230/3-76-004
ECONOMIC IMPACT OF EPA'S REGULATIONS
ON THE PETROLEUM REFINING INDUSTRY
Parts One and Two
Industry Description and Technical Analysis
APRIL 1976
FINAL REPORT
Contract No. 68-01-2830
Prepared by
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Planning and Evaluation
Washington, D. C. 10460
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EPA
230/3-76-004
ECONOMIC IMPACT OF EPA'S REGULATIONS
ON THE PETROLEUM REFINING INDUSTRY
Part One
APRIL 1976
FINAL REPORT
Contract No. 68-01-2830
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Planning and Evaluation
Washington, D. C. 20460
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TABLE OF CONTENTS
Page
Preface 1
Introduction & Summary 5
Chapter I - Demand 9
A. The Products 10
B. Market and Distribution 11
C. Government Influence on Market 17
Chapter II -Supply 19
A. Industry Operations 20
B. Financial Structure and Trends 48
C. Refinery Technology and
Technological Trends 52
D. Industry Utilization Rates 53
E. Competition 55
Appendix Growth in Refining Capacity 1968-1975 57
Exhibits
1 Petroleum Administration for Defense
(PAD) Districts 13
2 Domestic Demand for Petroleum Products 14
2a U.S. Sales of Distillate Fuel Oil,
By Uses 1969-1973 15
2b U.S. Sales of Residual Fuel Oil,
By Uses 1968-1973 16
3 Functional Characterization of
Petroleum Refinery Processes 22
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TABLE OF CONTENTS (Cont'd.)
Page
Exhibits (Cont'd.)
4 Schematic Flow Diagram of Petroleum
Refinery - Petroleum Product
Manu f ac tur ing 23
5 Refinery Environmental Control
Processes 25
6 Schematic Flow Diagram of Petroleum
Refinery - Pollutant Collection
and Treatment 29
7 Refineries - Distribution by Size
12/1/74 33
8 Refineries - Distribution by Size
1/1/68 34
9 Refineries - Distribution by Size
1/1/74 35
9A Number of Refineries By Size Classes
1968 - 1974 36
9B Refinery Capacity By Size Class
1968 - 1974 37
10 Refinery Shut-Downs 1/1/68 - 12/1/74 38
11 New or Reactivated Refinery Additions
United States, Puerto Rico, Guam
Hawaiian FTZ, Virgin Islands
1/1/68 - 12/1/74 39
11A Additions & Shut-Downs By Refinery
Size Class 1/1968 - 12/1974 40
11B Refinery Capacity By Size Class
1/1968 - 12/1974 41
12 New or Reactivated Refinery Additions
United States, Puerto Rico, Guam,
Hawaiian FTZ, Virgin Islands
1/1/68 - 12/1/74 43
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TABLE OF CONTENTS (Cont'd.)
Exhibits (Cont'd.)
Page
13 Employment, Earnings and Payrolls in
Pat.rolaum Refining, 1964 - 1973 47
14 Rate of Return on Net Worth for
Petroleum, Manufacturing, and
All Industry in the U.S.,
1964 - 1972 50
15 Growth of Refining Capacity and
Changes in Numbers of Refineries,
1968 - 1974 58
PART TWO FOLLOWS PART ONE IN THIS VOLUME
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1
PREFACE
GOVERNMENT INFLUENCE ON THE ECONOMIC
WELL-BEING OF THE PETROLEUM REFINING INDUSTRY
The economic well-being of this industry is greatly in-
fluenced by United States and foreign government policies unrelated
to environmental considerations. Both the legislative and the
executive branches of the government are considering policies and
legislation which will (or may) considerably affect this industry.
These policies have been in a state of flux for some years, but
recent legislation presents a better basis for forward planning
than has existed for many years. However, there is little pros-
pect that uncertainty resulting from the government's desire
to shape the development of the petroleum industry will soon
cease.
The impact of environmental rules may well be influenced
by the policies which govern the development of the industry in
the next several years. Consequently, a discussion of the probable
impact of government policies on the petroleum industry's economic
development, and of the relation of these policies to the ability
(or incentive) to absorb environmental costs by the industry is in
order.
Until fairly recently, the output of the refining industry
had grown at a steady rate, this would not have happened in the
absence of economic incentives necessary to attract capital to the
industry. As long as normal market incentives prevailed, the
viability of firms within/the industry was governed by their rel-
ative economic efficiency. Except for the oil import control and
small business set-aside programs, which substantially aided small
firms, there was little government influence on market incentives
prior to the abolition of the quota system and the rise of foreign
crude oil prices to, and above,, domestic levels in 1973.
