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

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                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
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This document is available to the public through the National Technical Informa-
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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

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                          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

-------
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

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                                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

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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

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                                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

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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

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                                            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

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                                             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

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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

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                           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

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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

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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

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     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

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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

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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

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          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

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       APPENDIX C
II.   EXTRACTION MODULES
     A.   Coal Mining
     B.   Oil Shale Mining
     C.   Oil Well
     D.   Gas Well
          C-4

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   APPENDIX C



II-A.   COAL MINING
       C-5

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                                         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

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                                         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

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                                    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

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                                     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

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                                         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

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                                         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

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                                            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

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                                         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

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                                         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

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                                         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

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                                        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

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                                         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

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                                         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

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                                        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

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              ..                          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

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                                          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

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                                          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

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                                          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

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                                          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

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                                           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

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                                          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

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                                          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

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                                          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

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                                  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

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                                           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

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                                   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

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                                      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

-------
                                     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

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                                      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

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          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

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                                      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

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                                      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

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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

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                                   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

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                              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

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                                       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

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                             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

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                                      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

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                                      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

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            APPENDIX C






III-C.   LOW BTU COAL GASIFICATION
               C-30

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                                       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

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                                      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
w
H-
t-n
H-
o
P3
rt
H-
o

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                                      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).
                             C-88

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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
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MD
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                                                                                                                                                            H-
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                                                                                                                                                            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.
                              C-100

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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.
                             C-103

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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

-------


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
C

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O
03
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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

-------
                               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

-------
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

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                              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

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                              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

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                              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.
                            C-121

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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.
                             C-122

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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
                             C-123

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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

                   C-124

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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).
                             C-125

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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.
                             C-126

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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
                        C-127

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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.
                              C-123

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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.
                              C-129

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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.
                             C-130

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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

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                              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

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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-
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                                                                                                                                                     (^
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                                                                                                                                                     Hi
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                                                                                                                                                     O
                                                                                                                                                     rt

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                              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

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                                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

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                                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

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                                      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

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                                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

-------
                              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

-------
                               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

-------
                      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

-------
                                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

-------
                              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

-------
                               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

-------
                               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

-------
                                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

-------
                     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

-------
                                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

-------
                                   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

-------
                                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

-------
                    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

-------
                     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

-------
                     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

-------
                                 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

-------
                   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

-------
                                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

-------
                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
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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

-------
                                        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

-------
                                    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

-------
                                 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

-------
                                 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
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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

-------
                                                     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

-------
                               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

-------
                             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

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                              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

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                               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
                                                                                                 H>
                                                                                                 P-

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                              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 '

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                             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%
                            C-269

-------
                                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.
                               C-270

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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
                              C-271

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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
                          C-273

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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,
                               C-274

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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).
                               C-275

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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
                              C-276

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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.

                               C-277

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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
                                 C-270

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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
                             C-279

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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
                              C-282

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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

-------
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-------
                              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).
                          C-293

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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,
                            C-294

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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.

                              C-295

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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.
                             C-296

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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.
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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.
                            C-298

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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.
                            C-299

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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%
                             C-300

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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.
                               C-301

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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
                              C-302

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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
I
                                                                                                                                        O
                                                                                                                                        O
                                                                                                                                        CO
                                                                                                                                        rt
                                                                                                                                        H-
                                                                                                                                        O

                                                                                                                                        O
                                                                                                                                        n>
                                                                                                                                        (D
                                                                                                                                        Hi
                                                                                                                                        H-

-------
                              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
                             C-304

-------
                                 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).
                               C-305

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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.
                               C-306

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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.
                             C-307

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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
                              C-308

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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
                             C-309

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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
                              C-310

-------
                          III-H.  Domestic Crude Refinery
                           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
                            C-311

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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,
                              C-312

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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

-------
                       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

-------
                       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

                        C-319

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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

                        C-320

-------
                        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

                         C-321

-------
                       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

                         C-322

-------
                       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
                        C-323

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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
                        C-324

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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
                             C-328

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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.
                              C-329

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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
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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

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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
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-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

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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).
                              C-342

-------
                         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),
                     C-343

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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.
                              C-344

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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.
                           C-345

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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.
                             C-346

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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.
                             C-347

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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.
                              C-348

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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.
                             C-349

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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
      C-351

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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.
                               C-352

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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;
                              C-353

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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.
                             C-354

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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.
                               C-357

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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;
                             C-358

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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.
                              C-359

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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)
                               C-365

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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.
                             C-366

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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
                             C-367

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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.
                              C-368

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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
                              C-369

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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)
                            C-371

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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.
                             C-374

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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

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                                    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

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                                  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

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                                 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

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                                   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

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                      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

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         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

-------
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

-------
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

-------
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

-------
     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

-------
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

-------
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
                         E-10

-------
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

-------
    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

-------
    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

-------
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

-------
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

-------
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

-------
    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

-------
    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

-------
    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

-------
         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

-------
    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

-------
    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

-------
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

-------
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

-------
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

-------
                     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

-------