water for Revegetation 700 gpm
4825 gpm
A module water requirement of 21.1 x 106 gal/day was determined.
As a result of a lack of data on revegetation, considerable
discrepancies exist in published estimates of oil shale industry
water demands. Selected estimates of water requirements for a
million barrel per day oil shale industry are as follows:
Cameron and Jones in 1959, 130,000 acre-ft/yr
Denver Research Institute in 1954, 145,000 acre-ft/yr
Dept. of the Interior in 1973, 155,000 acre-ft/yr
Colony Development Operation in 1974, 175,000 acre-ft/yr
In view of these increasing figures, an estimate of 200,000-250,000
acre-feet of water per year is probably reasonable for a million
barrel per day oil shale industry (GA-107).
C-242
-------
in
I- co
ratr
oo.
Q.
MINE
DUST
SUPPRESSION
o
10
ro
CRUSHER
DUST
SUPPRESSION
to
CM
CM
110—I
RAW SHALE SURFACE
MOISTURE
O
i
K>
-P-
U>
=2
O
O
O
to
:D
o
2:
3:
O
o
o
O
O
IO
PYROLYSIS
AND
OIL RECOVERY
'UNIT
WASTE HEAT
AND
UTILITY
BOILERS
J
220-
MAKEUP
CO
3
o
CM
CT>
CO
to
o
o
BFW 1300
FIRE/
SERVICE/
DRINKING
o
10
CO
CO
o
MAKEUP |
in
IO
-1300-
100-
RE6ENERATION
FOUL WATER
WATER.
TREATMENT
PLANT
o
to
•OU-
WATER
370
580
WATER MAKEUP
rFO
o
II
FOUL WATER-0-
1
O DRIVER WATER SUPPLY
^w ALL RATES IN GPM
* : WILL INCREASE TO 700 GPM
IN 12 YEARS
TOTAL RIVER WATER SUPPLY •
FOR YEARS I-II ' 4970 GPM
FOR YEARS 12-20= 5600 GPM
FOR DESIGN PURPOSES, NO CREDIT
TAKEN FOR SURFACE RUNOFF.
S. 25
1 STRIPPED WATER
t PURGE FROM
PROCESSED AMMONIA SEPARATION
SHALE UNIT
MOISTURIZING
GAS
RECOVERY
AND
TREATING
UNIT
'
COKE
L
WASI
I WATER
180
FIGURE 3-2 - RIVER WATER UTILIZATION
(Source:, CO-175)
M
M
I
CO
0>
o
o
o>
CO
co
H-
3
OP
-------
III-F. Oil Shale Processing
3. 6 Land Use
Land requirements for this module were determined from
information in the Enviornmental Statement for the Prototype Oil
Shale Leasing Program (US-093). A land impact of 320 acres is
given for a shale oil facility producing 50,000 bpd. This land
requirement is for retorting, upgrading, and off-site facilities.
The land impact from the TOSCO II Parachute Creek plant for these
facilities is given as 315 acres. This figure does not include
land required for mining, transportation, and spent shale disposal,
An equivalent land impact of 320 acres due to land re-
quirements for expansion, water containment (evaporation ponds),
and a green belt is assumed. A basis of 640 acres for a 50,000
bpd facility is obtained. Land requirements for the 1012 Btu/
day module are estimated to be 2000 acres.
3.7 Occupational Health
Occupational health information was obtained from the
Hittman Study (HI-083). The statistics are based on retorting
and power generation data. The occupational health data for a
TOSCO II plant processing 1012 Btu/yr are as follows:
deaths 1.38 x 10"3
injuries 1.45 x 10~
man-days 1.41 x 10
Since oil shale processing is a relatively new technology, better
occupational health statistics will be established as operating
time accumulates. The data from the Hittman Study were extra-
polated to a 1012 Btu/day output basis for this module.
C-244
-------
III-F. Oil Shale Processing
4.0 MODULE EMISSIONS
4.1 Air Emissions
Module air emissions result from fuels combustion,
shale moisturizing, sulfur recovery, storage, and miscellaneous
hydrocarbon emissions. A summary of module air emissions is
presented in Table 4-1.
4.1.1 Fuel Combustion
Fuel combustion emission sources were defined as
follows (CO-175):
Pyrolysis or Retorting Unit
Hydrogen Unit
Gas Oil Hydrotreating
Naphtha Hydrotreating
Delayed Coker
Utility Boilers
The type of fuel combusted at the individual source was determined
from the TOSCO II fuel mix (CO-175). The fuels combusted in
this module are retort gas, C^ liquid and distillate fuel. It was
assumed that particulate emissions from the pyrolysis unit are
controlled to 0.03 gr/scf of flue gas (HI-083).
The remaining emissions from the pyrolysis unit and
emissions from the other fuel combustion sources were calculated
using EPA fuel combustion emission factors for the appropriate
fuel (EN-071). Fuels used at the specific units are shown in
Table 3-1 (Mode 1). EPA combustion factors are presented
in Table 4-2. Note that residual oil factors are used for
C-245
-------
TABLE 4-1
SHALE OIL MODULE -10" BTU OUTPUT/DAY AIR EMISSIONS AND STACK PARAMETERS
Source
1. Pyrolysis
& Oil
Recovery
Unit
A. Preheat
System'
(6 units)
B. Steam
Superheat-
ers
(6 units)
C. Shale
Moistur-
izing
(6 units)
TOTAL
2. Hydrogen
Unit (4
furnaces)
TOTAL
Heat
Input
mm Btu'/Hr
932.7
72.7
6032.4
478.7
1915
Fuel
3.43xl03lb/
Hr
587x10 JSCFH
2.35xl06SCFf
Emissions Ibs/Hr
Partlculates
42.0
3.5
15.3
364.8
8.36
33.45
SO t
+77.7
>866
.71.!
L886
Total
Organ! cs
12.3
0.22
75.1
1.39
5.58
CO
19.8
1.20
L25.8
7.90
31.6
NOV
214.3
9.04
1340
111.5
446
Stack Parameters
Mass
Flow
Ibs/Hr
731.7xl03
61. 9x10 3
169.7x10'
5.78xlOG
262.5x10*
l.OSxlO6
ACFM
198.3x10'
16. 1x10 3
63.6xl03
113.9xl03
Velocity
FPS
60
60
60
60
Height
Ft.
200
200
200
200
Temperature
OF
130
150
195
500
Diameter
Ft.
8.11
2.38
4.59
6.35
o
I
N)
-P-
M
M
I
o
H-
ro
o
o
-------
TABLE 4-1 Continued
SHALE OIL MODULE -1Q12 BTU OUTPUT/DAY AIR EMISSIONS AND STACK PARAMETERS
Page 2
Source
3. Gas Oil
Hydro-
genation
A. Reactor
Heater
B. Reboiler
Heater
TOTAL
4. Naphtha
Hydro-
genation
5. Delayed
Coker
6. Utility
Boilers
(2 units)
TOTAL
7. Sulfur
Recovery
8. Refining
Misc.
Heat
Input
mm Btu/Hr
142.4
'121.2
263.6
30.3
266.6
140.9
281.8
30.3
Fuel
6.72xl03lb/
Hr
5.72xl03lb/
Hr
12. 43x10 3lb/
Hr
37.2xlO'SCFt
327.1x10'
SCFH
985 gal/Hr
1970 gal/Hr
37.2xl03SCFI
Emissions Ibs/Hr
Particulates
2.63
2.24
4.87
0.53
4.66
22.65
45.3
SO,
>9.8
>53.*
i6.3!
52.7
L95.I
Total
Organics
0.44
0.37
0.81
0.09
0:78
3.94
7.88
2475
CO
2.34
1.99
4.33
0.50
4.40
3.94
7.88
NOV
17.7
15.07
32.77
7.06
62.1
39.4
78.8
Stack Parameters
Mass
Flow
Ibs/Hr
121. 3x10 3
103. 2x10 3
224.5xl03
16. 7x10 3
146.8x10'
136.8xl03
273.5xl03
471.3xl03
ACFM
67.4x10*
57.4x10'
.
9.8x10'
63.4x10'
55.2x10'
97.3x10'
Velocity
FPS
60
60
60
60
60
60
Height
Ft.
200
200
200
200
200
200
5
Temperature
op
850
850
850
500
500
100
Diameter
Ft.
4.88
4.51
1.86
4.74
4.42
5.65
o
H-
(D
I
K>
-1^
--J
O
n
(D
CO
co
H-
3
CT9
-------
TABLE 4-1 Continued
SHALE OIL MODULE -10'*. BTU OUTPUT/DAY AIR EMISSIONS AND STACK PARAMETERS
Page 3
1
Source
9. Storage
TOTAL
O
to
-P-
CD
1
Heat
Input
mm Btu/Hr
Fuel
Emissions Ibs/Hr
Particulates
453.6
S02
>324J
Total
Organics
87.1
2652.3
CO
174.!
-
NO
19667
NH,
31.1
31.1
Stack Parameters
Mass
Flow
Ibs/Hr
I
ACFM
Velocity
FPS
Height
Ft.
50
Temperature
oF
Diameter
Ft:.
M
M
M
O
P-
£»"*
9)
(0
•x)
N
O
O
CO
H-
CQ
-------
III-F. Oil Shale Processing
TABLE 4-2
FUEL COMBUSTION EMISSION FACTORS
Natural Gas Cy Liquid Residual Oil
lb/106 ft3 lb/10? gal lb/103 gal
Particulates
S02
HC
CO
NOX
Aldehydes
18.0
0.6
3.
17.
230.
_ —
1.8
0.095
0.3
1.6
12.1
_. *.
23.0
157 x S*
3.
4.
40.
1.
S = wt. % sulfur in fuel oil
Source: (EN-071)
:-249
-------
III-F. Oil Shale Processing
fuel oil combustion. All factors used were for fuel combustion
in process boilers. Fuel gas emissions were adjusted by a
factor of 0.791 (ratio of heating value 815/1050) to compensate
for the different composition of retort gas relative to natural
gas. Sulfur dioxide emissions were determined by considering
the following:
(1) approximately 0.5 vol °L H2S in retort gas,
(2) essentially zero H2S in C4 liquid after amine
treating, and
(3) fuel oil containing 0.3 wt. % S.
Aldehyde emissions from fuel oil combustion were combined with
hydrocarbons to give total organic emissions.
Flue gas rates resulting from fuel combustion were
calculated assuming stoichiometric combustion and 2070 excess
oxygen. Combustion of one scf of fuel gas results in 6.3 scf
of flue gas. Combustion of one pound of C^ liquid results in
239.3 scf of flue gas. One gallon of fuel oil yields 1820 scf
of flue gas. Stack temperatures were taken from the estimated
stack temperatures for the TOSCO II plant (CO-175). A stack
velocity of 60 fps was assumed for dispersion modeling.
4.1.2 Shale Moisturizing
The only emissions from the spent shale moisturizing
operation should be particulates. Particulates were assumed
to be controlled to 0.03 gr/scf of flue gas. The flue gas rate
was determined from shale moisturizing rates and operating data
in the TOSCO II environmental impact analysis (CO-175).
C-250
-------
III-F. Oil Shale Processing
4.1.3 Sulfur Recovery
Sulfur dioxide was considered to be the only emission
from the sulfur recovery facilities. Module sulfur recovery
facilities were assumed to consist of a Glaus plant and a tail
gas treating unit. A module sulfur balance was used to determine
the equivalent sulfur in the charge. The sulfur recovery unit
was assumed to recover 99% of the equivalent sulfur in the
charge (HI-083).
4.1.4 Ammonia Storage
EPA emission factors (EN-071) for the storage and~
loading of ammonia (200 Ib/ton NH3) were used to determine
ammonia emissions. This factor was reduced by 99% considering
the use of a packed tower scrubber. Ammonia production rates
were calculated from estimated ammonia yields for a typical shale
oil plant (US-093).
4.1.5 Petroleum Storage
Based on literature data and experience, the following
assumptions were formulated to calculate the hydrocarbon
emissions from petroleum storage.
All product storage is in floating roof tanks.
Storage capacity is 10 days (HI-083).
Combined hydrocarbon products are equivalent to
crude oil.
C-251
-------
III-F. Oil Shale Processing
Using petroleum storage emission factors for storing crude oil
in floating roof tanks (0.029 Ib/day - 103 gal), hydrocarbon
emissions from storage were calculated to be 87.1 Ib/hr. These
emissions were assumed to occur at a height of fifty feet.
4-1-6 Miscellaneous Hydrocarbons
There can be numerous miscellaneous hydrocarbon
emissions in the shale oil upgrading facilities which escape
from sources such as valve stems, flanges, loading racks,
equipment leaks, pump seals, sumps, and API separators. These
losses are discussed in Radian's Refinery Siting Report (RA-119).
Based on literature data, Radian found that miscellaneous
hydrocarbon emissions can amount to about 0.1 wt. 70 of refinery
capacity for a new well-designed, well-maintained refinery.
This value of 0.1 wt. 70 was used to determine miscellaneous
emissions from the shale oil upgrading facilities. Upgrading
capacity was considered to be the equivalent crude distillation
tower feed rate (182,900 bpd). Crude shale oil from the TOSCO II
retort is approximately 21°API (US-093). The composition of
these fugitive hydrocarbon emissions can be expected to be a
composite of all volatile intermediate and refined products
handled by the module. The emissions were assumed to occur at
a height of five feet.
4.2 Water Effluents
Water effluents were assumed to be nonexistent since
the module is assumed to operate with zero discharge (HI-083).
C-252
-------
III-F. Oil Shale Processing
4.3 Thermal
Thermal discharges to water bodies were determined to
be zero since no water was assumed to be discharged from the
module.
4.4 Solid Wastes
Solid wastes were determined from the amount of
spent shale generated by a typical shale oil process (US-093).
A value of 60,000 tpd spent shale for a 72,700 tpd raw shale
process was extrapolated to 164,300 tpd spent shale for this
1012 Btu/day output module. Most of this waste would normally
be returned to the mine site for disposal.
C-253
-------
APPENDIX C
III-G. LIQUEFACTION SYN-CRUDE REFINERY
C-254
-------
III-G. Liquefaction Syn-Crude Refinery
1-0 INTRODUCTION
A refinery built for the specific purpose of upgrading
a synthetic crude will differ from a typical petroleum refinery
processing a full range domestic crude if the properties of
the synthetic and natural crudes are different. Most schemes
for the production of a synthetic crude from coal call for
on-site upgrading. This on-site upgrading normally consists of
stabilization by removal of light ends and desulfurization of
the liquid product. As a result, the liquid fuel charged to a
liquefaction syn-crude refinery will not require exactly the
same processing as a refinery receiving a full range domestic
crude. These differences are discussed in Section 3.0.
C-255
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III-G. Liquefaction Syn-Crude Refinery
2.0 MODULE BASIS
This module is based on a typical refinery size of
100,000 BPD* of crude capacity. However, the emission values
for this module are also expressed on the basis of 1012 Btu/
day output of major liquid fuels to facilitate comparisons
with other energy conversion modules. Major liquid fuels in-
clude gasoline, distillate fuel oil, and residual oil. Esti-
mated liquefaction refinery module emissions for a module
producing 1012 Btu/day of liquid fuels are shown in Table 2-1.
* All flow rates in this module are based on calendar days
C-256
-------
III-G. Liquefaction Syn-Crude Refinery
TABLE 2-1
SUMMARY OF ENVIRONMENTAL IMPACTS
LIQUEFACTION SYN-CRUDE REFINERY MODULE
BASIS: 1012 Btu OUTPUT LIQUID FUEL
Air (Ib/hr)
Particulates 465
S02 1378.7
NOX 1710
CO . 129
HC 4133
Water (Ib/hr)
Suspended Solids 297
Dissolved Solids 10,996
Organic Material 62.5
Thermal (Btu/hr)- 0.
Solid Wastes (tons/day) 3.7
Land Use (acres) 5178
Water Requirements (gal/day) 16.3 x 10s
Occupational Health (per year)
Deaths 0.475
Injuries 35.0
Man-days Lost 8363
Efficiency
Primary Fuels Efficiency 81.5
Total Products Efficiency 89.5
Overall Efficiency 87.1
Ancillary Energy (Btu/day) 3.51 x 101 °
C-257
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III-G. Liquefaction Syn-Crude Refinery
3.0 MODULE DESCRIPTION
Properties of the major liquid products from coal
liquefaction processes are shown in Table 3-1 (KA-124). A
liquefaction syn-crude of approximately 10° API, containing
0.5 wt. % S, was assumed to be used as charge to the liquefaction
refinery. Extensive cracking would be required to upgrade this
feed to produce gasoline and distillate fuels. For this reason
a heavy oil hydrocracker was utilized in place of a crude dis-
tillation unit. The liquefaction refinery module produces 0.51
bbl gasoline, 0.35 bbl distillate fuel and 0.03 bbl residual
fuel per bbl of syn-crude charged.
3-1 Processing Steps
The processes necessary for the module to produce
gasoline and distillate fuel were estimated from the charge
quality. Processes included in the liquefaction refinery module
are as follows:
heavy oil hydrocracker
flexicoker
gas treating facilities
sulfur recovery facilities
isomerization unit
catalytic reformer
fluid catalytic cracker
light end recovery
ethylene plant
alkylation unit
hydrogen plant
gasoline blending facilities
C-258
-------
TABLE 3-1
O
Ul
ppccrss
Hydrogen used
In dissolution?
Scb.-^-ent Extract
Cntilytlc Dlssol.
Kc.^..lcr Temperature.
Rca :tor Pressure .
Coal
5>:!'ur. Wt . !
Solvent to Coal
R.it to (to slurry).
Percent Co.il
DU-olved (MAT).
Hydrogen Consump-
tion 5cf/ton Coal
O!Ai).
Solids Separation,
Sol l.ls Content In
Prc--.!jcl -
Principal Products
1. Fuel
Yield bbl/ton
AH f.rjvlty
Viscosity
S-ilfur, Vt.Z
Nitrojen, Wt.Z
2. Fuel
API gravity
Yield bbl/ton
Viscosity
Sulfur. Wt.Z
COAL LIQUEFACTION PROCESS OPERATING CONDITIONS AND TYPICAL
PRODUCTS (KA-124)
H-COAL PARSONS MODIFIED PAMCO KUR. OF GULF CCL GULF O^
n i •
Yes
No
Yes
8iO*
3000 pslg
111. No. 6
5t
l:l(by Wt.)
90*+
15,300
llyjroclones
and/or
filtration
Fuel Oil
1.73 bbl/ton
-3.1*API
0.5S
Naphtha
38.4'API
0.54bbl/ton
<0.1Z
PAMCO
Yes
Yes
No
840*F
1200 pslg
111. No. 6
3.38Z
2.0:l(by'wt.)
90Z+
12,600
Filtration
Residual Fuel
Oil
1.43bbl/ton
-9.7'API 60/60
<0.5Z
Distillate Fuel
on
13.9*API 60/60
0.71 bbl/ton
0.2Z
(S.SERV.)
Yea
No
No
850*F
1500 pslg
..
5Z
2:l(by Wt.)
90Z+
02Z by Wt.
7600
Filtration
0.23 Wt.Z
Solvent
Refined Coal
1116 lb/ton*
<1.2Z
MINES
Yes
No
Yes
840*F
4 000 pslg
Kentucky
4.6Z
1.22:1.0(by Wt.)
90Z+
9000
Centrifuge
1.3 Wt.Z
Fuel Oil
3 bbl/MAF ton*
Sp Cr-1.12-1.14
Vise - 75-204
SSF@ 180*F
0.31Z
0.9Z
Yea
No
Yea
aoo*p
3000 pslg
Big Horn Subblt.
0.54Z
2.33:1.0(by Wt.)
91Z
22,800
llydrocloncs & Flit.
0.02 Wt.Z
Filtrate Fuel Oil
2.3 bbl/ton
9.0'API .
7.1 CS eiOO'F
0.04Z
0.40%
tight Ends
35.3*AP1
0.9 bbl/ton*
1.2 CS 6100'F
0.04X; .
0.19Z
Yes
No
Yes
800 *F
3000 pslg
Flttsburg Seam (Bit.)
1.49Z
2.33:1.0(by Wt.)
90Z
17,500
llyilroclonco & Flit.
0.03 Wt. Z
Filtrate Fi-el Oil
3.6 bbl/ton*
1.2* API
4.3 CS G210*P
0.11
Light Ends
0.45 bbl/ton* .
COt! SOL
' °
Yes
No
730*P
400 pslg
Pltt.iburg Seats Coal
3.671
2:1 (by Wt.)
63*
16 , 300
llydroclonea
Fuel Oil
1.52 bbl/ton coal
10.3'APl
.1281
Naphtha
58.0*API
0.52 bbl/ton
.056Z
I
O
t-h
(U
O
rt
CO
^
O
U.
n>
i-h
H-
3
ft>
-------
III-G. Liquefaction Syn-Crude Refinery
The assumed module processing sequence is shown in Figure 3-1.
Hydrocracking and flexicoking units are utilized in this refinery
to crack the heavy oil fractions into lighter boiling gasoline
and distillate fuel components.
3.2 Flow Rates
Flow rates were determined from specific process data
(HY-013) and syn-crude quality. Since the syn-crude quality
was estimated to be similar to a heavy residual oil, the feed
is initially routed to a heavy oil hydrocracker. Desulfurization
and cracking of the feedstock are accomplished with this unit.
Hydrocracker product distribution and utility requirements were
based on H-Oil hydrocracking process data (HY-013). Assuming
the yield to be essentially the same as that shown for West
Texas Vacuum Resid (12.7° API), the product streams from this
unit were estimated to be as follows:
Light ends 797,000 Ib/day
Naphtha 20,100 BPD
Distillate Fuel 25,500 BPD
Gas Oil 35,200 BPD
Heavy Resid 20,000 BPD .
Hydrogen requirements for this process are 1250 SCF/bbl charge.
The heavy resid from this unit is routed to a flexi-
coker. The product stream and utility requirements for flexi-
coking were estimated from literature information (HY-013).
Product streams include fuel gas, naphtha, distillate fuel,
residual fuel, and coke. The coke yield from the unit was
estimated to be 2.8 wt. % of the feed or 279 x 103 Ib/day.
The residual fuel stream which is routed to tankage is 8615 BPD.
C-260
-------
* Propane-Propylene
Liquefaction—*-
Syn-Crude
Coke
LIQUEFACTION SYN- CRUDE REFINERY MODULE
FIGURi: 3-1
i
O
C
n>
P>
o
rt
P-
O
3
O
0)
n>
Hi
5'
n>
i-j
-------
III-G. Liquefaction Syn-Crude Refinery
Distillate fuel make is 4000 BPD. The distillate fuel stream
also goes to product tankage. The naphtha stream from the flexi-
coker is routed to gasoline blending. The naphtha yield is esti-
mated as 9050 BPD. The gas stream from this unit (809 x 103 lb/
day) is routed to gas treating.
The gas oil stream from the hydrocracker is routed to
a fluid catalytic cracker. Product yields and utility require-
ments for that unit were based on the Gulf Development Corpora-
tion1 s Riser Cracking Process (HY-013). Product streams from the
catalytic cracker include light ends, naphtha, distillate fuel
and residual fuel. The heavy cycle oil (residual fuel) from
this unit is approximately 6.5 vol. "L of the feed. This stream
(2,288 BPD) is routed to product tankage. The distillate fuel
yield is approximately 15.5 vol. % of the charge or 5,456 BPD.