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With the imposition of price controls, and mandatory
product and crude oil allocations, normal economic incentives
ceased functioning. For example, during the winter 1973/1974
a mandatory program to regulate refinery product mix was in
force which reduced gasoline and increased distillate as well
as residual oil out-turn. At the same time price controls
prevented normal economic incentives from allocating products.
Also, since the winter 1973/1974 there has simultaneously been
in force a crude oil allocation system which mandates a distri-
bution among refiners of the total supply of crude oil produced
in, or imported into the United States. Recently the system
has been further supplemented with a crude oil entitlement, or
cost equilization program, under which the comparatively lower
cost, price-controlled oil is allocated according to a (changing)
formula which reflects the allocator's notion of equity or
political realities, rather than the working of natural economic
forces. Under this program, the rights to purchase price-
controlled "old" oil are allocated to refiners on the basis of
refinery runs. Thus, a company's current cost of crude oil
acquisition is determined by government regulation, rather than
by its own current or past business decisions and acumen. This
form of government intervention affects both the absolute and
the relative prpfitability of firms in the industry. Moreover,
it very significantly alters the incentive structure away from
that which would prevail if free market forces were allowed to
operate.
The Congress is now considering legislation which
would significantly restrict petroleum companies' allowed areas
of operations. For example, proposals which would prohibit crude
oil producers from marketing oil products have been made. Under
other proposals marketing and manufacturing could not be conduct-
ed by the same firm, or pipelines would have to be divested, or
petroleum companies would be prohibited from mining coal or pro-
ducing energy in other "non-oil" forms.
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It is not within the scope of this project to discuss
the desirability of the non-market rules now in effect. However,
it is necessary to point out that their economic impact is very
large. For example, a refiner who, under the current crude oil
entitlement program, is granted a substantially larger quota
of lower priced "old" crude oil than he would be able to purchase
on the open market is given a great deal of assistance by govern-
ment. On the other hand, a refinery who, because of price con-
trols, cannot charge market clearing prices - even if the effect
of price controls is to hold average prices only a few percentage
points below equilibrium levels - may have his income reduced
substantially below the levels that would prevail in a free
market.
It is important to recognize the role of industry
growth, or the lack of it, on the petroleum industry's ability
to recover the capital costs imposed by environmental regula-
tions. If the industry as a whole is growing, and capital is
being invested in new or growth facilities, then it is reason-
able to expect that aggregate of product prices (and hence
refiner's margins) will be sufficiently high to attract capital
to the industry. In this case there will be returns earned at
least on that portion of environmental capital associated with
growth. Because the pricing of industry products from new or
existing facilities are indistinguishable, the prices will then
also be high enough to defray the costs of environmental capital
expenditures on existing facilities to the extent that they do
not exceed the per unit costs in new facilities.
However, if the industry is not growing and no capital
is required for the expansion of existing facilities or the con-
struction of new plants, recovery of the costs of environmental
capital presumably will not take place. In the no growth case,
industry prices will only be sufficient to cover the variable
costs of operating existing facilities. This will be the
normal result of competition between firms who do not need to
attract capital to expand their output.capabilities. Under
these conditions the bulk of the environmental expenditures to
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bring existing facilities into conformance with environmental
standards would have to be absorbed by the refining industry,
which would tend to magnify the economic difficulties of those
refiners who already are at a cost disadvantage due to size,
location or type of equipment.
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PART ONE
INDUSTRY DESCRIPTION
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5
INTRODUCTION AND SUMMARY
This is Part One of a three-part report which studies
the economic impacts of the costs of pollution abatement require-
ments imposed by the Federal Environmental Protection Agency on
the petroleum refining industry (SIC 2911). This study is
limited to assessing the economic impact of pollution abatement
costs which result from regulation of petroleum refinery opera-
tions; the costs resulting in other activities within the
petroleum industry, such as exploration and production, trans-
portation, and marketing, are not within the scope of this
study.
The impact of limitations on emissions into the
atmosphere and into water, and product quality regulations are
the primary concern, and the study analyzes the impact of
existing federal regulations and of state or local regulations
or Federal law (or rules) not based on environmental considera-
tions are excluded from the impact analysis and are considered
part of base costs.
The level of emission control used in the study is
that envisaged under current and currently-proposed regulations.
The base period for the analysis is 1973 operations and the
period 1974-1983 is covered in the study, with subdivisions
made. *
Costs that have been incurred through 1973 (Which by
now are sunk, and therefore cannot be minimized or retrieved)
are not detailed. The reason for focusing on the period 1974
through 1983 is that the purpose of the study is to aid the
Government in making decisions with respect to environmental
regulations in the months arid years ahead, and to enable people
generally to make informed judgments about the costs and economic
impacts ofi environmental regulations.
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The study is presented in three parts. Part One
consists of a description of the industry and its financial
profile. Part Two measures investment and operating costs
which are incurred by the refining industry in the specific
areas of refinery water effluent guidelines, atmospheric
emissions from refineries, and product quality regulations.
Finally, Part Three considers in detail the cost impacts of
environmental regulations and the effect on the prices of the
industry's products, industry growth, profitability, changes
in industry output, including changes in the number, size and
location of plants that may close or curtail production, or to
significantly increase production, with the associated changes
in employment in the industry, localized community impacts,
and impacts on imports and exports of the products of the
industry and its raw material supplies.
The choice of data and description of the refining
industry which are presented in this part of the study are
influenced by two considerations. First, to present information
valuable to persons who guide the making of public policy for
this industry. Secondly, to discuss those aspects of the
industry's relations with other industries which would be
useful in assessing the impact of pollution abatement costs
In the economy generally.
The petroleum refining industry in the United States
and its possessions consists of some 277 plants, owned by about
139 firms, and located in 40 of the 50 states, Guam, Puerto Rico,
and the Virgin Islands. The refineries have a replacement value
in excess of $30 billion. The refinery industry employs about
150,000 persons.
The bulk of refining is done by firms which also
market refined products or produce crude oil, or do both. In
most firms the refining portion of the business is not its major
activity.
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Refinery investment is less than 15 percent of total investment
in the domestic oil industry. Refinery employment is a somewhat
larger fraction of total employment. The industry has grown at
a fairly steady rate, but slower than real GNP.
The U.S. refining industry is in a period of profound
change. For over 15 years the industry was protected from lower-
cost foreign competition by an import quota system on products
as well as crude oil. But industry capacity grew at a slower
rate than did product demand. Price controls were imposed in
August, 1971. They are still in effect but, according to present
legislation, will be phased out in about 3-1/2 years.
World crude oil prices have been forced up to about
3 or 4 times their 1971-1972 levels by the cartel of producing
countries. They are now greater than the average of U.S. prices
which are price controlled. Despite these high prices, oil
product and crude oil imports have increased until 1974 because
domestic crude oil production has failed to keep pace with growth
in consumption. In 1975 crude oil imports decreased slightly,
probably as a result of the continuation of recession and high
costs which have inhibited demand for petroleum products.
Domestic production of crude oil also declined, but not due to
a decline in demand. The domestic industry's ability to produce
Is in a period of decline resulting, in part, from the investment
climate prevailing prior to the recent price increases.
Due to recent price increases of petroleum products
demand growth is now lower than had previously been expected.
Escalating costs and environmental problems may also have restrict-
ed new plants. Since Mobil's Joliet refinery went on-stream in
1972, no new major refinery has come on-stream, and the next one
will not be completed until 1976. Two grassroot refineries with
capacities below 50,000 barrels per day have come on-stream in
the interim. There have been a substantial number, of refinery
expansions and modernizations at existing plant sites, some of
them of large magnitude. It is frequently less costly to modernize
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8
and expand an existing plant than to construct a new one. This
is because technological improvements create the opportunity to
use existing facilities more economically or to expand large
segments of existing plants. Also some of the delays and costs
resulting from environmental rules, zoning limitations and the
like, can be avoided by expanding existing facilities. On the
other hand, many announced large grassroot refineries and a
number of announced expansions/modernizations have been cancelled.
Compared to the above discussed major changes in the
economic environment, within which the industry operates, pol-
lution abatement costs will be small, and therefore the impact
of pollution abatements on the refining industry in aggregate
will also be small.
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CHAPTER
DEMAND
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1°
The Products
The industry manufactures hundreds of distinguishably
different products. From the viewpoint of environmental
control costs, these may be grouped into four broad product
classes: gasoline, middle distillates (often referred to as
intermediates), residual, and other.