This stream is combined with the straight run distillate from
the hydrocracker and routed to tankage. The naphtha yield is
58.5 vol. 7, of the feed or 20,592 BPD. This product stream is
routed to the gasoline blending facilities. Light ends yield
is approximately 2.57 x 106 Ibs/day. Composition of the light
end stream was determined by riser cracking yield data (HY-013).
A CO boiler is included in the refinery module to
combust the carbon monoxide in the flue gas from the cat cracker
regenerator. The CO boiler serves the purpose of reducing the
carbon monoxide emissions while recovering heat in the form of
flue gas sensible heat and carbon monoxide heat of combustion.
Fuel oil added to sustain combustion is considered to be 10%
of the energy supplied by CO combustion (RA-119). Using data
on 1) the composition of regenerator flue gases (HA-157), 2)
the specific heats, and 3) the heats of combustion of those
gases (PE-030), heat from the CO boiler was determined to be as
follows:
C-262
-------
III-G. Liquefaction Syn-Crude Refinery
Sensible Heat 122.5 MM Btu/hr
CO Combustion 131.9 MM Btu/hr
Fuel Combustion 13.2 MM Btu/hr
The total heat recovered by the CO boiler, 267.6 MM Btu/hr, is
sufficient to meet module steam demands. Therefore, a separate
boiler for steam generation which might be needed for startup,
turnaround and emergency standby would not normally be in operation,
Distillate fuel from the hydrocracker (25,SCO BPD) is
routed to product tankage. The distillate and gas oil streams
from the hydrocracker are assumed to contain 0.3 wt.% S. The
remainder of the sulfur that is in the charge is assumed to go
overhead from the hydrocracker with the light ends.
Due to the hydrogen sulfide formed in the hydro-
cracking process the light ends from this unit are routed to
gas treating facilities along with gas from the catalytic
cracker and flexicoker. An amine unit is used to remove the
hydrogen sulfide from the gas stream. The sweetened gas stream
is routed to the light end recovery facilities. The hydrogen
sulfide rich stream goes to a Glaus plant for sulfur recovery.
The module Glaus plant utilizes three reactors in
conjunction with a.tail gas treating unit and is capable of
approximately 99.9% sulfur recovery (RA-119). Equivalent sulfur
in the charge to the Glaus plant was determined by a plant sulfur
balance. Distillate fuel and heavier fractions from the hydro-
cracker were assumed to contain 0.3 wt. % S. The remaining sulfur
was assumed to be associated with the light ends from the hydro-
cracker and to be routed to the amine unit where 100% removal of
the sulfur compounds is estimated. Sulfur production from the
sulfur recovery facilities is 50.4 LTPD (2240 Ibs per long ton).
C-263
-------
III-G. Liquefaction Syn-Crude Refinery
Naphtha from the hydrocracker is routed to either an
isomerization unit or a catalytic reformer. The isomerization
unit of the module receives 30 vol.7a of the hydrocracker naphtha,
6030 BPD. Process yields and utility requirements were obtained
from the British Petroleum Trading Limited Isomerization Unit
data (HY-013). The isomerate yield is 100 vol.% The isomerate
stream is routed to gasoline blending. Light ends produced
from the isom unit are approximately 1.1 wt.% of the isom unit
charge. The hydrogen requirements for this unit are assumed to
be negligible.
The catalytic reformer receives 70 vol.% of the-hydro-
cracker naphtha (14,070 BPD). The module reformer is based on
data from the Rheniforming and Ultraforming Processes (HY-013).
The higher yields for a hydrocrackate charge are used. Products
from the reformer include hydrogen, light ends, and reformate.
The reformate produced is approximately 84.1 vol.% of the naphtha
feed or 11,833 BPD. This product stream is routed to the gaso-
line blending facilities. Light end yield is approximately
200 SCF/bbl feed. Light ends from the reformer are routed to
the light end recovery unit. The composition of the light end
stream was taken from data given on the Engelhard Mineral and
Chemicals Corp. Reformer (HY-006). Hydrogen production from
this unit is 1330 SCF/bbl feed for a total of 18.7 x 10s SCFD.
Module hydrogen requirements are determined from the
hydrocracker requirements (125 x 10s SCFD). A portion of this
hydrogen is produced at the CRU (18.7 x 106 SCFD) and at the
ethylene plant (4.87 x 10s SCFD). The bulk of the hydrogen
(101.4 x 106 SCFD) must be supplied from a hydrogen generation
plant. This module assumes the use of steam-naphtha reforming for
hydrogen production. The naphtha requirement for this unit is
12.98 lb/103 SCF H2 or 4874 BPD (VO-025). The naphtha is
supplied from the catalytic cracker.
C-264
-------
III-G. Liquefaction Syn-Crude Refinery
The light end recovery unit receives gases from the gas
treating facilities, isom unit, catalytic reformer, and catalytic
cracker. Total light end charge is approximately 4.54 x 106 lb/
day. Composition is determined by mass balance and specific unit
yield data. Since this module includes an ethylene plant to up-
grade the low molecular weight paraffins, the light end recovery
separates the propane and lighter components from the process
gas stream to supply feed to the ethylene plant. The butane and
butene rich stream is routed to an alkylation unit.
The ethylene plant receives approximately 2.4 x 10s
Ib/day charge including 112,800 Ib/day ethylene; 347,129 Ib/day
ethane; and 484,217 Ib/day propane. Yields are based on infor-
mation taken from the Radian Refinery Siting Study (RA-119).
Products from the ethylene plant include ethylene, propylene,
butadiene, gasoline, and fuel oil. The methane rich stream from
the ethylene plant is used for refinery fuel gas.
The alkylation unit receives 1,365,000 Ib/day C4 and
739,000 Ib/day d+~. Assuming complete conversion of the limiting
reactant (butene), alkylate production is 6129 BPD. This stream
is routed to gasoline blending. Excess butane, approximately
600,000 Ib/day, also goes to the gasoline blending facilities.
The gasoline blending facilities receive gasoline
components from the ethylene plant, alkylation unit, isom unit,
catalytic reformer, flexicoker and catalytic cracker. Total
gasoline make is 51,995 BPD.
3.3 Heat Requirements
Overall module heat requirements were determined from
individual process unit utility requirements and flow rates.
Heat requirements for the various process units are presented in
Table 3-2. The total module heat requirement is 44.5 x 103
C-265
-------
O
I
Ixi
TABLE 3-2
MODULE HEAT REQUIREMENT
(RA-119, HY-013)
Heat Requirement
Unit
Hydrocracker
Isomerization
Catalytic Reformer
Fluid Catalytic
Cracker
(3)
Alkylation
Ethylene Plant
H2 Plant
ion.
Unit
Heat
Per bbl Charge
(MBTU/bbl)
112
68.4
265
153.7
240
8760
165.4
Flow Rate
(BPD)
100,000
6,030
14,070
35,200
6,129 BPD alkylate
623.1 x 103lb/day C2 -
101.4 x 106SCF
ixcif i-t j_ j. cuic-ri u
(BTU/day)
11.2 x 109
0.412 x 109
3.73 x 109
5.41 x 109
1.47 x 109
5.46 x 109
16.8 x 109
44.5 x 109
(1) Alkylation heat requirement based on alkylate production.
(2) Ethylene plant heat requirement based on ethylene production.
(3) Hydrogen plant heat requirement based on 103 SCF hydrogen production.
i
o
f
H-
ro
H>
O
rt
H-
O
l
O
C
fl>
5*1
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P-
-------
III-G. Liquefaction Syn-Crude Refinery
Btu/day. This heat requirement is supplied partially by refinery
gas with a heating value of 1050 Btu/SCF. The refinery gas should be
capable of supplying approximately 16.7% of the heat requirement
or 7.05 x 109 Btu/day. The difference is supplied by residual
fuel oil. The fuel oil heating value is assumed to be 6.3 x 10s
Btu/bbl (EN-071). In order to determine emissions at specific
sources, fuel gas is considered to be used at the ethylene plant'
and alkylation unit. Fuel oil is utilized at the other processing
units.
Ancillary energy required by the module as electricity
'is estimated as 3% of the total heat requirement or 1.38 x 109
Btu/day (BA-230). This value is compared to the available process
utility information (HY-013) and the higher value used as the
energy requirement of the refinery. Since process utility infor-
mation indicates an electrical requirement of 1.66 x 10sKw-Hr/day
or 5.67 x 109 Btu/day, this value is used for the ancillary energy
requirement. Considering the energy required to produce electri-
city, a conversion of 10,000 Btu per Kw-Hr is used to determine
a total ancillary energy of 16.6 x 109 Btu/day. Ancillary energy
requirement for a module producing 1012 Btu/day of primary liquid
fuels is 35.1 x 109 Btu/day.
3.4 Module Efficiencies
Three different efficiency terms are defined for each
of the modules considered in this study. These three efficiencies
are defined as follows:
(1) Primary fuels efficiency:
Primary liquid fuels from the liquefaction
refinery module are naphtha, distillate oil, and residual oil.
The primary fuels efficiency is the heating value of these three
products divided by the heating value of the crude feed. This
value is 81.5% for this module.
C-267
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III-G. Liquefaction Syn-Crude Refinery
(2) Total products efficiency:
This efficiency credits any other hydro-
carbon products made. Sulfur is not included. Total
products efficiency is the heating value of all hydro-
carbon products divided by the heating value of the feed.
This efficiency accounts for the by-products such as
ethylene, propylene, and butadiene in this module. The
total products efficiency of the liquefaction refinery
module is 89.5%.
(3) Overall Efficiency:
This efficiency takes into account any
ancillary energy such as electricity that may be
supplied to a module. This efficiency is equal to
the heating value of all hydrocarbon products divided
by the heating value of the feed plus any ancillary
energy supplied to the module. The overall efficiency of
this module is 87.1%.
Determination of the efficiencies for the liquefaction refinery
are shown in Table 3-3.
3.5 Water Requirements
The make-up water requirement for the module was
estimated from the module heat requirement and the waste-
water effluent, assuming that heat (evaporation) and waste-
water represent the only significant losses of water from
the system. The heat requirement of 44.5 x 109 Btu/day was
estimated to result in 5.33 x 10s gal/day of water evaporated
from the module (1000 Btu/lb H20) or approximately 1.27. bbl
C-268 '
-------
III-G. Liquefaction Syn-Crude Refinery
TABLE 3-3
LIQUEFACTION REFINERY MODULE EFFICIENCY
Module Stream Heating Value Amount Total Heat
Syn-Crude 6.1 x 10sBtu/BBL 100,000 BPD 6.1 x lO
Gasoline 5.248 x 106Btu/BBL 51,995 BPD 2.73 x 10llBtu.
Distillate Fuel 5.88 x 10s Btu/BBL 34,956 BPD 2.05 x 10MBtu
Residual Fuel 6.3 x 10s Btu'/BBL 2,957 BPD 0.19 x lO^Btu
Primary Efficiency = 4.97/6.1 - 81.5%
Ethylene 21,625 Btu/lb 623,155 Ib/Day 0.13 x 10llBtu.
Propane-Propylene 21,339 Btu/lb 1,412,892 Ib/Day 0.32 x 10lIBtu
Butadiene 20,217 Btu/lb 24,456 Ib/Day 0.004 x 101
Coke 14,000 Btu/lb 279 x 103Ib/Day 0.04 x lO^
Total Products Efficiency = 5.46/6.1 = 89.5%
Ancillary Energy = 16.6 x 109 Btu/Day
Overall Efficiency = 5.46/6.27 = 87.1%
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III-G. Liquefaction Syn-Crude Refinery
water/bbl crude. Wastewater effluent is set at 15 gal/bbl crude
(RA-119). From these two rates, a make-up water requirement of
1.63 bb/bbl crude or 6.85 x 106 gal/day is defined. The water
requirement for a refinery producing 1012 Btu/day of primary
liquid fuels is 16.3 x 10s gal/day.
3.6 Land Requirements
The land requirement for a grass roots refinery is
estimated to be 218 acre/10,000 BPD crude capacity (NE-046).
The land requirement for this module is 2180 acres or 3.4 square
miles. The Radian Refinery Siting Study estimated that 1/4 of
the land is used for process units and 2/3 for the tank farm
with the remainder being unused boundary.
3.7 Occupational Health
Occupational health data were based on published data
for a refinery supplying fuel to a 1000 Mw power plant (BA-230).
Values for deaths, injuries, and man-days lost are presented on
a 106 Btu output basis in the Battelle study. These values
were adjusted to a 1012 Btu/day output basis for presentation
in Table 2-1.
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III-G. Liquefaction Syn-Crude Refinery
4.0 ENVIRONMENTAL EFFECTS
4.1 Air Emissions
Air emissions from the module result from fuels com-
bustion (process heaters), the CO boiler, sludge incineration,
sulfur recovery, petroleum storage and miscellaneous fugitive
sources. Module air emissions and stack parameters are shown
in Table 4-1.
4.1.1 Fuel Combustion Emissions
Fuel combustion emission sources were determined to
be the following:
Heavy oil hydrocracking
Isomerization Unit
Catalytic Reformer
Catalytic Cracker
Hydrogen Plant
Ethylene Plant
Alkylation Unit
Emissions from these sources were calculated by using appropriate
EPA fuel combustion factors (EN-071).
The factors for combustion of fuel gas and fuel oil in
process boilers are shown in Table 4-2. Sulfur dioxide emissions
from fuel gas were determined by assuming compliance with
the federal regulation of 0.10 gr H2S/dscf fuel gas (ST-124).
Sulfur dioxide emissions from distillate fuel combustion sources
were determined by assuming a 0.3 wt. % S content. Aldehyde
emissions from fuel oil combustion were combined with hydrocarbons
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TABLE 4-1
100.000 BPD REFINERY MODULE - LIQUEFACTION SYN-CRUDE EMISSIONS AND STACK PARAMETERS
Source
1. Hvy Oil
Hydro-
cracking
2. Isomeriza-
tion
3. Reformer
4. Catalytic
Cracker
i
5. Hydrogen
Plant
6. Ethylene
Plant
7. Alkylation
Unit
8. CO Boiler
9. Sludge
Incinera-
tion
10. Petroleum
Storage
11. Miscel-
laneous
TOTAL
Heat
Input
mm Btu/Hr
466.7
17.2
155.4
225.4
608.5
227.5
61.3
15.0
Fuel
3.1xl03gal/
hr
115 gal/hr
1.04xl03gal/
hr
1. 50x10 3 gal/
hr
4.06xl03gal/
hr
216.7xl03
SCFH
58.3xl03SCFF
86.4 gal/hr
100 gal/hr
Emissions Ibs/lh:
Particulates
46.7
1.7
15.6
22.6
81.1
3.9
1.1
20.2
2.9
195.8
SO 2
.32.6
4.9
44.2
64.1
.94.7
5.(
l.t
.21. i
4.f
80.!
Total
Organics
15.5
0.5
5.2
7.5
. 15.9
0.7
0.2
9.5
0.5
226.1
1458
1739.6
CO
12.5
0.5
4.2
6.0
16.2
3.7
1.0
8.5
1.8
54.4
N0r
L24.5
4.6
41.5
60.2
324.5
49.8
13.4
97.4
4.1
720
Stack Parameters
Mass
Flow
Ibs/Hr
432.1xl03
15.9xl03
143.9xl03
208. 7x10 3
563.3x10'
197.1xl03
53.1xl03
445.3x10'
14.0xl03
ACFM
165.3xl03
6. 1x10 3
55. 1x10 3
7 9. 8x10 3
215.5xl03
73.4xl03
21.1xl03
149.5xl03
5. 4x10 3
Velocity
FPS
60
60
60
60
60
60
60
60
60
Height
Ft.
200
200
200
200
200
200
200
200 .
200
50
5
Temperature
°F
450
450
450
450
450
450
450
350
450
Diameter
Ft.
7.65
1.47
4.42
5.32
8.73
5.27
2.73
7.27
1.38
o
I I
ro
•-j
N3
p
H«
C
Hi
O
H-
O
CD
n>
H)
H-
n>
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III-G. Liquefaction Syn-Crude Refinery
TABLE 4-2
EPA EMISSION FACTORS
(EN-071)
Fuel
Emissions
Particulates
S02
HC
CO
NOX
Aldehydes
Nat. Gas
lb/106ft3
18
0.6
3
17
230
Resid. Oil
lb/103 gal
23
157 x S*
3
4
40
1
*S = Wt. % Sulfur in fuel oil
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III-G. Liquefaction Syn-Crude Refinery
to give total organic emissions. Due to the high temperature
involved in the hydrogen plant furnace (1700°F), a different
set of emission factors were used for the hydrogen plant emissions
(RA-119). These factors are shown in Table 4-3.
TABLE 4-3
AIR EMISSIONS FOR 5TEAM-HYDROCARBON REFORMING FURNACE
Part. ' SO2 CO EC NOY Aldehydes
Ib/bbl
Fuel Oil 0.87 6.72S* 0.168 0.14 3.36 0.025
*wt. % S in the fuel oil
Flue gas rates resulting from fuel combustion were
calculated by assuming stoichiometric combustion with 2070 excess
oxygen. On this basis, combustion of one SCF of refinery gas
results in 12.4 SCF of flue gas, and combustion of one gallon of
fuel oil results in 1820 SCF of flue gas. A stack velocity of
60 FPS and temperature of 450°F were assumed for stack sizing
and dispersion modeling.
4.1.2 CO Boiler
Emissions from the CO boiler were calculated as follows
(1) Particulate emissions were assumed to be the
maximum allowed by Federal emission standards 0.027 gr/dscf
(EN-196).
(2) SOa emissions in the regenerator flue gas were
calculated by assuming that the coke content of the feed was
6%, the wt. % S in the coke was 70% of the wt. "L S in the feed,
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III-G. Liquefaction Syn-Crude Refinery
and all the sulfur in the coke burns to S02 (HA-157). Sulfur
present in the fuel oil which is normally used to sustain com-
bustion also contributes some S02. Stack gas from the sulfur
recovery area was combined with the effluent from the CO boiler;
therefore, the sulfur dioxide from this source is shown at the
CO boiler.
(3) The hydrocarbons in the regenerator flue gas
4
were assumed to be combusted in the CO boiler to a concentration
equivalent to the concentration of hydrocarbons in the flue gas
generated by normal fuel oil combustion. A distillate oil
emission factor of 3 Ibs hydrocarbons/Mgal distillate oil
(EN-071) was used.
(4) The regenerator flue gas entering the CO boiler
contains 71 Ibs N0x/Mbbl of cat cracker capacity (EN-071). Be-
cause of the relatively low combustion temperatures in a CO
boiler, it is assumed that the only NOX formed in the CO boiler
is from the combustion of NHa to NOx. With these premises,
Radian arrived at a NOX emission factor for CO boilers of 166
Ibs NOx/Mbbl cat cracker capacity.
(5) The emission factor Radian used for calculating
the CO emissions from the module CO boiler is 20 ppm. This
factor is based on a survey for EPA (EN-072) which reported
20 ppm to be the average CO concentration in CO boiler flue gas.
The CO boiler flue gas rate was calculated as 96,000 SCFM
(HA-157). The temperature was set at 350°F (assumes application
of heat recovery equipment).
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III-G. Liquefaction Syn-Crude Refinery
4.1.3 Sulfur Recovery
The sulfur recovery facilities consist of a three
reactor Glaus plant and a tail gas treating unit. These facili-
ties are considered capable of recovering approximately 99.97o
of the equivalent sulfur in the charge (RA-119). For an
equivalent sulfur charge of 113,000 Ib/day, the sulfur recovered
is 112,887 Ib/day. Sulfur dioxide from the tail gas treating
unit is approximately 226 Ib/day or 9.4 Ib/Hr. This gas stream
is combined with the stack gas of the CO boiler and, therefore,
this S02 emission is added to the CO boiler emission.
4.1.4 Sludge Incineration
A sludge incinerator is included in the module for
the disposal of oily and biological sludges. The quantity of
oil incinerated in the oily sludge was estimated to be 1900 gal/
day by assuming the following (RA-119):
(1) 0.0015 bbl of oily sludge/bbl syn-crude
throughput is produced.
(2) Oily sludge is 36.6 wt.7. oil.
(3) Weight of the sludge is 340 Ibs/bbl.
Assuming the oily sludge to have similar combustion character-
istics to residual oil, the EPA emission factors for residual
oil combustion (EN-071) were used to determine emissions. Using
BOD quantities and crude rates from the Radian Refinery Siting
Study (RA-119), biological sludges associated with the module
were determined to be 4167 Ib/day. Assuming a 0.5 Ibs volatile
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III-G. Liquefaction Syn-Crude Refinery
solids/lbs BOD removed and a 95% BOD removal efficiency, vola-
tile solids from waste treatment were calculated to be 1980 Ibs/
day. Assuming these sludges to be similar to those of municipal
wastes, the emission factors for municipal waste incinerators
(EN-071) were used to define the biological sludge's contribution
to the incinerator emissions. Emission factors used for the
sludge incineration are shown in Table 4-4. Sulfur dioxide emis-
sions from residual oil combustion were determined by assuming
0.005 wt. % S in the oil. Aldehyde emissions were added by the
hydrocarbon emissions to yield total organic emissions.
4.1.5 Petroleum Storage Emissions
The following assumptions based on literature data
and experience were formulated to calculate the hydrocarbon
emissions from petroleum storage.
Storage capacity is one month for feed and
products.
Only syn-crude and gasoline storage will result
in significant emissions. Residual and
distillate fuel oil storage create negligible
emissions due to low vapor pressures. High
volatility products are stored under pressure
in completely sealed vessels.
All feed and product storage will be in floating
roof tanks.
Using petroleum storage emission factors for floating roof tanks
(EN-071) for crude oil (0.029 lb/day-103 gal) and gasoline
(0.033 lb/day-103 gal), hydrocarbon emissions from storage were
calculated to be 226 Ib/hr. These emissions were estimated
to occur at a height of 50 feet.
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III-G. Liquefaction Syn-Crude Refinery
TABLE 4-4
EMISSION FACTORS FOR SLUDGE INCINERATION
Particulates
S02
HC
CO
N0x
Aldehydes
Oily
Sludge
Residual Oil
Combustion In
Process Boilers
Biological
Sludge
Municipal Incinerator
With Controls
23
157 x S*
3
4
40
1
14
2.5
1.5
35
3
* S •-- \7t. 70 sulfur in fuel oil
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III-G. Liquefaction Syn-Crude Refinery
4.1.6 Miscellaneous Hydrocarbon Emissions
There are numerous miscellaneous emissions in petro-
leum refineries which escape from sources such as valve stems,
flanges, loading racks, equipment leaks, pump seals, sumps, and
API separators. These losses are discussed in Radian's Refinery
Siting Report (RA-119). Based on literature data, Radian found
that the miscellaneous hydrocarbon emissions amount to about
0.1% of the refinery capacity for a new, well-designed, well-
maintained refinery. The composition of these hydrocarbons can
be expected to be a composite of all volatile intermediate and
refined products.
4.2 Water Effluents
. Module water effluents were estimated from information
published in the Radian Refinery Siting Study (RA-119). The waste.
water generation rate is taken as 15 gal/bbl syn-crude. Although
only 10 out of 43 petroleum refineries surveyed by API in 1967
(AM-041) reported aqueous effluent rates of 15 gal/bbl or less,
a new refinery is expected to be in the lower range due to the
use of air cooling, recycle, and new water conservation techniques
(DI-044). For a 100,000 BPD module, the wastewater effluent
is 1.5 x 106 gal/day. This quality of this effluent is defined
in Table 4-5.
4.2.1 Suspended Solids
The API survey of petroleum refinery effluents
indicated that 3 out of 23 refineries achieved suspended solids
concentrations of 10 ppm or less and that 6 out of 23 refineries
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III-G. Liquefaction Syn-Crude Refinery
TABLE 4-5
MODULE EFFLUENT WATER QUALITY
Wastewater rate = 1.5 x 106 gal/day
Concentration Amount
(ppm) (Ibs/day)
C-280
Suspended solids ' 10 125
Dissolved Solids 370 4,625
Total Organics 2.1 26.3
-------
III-G. Liquefaction Syn-Crude Refinery
achieved suspended solids concentrations of 13 ppm or less in
their wastewaters (AM-041). Based upon these data, Radian used
a suspended solids concentration of 10 ppm for the effluent
waters from this module. The mass flow rate.of suspended solid
in the module wastewater is 125 Ibs/day.
4.2.2 Dissolved Solids
Beychok (BE-147) reports that the dissolved solids
level in an typical refinery waste is 386 ppm for a wastewater
flow rate of 14.4 gal/bbl. Based upon the assumption that the
dissolved solids rate from a refinery is fixed by the refinery's
capacity, then the dissolved solids concentration is inversely
proportional to the wastewater flow rate. For the module's
wastewater flow rate of 15 gal/bbl the dissolved solids concen-
tration is approximately 370 ppm. At this concentration, 4625
Ibs/day of dissolved solids are discharged with the wastewater
from the module.
In general, as recycling increases and effluent rates
decrease, the dissolved solids content can be expected to in-
crease. The dissolved solids content will become more sensitive
to make-up water quality and to soluble salt pick-up in process
water. Dissolved solids will become variable from refinery to
refinery under these circumstances. The value chosen for this
module implies a relatively high quality make-up water. How-
ever, this value is supported by the API survey in which 16 of
26 refineries report effluent TDS values of less than 400 ppm
(AM-041).
4.2.3 Total Organics
Calculated effluent total organic concentration levels
for this module are based on information for oils and phenols
contained in the Radian Refinery Siting Report (RA-119). A
C-281
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III-G. Liquefaction Syn-Crude Refinery
2.1 ppm total organic concentration was assumed. The API survey
(AM-041) showed that 5 out of 31 companies were able to lower
wastewater oil levels to 2 ppm with biological treatment. Based
upon these data, an oil concentration of 2 ppm is considered
reasonable for a new refinery.
Beychok (BE-147) reported that a phenol level of 0.1
ppm in refinery wastes can be achieved with a well-designed
biological waste treatment system. The 1967 API survey of
petroleum refineries reported that 8 out of 38 refineries reached
phenol levels of 0.1 ppm,with biological treatment. For this
module, a phenol concentration of 0.1 ppm is assumed. Using an
assumed concentration of 2.1 ppm for total organics, 26.3 Ibs/day
of total organics are calculated to be emitted in the module
wastewater.
4.3 Thermal
The use of cooling towers should result in negligible
thermal pollution of receiving water bodies.
4.4 Solid Waste
Quantities of solids from refineries are highly
variable. Possible sources of solid waste in a refinery are
the following:
(1) entrained solids in the crude
(2) silt from surface drainage
(3) silt from water supply
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III-G. Liquefaction Syn-Crude Refinery
(4) corrosion products from process units and
sewer systems
(5) solids from maintenance and cleaning
operations
(6) water treatment sludges
(7) spent catalyst
With the exception of spent catalyst, the solids usually collect
as an oily sludge in the API separators and in the water treat-
ment plant. Literature sources (AM-042, MA-226, RA-081, and
RE-048) indicated a solid waste of three tons per day for the
200,000 BPD refinery defined in the Radian Refinery Siting Report.
Therefore, a solid waste of 1.5 tons per day is chosen for the
100,000 BPD module. This waste is assumed to be suitable for
landfill purposes.
C-283
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APPENDIX C
III-H. DOMESTIC CRUDE REFINERY
C-284
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III-H. Domestic Crude Refinery
1-0 INTRODUCTION
Petroleum refining is an established industry and, as
a result, the technology associated with refining a typical
domestic crude is well defined. In general, the processing
steps involved with refining depend upon the quality of crude
oil and the product distribution required. A typical U. S.
refinery will charge a medium sulfur domestic crude mix and
produce the normal array of liquid products ranging from light
ends through residual oil with emphasis on gasoline production.
Although processing options are available, the processing
sequence for such a refinery is reasonably straightforward.
As a result of the established and widely practiced procedures
for refining crude oil, a refinery module was obtained by
'determining the operations and processing sequences employed in
refining a typical domestic crude. For this module, a Gulf
Coast mix of approximately 35° API was used for the charge
crude. A crude sulfur content of 0.76 wt. 70 was assumed (BA-230)
C-285
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III-H. Domestic Crude Refinery
2.0 MODULE BASIS
This module is based on a typical refinery size of
100,000 BPD* of crude capacity. The module values discussed
in the following sections are determined for this 100,000 BPD
basis. However, the emission values for this module are also
expressed on a 1012 Btu/day output of major liquid fuels in
order to facilitate a comparison of this with other energy
conversion modules defined for this study: Major liquid fuels
which are assumed to be produced by this module include gasoline,
distillate fuel oil, and residual oil. A summary of the emissions
from a domestic crude refinery module producting 1012 Btu/day
of liquid fuels is presented in Table 2-1.
*A11 flow rates in this module are based on calendar days
C-206
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III-H. Domestic Crude Refinery
TABLE 2-1
SUMMARY OF ENVIRONMENTAL IMPACTS
DOMESTIC CRUDE REFINERY MODULE
Basis: 1012 Btu Output Liquid Fuel
Air (Ib/hr)
Particulates 398
S02 968
N0x 1210
CO 89.9
HC 3011
Water (Ib/hr)
Suspended Solids 246
Dissolved Solids 9121
Organic Material 51.8
Thermal (Btu/hr) 0
Solid Wastes (tons/day) 3.0
Land Use (acres) 4295
Water Requirements (gal/day) 11.2 x 10s
Occupational Health (per year)
Deaths 0.475
Injuries 35.0
Man-days lost 8363
Efficiency (7.)
Primary Fuels Efficiency 90.4
Total Products Efficiency 95.4
Overall Efficiency 94.7
Ancillary energy (Btu/day) 8.46 x 109
C-287
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III-H. Domestic Crude Refinery
3.0 MODULE DESCRIPTION
The feed to this module is a domestic crude mix of
approximately 35° API and 0.76x>7t % S (BA-230) . The module pro-
duces 0.52 bbl gasoline, 0.24 bbl distillate fuel oil, and 0.14
bbl residual fuel oil, per bbl of charge. The processing sequence
may basically be summarized as follows:
(1) First, the crude oil is separated into-light ends,
naphtha, distillate oil, gas oil, and residual oil. A series of
parallel operations follow this separation as the various frac-
tions are processed to achieve the desired products.
(2) The straight run naphtha is desulfurized and then
upgraded (isomerization and/or catalytic reforming) to product
gasoline quality.
(3) Light ends are treated for acid gas (H2S and C02)
removal and then separated for specific uses. Normally, methane
is consumed as fuel gas while ethane and propane rich streams
are used for petrochemical feedstocks. Butanes are routed with
butylenes to alkylation units for conversion to motor alkylate.
(4) The distillate oil fraction is normally desul-
furized with some additional production of naphtha, and either
used in-plant or sold as a distillate fuel.
(5) The gas oil from the crude may be desulfurized
and then routed to a fluid catalytic cracker for conversion to
gasoline. The gas oil fraction may be recycled to extinction
while producing light ends, gasoline, distillate fuel, and
residual fuel.
C-288
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III-H. Domestic Crude Refinery
(6) The residual oil fraction is also desulfurized.
Some additional naphtha and distillate fuel may be produced as
a result of this step. The desulfurized residual fuel is used
as a plant fuel with the excess routed to product tankage.
In addition to the units required for product processing, auxi-
liary units such as sulfur recovery, tail gas treating, hydrogen
generation, sour water stripping, and wastewater treating are
utilized.
3.1 Module Processes
The process units and processing sequences used in this
refinery module were obtained from the Radian Refinery Siting
Study (RA-119). The processing units included in this module
are the following:
crude desalter
atmospheric distillation unit
vacuum distillation unit
naphtha HDS unit
distillate HDS unit
gas oil HDS unit
residual oil HDS unit
gas treating plant
sulfur recovery unit
tail gas treating unit
isomerization unit
light end recovery unit
ethylene plant
catalytic reformer
alkylation unit
fluid catalytic cracker
CO boiler
C-239
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III-H. Domestic Crude Refinery
hydrogen plant
sour water stripper
wastewater treating plant
gasoline blending
A flow diagram of the domestic 'crude refinery module is shown
in Figure 3-1.
3.2 Module Basis and Flow Rates
Flow rates for the refinery were taken from the
Radian Refinery Siting Study (RA-119). In this module, crude
charged to the refinery is first desalted and then routed to the
atmospheric distillation tower. In this tower, the crude is
separated into light ends, naptha, distillate oil, atmospheric
gas oil, and reduced crude. Product distribution from the
atmospheric tower is as follows:
light ends 920,000 Ib/day
naphtha 28,300 BPD
distillate oil 17,000 BPD
gas oil 10,000 BPD
reduced crude 40,000 BPD
The reduced crude is routed to a vacuum distillation tower and
split into vacuum gas oil and vacuum residuum. Typical product
splits and utility requirements for crude distillation were
obtained from the Radian study. Radian assumed that 407o of the
incoming crude would be charged to the vacuum tower as reduced
crude (RA-119).
All liquid streams from the crude distillation unit
are assumed to be routed to hydrotreaters for desulfurization.
C-290
-------
V/A3TE
WflTfR
u
3,
hJAOMTUA
WDS
KGCHCDATO-GM
3uVtf MCU74L rulL
CO
BOILER.
RCSIU
uos
StAfUQ
ftCOVEW
PLAMT
TAIL G*s
Sutrua
TAIL G&S
THE *r IMG
PLANT
suurun
CLCMCMTAL 30LFUff
C£T*imc
CRfiCKlitl
t OIL
UCMT
CMOS
ficcovWr
T
-i- GA5OUME
FIGURE 3-1 DOMESTIC CRUDE REFINERY MODULE
-------
III-H. Domestic Crude Refinery
Straight run naphtha from the crude distillation
process goes to a naphtha hydrotreater. This unit was based on
the Unionfining Hydrotreating Process (HY-013). Naphtha yield
is 100 vol.7o of the feed. Light end production is approximately
4 scf/bbl of charge or 15,000 Ib/day. The light ends are routed
to gas treating facilities for acid gas removal. Approximately
30 vol% of the desulfurized naphtha from the hydrotreater (8490
BPD) is routed to an isom unit x^hile 70 vol.% of the product
stream (19,810 BPD) is routed to a catalytic reformer. Distillate
oil from the atmospheric distillation tower goes to a distillate
oil hydrotreater. Information for this module unit was obtained
from the Gulfining Hydrotreating Process and the GO-fining_Process
(HY-013). The desulfurized product is 99.6 vol.7« of the charge.
This stream, 16,592 BPD, is routed to distillate fuel storage.
Naphtha produced at this unit (1.7 vol. % of the feed = 714 BPD),
is routed to the gasoline blending facilities. Light end
production is approximately 0.75 wt.% of the feed. This stream,
45,000 Ib/day, goes to the gas treating facilities for acid gas
removal. Gas oil streams from the atmospheric and vacuum
distillation towers are routed to a gas oil hydrotreater. This
unit was also based on the Unionfining Hydrotreating Process (HY-013)
Desulfurized gas oil yield is 97.6 vol % of the feed, or -29,880
BPD. This stream is routed to a fluid catalytic cracker. Naph-
tha yield is. 4. 2 vol "L of the charge. The naphtha goes to gaso-
line blending. Light end production is approximately 17 SCF/bbl
or 270,000 Ib/day. The light ends are routed to gas treating
facilities for acid gas removal.
Vacuum resid from the vacuum distillation tower is
routed to a resid hydrotreater. Information on this unit was
obtained from the Gulf Hydrotreating Process and the Standard
Oil Resid Hydrotreating Process. Products "include desulfurized
resid, distillate oil, naphtha, and light ends. Desulfurized
C-292
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III-H. Domestic Crude Refinery
resid yield is 83.6 vol.7, of the feed, or 16,720 BPD. This stream
is routed to residual fuel product tankage. Distillate oil
production is 3,000 BPD or 15 vol.7, of the charge. This product
stream goes to distillate fuel storage. Naphtha yield is 4.2 vol.
7, of the feed (840 BPD) . A portion of this stream (630 BPD) is
routed to the steam-naphtha reformer for hydrogen production.
The remaining naphtha goes' to the gasoline blending facility.
Light end production is approximately 1.7 wt.7o of the feed. Light
ends are routed to the gas treating plant for acid gas removal.
The refinery hydrogen demand is considered to be 42.7
x 106 scfd» This value is estimated from the Radian Refinery
Siting Study (RA-119). Some hydrogen is supplied by both the catalytic
reformer (24'x 106 scfd) and the ethylene plant (5.6 x 10s scfd).
The difference (13.1 x 10s scfd) is supplied by a hydrogen
generation plant. A steam-naphtha reformer is used. The naphtha
requirement for this unit is 12.98 lb/103 scf or 630 BPD (VO-025).
The fluid catalytic cracker receives 29,880 BPD from
the gas oil hydrotreater. Product yields and utility requir-
ments were based on the Gulf Development Corporation's Riser
Cracking Process (HY-013). Product streams from the catalytic .
cracker include light ends, naphtha, distillate fuel and residual
fuel. The residual oil from this unit is approximately 6.5 vo!70
of the feed. This stream (1942 BPD) is routed to product tankage.
Distillate fuel'yield is 15.5 vol.% of the feed or 4632 BPD. This
product stream is routed to distillate fuel tankage. Naphtha
production is 17,480 BPD or 58.5 vol.7* of the feed. This product
stream is routed to the gasoline blending facilities. Light
ends from the cat cracker go to a light end recovery unit. The
light end yield is 2.22 x 105 Ib/day. Composition of the light
end stream is determined by riser cracking yield data (HY-013).
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III-H. Domestic Crude Refinery
A CO boiler is included in the refinery module to
combust the carbon monoxide in the flue gas from the cat cracker
regenerator. The CO boiler serves the purpose of reducing the
carbon monoxide emission while recovering heat in the form of
flue gas sensible heat and carbon monoxide heat of combustion.
Fuel oil added to sustain combustion is considered to be 10%
of the energy supplied by CO combustion (RA-119). Using data
on the composition of regenerator flue gases (HA-157) and on the
specific heats and heats of combustion of .gases (PE-030.) , heat
from the CO boiler is determined to be as follows:
sensible heat 104 MM Btu/hr
CO combustion 112 MM Btu/hr
fuel combustion 11 MM Btu/hr
The total heat recovered by the CO boiler, 227 MM Btu/hr, is
sufficient to meet module steam demands. Therefore, a separate
boiler for steam generation will not normally be in operation.
The gas treating plant receives light ends from the
atmospheric distillation tower, the four hydrotreating units,
and the fluid catalytic cracker. An amine unit is used to re-
move the acid gas (H2S and CC^) from the gas stream. The
sweetened gas stream is routed to the light end recovery faci-
lities. The.hydrogen sulfide rich stream goes to a Glaus plant
for sulfur recovery. Radian assumed 100% H2S removal at the
gas treating facilities.
Equivalent sulfur in the acid gas is determined by a
module sulfur balance assuming that the distillate and residual
fuels contain 0.3 wt.% S. The sulfur recovery facilities consist
of a three reactor Glaus plant and a tail gas treating unit.
These facilities are considered capable of recovering approxi-
mately 99.9% of the equivalent sulfur in the charge to the Glaus
plant (RA-119). For an equivalent sulfur charge of 43,751 Ib/day,
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III-H. Domestic Crude Refinery
the sulfur recovered is 43,707 Ib/day or 19.5 LTPD. Stack gas
from the tail gas treating unit is routed into the CO boiler
effluent gases.
The isomerization unit of the module receives 30 vol.%
of the straight run desulfurized naphtha. Process yields and
utility requirements were obtained from the British Petroleum
Trading Limited Isomerization Unit data (HY-013) . The isotnerate
yield is 100 vol.70. The isomerate stream is routed to gasoline
blending. Light ends produced from the isom unit are approxi-
mately 1.1 wt % of the isom unit charge. The hydrogen require-
ments for this unit were assumed to be negligible.
The catalytic reformer receives 70 vol "L of the
straight run desulfurized naphtha. The module reformer was based
on data from the Rheniforming and Ultraforming processes (HY-013) .
Products from the reformer include hydrogen, light ends, and
reformate. The reformate produced is approximately 73 vol % of
the naphtha feed or 14,460 BPD. This product stream is routed
to gasoline blending. Light end yield is approximately 15.7 wt "L
of the feed. Light ends from the reformer are routed to the
light end recovery unit. The composition of the light end stream
was taken from data given on the Engelhard Minerals and Chemical
Corp. Reformer (HY-006). Hydrogen production from this unit is
1210 scf/bbl feed for a total of 24.0 x 106 scfd.
The light end recovery unit receives gases from the
gas treating plant, isom unit and catalytic reformer. Total
light end charge is approximately 4.13 x 10s Ib/day. Composition
is determined by mass balance and specific unit yield data. Since
this module includes an ethylene plant to upgrade the low
molecular weight paraffins, the light end recovery section separates
propane and lighter components from the process gas stream to
supply feed for the ethylene plant. The butane and butene rich
stream is routed to an alkylation unit.
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III-H. Domestic Crude Refinery
The ethylene plant receives approximately 1.79 x 106
Ib/day charge including 101,000 Ib/day ethylene, 200,000 Ib/day
ethane, and 437,000 Ib/day propane. Yields are based on infor-
mation from the Radian Refinery Siting Study (RA-119). Products
from the ethylene plant include ethylene, propylene, butadiene,
gasoline, and fuel oil. The methane rich stream from the ethylene
plant is used for refinery fuel gas.
The alkylation unit received 170.9 x 106 Ib/day Ci»
and 630 x 103 Ib/day Ci»=. Assuming complete conversion of the
limiting reactant (butene) alkylate production is 5,225 BPD.
This stream is routed to gasoline blending. Excess butane,
approximately 1.06 x 10s Ib/day, also goes to the gasoline
blending facilities.
The gasoline blending facilities receive gasoline
components from the ethylene plant, alkylation unit, isom unit,
catalytic reformer and catalytic cracker. Total gasoline make
is 52,458 BPD.
3.3 Module Heat Requirements
Overall module heat requirements were determined from
process unit utility requirements and flow rates. Heat require-
ments for the various process units are presented in Table 3-1.
The total module heat requirement is 34.7 x 109 Btu/day. This
heat requirement is supplied by refinery gas with a heating value
of 1050 Btu/scf. The refinery gas should be capable of supplying
approximately 18.2% of the heat requirement or 6.3 x 109 Btu/day.
The difference is supplied by residual fuel oil. The fuel oil
heating value is assumed to be 6.3 x 10s Btu/bbl (EN-071). In
order to determine emissions at specific sources, fuel gas was
considered to be used at the ethylene plant and fuel oil was
assumed to be utilized at the other processing units.
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TABLE 3-1
o
N3
Unit
MODULE HEAT
(RA-119,
Heat Requirement
Per bbl Charge
(M Btu/bbl)
80
50
25
55
55
64
68.4
265
153.7
240
8760
165.4
REQUIREMENT
HY-013)
Flow Rate
(BPD)
100,000
40,000
28,300
17,000
30,000
20,000
8,490
19,810
29,880
5,225 BPD alkylate
715 x 103 Ib/day C2=
13.1 x 106SCFD H2
TOTAL
Unit
Heat
Requirement
(Btu/day)
8.00 x 109
2.00 x 109
0.71 x 109
0.94 x 109
1.65 x 109
1.28 x 109
0.58 x 109
5.25 x 109
4. 59 x 109
1.25 x 109
6.26 x 109
2.17 x 109
34.68 x 109
Atmospheric^ '
Distillation
Vacuum Distillation
Naphtha HDS
Distillate HDS
Gas Oil HDS
Resid HDS
Isomerization
Catalytic Reformer
Fluid Catalytic Cracker
Alkylation ^
Ethylene Plant
Hydrogen Plant
(1) Crude distillation heat requirement 100M Btu/bbl. Radian assumed 8070 of this
heat requirement at atmospheric tower.
(2) Alkylation heat requirement based on alkylate production.
(3) Ethylene plant heat requirement based on ethylene production.
(4) Hydrogen plant heat requirement based on 103scf hydrogen production.
O
O
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III-H. Domestic Crude Refinery
Ancillary energy required by the module as electricity
is estimated as 37. of the total heat requirements (1.07 x 109
Btu/day) (BA-230). This value was compared to the available process
utility information (HY-013) and the higher value was used as the
ancillary energy requirement of the refinery. Since process utility
information indicates an electrical requirement of 429 x 103
kwhr/day or 1.46 x 109 Btu/day, this value was used as the
ancillary energy requirement. Considering the energy required
to produce electricity, a conversion of 10,000 Btu/kwhr is used
to determine an ancillary energy of 4.28 x 109 Btu/day. Ancillary
energy requirement for a module producing 1012 Btu/day of primary
liquid fuels is 8.46 x 199 Btu/day.
3-4 Module Efficiency
Three different efficiency terms are defined for each
of the modules considered in this study. These three efficiencies
are defined as follows:
(1) Primary fuels efficiency:
Primary liquid fuels from the domestic crude
refinery module are naphtha, distillate oil, and residual oil.
The primary fuels efficiency is the heating value of these three
products divided by the heating value of the crude feed. This
value is 90.4% for this module.
(2) Total Products efficiency:
This efficiency credits any other hydrocarbon
products made. Sulfur is not included. Total products efficiency
is the heating value of all hydrocarbon products divided by the
heating value of the feed. This efficiency accounts for the by-
products such as ethylene, propylene, and butadiene in this
module. The total products efficiency of the domestic crude
refinery module is 95.47a.
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III-H. Domestic Crude Refinery
(3) Overall Efficiency:
This efficiency takes into account any ancillary
energy such as electricity that may be supplied to a module.
This efficiency is equal to the heating value of all hydro-
carbon products divided by the heating value of the feed plus
any ancillary energy needs of the module. The overall efficiency
for this module is 94.7%.
Determinations of these efficiencies for the domestic
crude refinery are shown in Table 3-2.
3. 5 Wa t er Requir emen ts
The makeup water requirement for the module x^as estimated
from the module heat requirement and the wastewater effluent, as-
suming that heat (evaporation) and wastewater represent the only
significant losses of water from the system. The heat require-
ment of 34.7 x 109 Btu/day was estimated to result in 4.15 x 106
gal/day of water evaporated from the module (1000 Btu/lb H20) or
approximately 0.99 bbl water/bbl crude. Wastewater effluent was
set at 15 gal/bbl crude (RA-119). From these two rates a makeup
water requirement of 1.35 bbl/bbl crude (5.65 x 106 gal/day) was
defined. Water requirement for a refinery producing 1012 Btu/day
of primary liquid fuels is 11.2 x 10s gal/day.
3.6 Land Requir ement s
The land requirement for a grass roots refinery is
estimated to be 218 acre/10,000 BPD (NE-046). The land
requirement for this module is 2180 acres or 3.4 square miles.
The Radian Refinery Siting Study estimated that 1/4 of the land
is used for process units and 2/3 for the tank farm, with the
remainder being unused boundary.
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III-H. Domestic Crude Refinery
TABLE 3-2
EFFICIENCY CALCULATIONS FOR DOMESTIC
CRUDE REFINERY MODULE
Module Stream
Crude
Gasoline
Distillate
Fuel
Residual Fuel
Heating Value
5.6 x 10sBtu/bbl
5.248 x 106Btu/bbl
5.88 x 106Btu/bbl
6.3 x 106Btu/bbl
Amount
100,000 BPD
52,458 BPD
24,224 BPD
14,265 BPD
Total Heat
5.60 x 10M Btu-
2.75 x 101.1 Btu
1.41 x 10ll Btu
0.90 x 10ll Btu
Primary Efficiency = 5.06/5.6 =90.4
Ethylene 21,625
Propane-Propylene 21,339
Butadiene 20,217
715,000 Ib
550,000 Ib
30,000 Ib
0.15 x 1011 Btu
0.12 x 1011 Btu
0.01 x 1011 Btu
Total Products Efficiency = 5.34/5.6 = 95.4%
Ancillary Energy = 4.28 x 109 Btu/day
Overall Efficiency = 5.34/5.64 = 94.7%
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III-H. Domestic Crude Refinery
3.7 Occupational Health
Occupational health data were obtained from the Battelle
study (BA-230). Values for deaths, injuries, and man-days lost
were presented on a 106 Btu output basis in the Battelle study.
These values were adjusted to a 1012 Btu/day output basis for
this study.
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III-H. Domestic Crude Refinery
4.0 ENVIRONMENTAL EFFECTS
4.1 Air Emissions
Air emissions from the module result from fuels com-
bustion (process heaters), CO boiler, sulfur recovery, sludge
incineration, petroleum storage, and miscellaneous hydrocarbon
emissions. Module air emissions and stack parameters are shown
in Table 4-1.
4.1.1 Fuel Combustion Emission
Fuel combustion emission sources were determined to be
the following:
atmospheric distillation
vacuum distillation
naphtha hydrotreater
distillate hydrotreater
gas oil hydrotreater
resid hydrotreater
isom unit
catalytic cracker
catalytic reformer
hydrogen plant
ethylene plant
alkylation unit
Emissions from these sources are calculated by use of EPA fuel
combustion factors (EN-071).
Factors for the combustion of fuel gas and residual
fuel oil are shown in Table 4-2. Sulfur dioxide emissions from
fuel gas combustion were determined by assuming that the fuel gas
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TABLE 4-1
AIR EMISSIONS AND STACK PARAMETERS
100.000 BPD RSFINERY MODULE
O
i
SOURCE
Atm. Distillation
Vac. Distillation
Naphtha HDS
Distillate KDS
Gas Oil HDS
Residual H!)S
Isoinerization
Catalytic Cracker
Reforner
Hydrogen Plant
Echylcnc
Alkylation
CO Boiler
Sludge Incineration
Petroleum Storage
Miscellaneous
TOTAL
HEAT DUTY
MMBTU/HR
331.5
84.5
'28.0
37.5
69.0
55.4
25.0
190.5
212.5
90.3
262.5
53.0
14.7
FUEL
2.21x10'
gal/hr
562.5
gal/hr
187.5
gal/hr
250 gal/
hr
458 gal/
hr
370 gal/
hr
166.7
gal/hr
1.27xl03
gal/hr
1.42x10'
gal/hr
602 gal/
hr
250x10'
SCFK
353 gal/
hr
73.3 gal/
hr
97.1 gal/
hr
EMISSIONS Ibs/hr
PARTIC-
ULATES
50.8
12.9
4.3
5.75
10.5
S.5
3.83
29.2
32.7
12.0
4.5
3.13
15.4
2.8
201.3
so2
104
26.5
8.8
11.8
21.6
17.4
7. £5
59.9
66.9
28.8
67.0
16.6
LOS. 7
4.67
490.2
TOTAL
ORGANICS
8.8)
2.25
0.75
1.0
1.8J
1.4J
0.67
5. 03
5.6}
2.4
0.7>
1.41
8.05
0.4>
243
1240
CO
8.83
2.25
0.75
1.0
1.83
1.48
0.67
5.08
5.68
2.4
4.25
1.41
8.06
1.83
1523.6 45.5
N0x
88.3
22.5
7.5
10
18.3
14.8
6.66
50.8
56.8
48.0
60
14.1
206.8
4.0
608.0
STACK PARAMETERS
MASS FLOW
LB/HR
307.4x10'
78.0xlOJ
25.9x10'
34.7x"lO'
63.6x10'-
51.4x10'
23.1xlOJ
176.3x10'
192.5x10'
83.6x10'
227.3x10'
49.0x10'
378x10'
14.2x10'
! ACFM
117.6x10'
29.8x10'
10.0x10'
13.2x10'
24.3x10'
19.7x10'
8.85x10'
67.4x10'
75.3x10"
11.8x10'
90.3x10'
18,7x10'
127xlOs
5.2x10'
»_L
VEL.
FPS
60
60
60
60
60
60
60
60
60
60
60
60
60
60
HT.
FT.
200
200
200
200
200
200
200
200
200
200
200
200
200
200
50
5
TEMP
°F
450
450
450
450
450
450
450
450
450
450
450
450
450
450
DIAM.
FT.
6.45
3.25
1.88
2.17
2.93
2.64
1.77
4.89
5.16
3.35
5.66
2.57
6.70
1.35
M
M
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III-H. Domestic Crude Refinery
TABLE 4-2
EPA EMISSION FACTORS
(EN-071)
Fuel
Nat. Gas ResTd. Oil
Emissions lb/106ft3 lb/103gal
Particulates 18 23
S02 0.6 157 x S*
HC 3 3
CO 17 4
230 40
Aldehydes -- 1
*S = wt. 7o sulfur in fuel oil
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III-H. Domestic Crude Refinery
contained 0.10 gr H2S/dscf fuel gas (ST-124). Sulfur dioxide
emissions from the distillate fuel were determined by assuming
a 0.3 wt 70 S content. Aldehyde emissions from fuel oil combustion
were combined with hydrocarbons to give total organic emissions.
Due to the high temperature involved in the hydrogen plant fur-
nace (1700°F), a different set of emission factors was used for
the hydrogen plant emissions (RA-119). These factors are shown
in Table 4-3.
TABLE 4-3
AIR EMISSIONS FOR STEAM-HYDROCARBON REFORMING FURNACE
Part. SOj CO HC NO.. Aldehydes
Ib/bbl
fuel oil Oj84 6.72S* 0.168 0.14 3.36 0.025
*wt % sulfur in fuel oil
Flue gas rates resulting from fuel combustion were
calculated by assuming stoichiometric combustion with 20% excess
oxygen. Combustion of one scf of refinery gas results in 12.4 scf
of flue gas. Combustion of one gallon of residual oil results in
1820 scf of flue gas. A stack velocity of 60 fps and temperature
of 450°F were assumed.
4.1.2 CO Boiler
Emissions from the CO boiler were calculated as follows:
1) Particulate emissions were assumed to be the
maximum allowed by Federal emission laws, 0.027 gr/dscf (EN-196).
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III-H. Domestic Crude Refinery
2) S02 emissions in the regenerator flue gas were
calculated by assuming that the coke content of the feed was 6%,
the wt 7o S in the coke was 70% of the wt % S in the feed, and all
the sulfur in the coke burns to S02 (HA-157). Sulfur in the fuel
oil, necessary to sustain combustion, also contributes S02 emis-
sions. Stack gas from the sulfur recovery unit was combined with
the effluent from the CO boiler; therefore, the sulfur dioxide
from this source is shown at the CO boiler.
3) The hydrocarbons in the regenerator flue gas were
assumed to be combusted in the CO boiler to a concentration
equivalent to the concentration of hydrocarbons in the flue gas
generated by normal fuel oil combustion. A residual oil emission
factor of 3 Ibs. hydrocarbons/Mgal residual oil (EN-071) was used.
4) The regenerator flue gas entering the CO boiler
contains 71 Ibs N0x/Mbbl of cat cracker capacity and 54 Ibs NEj /
Mbbl of cat cracker capacity (EN-071). Because of the relatively
low combustion temperatures in a CO boiler it was assumed that
the only NOx formed in the CO boiler is from the combustion of
Ni^ to N0x. With these premises Radian arrived at a NOX
emission factor for CO boilers of 166 Ibs N0x/Mbbl cat cracker
capacity.
5) The emission factor Radian used for calculating
CO emissions from the module CO boiler were 20 ppm. This factor
is based on an EPA survey (EN-072) which reported 20 ppm to be
the average CO concentration in CO boiler flue gas. The CO
boiler flue gas rate was calculated as 81,500 scfm (HA-157).
The temperature was set at 350°F assuming the application of
heat recovery equipment.
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III-H. Domestic Crude Refinery
solids from waste treatment were calculated to be 1980 Ibs/day.
Assuming these sludges to be similar to those of municipal waste,
the emission factors for municipal waste incineration (EN-071) .
were used to define the biological sludge's contribution to the
incinerator emissions. Emission factors used for the sludge
incinerator are shown in Table 4-4.
4.1.5 Petroleum Storage Emissions
The following; assumptions based on literature data
and experience were formulated to calculate hydrocarbon emissions
from petroleum storage.
Storage capacity is one month for feed and products.
Only crude and gasoline storage will result in
significant emissions. Residual and distillate
fuel oil storage create negligible emissions due
to low vapor pressures. High volatility products
are stored under pressure in completely sealed
vessels.
All feed and product storage will be in floating
roof tanks.
Using petroleum storage emission factors for floating roof tanks
(EN-071) for crude oil (0.029 lb/day-103 gal) and gasoline
(0.033 lb/day-103 gal), hydrocarbon emissions from storage were
calculated to be 243 Ib/hr. The height of these emissions was
estimated to be 50 feet.
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III-H. Domestic Crude Refinery
4.1.3 Sulfur Recovery
The sulfur recovery facilities consist of a three
reactor Glaus plant and a tail gas treating unit. These facilities
are considered capable of recovering approximately 99.9% of the
equivalent sulfur in the charge (RA-119). For an equivalent
sulfur charge of 43,751 Ib/day, the sulfur recovered is 43,707..
Ib/day. Sulfur dioxide from the tail gas treating unit is
approximately 88 Ib/day or 3.7 Ib/hr. This gas stream is
considered routed into the stack gas of the CO boiler and, there-
fore, this S02 emission is added to the CO boiler emissions.
4.1.4 Sludge Incinerator
A sludge incinerator is included in the module for
the disposal of oily and biological sludges. The quantity of
oil incinerated in the oily sludge was estimated to be 1900 gal/
day by assuming the following (RA-119):
1. 0.0015 bbl of oily sludge, produced/bbl crude
throughput.
2. Oily sludge is 36.6 wt % oil.
3. Weight of the sludge is 340 Ibs/bbl.
Assuming the oily sludge to have similar combustion character-
istics to residual oil, the EPA emission factors for residual
oil combustion (EN-071) were used to determine emissions. Using
BOD quantities and crude rates from the Radian Refinery Siting
Study (RA-119), biological sludges associated xvith the module
were determined to be 4167 Ib/day. Assuming 0.5 Ibs volatile
solids/Ibs BOD removed and a 95% BOD removal efficiency, volatile
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III-H. Domestic Crude Refinery
TABLE 4-4
EMISSION FACTORS FOR SLUDGE INCINERATOR
Oily
Sludge
Residual Oil
Combustion in
^Proce'ss Boilers
Particulates
S02
HC
CO
NO
X
Aldehydes 1
*S = wt. % sulfur in the fuel oil
Biological
Sludge
Municipal Incinerator
with controls
23
157 x S*
3
4
40
14
2.5
1-5
35
3
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III-H. Domestic Curde Refinery
4.1.6 Miscellaneous Hydrocarbon Emissions
There are numerous miscellaneous hydrocarbon emissions
in petroleum refineries which escape from sources such as valve
stems, flanges, loading racks, equipment leaks, pump seals, sumps,
and API separators. These losses are discussed in Radian's
Refinery Siting Report (RA-119). Based on literature data,
Radian found that the miscellaneous hydrocarbon emissions amount
to about 0.1% of the refinery capacity for a new, well-designed,
well-maintained refinery. The composition of these hydro-
carbons can be expected to be a composite of all volatile
intermediate and refined products.
4.2 Water Effluents
Module water effluents were estimated from information
published in Radian Refinery Siting Study (RA-119). The waste-
water generation rate was taken as 15 gal/bbl crude. Although
only ten out of 43 petroleum refineries surveyed by API in 1967
(AM-041) reported aqueous effluent rates of 15 gal/bbl or less,
a new refinery is expected to be in the lower range due to the
use of air cooling, recycle, and new water conservation techniques
(DI-044). For the 100,000 BPD module the wastewater effluent is
1.5 x 106 gal/day. This effluent is defined in Table 4-5.
4.2.1 Suspended Solids
The API survey of petroleum refinery effluents
indicated that 3 out of 23 refineries achieved suspended solids"
concentrations of 10 ppm or less and that 6 out of 23 refineries
achieved suspended solids concentrations of 13 ppm or less in
their wastex^aters (AM-041). Based upon these data, Radian used
a suspended solids concentration of 10 ppm for the effluent
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TABLE 4-5
DOMESTIC CRUDE REFINERY MODULE
WATER EFFLUENTS
Wastewater Production Rate = 1.5 x 106 gal/day
Concentration Amount
(ppm) (Ibs/day)
Suspended Solids 10 125
Dissolved Solids 370 4,625
Total Organics 2.1 26.3
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III-H. Domestic Crude Refinery
waters from the module. The mass flow rate of suspended solid
in the module wastewater is 125 Ibs/day.
4.2.2 Dissolved Solids
Beychock (BE-147) reports that the dissolved solids
level in an example refinery waste is 386 ppm for a wastewater ,
flow rate of 14.4 gal/bbl. Based upon the assumption that the
dissolved solids discharge rate is fixed by the refinery's
capacity, the dissolved solids concentration is inversely
proportional to the wastewater flow rate. For-this moxdule'-s
wastewater flow rate of 15 gal/bbl, the dissolved solids con-
centration would be approximately 370 ppm. At this concentration,
4625 Ibs/day of dissolved solids are discharged with the waste-
water from the module.
In general, as recycling increases and effluent rates
decrease, the dissolved solids content can be expected to
increase. The dissolved solids content will become more sensitive
to makeup water quality and to soluble salt pick-up in process
water. Dissolved solids will become variable from refinery to
refinery under these circumstances. The value chosen for this
refinery implies a relatively high quality makeup water. However,
this value is supported by the API survey, since 16 of 26 refineries
reported effluent TDS values of less than 400 ppm (AM-041).
4.2.3 Total Organics
A total organic concentration value of 2.1 ppm was based
on information for oil and phenol levels reported in the Radian
Refinery Siting Study; (RA-119). The API survey (AM-041) showed
that 5 out of 31 companies were able to lower wastewater oil
levels to 2 ppm with biological treatment. Based upon these data,
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III-H. Domestic Crude Refinery
an oil concentration of 2 ppm is considered reasonable for a new
refinery.
Beychock (BE-147) reported that a phenol level of 0.1
ppm in refinery wastes can be achieved with a well-designed
biological waste treatment system. The 1967 API survey of
petroleum refineries reported that 8 out of 38 refineries reached
phenol levels of 0.1 ppm with biological treatment. For this
module, a phenol concentration of 0.1 ppm was assumed. Using a
2.1 ppm concentration for total organics, 26.3 Ibs/day of total
organics were calculated to be emitted in the module wastewater.
4.3 Thermal
Use of cooling towers should result in negligible
thermal pollution.
4.4 Solid Waste
Quantities of solids from refineries are highly
variable. Possible sources of solid waste in a refinery are
the following:
1) entrained solids in the crude
2) silt from surface drainage
3) silt from water supply
4) corrosion products from process units
and sewer systems
5) solids from maintenance and cleaning
operations
C-313
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III-H. Domestic Crude Refinery
6) water treatment sludges
7) spent catalyst
With the exception of spent catalyst, these solids usually collect
as an oily sludge in the API separators and in the water treat-
ment plant. Literature sources (AM-042, MA-226, RA-081, and
RE-048) indicated a solid waste of three tons per day for the
200,000 BPD refinery in the Radian Refinery Siting. Therefore,
a solid waste production rate of 1.5 tons per day was chosen for
the 100,000 BPD refinery considered here. This waste is suitable
for landfill purposes.
C-314
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APPENDIX C
III-I. FOSSIL FUEL-FIRED STEAM ELECTRIC GENERATION
C-315
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III-I. Fossil Fuel-Fired Steam Electric
Generation
1.0 INTRODUCTION
This section describes Radian Corporation's module
for the generation of electricity from fossil fuels. This is
a multiple module, with emission and efficiency data given for
a variety of boiler fuels used in a midwestern location. Boiler
fuels considered are low Btu fuel gas, western coal, Illinois
coal, physically cleaned Illinois coal, chemically cleaned
Illinois coal, residual fuel oil and natural gas. Pollution
control equipment utilized includes wet cooling towers, electro-
static precipitators, and limestone S02 scrubbers. Most of the
module emission data presented here are based upon information
published by Battelle (BA-230). When applicable, Battelle's
numbers.are used directly. In many cases, however, additions
or corrections to Battelle's numbers have been made by Radian
using best available data and engineering judgment.
C-316
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III-I. Fossil Fuel-Fired Steam Electric
Generation
2.0 MODULE BASIS
Impact parameters which are presented here were de-
veloped for a power plant capable of a net production of 1012
Btu/day of electricity. This is equivalent to a net power
plant capacity of 12,200 Mw.
C-317
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III-I. Fossil Fuel-Fired Steam Electric
Generation
3.0 MODULE DESCRIPTION
The power plants described in this study are new
plants which utilize supercritical steam boiler systems to
drive steam turbines which in turn drive generators. The other
facilities of each plant consist of processing equipment similar
to that found in older conventional power plants. Tables 3-1
to 3-7 summarize the impacts of power plants located in the
midwest burning the various fossil fuels .considered and using
limestone S02 scrubbers or electrostatic precipitators as re-
quired to meet applicable federal new source performance stan-
dards. Modules requiring limestone S02 scrubbers do not use
electrostatic precipitators since the scrubbers will adequately
control particulate emissions.
3.1 Module Efficiency
The primary product efficiency of the power plant it-
self is assumed to be 37%. This efficiency is defined as the
net electrical energy output of the plant divided by the energy
input to the plant. Net electrical energy output is defined as
gross electrical energy generated minus any plant auxiliary
energy requirements. Generally, power plants produce no saleable
by-products and require no ancillary energy input. Therefore,
the total product and overall efficiencies of the power plant
are equal to the primary product efficiency.
For power plants utilizing a flue gas desulfurization
(FGD) unit, approximately 570 of the gross energy output of the
plant is required by the FGD system. Therefore, power plants
utilizing FGD systems are assumed to have an efficiency of 35%.
C-318
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III.I Fossil Fuel-Fired Steam Electric
Generation
TABLE 3-1
SUMMARY OF ENVIRONMENTAL IMPACTS
POWER PLANT WITH ELECTROSTATIC PRECIPITATOR
Fuel: Western Coal
Location: Midwest
Basis: Production of 1012 Btu/day equivalent
of electrical energy
Air (Ib/hr)
Particulates 6,140
S02 124,000
NOX . 84,500
CO 4,700
HC 1,430
Water (Ib/hr)
Suspended Solids 2,830
Dissolved Solids 16,000
Organic Material 1,220
Thermal (Btu/hr) 0
Solid Wastes (tons/day) 9,130
Land Use (acres) 9,760
Water Requirements (gal/day) 117 x 10s
Occupational Health (per year)
Deaths 0.32
Injuries 13.4
Man-Days Lost 5,000
Efficiency (%)
Primary Product Efficiency 37
Total Product Efficiency 37
Overall Efficiency 37
Ancillary Energy (Btu/day) 0
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III-I. Fossil Fuel-Fired Steam Electric
Generation
TABLE 3-2
SUMMARY OF ENVIRONMENTAL IMPACTS
POWER PLANT WITH LIMESTONE SCRUBBER
Fuel: Illinois Coal
Location: Midwest
Basis: Production of 1012 Btu/day
equivalent of electrical energy
Air (Ib/hr)
Particulates . 9,520
S02 74,000
NOX 97,300
CO 5,410
HC 1,650
Water (Ib/hr)
Suspended Solids 3,000
Dissolved Solids 16,900
Organic Material 1,280
Thermal (Btu/hr) 0
Solid Wastes (ton/day) 54,900
Land Use (acres) 9,760
Water Requirements (gal/day) 131 x 10s
Occupational Health (per year)
Deaths 0.35
Injuries 14.6
Man-Days Lost 5,500
Efficiency (%)
Primary Product Efficiency 35
Total Product Efficiency 35
Overall Efficiency 35
Ancillary Energy (Btu/day) 0
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III-I. Fossil Fuel-Fired Electric
Generation
TABLE 3-3
SUMMARY OF ENVIRONMENTAL IMPACTS
POWER PLANT WITH LIMESTONE SCRUBBER
Fuel.: Physically Cleaned Illinois Coal
Location: Midwest
Basis: Production of 1012 Btu/day equiv-
alent of electrical energy
Air (Ib/hr)
Particulates . 5 ,.690
S02 41,300
NOX 93,200
CO 5,180
HC 1,570
Water (Ib/hr)
Suspended Solids 3,000
Dissolved Solids 16,900
Organic Material 1,280
Thermal (Btu/hr) 0
Solid Wastes (tons/day) 31,600
Land Use (acres) 9,760
Water Requirements (gal/day) 131 x 10s
Occupational Health (per year)
Deaths 0.35
Injuries 14.6
Man-Days Lost 5,500
Efficiency
Primary Product Efficiency 35
Total Product Efficiency 35
Overall Efficiency 35
Ancillary Energy (Btu/day) 0
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III-I. Fossil Fuel-Fired Steam Electric
Generation
TABLE 3-4
SUMMARY OF ENVIRONMENTAL IMPACTS
POWER PLANT WITH LIMESTONE SCRUBBER
Fuel: Residual Fuel Oil
Location: Midwest
Basis: Production of 1012 Btu/day
equivalent of electrical energy
Air (Ib/hr)
Particulates 63
S02 21,800
NOX 83,300
CO 2,380
NC 2,380
Water (Ib/hr)
Suspended Solids 3,000
Dissolved Solids 16,900
Organic Material 1,280
Thermal (Btu/hr) 0
Solid Wastes (tons/day) 9,940
Land Use (acres) 3,660
Water Requirements (gal/day) 131 x 10s
Occupational Health (per year)
Deaths 0.35
Injuries 14.6
Man-Days Lost 5,500
Efficiency
Primary Product Efficiency 35
Total Product Efficiency 35
Overall Efficiency 35
Ancillary Energy (Btu/day) 0
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III-I. Fossil Fuel-Fired Steam Electirc
Generation
TABLE 3-5
• SUMMARY OF ENVIRONMENTAL IMPACTS
POWER PLANT
Fuel: Low JBtu. Fuel Gas from Illinois Coal
Location: Midwest
Basis: Production of 1012 Btu/day equiva-
lent of electrical energy
Air (Ib/hr)
Particulates 1..680
S02 58,300
NOX 67,500
CO 1,920
HC 112
Water (Ib/hr)
Suspended Solids 2,830
Dissolved Solids 16,000
Organic Material 1,220
Thermal (Btu/hr) 0
Solid Wastes (tons/day) 0
Land Use (acres) 1,830
Water Requirements (gal/day) 117 x 10s
Occupational Health (per year)
Deaths 0.32
Injuries 13.4
Man-Days Lost 5,000
Efficiency
Primary Product Efficiency 37
Total Product Efficiency 37
Overall Efficiency 37
Ancillary Energy (Btu/day) 0
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III-I. Fossil Fuel-Fired Steam Electric
Generation
TABLE 3-6
SUMMARY OF ENVIRONMENTAL IMPACTS
POWER PLANT
Fuel: Natural Gas
Location: Midwest
Basis: Production of 1012 Btu/day
equivalent of electrical
energy
Air (Ib/hr)
Particulates
S02
NOX
CO
HC
1,680
68
67,500
1,920
112
Water (Ib/hr)
Suspended Solids
Dissolved Solids
Organic Material
2,830
16,000
1,220
Thermal (Btu/hr)
Solid Wastes (tons/day)
Land Use (acres)
Water Requirements (gal/day)
0
0
1,830
117 x 106
Occupational Health (per year)
Deaths
Injuries
Man-Days Lost
0.32
13.4
5,000
Efficiency (%)
Primary Product Efficiency
Total Product Efficiency
Overall Efficiency
37
37
37
Ancillary Energy (Btu/day)
0
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III-I. Fossil Fuel-Fired Steam Electric
Generation
TABLE 3-7
SUMMARY OF ENVIRONMENTAL IMPACTS
POWER PLANT WITH LIMESTONE SCRUBBER
.Fuel: -Chemically Cleaned Illinois Coal
Location: Midwest
Basis: Production of 1012 Btu/day equiv-
alent of electrical energy
Air (Ib/hr)
Particulates 8,890
SO2 29,200
NOX 89,300
CO 4,960._
HC 1,510
Water (Ib/hr)
Suspended Solids 3,000
Dissolved Solids 16,900
Organic Material 1,280
Thermal (Btu/hr) 0
Solid Wastes (tons/day) 33,500
Land Use (acres) 9,760
Water Requirements (gal/day) 131 x 10s
Occupational Health (per year)
Deaths 0.91
Injuries 34.1
- Man-Days Lost 2,252
Efficiency
Primary Product Efficiency 35
Total Product Efficiency 35
Overall Efficiency 35
Ancillary Energy (BTu/day) 0
C-325
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III-I. Fossil Fuel-Fired Steam Electric
Generation
3.2 Fuel Requirements
Table 3-8 lists the important characteristics of the
boiler fuels used in this study. Based on the efficiencies
given in Section 3.1, a 37% efficient plant requires 2.70 x 1012
Btu/day of energy input while a 35% efficient plant requires
2.86 x 1012 Btu/day in order to produce 1012 Btu/day of electrical
energy. Table 3-9 lists the fuel rates which meet these energy
requirements.
3.3 Water Requirements
The major consumer of water in a power plant is the
cooling tower system. In addition, a flue gas desulfurization
unit (FGD), if present, requires make-up water. Other water re-
quirements of the plant are insignificant compared to the above
two items.
The make-up water for the cooling tower system replaces
three losses; drift, blowdown and evaporation. The magnitude of
each of these losses was calculated from mass and energy balances
around the cooling system using the following assumptions or data.
1) 48% of input heat to the plant is sent
to the cooling towers
2) 75% of the heat lost in the cooling
towers is dissipated via evaporation
3) the heat of vaporization of water is
1050 Btu/lb
4) the cooling water temperature rise across
the steam condenser is 25°F
C-326
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TABLE 3-8
IMPORTANT CHARACTERISTICS OF POWER PLANT FUELS
Physically Cleaned Chemically Cleaned Residual Low Btu Natural
Western Coal Illinois Coal Illinois Coal Illinois Coal Fuel Oil Fuel Gas Gas
Ash 6.0
Sulfur 0.51
Heat Value 8,306
1 Notes: (1) Ash and sul
11.0 6.87
3.6 2.10
11,000 11,500
fur figures are in wt 7».
11.2
1.55 1.75
12,000 ' 6.3 x 10C 193 1,000
(2) Heating values are expressed as Btu/lb for coal, Btu/bbl for fuel oil and
Btu/SCF for gases.
M
i
M
(3) Sulfur content of low Btu fuel gas from western coal is 0.0458 lbS/10c'Btu. rt O
fu co
(4) Sulfur content of low Btu fuel gas from Illinois coal is 0.259 lbS/10'Btu. ?. H.
o M
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III-I. Fossil Fuel-Fired Steam Electric
Station
TABLE 3-9
POTTER PLANT FUEL REQUIREMENTS
Basis: Net production of 1012 Btu/day of electricity
Fuel
Power Plaut Efficiency Fuel Requirements
Western Coal
Illinois Coal
Physically Cleaned
Illinois Coal
Chemically Cleaned
Illinois Coal
Residual Fuel Oil
Low Btu Fual Gas
Natural Gas
37%
35%
35%
35%
"35%"
37%
37%
153,000 tons/day
130,000 tons/day
124,000 tons/day
119,000 tons/day
454.-000 bbl/day
14.0 x 109SCF/day
2.70 x 10sSCF/day
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III-I. Fossil Fuel-Fired Steam Electric
Station
(5) cooling tower drift losses are 0.02%
of the cooling water circulation rate
For a power plant with a 3770 efficiency, cooling tower make-up
water requirements are 81,200 gpm or 117 x 106 gal/day. For a
plant with a 3570 efficiency, cooling tower make-up water re-
quirements are 85,800 gpm or 124 x 10s gal/day.
The make-up water requirement of an FGD unit is
assumed to be 4880 gpm. This figure is calculated by assuming
(1) the FGD unit inlet flue gas temperature is 250°F and
(2) the FGD unit-adiabatically saturates the flue gas. It
might be possible to use cooling tower blowdown as make-up
water to the FGD units but in this study it is assumed that
fresh make-up is used.
The make-up water requirements for a power plant
with a 37% efficiency are 117 x 106 gal/day. The water require-
ments for a plant with a 3570 efficiency are 131 x 10s gals/day
including cooling tower and FGD units needs.
3.4 . Land Usage
From Battelle (BA-230), the land requirements for a
1000 Mw power plant are 150, 300, and 800 acres for gas, residual
fuel oil and coal fired plants, respectively. Linearly scaling
to a 12,200 Mw plant gives the land requirements of 1830, 3660,
and 9760 acres for gas, residual fuel oil and coal fired plants,
respectively.
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III-I. Fossil Fuel-Fired Steam Electric
Station
3.5 Occupational Health
The data on injuries, deaths and man-days lost for the
power plant module were taken directly from Battelle (BA-230).
These numbers have been converted from Battelle's basis of 10s
Btu of electricity production to Radian's basis of 1012 Btu/day
of electricity produced.
C-330
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III-I. Fossil Fuel-Fired Steam Electric
Station
4.0 MODULE EMISSIONS
4.1 Air Emissions
Essentially, the only air emissions from a power plant
come from the boiler flue gas produced during combustion of the
plant's fuel. Emission rates of particulates, SOz, NOX, CO, and
hydrocarbons are calculated from fuel rates, fuel ash and sulfur
contents and emission factors from "Compilation of Air Pollutant
Emission Factors" (EN-071). Aldehyde and organic emissions are
both included in the hydrocarbon category. Table 4-1 lists the
emission factors used.
Sulfur emissions resulting from the firing of low Btu
fuel gas were calculated from the sulfur content of the fuel gas
fired (see Table 3-8, notes 3 and 4). All other emissions from
firing low Btu fuel gas were calculated using the natural gas
equivalent of the low Btu fuel and natural gas emission factors.
Sulfur and particulate emissions from firing subbi.-
tuminous coal were' calculated using actual coal rates. However,
CO, NOX and hydrocarbon emissions were calculated using bituminous
coal equivalent flows (the bituminous coal was assumed to have a
heating value of 12,000 Btu/lb)(HI-083).
SQ2 scrubbers and electrostatic precipitators were
used as necessary to control SQ2 and particulates. The electro-
static" precipitators were assumed to remove 9970 of the particu-
late matter in the flue gas. SOa scrubbers were assumed to remove
90% of the S02 and 99% of the particulates.
In order to evaluate the effect that particulates,
S02, NOX, CO and hydrocarbon emissions have on ambient air
C-331
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TABLE 4-1
o
I
CO
K>
Fuel
Coal
Fuel Oil
Natural Gas
EMISSION FACTORS FOR
Source: "Compilation
Emission
Factor Units
Ib/ton coal burned
lb/103. gal
lb/106 SCF
UNCONTROLLED COMBUSTION OF FOSSIL FUELS
of Air Pollutant
Particulates
16xA
8
15
Emission
S02
38xS
157xS
0.6
Factors" (EN-071)
NOX
18
105
600
Hydrocarbons
0.305
3
1
Notes: (1) A is ash content of fuel in percent.
(2) S is sulfur content of fuel in percent.
CO
1
3
17
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pi co
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-------
III-I. Fossil Fuel-Fired Steam Electric
Station
quality, it is necessary to define certain stack parameters
used in calculating ambient air conditions. Table 4-2 lists
the air emissions and stack parameters for each type of power
plant considered in this study.
Mass and volumetric flow data shown in Table 4-2 were
calculated from material balances. Stoichiometric combustion
was assumed with 25% excess air. Volumetric flow rates were
based on an assumed exit gas temperature of 250°F. Stack heights
and gas velocities were also assumed. Stack diameters were
calculated from assumed gas velocities and volumetric flow rates.
4. 2 Water Emissions
Water emissions were characterized by defining suspended
solids, total dissolved solids and organic matter contents.
Battelle (BA-230) states that suspended solids and organic matter
in power plant liquid wastes amount to 0.036 lb/106 Btu of fuel
burned. Of this total, 70% is suspended solids and 30% is organic
matter. This factor and plant heat rates were used to calculate
these two emissions. Total dissolved solids (TDS) were calculated
by assuming that cooling tower blowdown, the most significant
liquid waste stream, contained 10,000 ppm of TDS. For a plant
with a 35% efficiency, the TDS load is 16,900 Ib/hr.
4.3 Solid Wastes
Solid wastes from a power plant consist of ash and/or
S02 scrubber wastes. For coal fired plants, the amount of bot-
tom ash produced was assumed to be 20% of the ash brought in with
the coal. The amount of S02 scrubber waste was calculated, using
the following assumptions.
C-333
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TABLE 4-2
AIR EMISSIONS AND STACK PARAMETERS FOR 1000 MW POWER PLANTS
O
I
LO
U>
-P-
Source
Stack pas
Stack f,as w/
S02 acrubber
Stack p,as w/
SOj r.crubber
Stac!: gas w/
S02 scrubber
Stack gas
Stack gas
Stack gas w/
SO- scrubber
Heat
Input
MM Btu/Hr
9220
9750
9750
9750
9220
9220
9750
Fuel
Western coal
111. coal
Fhy. Clean
111. coal
Residual
fuel oil
Low BTU uas
Emissions Ibs/Hr
Parti-
culates
503
780
466
52
from 111. coal 138
Natural gas
Chem. Clean
111. coal
138
728
so2
10.200
6,060
3.380
1.790
4.780
5.53
2, 390
Total
Orp,anics
117
135
129
195
9.22
9.22
124
CO
385
443
424
195
157
157
406
N<\
6920
7970
7630
6820
5530
5530
7310
Stack Parameters
Mass
Flow
Ibs/Hr
10.0X106
11.0X106
11.0X106
f.
9.94X10°
f.
9.89X10°
9.01X106
10.4xl06
ACFM
2.95X106
3.31X106
3.31X106
f.
3.02X106
2.94X10°
2.80X106
3.05xl06
Velocity
FPS
60
60
60
60
60
60
60
Height
Ft.
500
500
500
500
500
500
500
j
Temperature! Diameter
°F ! Ft.
250
250
250
250
250
250
250
32.3
34.2
34.2
32.7
32.2
31.4
32.8
Oi **}
ft O
(O CO
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-------
III-I. Fossil Fuel-Fired Steam Electric
Station
For a limestone S02 scrubber:
(1) The sludge wastes are ponded and the
settled composition is 60% sludge and
40% water.
(2) The sludge consists mainly of CaS03*%H20,
CaSCV2H20, Ca(OH)2 and ash.
(3) The sludge, ash excluded, is 20% sulfur.
(4) The scrubber removes 9070 of the flue
gas sulfur.
Coal ash is the only solid waste from the power plant
firing western coal and utilizing an electrostatic precipitator
Solid wastes from this plant were calculated as the total ash
rate to the boiler minus the particulate emissions to the air.
No solid wastes were assumed to be produced by power plants
firing natural gas or low Btu fuel gas.
4.4 Thermal Discharges
All thermal discharges to water bodies were assumed
to be negligible due to the use of wet cooling towers.
C-335
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APPENDIX C
IV. TRANSPORTATION MODULES
A. Railway
B. Pipeline
C-336
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APPENDIX C
IV-A. RAILWAY
C-337
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IV-A. Railway
1-0 INTRODUCTION
The railway is one of the major land transportation
modes utilized to move small as well as large quantities of
commodities. To date, there are about 206,000 track miles
(mainline right-of-way) in the U.S. (GO-090). The types of
railway currently employed for transporting coal can be classi-
fied according to the type of locomotive power plant used,
namely diesel electric train or electric train. The former type
is predominantly used.
Electric trains are in use today as energy transport
systems on a limited basis, although they were introduced in
the U.S. more than 70 years ago (GO-090). The two electric
trains that transport coal are: the Muskingum Electric Rail-
road and the Black Mesa and Lake Powell (BM&LP) Electric Rail-
road. The Muskingum Electric Railroad transports about 18,000
tons of coal per day to American Electric Power's Muskingum
River power plant at Zanesville, Ohio - served by a 15-mile
long electrified rail system (FI-067, OL-020, OL-021, TI-025,
WE-110, WE-116). The BM&LP Electric Railroad hauls approximately
30,000 tons of coal per day from the Black Mesa Mine near Kayenta,
Arizona to the Navajo Generating Station at Page, Arizona,
a distance of 78 miles (AU-018, EL-054),
Electric trains have some advantages and disadvantages.
They consume less fuel, have a higher relative availability
index, have no direct air emissions and are much quieter than
their diesel electric counterparts (BA-223, EL-050, EN-036,
EN-199, GO-090, TH-058). Their major drawback is the formidable
cost of the catenary system (EL-050), Since electric trains are
not widely used for coal transportation, they are not pursued
further here.
C-338
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IV-A. Railway
Diesel electric trains have been used in energy trans-
portation for a long period of time, They have been used to
transport a variety of energy, forms - such as: LPG, LNG, crude
oil, coal and radioactive fuel materials.
C-339
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IV-A. Railway
2.0 COAL RAIL TRANSPORTATION
For diesel electric trains to be considered feasible
as a means of transportation for coal, they must meet the follow-
ing basic requirements.
1. Availability of continuous-service
railroad tracks and licensed freight
carriers, from the coal mines to the
point of coal utilization.
2. Availability of locomotive engines
and freight cars,
These basic requirements can be viewed in terms of the existing
facilities and the projected growth of the railroad industry,
freight car manufacturers, and locomotive suppliers,
Railroads with direct service lines between Illinois
coal mines and Chicago are mature, developed coal transporters.
Also, a current survey on continuous service routes indicates
that one of the major coal transporters has direct service lines
between two western states, namely Wyoming and Colorado, and the
load center, namely Chicago (BO-120). Thus, the first basic
requirement, i.e., availability of continuous-service railroad
tracks and licensed freight carrier(s) from the coal mines to
the point of coal utilization, is partially satisfied,
The second requirement is the availability of locomotive
engines and freight cars. Reports (IN-041, RA-128) submitted
to the committee on interstate and foreign commerce and the
Committee on Agriculture and Forestry have indicated the
existence of a freight car shortage. Commodities, including
coal and other energy resource items, are affected by the freight
C-340
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IV-A. Railway
.car shortage. To alleviate this problem, the Department of
Transportation announced in mid-1975 that an additional
130,000 cars, were needed .to meet the car shortage of that
year, requiring an investment of $2.3 billion (AL-046). Fore-
casts show that a one-third growth in rail-freight transportation
between 1971 and 1980 will require about 617,000 cars of 80-ton
capacity to meet the demand. The Department of Transportation
also estimated that a modest $8.8 billion fund will be required
to keep abreast with demands of the future. The above "statis-
tics do not include freight cars of the 100-ton capacity class,
which is the standard size for coal cars of today. Although
some funds may be available for the purchase of freight cars,
the lead time required is at least two years (BO-120).
The development of western coal will require addi-
tional freight cars in the 100-ton capacity class. A new design
of a 125-ton capacity is also available which requires new light-
weight materials for its construction and implementation. These
new materials are required because a freight car's gross weight
has to be within the allowable rail limit of about 132 tons
(GR-117).
Although there is no report of a locomotive engine
shortage, the development of the western states might create
one. To order a locomotive engine requires one year lead time
for the expected delivery (EN-199, WH-036). The lead time is
a function of the manufacturer's rate of production and back-
log.
C-341
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IV-A. Railway
The environmental effects of coal-rail transportation
were estimated on the basis of the following major assumptions:
1. A unit train will consist of that number
of cars of one hundred ton-capacity which
will supply 0.25 x 1012 Btu of energy (*
100-150 cars depending on heating value of
coal transported) .(GR-117),
2. A medium grade traffic requiring approxi-
mately 1,4 HP per trailing ton (GE-050).
3. Each unit train will have the required
number of diesel electric locomotives
rated at 3600 HP each, END SD45-2 class
with the following fuel consumption
characteristics (OV-008):
at full power: 199 gals/hr/locomotive
at reduced power: 28 gals/hr/locomotive
4, Track length is equal to highway length,
but 10% longer than a pipeline length
(WA-139),
5. The train moves at reduced power during
the 16 total hours required for loading
and unloading (BU-116).
6. One hour is required for passing each large
city and for undergoing each federal in-
spection (BU-116).
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IV-A. Railway
7. One large city every 110-track miles
CBU-116).
8. Federal inspection every 500-track miles
(BU-116).
9. Average train speed in open country
is 25 mph (BU-116).
10. Emission factors which apply are those
defined for a two-stroke turbocharged
line haul class diesel electric loco-
motive (EN-071, HA-231, SO-066).
11. One percent of the total train load is
lost as coal dust blow-off which occurs
mainly during loading and unloading, and
is independent of the haulage distance
(CO-129, HI-090).
12. 50-foot railroad right-of-way per track
(CO-129).
13. The train returns to the mine with empty
cars.
14. A train loaded with coal is dispatched
every 11 or 12 hours; the reason for this
is to avoid imposing a continuous load on
the track. Otherwise, the track's design
service life of 10 years will be reduced
to 11 months (BE-238),
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IV-A. Railway
15. Two parallel tracks, one delivery track
and one return track, both on the same
right-of-way.
16. The heating value of western coal is
17.6 x 106 Btu/ton and that of run
of mine Illinois coal is 22 x 106 Btu/
ton. Physically cleaned Illinois coal
is assumed to have a heating value of
23 x 10s Btu/ton.
The aforementioned assumptions were applied to the specific track
lengths called for in this study, Two track lengths were con-
sidered: an 1100 mile run originating in Wyoming and a 275 mile
run originating from an Illinois coal mine.
Coal Rail Transportation Modules
The environmental effects of rail transportation of
coal are summarized in Tables 2-1 through 2-3 for the three
transportation cases considered. The numbers given are for a
module designed to deliver 1012 Btu of coal per day (on the
average) to the terminal point.
Table 2-1 defines the impacts of transporting 1012 Btu/
day of western coal over a 1100 mile rail line from Wyoming to
Chicago, A round trip requires approximately six days. The rail
transport module in this case consists of 24 unit trains operat-
ing on two pairs of parallel tracks. Each unit train contains
143 one hundred ton cars and eight 3600 hp locomotives. Each
train is assumed to operate at full power for 88 hours, at re-
duced power for 40 hours, and at zero power for the remainder
of the time on a round trip.
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IV-A. Railway
TABLE 2-1
SUMMARY OF ENVIRONMENTAL IMPACTS
WESTERN COAL RAIL TRANSPORTATION MODULE*
Air (Ib/hr)
Particulates 6.99 x 102
S02 1.59 x 103
NO 9.22 x 103
X
CO 4.46 x 103
HC 7.83 x 102
Water (Ib/hr) 0
Thermal (Btu/hr) 0 .
Solid Wastes (tons/day) 5.72 x 102
Land Use (acres) 2.67 x 10"
Water Requirements (gal/day) 0
Occupational Health (per year)
Deaths 1.03
Injuries 101
Man-Days Lost 9.13 x 103
Primary Efficiency (%) 99
Overall Efficiency (%) 91.6
Ancillary Energy (Btu/day) 8.23 x 1010
Twelve unit trains of 143 cars each/pair of tracks (one delivery
track and one return track), 2 pairs of tracks, 2.5 x 10!l Btu/
unit train, 1012 Btu/day delivered.
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IV-A. Railway
TABLE 2-2
SUMMARY OF ENVIRONMENTAL IMPACTS
ILLINOIS COAL RAIL TRANSPORTATION MODULE*
Air (lb/hr)
Particulates 1.36 x 102
S02 3.11 x 102
NOX 1.80 x 10 3'
CO 8.72 x 102
HC 1.53 x 102
Water (lb/hr) 0
Thermal (Btu/hr) 0
Solid Wastes (tons/day) 4.6 x 102
Land Use (acres) 6.67 x 103
Water.Requirements (gal/day) 0
Occupational Health (per year)
Deaths 0.85
Injuries 81.23
Man-Days Lost 7.31 x 103
Primary Efficiency (70) 99
Overall Efficiency (%) 97.4
Ancillary Energy (Btu/day) . 1.66 x 1010
*Four unit trains of 115 cars each/pair of tracks (one delivery
track and one return track), 2 pairs of tracks, 2.5 x 10J1 Btu/
unit train, 1012 Btu/day delivered.
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IV-A. Railway
TABLE 2-3
SUMMARY OF ENVIRONMENTAL IMPACTS
PHYSICALLY CLEANED ILLINOIS COAL RAIL TRANSPORTATION MODULE-'
Air (Ib/hr)
Particulates 1.36 x 102
S02 3.11 x 102
N0x 1.80 x 103-
CO 8.72 x 102
HC 1.53 x 102
Water (Ib/hr) 0
Thermal (Btu/hr) 0
Solid Wastes (tons/day) 4.4 x 102
Land Use (acres) 6.67 x 103
Water Requirements (gal/day) 0
Occupational Health (per year)
Deaths 0.79
Injuries 77.70
Man-Days Lost 6.99 x 103
Primary Efficiency (%) 99
Overall Efficiency (%) 97.4
Ancillary Energy (Btu/day) 1.66 x 1010
*Four unit trains of 100 cars each/pair of tracks (one delivery
track and one return track), 2 pairs of tracks, 2.5 x 10X1 Btu/
unit train, 1012 Btu/day delivered.
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IV-A. Railway
Table 2-2 defines the impacts of transporting run-of-
mine Illinois coal over a 275 mile rail line to Chicago. A
round trip for each unit train requires almost two days. The
rail transport module in this case consists of eight unit trains
operating on two pairs of parallel tracks. Each unit train
which consists of 115 one hundred ton cars and six 3600 hp
locomotives, is assumed to operate at full power for 22 hours,
at reduced power for 22 hours, and at zero power for the re-
mainder of the time on a round trip.
The impacts of transporting physically cleaned Illinois
coal to Chicago are defined in Table 2-3. A round trip for a
single unit train requires about 2 days. The rail transport
module in this case consists of eight unit trains operating on
two pairs of parallel tracks. Each unit train, which consists of
110 one hundred ton cars and six 3600 hp locomotives, is assumed
to operate at full power for 22 hours; at reduced power for 22
hours, and at zero power for the remainder of the time on a
round trip.
Ancillary Energy
The ancillary energy required by each module is
computed from the diesel fuel consumption of the unit trains in
the module, and~"a~fuel "Heating "value prescribed by the
Association of American Railroads (AAR). This heating value
is 133,000 Btu/gal at 36° API (WH-036).
Primary Product Efficiency
The primary product efficiency of coal rail transport.
is about 99%. The losses are due primarily to coal dust blow-
off during loading and unloading operations. Thus the effect
of transport distance is negligible.
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IV-A. Railway
Water Requirements
The only water use in rail transport is for engine
cooling which is a negligible amount.
Land Use
Rail transportation land use is computed based on the
1 7
number of track pairs necessary to deliver 10 'Btu/day of coal
to the end point. Each track pair is assumed to require a 50
foot right-of-way. A track pair is a set of parallel rail lines,
one used for delivery, the other for return.
Occupational Health
Occupational health hazards of unit trains were
estimated based on the accident statistics and amount of coal
transported for the year 1972. The Federal Railroad Adminis-
tration's accident bulletin for the calendar year 1972 included.
statistics of casualties to railroad employees on duty, and the
casualties were categorized as follows (US-125): 127 deaths,
12,456 injuries, and 1,123,180 disability days. The man-days •
lost per injury was computed to be 90.
The Statistical Abstract of the U.S. in 1973 reported..
that, in 1972, freight tonnage transported by rail totaled
2,544 million tons (US-154). For the same year, the Coal Traffic
Annual (NA-184) reported that approximately 136.5 million tons '
of bituminous coal were transported by unit trains.
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IV-A. Railway
Assuming a linear relationship exists between the
occupational health statistics and coal tonnage transported, the
occupational health statistics for unit trains can be expressed
in terras of coal transported. This analysis implies that the
occupational health statistics are independent of the mileage
distance transported. However, due to the difference in
energy content between Western coal and Illinois coal, the
occupational health statistics based on 10 Btu/day delivered
will differ between the western coal rail module and the
Illinois rail module.
Air Emissions
Total air emissions were computed by summing the
emissions of locomotive engines. The emissions were estimated
by multiplying the emission factors for a two-stroke turbo-
charged, line-haul class, diesel electric locomotive, by the
computed train fuel consumption.
Water Emissions
Trains have negligible water emissions.
Thermal Emissions
The thermal emissions from trains are negligible.
Solid Wastes
Solid wastes are produced in rail transportation of coal
at the loading and unloading points when coal dust is blown off
during the loading and unloading processes. This amounts to
one percent of the coal transported.
C-350
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APPENDIX C
IV-B. PIPELINE
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IV-B. Pipeline
1-0 INTRODUCTION
Many commodities are transported by pipeline. The
ones of particular interest in this section are oil and natural
gas.
In this write-up separate treatments of the environ-
mental effects of crude oil and natural gas pipelines are
presented. For each type of pipeline, two cases are considered:
a typical existing pipeline of a specific capacity; and a pipe-
line module that has an equivalent throughput of 1012 Btu/day.
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IV-B. Pipeline
2 . 0 CRUDE OIL PIPELINE
The technology of crude oil transportation by pipeline
is well developed and has been applied for decades. Although
there have been a number of innovations in crude oil transporta-
tion, its technology continues to advance in the areas of
materials, techniques of pipe manufacture, and improved design
and methods of construction for both pipelines and stations
(PE-097, PE-098).
A crude pipeline system consists of pipes and pump
stations. Pipe sizes range from a nominal diameter of 6 inches,
with a flow of 7,700 barrels per day, to 48 inches with a flow
of as much as 10 million barrels per day (PE-098). Both electric
and diesel-powered pump stations are widespread. In the early
1960's, pumping stations were spaced approximately every 80 to
90 miles (BA-224), whereas in the newer systems they are spaced
about every 100 to 150 miles (BA-234).
Environmental effects of crude oil transportation
by pipeline were estimated on the basis of the following
assumptions:
1. a throughput of 600,000 barrels per day;
2. a cargo transport propulsion efficiency
of 500 cargo ton-miles per gallon of
fuel (RI-063);
3. crude oil heating value of 5.8 x 106
Btu/bbl;
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IV-B. Pipeline
4. distillate oil (#2) heating value
of 136,000 Btu/gallon;
5. an average right-of-way of 62.5 feet
(CO-129, PE-097);
6. a physical loss, due to spillage
of 0.006% by volume of the total
crude oil transported (CO-129, EN-129);
7. non-degradable organics amount to
about 5% of the total quantity of
oil spilled (HI-090);
8. pump station spacing of 100-mile
(BA-234);
9. pump station land use of 10 acres/
site (CO-129);
10. diesel-driven pumps;
11. EPA emission factors for heavy-duty,
diesel-powered vehicles (EN-071).
When the above assumptions were applied to the specific crude
oil pipeline length required in this study, the environmental
impacts summarized in Table 2-1 were obtained.
A typical crude oil pipeline system has an equivalent
throughput of 3.48 x 1012 Btu/day and consumes 2.18 x 1010 Btu/
day of ancillary energy. This figure was obtained by using
Assumptions 1, 2 and 4. The ancillary energy requirement of a
1012 Btu/day module is estimated to be 6.26 x 109 Btu/day.
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IV-B. Pipeline
TABLE 2-1
SUMMARY OF ENVIRONMENTAL IMPACTS
DIESEL OPERATED CRUDE OIL PIPELINE
TYPICAL SIZE' - 6QQ',OOQ-BPD (3.48 x 1012 BTU/DAY)
900 MILES LONG - 30" P.P. PIPELINE
TEXAS TO CHICAGO
Typical/Or 1012 Btu/day
Estimated Design Module
Air (Ib/hr)
Particulates 87.11 25.03
S02 1.81 x 102 52.01
NOX 2.48 x 103 7.13 x 102
CO 1.50 x 103 4.31 x 102
HC 2.48 x 102 71.26
Water (Ib/hr)
Suspended Solids 0 0
Dissolved Solids 0 0
Organic Material 22.3 6.41
Thermal (Btu/hr) 0 0
Solid Wastes (tons/day) 0 0
Land Use (acres) 6.91 x 103 1.99 x 103
Water Requirements (gal/day) 0 0
Occupational Health (per year)
Deaths 0.12 3.45 x 10~*
Injuries 10.03 2.88
Man-Days Lost 1.03 x 103 2.96 x 102
Primary Product Efficiency (%) 100 100
Overall Efficiency (%) 99.4 99.4
Ancillary Energy (Btu/day) 2.18 x 1010 6.26 x 109
C-355
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IV-B. Pipeline
Primary Product Efficiency
The primary product efficiency of a crude oil pipe-
line is assumed to be 100%, i.e., since the physical loss of
0.006% of the total crude oil transported is negligible.
Wa t er Re qu ir emen t s
Transporting crude oil by pipeline does not require
water.
Land Use
Crude oil pipeline land use represents the sum of
the pipeline right-of-way and pump stations' land acreage.
Occupational Health
Occupational health hazards involved in transporting
crude oil via pipeline were calculated based on the crude oil
pipeline accident statistics, trunk pipeline mileage, and volume
of crude oil delivered for the year 1973. The American Petroleum
Institute's annual summary of disabling work injuries for the
year 1973 categorized the casualties as follows (AM-120): 1
death, 83 injuries, and 8,540 man-days lost.
The Interstate Commerce Commission's "Transport
Statistics in the United States, 1973" reported that, in 1973,
movement of crude oil amounted to 1.63 x 1012 barrel-miles
(IN-047).
Assuming a linear relationship exists between the
occupational health statistics, trunk pipeline mileage, and
C-356
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IV-B. Pipeline
volume of crude oil delivered, the occupational health statistics
for the crude oil pipeline system in this report were computed
accordingly.....
Air Emissions
Air emissions were estimated using emission factors
for heavy-duty, diesel-powered vehicles (EN-071), and the com-
puted fuel consumption of the diesel-driven pumps. The- results
are listed in Table 2-1.
Water Emissions
A minute portion of the crude oil that is spilled from
the pipeline system, while in operation, can eventually reach
receiving water bodies in the form of non-degradable organics
(HI-090). The amount of non-degradable organics is calculated
by employing Assumptions 6 and 7. The results of the computa-
tion indicate that the crude oil pipeline module accounts for
6.41 pounds of non-degradable organics/hour. A crude oil pipe-
line system in operation does not produce any form of suspended
or dissolved solids that may degrade water bodies.
Thermal
A crude oil pipeline system in operation does not
generate any significant thermal emissions.
Solid Wastes
Transporting crude oil by pipeline does not produce
any form of solid wastes.
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IV-B. Pipeline
3.0 NATURAL GAS PIPELINE
The transport of natural gas to major markets is
primarily accomplished by pipelines. Current pipelines are
24, 30, 36 and 42-inch diameter systems (ST-204, VA-093), and
their right-of-way can be as small as 50 feet wide or as much
as 75 feet wide, with a mean width of 62.5 feet (KA-134). The
compressor stations are driven either by gas engines, gas
turbines, or electric compressors. The frequency of compressor
stations is one every 50 to 75 miles. Each compression site is
assumed to occupy 10 acres of land (CO-129, ST-204).
The purpose of this section is to define the proce-
dures used to quantify the environmental impacts of a pipeline
used to transport natural gas from the Texas Gulf Coast to the
load center of Chicago. It was assumed here that the required
compressor stations are electrically-powered. The impacts of
the natural gas pipeline system were computed using the follow-
ing assumptions:
1. a throughput of 1.25 BCFD;
2. a natural gas heating value of
1,050 Btu/ft3;
3, the use of electric-driven
compressors with a 20,000 hp
capacity (ST-204);
4. heat equivalent of electric
energy is 10,000 Btu/kwhr;
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IV-B. Pipeline
5. Compressor stations at 50-mile intervals.
6. Compressor station land use of 10 acres
per site (CO-129).
7. 62.5-foot pipeline right-of-way (KA-134).
8. No significant fugitive losses of gas.
The electric-operated natural gas pipeline system
presented in this section is 900 miles long and is assumed to
originate in Texas' gulf coast gas fields. The environmental
impacts of this electric pipeline system are given in Table 3-1,
Values are given for both a typical design pipeline system and
a module having an equivalent throughput of 1012 Btu/day.
The typical electric-operated natural gas pipeline
system considered here (1.25 BCFD capacity) has an equivalent
throughput of 1.31 x 1010 Btu/day. This is calculated using
the natural gas heating value of 1,050 Btu/ft .
Ancillary Energy
Electricity is supplied to the natural gas pipeline
system by transmission and distribution lines. The amount of
energy supplied to the system is estimated by using Assumptions
3 to 6.
Primary Product Efficiency
An electrically-powered natural gas pipeline system
is assumed to have a primary product efficiency of 100% since
it is assumed that no loss of gas occurs during transport.
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IV-B. Pipeline
TABLE 3-1
SUMMARY OF ENVIRONMENTAL IMPACTS
ELECTRIC-OPEEATED NATURAL GAS PIPELINE
1.25 BCFD (1.31 x 10 BTU+/DAY)
900 MILES LOITG - 30" P.P. PIPELINE
TEXAS TO CHICAGO
Typical/or
Estimated Design
1012 Btu/day
Module
Air (Ib/hr)
Particulates
S02
NOX
CO
HC
Water (Ib/hr)
Suspended Solids
Dissolved Solids
Organic Material
Thermal (Btu/hr)
Solid Wastes (tons/day)
Land Use (acres)
Water Requirements (gal/day)
Occupational Health (per year)
Deaths
Injuries
Man-Days Lost
Primary Product Efficiency (%)
Overall Efficiency (%)
Ancillary Energy (Btu/day)
0
0
0
0
0
0
0
0
0
0
0
7.00 x 103
0
1.51 x 10~3
4.60 x 10
10.22
100
95.3
6.44 x 1010
0
0
0
0
0
0
0
0
0
0
0
5.34 x 103
0
1.15 x 10
3.51 x 10
7.80
-3
-2
100
95.3
4.92 x 1010
. 1,050 Btu/ft3 of natural gas
C-360
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IV-B. Pipeline
Water Requirements
Gas pipeline systems do not require water for their
operation.
Land Use
The land use impact of a natural gas pipeline system
includes land allocated to the pipeline right-of-way and com-
pressor stations. It is computed using Assumptions 5 to 7.
Occupational Health
Occupational health hazards involved in transporting
natural gas via pipeline were calculated based on gas pipeline
accident statistics, transmission pipeline mileage, and volume
of natural gas delivered for the year 1972. The American
Petroleum Institute's annual summary of disabling work injuries
for the year 1972 categorized the casualties as follows (AM-120)
10 deaths, 305 injuries, and 67,630 man-days lost.
The Federal Power Commission's "Statistics of Inter-
state Natural Gas Pipeline Companies-1972" reported that, in
1972, there were 158,906 miles of transmission pipeline with
gas volume of 17.1 trillion cubic feet (FE-066).
Assuming a linear relationship between occupational
health statistics, transmission pipeline mileage, and volume of
natural gas transported, occupational health statistics for the
natural gas pipeline system developed for this study were
computed.
0361
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IV-B. Pipeline
Air Emissions
Electrically-operated natural gas pipeline systems
do not directly produce any form of air emissions.
Wa t e r Eini s s i on s
Transporting natural gas via pipelines does not result
in the production of any liquid wastes.
Thermal Emis sions
Heat emissions are negligible.
Solid Wastes
Natural gas pipelines do not produce any form of
solid wastes.
C-362
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APPENDIX C
V. END USE MODULES
C-363
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V. End Use Modules
1-0 INTRODUCTION
Radian's definition of the environmental impact of
all end use modules is restricted to air emissions as there
are no data available at the present time that can be used to
assess other possible impacts associated with the end uses
examined. The thermodynamic efficiency of each equipment type
is discussed in Appendix B. As a result, end use module
efficiencies are presented in summary tables in this section
without including any of the factors involved in their selec-
tion. Air emissions are assumed to result only from the
combustion of fossil fuels by the end use equipment. Since
electrical equipment emits no pollutants to the air, only
direct-fired fossil fuel end use module impacts need to be
documented. All modules have a common basis of 1012 Btu out-
put of useful energy.
Air emissions from each end use module are calculated
from EPA emission factors (EN-071), taking into account the
efficiency of the module. The emission factors used for these
calculations are shown in Tables 1-1 and 1-2.
C-364
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V. End Use Modules
TABLE 1-1
EMISSION FACTORS FOR FUEL OIL COMBUSTION
Type of Unit
Industrial and Commercial
Pollutant
Particulate
Sulfur dioxide*
Carbon monoxide
Hydrocarbons
Nitrogen oxides (N02)
Residual
lb/103 gal
23
157 x S*
4
3
(40 to 80)
Distillate Domestic
lb/103 gal lb/103 gal
. 15 . 10
142 x S* 142 x S*
5 5
3 -3
(40 to 80) 12
*S equals percent by weight of sulfur in the oil.
TABLE 1-2
EMISSION FACTORS FOR NATURAL GAS COMBUSTION
Type of Unit
Pollutant
Industrial
Process Boiler
lb/106 ft3
Domestic and
Commercial
Heating
lb/106 ft3
Particulates•
Sulfur-oxides (S02)
Carbon monoxide
Hydrocarbons (CHO
Nitrogen oxides (N02)
18
0.6
17
3
(120 to 230)
19
0.6
20
8
(80 to 120)
1 Source: (EN-071)
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V. End Use Modules
2.0 END USE MODULE IMPACT SUMMARIES
The results of Radian's air emission calculations
for the end use modules considered in this study are presented
in the environmental impact summary tables which follow.
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V. End Use Modules
TABLE 2-1
SUMMARY OF ENVIRONMENTAL IMPACTS
RESIDENTIAL NATURAL GAS-FIRED SPACE HEATING MODULE
Basis: 1012 Btu Output of Useful Energy
Air (Ib/hr)
Particulates 1,300
S02 42
NO 5,600
x
CO 1,400
HC 560
Efficiency
Overall Efficiency 60
Ancillary Energy (Btu/day) 0
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V. End Use Modules
TABLE 2-2
SUMMARY OF ENVIRONMENTAL IMPACTS
RESIDENTIAL OIL-FIRED SPACE HEATING MODULE
Basis: 1012 Btu Output of Useful Energy
Air (Ib/hr)
Particulates 5,400
S02 23.0001 (210)2
N0x 6,500
CO 2,700
HC 1,600
Efficiency
Overall Efficiency 55
Ancillary Energy (Btu/day) 0
NOTES:
1. . 37o sulfur in fuel oil - Fuel Supply Scenario S8 & 10,
2. .005% sulfur in fuel oil - Fuel Supply Scenario S9.
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V. End Use Modules
TABLE 2-3
SUMMARY OF ENVIRONMENTAL IMPACTS
RESIDENTIAL NATURAL GAS-FIRED WATER HEATING MODULE
Basis: 1012 Btu Output of Useful Energy
Air (Ib/hr)
Particulates 1,300
S02 ' 42
NO 5,600
x
co
HC 560
Efficiency (%)
Overall Efficiency 60
Ancillary Energy (Btu/ day) 0
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V. End Use Modules
TABLE 2-4
SUMMARY OF ENVIRONMENTAL IMPACTS
RESIDENTIAL OIL-FIRED WATER HEATING MODULE
Basis: 1012 Btu Output of Useful Energy
Air (Ib/hr)
Particulates 5,400
S02 23.0001 (210)2
NO 6-500
cox 2>700
HG i
Efficiency
Overall Efficiency 55
Ancillary Energy (Btu/day) '0
NOTES:
1. .3% sulfur in fuel oil - Fuel Supply Scenario S8 & S10.
2. . 005% sulfur in fuel oil - Fuel Supply Scenario S9.
C-370
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V. End Use Modules
TABLE 2-5
SUMMARY OF ENVIRONMENTAL IMPACTS
RESIDENTIAL NATURAL GAS-FIRED COOKING MODULE
Basis: 1012 Btu Output of Useful Energy
Air (Ib/hr)
Particulates 2,100
S02 68
NO 9,000
CO* 2,300
HC 900
Efficiency (%)
Overall Efficiency
Ancillary Energy (Btu/day)
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V. End Use Modules
TABLE .2-6
SUMMARY OF ENVIRONMENTAL IMPACTS
RESIDENTIAL OIL-FIRED COOKING MODULE
Basis: 1012 Btu Output of Useful Energy
Air (Ib/hr)
Particulates 8,800
S02 - 37.0001 (620)2
NO 11,000
cox 4>400
HC 2'600
Efficiency (%)
Overall Efficiency
Ancillary Energy (Btu/day) 0
NOTES:
1. .3% sulfur in fuel oil - Fuel Supply Scenario S8 & S10
2. .005% sulfur in fuel oil - Fuel Supply Scenario S9.
C-372
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V. End Use Modules
TABLE 2-7
SUMMARY OF ENVIRONMENTAL IMPACTS
COMMERCIAL NATURAL GAS-FIRED SPACE HEATING MODULE
Basis: 1012 Btu Output of Useful Energy
Air (Ib/hr)
Particulates 1,000
S02 32
NO 6,500
X
CO 1.10°
HC «0
Efficiency
Overall Efficiency 77
Ancillary Energy (Btu/day) 0
C-373
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V. End Use Modules
TABLE 2-8
SUMMARY OF ENVIRONMENTAL IMPACTS
COMMERCIAL OIL-FIRED SPACE HEATING MODULE
Basis: 1012 Btu Output of Useful Energy
Air (Ib/hr)
Particulates 5,900
S02 17.0001 (280)2
NO 23,000
HC
Efficiency
Overall Efficiency
Ancillary Energy (Btu/day)
NOTES:
1. .3% sulfur in fuel oil - Fuel Supply Scenario S8 & S10
2. .005% sulfur in fuel oil - Fuel Supply Scenario S9.
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V. End Use Modules
TABLE 2-9
SUMMARY OF ENVIRONMENTAL IMPACTS
COMMERCIAL NATURAL GAS-FIRED WATER HEATING MODULE
Basis: 1012 Btu Output of Useful Energy
Air (Ib/hr)
Particulates . 1,300
S02 42
NO 8,300
HC 560
Efficiency (%)
Overall Efficiency 60
Ancillary Energy (Btu/ day) 0
C-375
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V. End Use Modules
TABLE 2-10
SUMMARY OF ENVIRONMENTAL IMPACTS
INDUSTRIAL NATURAL GAS-FIRED SPACE HEATING MODULE
Basis: 10u Btu Output of Useful Energy
Air (Ib/hr)
Particulates 1,000
S02 . 32
NO 6,500
COX 920
HC
Efficiency (%)
Overall Efficiency 77
Ancillary Energy (Btu/ day) 0
C-376
-------
V. End Use Modules
TABLE 2-11
SUMMARY OF ENVIRONMENTAL IMPACTS
INDUSTRIAL OIL-FIRED SPACE HEATING MODULE
Basis: 1012 Btu Output of Useful Energy
Air (Ib/hr)
Particulates 5,900
S02 17.0001 (280)2
N0x 23,000
CO 1,600
HC 1,200
Efficiency
Overall Efficiency 76
Ancillary Energy (Btu/day) 0
NOTES:
1. . 3% sulfur in fuel oil - Fuel Supply Scenario S8 & S10
2. .005T sulfur in fuel oil - Fuel Supply Scenario S9.
C-377
-------
V. End Use Modules
TABLE 2-12
SUMMARY OF ENVIRONMENTAL IMPACTS
INDUSTRIAL NATURAL GAS-FIRED COOKING MODULE
Basis: 1012 Btu Output of Useful Energy
Air (Ib/hr)
Particulates 2,000
S02 ' 68
NO 14,000
cox 1'900
HC 340
Efficiency (%)
07
Overall Efficiency
Ancillary Energy (Btu/day) 0
C-378
-------
V. End Use Modules
TABLE 2-13
SUMMARY OF ENVIRONMENTAL IMPACTS
INDUSTRIAL NATURAL GAS-FIRED STEEL MAKING MODULE
Basis: 1012 Btu Output of Useful Energy
Air (Ib/hr)
Particulates 1,800
S02 60
NO 24,000
CQX 1,700
HC 300
Efficiency (7.)
Overall Efficiency ^
Ancillary Energy (Btu/day) 0
C-379
-------
V. End Use Modules
TABLE 2-14
SUMMARY OF ENVIRONMENTAL IMPACTS
INDUSTRIAL OIL-FIRED STEEL MAKING MODULE
Basis: 10n Btu Output of Useful Energy
Air (Ib/hr)
Particulates 11,000
S02 30.0001 (500)2
NO 43,000
CQX 2,800
HC 2,100
Efficiency (%)
Overall Efficiency 4-2
Ancillary Energy (Btu/day) 0
NOTE:
1. .3% sulfur in fuel oil - Fuel Supply Scenario S8 & S10
2. .005% sulfur in fuel oil - Fuel Supply Scenario S9.
C-380
-------
V. End Use Modules
TABLE 2-15
SUMMARY OF ENVIRONMENTAL IMPACTS
INDUSTRIAL NATURAL GAS-FIRED HEATING AND ANNEALING MODULE
Basis: 1012 Btu Output of Useful Energy
Air (Ib/hr)
Particulates 6,800
S02 " 230
N0x 87,000
CO 6,400
HC 1,100
Efficiency (70)
Overall Efficiency 11
Ancillary Energy (Btu/day) 0
C-381
-------
V. End Use Modules
TABLE 2-16
SUMMARY OF ENVIRONMENTAL IMPACTS
INDUSTRIAL OIL-FIRED HEATING AND ANNEALING MODULE
Basis: 10lz Btu Output of Useful Energy
Air (Ib/hr)
Particulates 41,000
S02 . 120,OOO1 (1,900)2
NO 160,000
cox n.ooo
HC 8'100
Efficiency (%)
Overall Efficiency 11
Ancillary Energy (Btu/day) 0
NOTE:
1. .3% sulfur in fuel oil - Fuel Supply Scenario S8 & S10,
2. .005% sulfur in fuel oil - Fuel Supply Scenario S9.
C-382
-------
V. End Use Modules
TABLE 2-17
SUMMARY OF ENVIRONMENTAL IMPACTS
INDUSTRIAL NATURAL GAS-FIRED GLASS MELTING MODULE
Basis: 1012 Btu Output of Useful Energy
Air (Ib/hr)
Particulates 4,400
S02 150
NO 56,000
CO 4,200
HC 740
Efficiency (%)
Overall Efficiency • 17
Ancillary Energy (Btu/day) 0
C-383
-------
V. End Use Modules
TABLE 2-18
SUMMARY OF ENVIRONMENTAL IMPACTS
TANK TRUCK DISTRIBUTION OF FUEL OIL MODULE*
Basis: Distribution of 1012 Btu of Fuel Oil
From Bulk Terminal to End Use Site (30 miles)
Air (Ib/hr)
Particulates 6
S02 12
N0x 160
CO 100
HC 17
Efficiency (%)
Primary Product 100
Overall Efficiency 100
Ancillary Energy (Btu/day) 1.5 x 109
*1,400 Tank Trucks, 5,000 gal capacity each, 4 miles per gallon
of fuel (NA-187).
C-384
-------
REFERENCES
AI-013 Air Products and Chemicals, Inc., Engineering
Study and Technical Evaluation of the Bituminous
Coal Research, Inc., Two-State Super Pressure
Gasification Process, Contract No. 14-32-0001-1204,
R&D Rept. 60, Washington, B.C., OCR.
AL-046 To Alleviate Freight Car Shortages, Report of the
Senate Committee on Commerce, Senate Rept. 92-982,
Calendar No. 932, Washington, D.C., 1972.
AM-041 American Petroleum Inst., Div. of Refining,
Recommended Rules for Design and Construction
of Large, Welded, Low-Pressure Storage Tanks,
API Standard 620, Washington, B.C., 1970.
AM-042 American Petroleum Inst., Biv. of Refining,
Manual on Bisposal of_ Refinery Wastes, Vol. VI,
Solid Wastes, First Edition, Washington, B.C.,
1963.
AM-099 American Petroleum Institute, Annual Statistical
Review, Petroleum Industry Statistics, 1964-1973,
Washington, B.C., 1974.
AM-120 American Petroleum Institute, Annual Summary of_
Bisabling Work Injuries in the Petroleum Indus try
for 1973, Washington, B.C., 1974.
AU-018 "Automated Black Mesa First 50 KV Railway", Reprint,
Railway Gazette Intnat'1, January 1973.
C-385
-------
REFERENCES CONTINUED
AV-003 Averitt, Paul, Stripping Coal Resources o_f the
U. S. - January 1, 1970, USGS Bull. 1322,
Washington, D.C., GPO, 1970.
BA-158 Battelle, Columbus Labs., Detailed Environmental
Analysis Concerning a Proposed Coal Gasification
Plant for Transwestern Coal Gasification Co. ,"
Pacific Coal Gasification Co., and Western
Gasification Co., and the Expansion of a Strip
Mine Operation Near Burnham, N. M. Owned and
Operated by_ Utah International. Inc. , Columbus,
Ohio, 1973.
BA-166 Barry, Charles B., "Reduce Glaus Sulfur Emission",
Hydrocarbon Proc. 5U4) , 102-6 (1972).
BA-223 Battelle-Columbus Laboratories, A Study of the
Environmental Impact of_ Projected Increases in
Intercity Freight Traffic, Final Report, Columbus,
Ohio, 1971.
BA-224 Battelle-Columbus Laboratories, Topical Report
on Energy Requirements for the Movement of
Intercity Freight, Columbus, Ohio, 1972.
BA-230 Battelle-Columbus Labs., Environmental Considerations
in Future Energy Growth, Contract No. 68-01-0470,
Columbus, Ohio, 1973.
BA-234 Battelle-Columbus and Pacific Northwest Labs.,
Environmental Considerations in Future Energy
Growth, Contract No. 68-01-0470, Columbus, Ohio,
1973.
C-386
-------
REFERENCES CONTINUED
BA-260 Ball, D., et al., Study of Potential Problems and
Optimum Opportunities in Retrofitting Industrial
Processes t£ Low and Intermediate Energy Gas from
Coal, Final Report, Contract 68-02-1323, Task I.,
EPA 650/2-74-052, Columbus, Ohio, Battelle, Columbus
Labs., 1974.
BE-147 Beychok, Milton R., Aqueous Wastes from Petroleum
and Petrochemical Plants, N. Y., Wiley, 1967.
BE-148 Beavon, David K., "Add-On Process Slashes Glaus
Tailgas Pollution", Ch.em. Eng. 7_8(28) , 71-3 (1971).
BE-238 Bentley, Charles, Private Communication, Burlington
Northern, Safety Division, 6 January 1975.
BO-117 -Bodle, Wm. W. and Kirit C. Vyas, "Clean Fuels from
Coal", Oil Gas J., 26 August 1974.
BO-120 Boyce, Allan R., Private Communication, Burlington
Northern, Energy, Metallics and Chemicals Section,
28 August 1974.
BR-137 Bright, James R. , South Africa's Oil-from-Coal.
Plant and Its Relevance for Texas, Austin,
University of Texas, 1974.
BU-116 Buck, P. and N. Savage, "Determine Unit - Train
Requirements", Power 118(1) , 90 (1974).
C-387
-------
REFERENCES CONTINUED
CH-182 Chilingar, George V. and Carrol M. Beeson,
Surface Operations in Petroleum Production,
N. Y., American Elsevier, 1969.
CO-129 Council on Environmental Quality, Energy & the
Environment, Electric Power, Washington, D.C.,
1973.
CO-175 Colony Development Operation, Atlantic Richfield
Co., Operator, An Environmental Impact Analysis for
a Shale Oil Complex at Parachute Creek, Colorado,
Vol. 1, Pt. 1, Plant Complex and Service Corridor,
1974.
DI-044 Diehl, Douglas S., et al., "Effluent Quality Control
at a Large Oil Refinery", J. WPCF 43, 2254-70 (1971)
EL-050 "Electrification Looking Increasingly Attractive to
U. S. Railroads", Railway Locomotives Cars 148(2),
12 (1974).
EL-052 El Paso Natural Gas Co., Application of El Paso
Natural Gas Co. for a Certificate of Public
Convenience and Necessity, Docket No. CP73-131,
El Paso, Texas, 1973.
EL-054 "Electrification", Progressive Railroading,
May-June, 1973 , 64.
C-388
-------
REFERENCES CONTINUED
EN-036 Environmental Protection Agency, Office of Noise
Abatement and Control, Report to the President
and Congress on Noise, Washington, D.C., 1971,
PB 206 716.
EN-071 Environmental Protection Agency, Compilation of
Air Pollutant Emission Factors, 2nd ed.
with Supplements, AP-42, Research Triangle Park,
N.C., 1973.
EN-072 Environmental Protection Agency, Office of Air and
Water Programs, Office of Air Quality Planning and
Standards, Background Information for Proposed New
Source Standards: Asphalt Concrete Plants,
Petroleum Refineries, Storage Vessels, Secondary
Lead Smelters and Refineries, Brass or Bronze Ingot
Production Plants, Iron and Steel Plants, Sewage
Treatment Plants, Vols. 1 and 2, Research Triangle
Park, N.C., 1973.
EN-129 Environmental Protection Agency, "Vapor Recovery
Regulations: Changes in Initial Compliance Dates
and Request for Comments on Alternative Systems",
Fed. Reg. 39(118), 21049-53 (1974).
EN-196 Environmental Protection Agency, "Air Programs,
Standards of Performance for New Stationary Sources -
Additions and Miscellaneous Amendments", Fed. Reg.
39(47), 9308 (1974).
EN-199 Engel, A. P., Private Communication, General Electric
Co., Locomotive Products Dept., Domestic Electrifi-
cation Projects, 15 August 1974.
C-389
-------
REFERENCES CONTINUED
EN-204 . Engineering-Science,- Inc. , Air Quality Assessment
of_ the Oil Shale Development Program in the
Piceance Creek Basin, McLean, Va., 1974.
FA-083 Fawnsworth, J. Frank, et al.- "K-T: Koppers
Commercially Proven Coal and Multiple-Fuel
Gasifier", Pittsburgh, Pa., Koppers Co., Inc.
1974.
FE-066 Federal Power Commission, Statistics of Inter-
state Natural Gas Pipeline Companies, 1972,
Washington, D.C., 1973.
FE-068 Federal Power Commission, Synthetic Gas-Coal
Task Force, Final Report, The Supply-Technical
Advisory Task Force-Synthetic Gas-Coal,
Washington, D.C., 1973.
FI-067 Fisher, H. A. and Blair, A. Ross, "The Muskingum
Electric Railroad", N.Y., Electric Power Service
Corporation.
GA-107 Gary, James H. , ed. , Proceedings p_f the Seventh
Oil Shale Symposium, April, 1974, Colorado School
of Mines Quarterly 69(2), 1974.
GE-050 General Electric Co., Transportation Systems Div.,
Applications of_ Diesel - Electric Locomotives,
GED 4204A, Erie, Pa., 1974.
C-390
-------
REFERENCES CONTINUED
GO-090 Government - Industry Task Force on Railroad
Electrification, A Review p_f Factors Influencing
Railroad Electrification.
GR-117 Greenville Steel Car Co., From Mine t£ Power
Station Greenville Cars Move on Schedule,
Greenville, Pa., 1974.
HA-157 Hardison, L.C., "Air Pollution Control Equipment",
Petro/Chem. Eng., March 1968.
HA-231 Hare, C. T., J. J. Springer and T. A. Huls,
"Locomotive Exhaust Emissions and Their Impact",
Presented at the ASME, Diesel and Gas Engine
Power Div., Conf., Houston, Texas, 1974.
HE-055 Hellwig, Katherine C., et al., "Convert Coal to
Liquid Fuels w/ H-Coal", CEP Symp. Ser. 64(85),
98-103 (1968).
HI-083 Hittman Associates, Inc., Environmenta1 Impacts,
Efficiency and Cost of Energy Supplied by_ Emerging
Technologies, Phase 2, Draft Final Report, Tasks 1-11,
HIT-573, Contract No. EQC 308, Columbia, Md., 1974.
HI-090 Hittman Associates, Inc., Environmental Impacts,
Efficiency and Cost of Energy Supply and End Use,
Phase 1, Draft Final Report, HIT-561, Columbia,
Md., 1973, Phase 2 - see HI-083.
C-391
-------
REFERENCES CONTINUED
HY-006 . "Hydrocarbon Processing 1972 Refining Processes
Handbook", Hydrocarbon Proc. 51(9), 111-222 (1972).
HY-013 "Hydrocarbon Processing Refining Process Handbook",
Hydrocarbon Proc. 53(9) (1974).
IN-041 Inquiry into Freight Car Shortages, Pt. 2, 92nd
Congress, 1st & 2nd Sessions, Serial 92-82,
Washington, D.C., GPO, 1972.
IN-047 Interstate Commerce Commission, Transport
Statistics in the United States for the Year
Ended December 31, 1973, Pt. £, Pipe Lines,
Washington, D.C., 1974.
KA-124 Katz, Donald L. , et al, Evaluation of_ Coal
Conversion Processes t£ Provide Clean Fuels,
EPRI 206-0-0, Final Report, Ann Arbor, Mich.,
Univ. of Michigan, College of Engineering, 1974.
KA-134 Katz, L., et al, "Transmission to Market",
Handbook of Natural Gas Engineering, N.Y.,
McGraw, 1959.
LI-094, Litman, R., Private Communication, Union Oil,
17 Feb. 1975.
LO-096 Lorenzi, Lr., Jr., "Plant Design for Chemical
Desulfurization of Coal", Presented at the ACS,
Spring 1974 Mtg., Low Sulfur Fuels from Coal,
Los Angeles.
C-392
-------
REFERENCES CONTINUED
LO-126 Lorenzi, Lloyd, Private Communication, Environ-
mental Protection Agency, Raleigh, N.C., 11 March
1975.
MA-226 Mallatt, R. C., J. F. Grutsch and H. E. Simons,
"Incinerate Sludge & Caustic", Hydrocarbon Proc.
49, 121 (1970).
NA-172 National Academy of Engineering, Rehabi1itation
Potential of Western Coal Lands, Ford Energy
Policy Project, Cambridge, Mass., Ballinger,
1974.
NA-184 National Coal Association, Coal Traffic Annual,
1974 Ed., Washington, D.C., 1974.
NE-044 Nelson, W. L., Petroleum Refinery Engineering, 4th Ed,
McGraw-Hill Series in Chemical Engineering, N. Y.,
McGraw-Hill, 1958.
NE-046 Nelson, W. L., "How Much Land Investment Needed?",
Oil Gas J., 4 Dec. 1972.
NI-036 Nielson, George F., ed., 1974 Keystone Coal Indus try
Manual, N. Y., McGraw-Hill, Mining Publications, 1974.
OL-020 Oliver, J. A., et al., "The Catenary System and
Power Supply Facilities of the Muskingum Electric
Railroad", N.Y., American Electric Power Service
Corp.
C-393
-------
REFERENCES CONTINUED
OL-021 Oliver, J. A., et al., "Electric Locomotives for
the Muskingum Electric Railroad", N.Y., American
Electric Power Service Corp.
OV-008 Overman, G. J., Private Communication, General
Motors Co., Southwestern Region, Electromotive
Div., Sept. and Oct., 1974.
PA-139 (Ralph M.) Parsons Company, Demonstration Plant,
Clean Boiler Fuels from Coal, OCR R&D Rept. 82,
Int. Rept. 1, 2 Vols, Contract No. 14-32-0001-1234,
Los Angeles, California.
PE-030 Perry, John H., Chemical Engineers Handbook,
4th Ed., New York, McGraw-Hill, 1963.
PE-097 Petroleum Extension Service, Univ. of Texas, and
Pipeline Contractors Assoc., A Primer of Pipeline
Construction, 2nd Ed., Austin, Texas, 1966.
PE-098 Petroleum Extension Service, Univ. of Texas, Oil
Pipeline Construction and Maintenance, Vol. 2, 2nd
Ed., Austin, Texas, 1973.
PF-003 Pforzheimer, H., "Parajo-New Prospects for Oil
Shale", CEP70(9), 62 (1974).
RA-081 Rabb, A., "Sludge Disposal: A Growing Problem",
Hydrocarbon Proc. 44(4), 149 (1965).
RA-119 Radian Corporation, A Program t£ Investigate Various
Factors in Refinery Siting, 2 Vols, Final Report
with Map Inserts, Austin, Texas, 1974.
C-394
-------
REFERENCES CONTINUED
RA-128 Rail Freight Car Shortage, 93rd Congress, 1st Session,
Rept. 93-16, Washington, D.C., 1973.
RE-048 Recent Developments in Industrial Pollution Control,
Proceedings of the Fourth Annual Northeastern Regional
Antipollution Conference, Greater Providence, R.I.,
College of Engineering, Univ. of Rhode Island, 1971.
RI-063 Rice, Richard A., "System Energy As a Factor in
Considering Future Transportation", Presented at
the ASME Winter Annual Mtg., N.Y., 1970.
SA-109 Sass, A., "The Production of Liquid Fuels from
Coal". Minerals Sci. Eng. 4(4), 18 (1972).
SH-157 "Shale Oil - Process Choices", Chem. Eng. 81(10),
66 (1974).
SO-039 Southwest Energy Study, Dept. of Interior, Study
Management Team, Washington, D.C., 1972.
SO-066 Southwest Research Inst., "Exhaust Emissions from
Uncontrolled Vehicles and Related Equipment Using
Internal Combustion Engines, Pt. 1, Locomotive
Diesel Engines and Marine Counterparts", EHS-70-
108, APTD-1490, San Antonio, Texas, 1972.
ST-124 "Standards of Performance for New Stationary
Sources - Proposed Standards for Seven Source
Categories", Fed. Reg. 38(111), Pt. 2 (1973).
C-395
-------
REFERENCES CONTINUED
ST-204 Stillwagon, R. E., "Economic Aspects of Electrically
Driven Compressor Stations for Natural Gas Pipelines" -,
Presented at the IEEE Pet. Chem. Ind. Conf., 20th
Annual, Houston, Texas, Sept. 1973.
TH-058 "Three 50-kv Units are World's First", Railway
Locomotives Cars 147(1), 26 (1973).
TI-025 Tillinghast, John, "The Electric Railroad - A New
Partner for Surface Mining", Presented at the
3rd Energy Transportation Conference, 1973.
US-093 U. S. Dept. of the Interior, Final Environmental
Statement for the Prototype Oil Shale Leasing
Program, 6 Vols., Washington, D.C., 1973 (GPO).
US-109 U. S. Bureau of Mines, (Energy Research), Technology
of Coal Conversion, Washington, D.C., 1973.
US-125 U. S. Dept. of Transportation, Federal Railroad
Administration, Summary and Analysis of Accidents
on Railroads in the United States, 1972, Accident
Bull. No. 141, Washington, D.C., 1973.
US-130 U. S. Bureau of Mines, Crude Petroleum, Petroleum
Products and Natural-Gas-Liquids, 1972, Final
Summary, Mineral Industry Surveys, Annual Petroleum
Statement, Washington, D.C., 1973.
US-154 U. S. Dept. of Commerce, Bureau of the Census,
Statistical Abstract of the U. S. 1973, 94th Ed.,
Washington, D. C., 1973.
C-396
-------
REFERENCES CONTINUED
US-164 Bureau of Reclamation, Upper Colorado Region,
WESCO Gasification Project and Expansion of
Nava jo Mine by_ Utah International, Inc., San
Juan County, New Mexico, Draft Environmental
Statement, DES 74-107, Washington, D.C., 1974.
VA-093 Van Norman, Jerry L., "New Ideas Are Evolving
in Compressor Station Piping Design", Pipeline
Gas J., 1972 (Nov.), 26 (1972).
VO-025 Voogd, J. and Jack Tielrooy, "Improvements in
Making Hydrogen", Hydrocarbon Proc. 46(9),
115 (1967).
WA-139 Wasp, E. J. and T. L. Thompson, "Slurry Pipelines -
Energy Movers of the Future", Presented at the
Interpipe '73 Conference, Houston, Texas, Nov.
1973, San Francisco, Bechtel, Inc., 1973.
WE-110 Wefers, H. J. and L. E. Ettlinger, "Modern
Railroad Electrification", Mech. Eng_. 1970 (Sept.),
39.
WE-116 Wefers, H. J. and L. E. Ettlinger, "Modern
Railroad Electrification at Muskinghum", Presented
at the ASME-IEEE Joint Railroad Conference,
Philadelphia, Pa., April 1970, N.Y., ASME, 1970.
WH-036 Whittle, T. C., Private Communication, General
Electric Co., Transportation Systems Div., 11
Sept. 1974.
C-397
-------
APPENDIX D
DISPERSION MODEL DESCRIPTION
-------
The purpose of this discussion is to give a brief
outline of the dispersion model used to calculate the anticipated
pollutant concentrations in the Chicago AQCR.
The model is similar to the Climatological Dispersion
Model (CDM) recently developed at the National Environmental
Research Center, Research Triangle Park, North Carolina. The
CDM is a long-term average model which utilizes long-term
meteorological data in conjunction with Gaussian dispersion
using Pasquill-Gifford dispersion coefficients. This model is
essentially an updated version of the well-known AQDM (Air
Quality Display Model) developed under EPA auspices and both
models share a common conceptual approach. The primary dif-
ferences between the two models relate to calculation of plume
rise for point sources, specification of mixing heights and wind
profiles, and the treatment of the effects of area sources.
The average concentration "CA due to area sources at
a particular receptor is given by
16 66
I [I «k I I «
-------
where
k = index identifying wind direction sector
qk(p) = J Q(p,v)dop (k sector)
Q(p,cp) = emission rate of the area source per unit
area and unit time
p «= distance from the receptor to an infintesimal
area source
cp = angle relative to polar coordinates centered
on the receptor
t - index identifying the wind speed class
m = index identifying the class of the Pasquill
stability category
$(k,£,m) = joint frequency function (generally for_an
annual period
S(p,z;u ,P ) = dispersion function defined in Equations (3) and (4)
z = height of receptor above ground level
u = representative wind speed
P = Pasquill stability category
D-2
-------
For point sources , the average concentration Cp due
to N point sources is given by:
r - I* ' **'m> Gn
Gp
n=l 4=1 m=l pn
where k = wind sector appropriate to the n point source
t*K
G = emission rate of the n point source
n r
p = distance from the receptor to the n point source
If the receptor is presumed to be at ground level, that
is, z = 0, then the functional form of S(p,z;U0,P ) will be:
Xr Hi
exp
(2
exp
-0.692p
if 0z(p) ^ 0-8 L and
SCp.OjUj^) = JL
if a (p) > 0.8L. New terms in Equations 3 and 4 are defined as
follows:
a (p) = vertical dispersion function, i.e., the standard
- Z
deviation of the pollution concentration in the
vertical plane
nm, h = effective stack height of source distribution,
i.e., the average height of area source emis-
sions in the k wind direction sector at
radial distance p from the receptor
D-3
-------
L = the afternoon mixing height
Tl/2.= assumed half life of pollutant, hours
The possibility of pollutant removal by phisical of chemical
processes is included in the program by the decay expression
exp
The total concentration for the averaging period is
the sum of concentrations of the point and area sources for that
averaging period.
For point sources, the effective stack height, h, is
the sum of the physical stack, h" and the plume rise, Ah:
h <= ho + Ah (5)
The plume rise, /(h, is computed with formulas developed by
Briggs (BR-102). For unstable and neutral conditions:
, , ,,,1/a -i a/3
Ah = 1.6F 'Up7 p <; 3.5X* (6)
and
Ah = 1.6F1/3 U^O.SX*)"/9 p > 3.5X* (7)
= 14FS/$ if F & 55
X* = 34F0/5 if F > 55
D-4
-------
8 Vs Ks
g = acceleraclon due to gravity
V = average exit velocity of gases of plume
s
R « inner radius of stack
s
T •=* average temperature of gases, of plume
S '
T = ambient air temperature
U - wind speed
p « distance from source to receptor
For stable conditions
Ah = 2.9 (F/US)1/3
(8)
(i.e., Equation (8) rather than Equation (7) is used for stable
conditions)
where
s ** f" "hi ^
a
0 = ambient potential temperature
z «= height.
D-5
-------
The joint probability function ^(kn,,m) is obtained
from historic meteorological data collected at meteorological
stations near the site in question. Average ambient temperature
and average daytime and nighttime mixing height for each site
are obtained from an analysis of the meteorological data for
the site.
D-6
-------
APPENDIX E
SUPPORTING CALCULATIONS FOR THE COST
COMPARISONS OF ALTERNATE ELECTRIC AND
FOSSIL FUEL FIRED EQUIPMENT IN THE
RESIDENTIAL, COMMERCIAL, AND INDUSTRIAL SECTORS
-------
I. Residential Sector Capital and Operating Cost Calculations
A. Air Conditioner Capital Costs, 1974
central electric air conditioner
units shipped = 2. 880x10 6 (EN-221)
installed value = $2,641. 738xl06
capital cost =
central gas air conditioner
capital cost = $1,500 (AM- 126)
Space Heater Capital Costs. 1974
central electric space heater
units shipped = 1. 376x10 6 (EN-221)
installed value = $744.141xl06
capital cost - ^ = $541
central gas space heater
units shipped » 2. 118x10 6 (EN-221)
installed value = $1,088. 144x10 6
capital cost - ^iffijft0' - 9314
central oil fired space heater
units shipped = . 825x10 5
E-l
-------
installed value = 468.468x106
capital cost-- ^g^68 = $568
C. Stove/Oven Capital Costs, 1974
electric units shipped = 2.925xl06 (TE-177)
value = $701.839x106
capital cost = 701.839/2.925 = $240
gas units shipped = 1.953xlOs (TE-177)
value = $447.551x106
capital cost - 447.551/1.953 = $229
microwave units shipped = 675,000 (TE-177)
value = 247.725xl06
capital cost = 247.72S/.675 = $367
D. Clothes Dryer Capital Costs, 1974
electric units shipped = 2.841x10s (TE-177)
value = $514.221x106
capital cost = $514.221/2.841 = $181
E-2
-------
gas units shipped = 739,000 (TE-177)
value - $155.190x106
capital cost = $155.19/.739 » $210
E. Water Heater Capital Costs, 1974
electric units shipped = 2.505xl06 (TE-177)
value = $242.985x106
capital cost = $242.985/2.505 = $97
gas units shipped = 2.56xl06 (TE-177)
value = $236.072xl06
capital cost - $236.072/2.56 = $92
F. Stove/Oven Capital Costs, 1972
electric units shipped = 3.232xl06 (TE-177)
value « $706.934x106
capital cost = $706.934/3.232 = $219
gas units shipped = 2.661xl06 (TE-177)
value = $564,568x106
capital cost = $564.568/2.661 = $212
E-3
-------
microwave units shipped = 325,000
. . . value - $130.0x106
capital cost = $130/.325 = $400
G. Clothes Dryer Capital Costs, 1972
electric units shipped = 2.989xl06 - (TE-177)
value = $505.141x105
capital cost = $505.141/2.989 = $169
gas units shipped = 936,000
value = $183.456xl06
capital cost = $183.456/.936 = $196
H. Water Heater Capital Costs, 1972
electric units shipped = 2.265x106 . (TE-177)
value = $203.85xl06
capital cost = $203.85/2.265 = $90
gas units shipped = 3.163x106
value = $268.855xl06
capital cost = $268.855/3.163 = $85
E-4
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I- Air Conditioner Capital Costs, 1972
1974/1972 Cost Ratios (TE-177)
Gas Electric
water heater 1.082 1.078
stove/oven 1.080 1.096
dryer 1.071 1.071
refrigerator - 1.093
room air conditioner - 1.010
Avg. 1.078 1.070
1972 capital cost gas air conditioner = 1,500/1.078
= $1,390
1972 capital cost electric air conditioner
= 917/1.070 = $857
J. Space Heater Capital Costs , 1972
1972 capital cost gas space gas heater = 514/1.078
= $477
1972 capital cost electric space heater = 541/1.070
= $502
1972 capital cost oil space heater = 567/1.078 = $526
K. Central Electric Air Conditioner Operating Cos ts
Assuming 5 rooms /unit (US -189)
1974 cost - x 5 rooms x . $196/yr
(AI-018)
1972 cost = 1,389 x 5 x .0240 = $167/yr
E-5
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L. Central Gas Air Conditioner Operating Costs
1974 cost - i!2j|J!E£ x ii - $169/yr
1972 cost = 119.2 x $1.186/mcf = $141/yr
N. Oil-Fired Space Heater Operating Costs
1974 cost , U92_a»™ x 60% x 100,000^
1974 cost-- 1,389 x 5. x |°* x 3.413 . 10-' j x
= $56/yr
1972 cost - $56/yr x f^f^f = $47/yr
M. Central Gas Space Heater Operating Costs
energy requirement = 119.2 mcf/yr (AM- 126)
140, 00 Btu
1972 cost = $225/yr x |;; = $86,9/yr
0. Central Electric Space Heater Operating Costs
1974 cost - MJUJnjhr x 5^ . $5n/yr
1972 cost = 20,955 x $° = $503/yr
E-6
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P. Stove Oven Operating Costs
1974 electric cost = 1'17L.kwhr x ^M2- = $33/yr
1974 microwave cost - 190y^whr x - $5.4/yr
1974 gas cost » 1,175 x 75% x 3.413 x 10-a _ x
- $11.5/yr fc $12/yr
1972 electric cost = 33/yr x = $28/^r
1972 microwave cost - $5.4/yr x 'jjjjgjj =
1972 gas cost » $11.5/yr x =• $9.6/yr
Q- Clothes Dryer Operating Costs
1974 electric cost = 993 x $ = $28/yr
1974 gas cost - 993 x x 3.413 x 10'3 m||? x $1.418/mcf
- $5.5/yr
1972 electric cost = 28 x -Q. » $24/yr
1972 gas cost = 5.5 x '} = $4.6/yr
E-7
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R. Water Heater Operating Costs
197.4 electric cost = 4,219 ^f£ x $.0282/kwhr = $119/yr
1974 gas cost = 4,219 x x 3.413 x 10~3 g x $1.418/mcf
- $31/yr
1972 electric cost = $119/yr x "jj^ = $101/yr
1972 gas cost = $31/yr x '* - $26/yr
II. Residential Sector Present Cost Calculations
A. Base Case Calculations, 1972
20 yr lifetime, 8% interest, constant operating
costs over equipment life
1. Air Conditioning, Electric
P = $857 + (P/A, 8%, 20 yr)($167/yr)
= 857 + (9.818)(167)
= $2,497
2. Air Conditioning, Gas
P = $1,390 + 9.818 ($47/yr)
= $1,851
E-8
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3. Dryer, Electric
P = $169 + 9.818 ($23.8/yr)
- $403
4. Dryer, Gas
P * $196 + 9.818 ($4.6/yr)
* $241
5. Stove/Oven, Electric
P - $219 + 9.818 ($28.2/yr)
= $496
6. Stove/Oven, Gas
P » $212 + 9.818 ($9.6/yr)
= $307
7. Stove/Oven, Microwave
P * $400 + 9.818 ($4.6/yr)
- $445
E-9
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B. Base Case Calculations, 1974
1. Air Conditioning, Electric
P = $917 + 9.818 ($196/yr)
= $2,841
2. Air Conditioning, Gas
P = $1,500 + 9.818 ($56/yr) = $2,050
3. Dryer, Electric
P = $181 + 9.818 ($28/yr) « $456
4. Dryer, Gas
P = $210 + 9.818 ($5.5/yr) = $264
5. Stove/Oven, Electric
P - $240 + 9.818 ($33/yr) = $565
6. Stove/Oven, Gas
P = $229 + 9.81.8 ($11.5/yr) = $342
7. Stove/Oven, Microwave
P = $367 + 9.818 (5.4/yr) = $420
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C. Case 1, 1972
equipment life = 20 yr, interest rate = 8%
gas prices increase 9.8770/yr "> 1972-74 average
electricity prices increases 8.75%/yr J increases
1. Air Conditioning, Electric
P20 ,
P = $857 + $167/yr I 7TTTW (1+.0875)1
Ln=l
= 857 + 167
20
20
,
1.
0875
.0875)n
. 35,
= 857 + 154
(1.Q06944)21-!
1.006944 - 1
•1
857 + 154 (21.52)
$4,162
2 . Air Conditioning , Gas
= 1,390
QJr(1.0173)21-l1
-81|_ 1.0173 - 1 J -
1,390 + 42.8 (24.06)
$2,419
E-ll
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3. Dryer, Electric
P = $169 + 1^373- (21.52) = $641
4. Dryer, Gas
P = $196 + $4 (24.06) = $297
5. Stove/Oven, Electric
P = $219 + (21.52) = $777
6. Stove/Oven, Gas
P = $212 + (24.06) - $423
7. Stove /Oven, Microwave
P = $40° + 1.0875
D. Case 1, 1974
1. Air Conditioner, Electric
P = $917 $
i0875
2. Air Conditioner, Gas
P = $1,500 + Y^W (24.06) = $2,726
3. Dryer, Electric
P = 181 + ^875 (21.52) = $735
E-12
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4. Dryer, Gas
P = $210 + ^0337 (24.06) = $330
5. Stove/Oven, Electric
P = $240 + T^irr (21.52) - $896
6. Stove/Oven, Gas
P «. $229 + i^Htf (24.06) = $481
7. Stove/Oven, Microwave
p = $367 + ^$^5 (21.52) - $473
E. Case 2, 1972
equipment life = 20 yr, interest rate - 12%
gas prices increase 9.87%/yr
electricity prices increase 8.757<>/yr
1. Air Conditioning, Electric
n -,
P - S8-57 1.0875
p - $857
857 + n 167 (.971)21Tl"
J/ ^ 1.0875 .971 - 1
(14'90)
$3,145
E-13
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2. Air Conditioning, Gas
1.12
i 390 4- ~Z~ •
' 1.0987
981-1
-1
1,390 +
(16.45)
» $2,094
3. Dryer, Electric
P = $169 +
(14.90) = $495
4. Dryer, Gas
P = $196 +
(16.45) = $265
5. Stove/Oven, Electric
P = $219 + LQS
- $673
6. Stove/Oven, Gas
P - $212 +
(16.45) = $356
7. Stove/Oven, Microwave
P = $400 +
(14.90) = $462
E-14
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F. Case 2, 1974
1. Air Conditioning, Electric
P = $917 + ^0375 (14.90) = $3,602
2. Air Conditioning, Gas
P = $1,500 + (16.45) = $2,338
3. Dryer, Electric
P - $181 + - (14.90) = $565
4. Dryer, Gas
P = $210 + (16.45) - $292
5. Stove/Oven, Electric
P = $24° +
6. Stove/Oven, Gas
P = $229 +
7. Stove /Oven, Microwave
P = $367 + 1^75 (14.90) = $441
E-15
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III. Commercial Sector Capital and Operating Cost Calculations
A. . Stove Oven Capital Costs, 1974
1. Electric
units shipped = .006x106
value = $3.823x106
capital cost ^yjjf3- = $637
2. Gas
unit shipped = .029x106
value = $17.663xl06
capital cost = = $609
B- Space Heating Operating Costs, 1972
1. Electric, 95% Efficient
met- m 10s Btu input 2.93xlQ-'tkwhr $.0339
cobi. XQ~6Btu output Btu x kwhr
= $10.45/106 Btu
2. Gas, 77% Efficient
cost = input 1 mcf $.906
.77xlOe Btu output 10s Btu x mcf
= $1.18/106Btu
E-16
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3. Oil, 76% Efficient
10_6Btu input 1 gal $.102
.76xl06Btu output 1. 4x10 s Btu x gal
- $0.96/106Btu
C. Water Heater Operating Costs, 1972
1. Electric, 92% Efficient
n .. _ 106Btu v 2.93x10-'* kwhr $.0339
cosc ,92xl06Btu x Btu x kwhr
= $10.80/106Btu
2. Gas, 60% Efficient
cost = 10 6 Btu 1 mcf $.906 = Sl 51/106Btu
COSt - >60xl06Bt:u X 106Btu X -£££- - !?l.il/lU BtU
D. Stove/Oven Operating Costs, 1972
1. Electric, 75% Efficient
™«t- = 10s Btu 2. 9 3x10 -"kwhr $.0339
cosi: .75xlQ6Btu x Btu x kwhr
» $13.25/106Btu
2. Gas, 37% efficient
E-17
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3. Microwave (assume electric use ratio of electric
to microwave is same as residential)
cost = 13.25 x '1?S[- = $2.14/106Btu
E. Air Conditioning, 1972
1. Electric, 50% Efficient
= 106Btu 2.93xlQ-'kwhr $.0339
cosc ,5xlOsBtu x Btu kwhr
» $19.87/106Btu
2. Gas, 30% Efficient
F. Space Heating, 1974
1. Electric
-10'45 x
2. Gas
co.f 1.
3. Oil
cost = 0.96 x -Aga- = $2.48/106Btu
ga J-
E-18
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Water Heating, 1974
1. Electric
cost = 10.80 x •:"0fff - $12.39/106Btu
2. Gas
cost - 1.51 x * $1.84/106Btu
H. Stove/Oven. 1974
1. Electric
cost = 13.25 x = $15.20/106Btu
2. Gas
cost - 2.45 x » $2.99/106Btu
3 . Microwave
cost - 2.14 x ^ = $2.46/106Btu
I- Air Condi tioning. 1974
1. Electric
cost = 19.87 x - = $22.80/10sBtu
E-19
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2. Gas
. cost = 3,02.x l' = $3.68/106Btu
IV. Industrial Operating Costs
A. Space Heating. 1972
1. Electric, 95% efficient
cost = lO'Btu kwhr $.0230 = $y 09/106Btu
COST: .95xl06Btu x 3413 Btu x kwhr ?/ . u?j lu ocu
2. Gas, 77% Efficient
« « ' ?0.58/10'Btu
3. Oil, 76% Efficient
B. Space Heating. 1974
1. Electric
cost - 7.09 x | - $8.66/10'Btu
2. Gas
cost = 0.58 x ' = $0-85/106Btu
E-20
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3. Oil
cost - 0.96 x 1'fft?7!^! = $2.48/106Btu
C. Steel-Making Furnaces, 1972
1. Electric
cost . l^l£H K -. x . $12.80/con
2. Gas
3. Oil (low- sulfur residual)
cost - ^i^ x .1 x 2,288 . $2.52/ton
D. Steel-Making Furnaces, 1974
1. Electric
• $15. 64/ ton
2. Gas
cost = 1-93 x
E-21
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3. Oil
cost = 2..52.x= $8.05/ton
E. Heating and Annealing of Steel, 1972
1. Electric
cost . 2.1xl06Btu kwhr $.0230
cost ton x 3,413 Btu x kwhr
2 . Gas
3. Oil
cost = 19x10 6 Btu 1 gal $.088 = $u 15/
cost — x 150,000 Btu x ^ :?ii.i5/ton
F. Heating and Annealing of Steel, 1974
1. Electric
cost = 14.15 x |;gi$i"{£ - ?17.29/ton
2. Gas
cost- 8.53 x|;^°.cf.$12.48/toa
3. Oil
cost = 11.15 x 'Aftfl- = $35.60/ton
:?. Uoo/gal
E-22
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G. Aluminum Melting, 1972
1. Electric
«**.
cost
2.1xl06Btu
to - 3.413 Btu
kwhr v $.0230
x
2. Gas
4. 7x10 6 Btu „ 1 mcf v $.449
-- ~ - x --
3. Oil
cost
x
, M88 . $2.76/ton
H. Alxjminum Melting, 1974
1. Electric
?«.29/ton
2. Gas
cost = 2.11 x
- $3.09/ton
3 . Oil
cost - 2'76
E-23
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I. Glass Melting, 1972
1. . Electric
cost - L3*£S> x _ x 2.2210 . $19.54/ton
2. Gas
3. Oil
cost - 16xlO*Btu gal x $^88 . $9.39/ton
ton ljU.uuu otu gal
J. Glass Melting, 1974
1. Electric
cost = 19.54 x l-XMft'yff" - $23.87/ton
2. Gas
cost - 7.18 x I'IMZS - $10.51/ton
3. Oil
cost = 9.39 x l-flfc^t = $29.98/ton
E-24
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K. Cooking, 1972
1. Electric
cost " 775xlO%tu x 3.413rBtu x ^^ = $8.99/106Btu
2. Gas
cosr = ...1 mcf •$.449 _ g, 21/106Btu
cost _ x " x ^ " J?1-21/10 Btu
3. Oil
"°° = $0.77/106Btu
150,000 Btu
L. Cooking, 1974
1. Electric
„,-,„.(- _ o QO -, y.UZoJ./tCWnr _ CIA 00/106134-,.
cost - b.yy x ^ M^i^r.^* - 9iu.y«/iu Btu
2. Gas
cost - 1.21 x l'^^ = $1.77/106Btu
3. Oil
cost « 0.77 x 'Afl = $2.46/106Btu
9.uoo/gai
E-25
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APPENDIX E - REFERENCES
AI-018 . Air Conditioning Heating and Refrigeration News
27 January 1975.
AM-124 American Gas Association, Department of Statistics,
1972 Gas Facts, Arlington, VA (1973).
AM-125 American Gas Association, Department of Statistics,
Private Communication (April 1975).
AM-126 American Gas Association, Private Communication
(April 1975).
AN-094 Andrew, Glenn A., A Comparative Analysis of the
Efficiencies of Electrical Equipment Versus
Direct-Fired Fossil Fuel Equipment, Draft Interim
Report, Contract No. 68-02-1319, Task 13, Austin, TX,
Radian Corporation (April 1975).
EN-221 "Environmental Confort Appliances," Appliance Manuf.
1973 (December).
FE-090 Federal Power Commission, Typiccil Electric Bills,
Washington, D.C. (December 1974).
HO-176 "How to Cut Fat Out of Your Home Energy Budget,"
Smithsonian (March 1974).
RA-157 Radian Corporation, Fuel Usage Assessment for EPA
Energy End Use Study, Interim Report, Contract No.
68-02-1319, Task 13, Austin, TX (December 1974).
RE-123 "Refined-Products Prices," Oil Gas J, (17 July 1972).
RE-124 "Refined-Products Prices," Oil Gas J. (15 July 1974).
TE-177 "The Ten Year Tables: A Look at Product Sales Growth
and Performance," Merchandising Wk. (24 February 1975)
US-187 United States Steel Corporation (USS), The Making,
Shaping and Treating of Steel. Harold E. McGannon,
ed., 8th ed., Pittsburgh, PA (1964).
US-189 U.S. Department of Commerce, Bureau of the Census,"
Detailed Housing Characteristics, U.S. Summary,
Washington, D.C. (1972).
E-26
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TECHNICAL REPORT DATA
(Please read lunnictmns on the reverse before completing)
1. REPORT NO.
EPA-600/2-76-049b
2.
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Electrical Energy as an Alternate to Clean Fuels
Stationary Sources; Volume II--Appendix
for
5. REPORT DATE
March 1976
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
R.M. Wells andW.E. Corbett
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME ANO ADDRESS
Radian Corporation
8500 Shoal Creek Boulevard (P.O. Box 9948)
Austin, Texas 78766
10. PROGRAM ELEMENT NO.
1AB013; ROAP 21ADD-042
11. CONTRACT/GRANT NO.
68-02-1319. Task 13
12. SPONSORING AGENCY NAME ANO ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park. NC 27711
13. TYPE OF REPORT AND FSSiQD COVERED
Task Final: 6/74-10/75
14. SPONSORING AGENCY COCS
EPA-ORD
15. SUPPLEMENTARY NOTES
Project officer for this report is Walter B.Steen, Ext 2825.
«6. ABSTRACT -
rep0r£ gjves res ults of an examination of technical and environmental
incentives for increased electrification in stationary use sectors. It compares the
impacts which result from the production and consumption of equivalent quantities of
natural gas, fuel oil, and electricity. It also examines several alternative methods of i
producing each end-use fuel and considers technical and economic barriers to incr-
eased electrification. It concludes that incentives for increased electrification are
associated with the potential of this technique to reduce fossil fuel demands per se j
since direct consumption of fossil fuels appears to be more attractive from an energy j
efficiency and an environmental impact viewpoint. Most of the natural gas and dis- I
tillate fuel oil consumed in the U.S. is in the residential, commercial, and indus-
trial sectors. Currently experienced shortages of these clean premium fuels are
providing incentives for the development of new energy sources for these markets.
Among apparent alternatives are increased exploration for new sources of oil and
gas, and production of clean synthetic fuels from the more abundant (but less
environmentally attractive) fossil fuels such as coal or oil shale. Increased use of
electrical energy is another option for satisfying future stationary sector energy
demands.
17.
KEY WORDS ANO DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. coSAti j'iild/Group
Air Pollution
Energy
Electricity
Natural Gas
Fuel Oil
Economics
Evaluation
Coal
Oil Shale
Air Pollution Control
Stationary Sources
Clean Fuels
Electrical Energy
13B
20C
20D
05C
14A
13. DISTRIBUTION STATEMENT
Unlimited
UPA. Form 2220-1 (9-73)
19. SECURITY CLASS (This Report)
Unclassified
21. NO. Zf --oES
476
Unclassmeci
E-27
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