Gasoline accounts for about 45 percent of industry
output volume. It is currently priced at about 30 cents
per gallon^ in cargo lots on the Gulf Coast. Although
other materials can be used as gasoline substitutes,
(propane, methyl and ethyl alcohol, electric batteries)
their use is negligible for cost reasons. Economics and
government policy may at least temporarily decrease the
fraction of crude oil going to gasoline. This might happen
if the evolving import control program is more evenhanded
than the previous one with respect to residual oil or if
increases in the price of gasoline, due to new taxes or for
other reasons, inhibit sales of gasoline more than of other
products,
Intermediates include military and commercial jet
fuel, kerosene, space heating oil, also called No. 2 fuel
oil or furnace oil, and diesel fuel. These products are
currently also priced at about 30 cents per gallon and make
up about 33 percent of industry output. No substitutes
exist for the transportation fuel portion of the intermediates
market. Natural gas is more extensively in the space heating
market and may be more or less expensive than oil, depending
on user location and government price control policy. Some
heating oil is imported, which reduces the demand for dom-
estic product.
Piatt's Oilgram 12/6/74.
See the discussion of residual oil which follows.
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11
Residual is currently priced at from about 25 cents
to about 32 cents per gallon or even more, depending on
sulfur content and location. Residual amounts to about
8 percent of domestic petroleum production and 15.5 percent
of domestic demand for oils. The difference is accounted
for by imports. Through most of the 1960's residual was
priced sufficiently below crude oil as a result of govern-
ment import policies to prompt increased investment in
domestic refineries in order to reduce residual yields.
Currently, residual oil is treated as any other refined
product. Consequently, the incentive to reduce residual
yields exists only to the extent that this product competes
with energy forms not produced from crude oil. In large
volume installations, natural gas and coal compete directly
with residual oil.
Other products include asphalt, lubricants, liquefied
petroleum gas (mostly propane), naphthas and solvents,
coke, petrochemicals and petrochemical feedstocks. (Asphalt
and lubricating oils are important products for many small
refineries.) These products account for about 16 percent
of the domestic industry's output. They are priced from
25 cents to $1.00 or even more per gallon. Most lubricants
and liquefied petroleum gas (LPG) have no significant econom-
ical substitutes from outside the industry. On the other
hand, petroleum solvents face direct competition from the
chemical industry. Non-metallurgical petroleum coke is
exported in significant amounts. The market for this pro-
duct depends in large part on emission rules in customer
countries.
Market and Distribution
The U.S. petroleum market is divided into five geo-
graphic regions called "PAD Districts". (See Exhibit 1).
Product consumption is also classified by end use.
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Market data for 1969 through 1973 by product and
District are shown in Exhibits 2, 2a, and 2b.
Oil products are distributed from refineries to
terminals primarily by pipeline and tankers or barges.
From there, local deliveries are made by truck. Some
minor rail distribution is utilized. The impact of new
environmental standards on the distribution and marketing
of oil products does not fall within the scope of this
study. But the costs of meeting new standards in moving
the products from the refinery to the final consumer in
the associated storage facilities, including terminals
and service stations, may be important. Environmental
standards applicable to exploration and production of
crude oil and natural gas also impose costs on the industry.
The impacts of these costs also are not a part of this study.
From the viewpoint of dollar volume, gasoline accounts
for roughly 50 percent of the refining industry's value
of output. Intermediates account for 33 percent, and re-
sidual for only b percent.^ Well over one-half of total
refinery output is sold through distribution and marketing
facilities which refining companies own or in which they
have a financial interest. In general, sales of gasoline
and jet fuel are more highly integrated than are distillate
and residual oil. Most large companies operate their re-
fining, distribution and marketing functions in an integrated
manner. Assigning product prices at various points within
the operation is an internal matter to most companies. Never-
theless, product is often sold by refiners directly to cus-
tomers in arm's-length transactions, especially to Federal,
state or local government consumers. Thus, conclusions
adequate for this study can be drawn about the costs as-
sociated with EPA's environmental standards.
Because of residual imports, and different product integration
levels for distribution/marketing, the relative contribution o
the various products to domestic refiners' gross dollar revenu
is different than the relative contribution at tho consumer
level.
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Exhibit 1
13
PETROLEUM ADMINISTRATION FOR DEFENSE (PAD) DISTRICTS
rfci
r* to?
(lacl. Alaska
and Hawaii)
). (
\
1 ir. \
(who*.
^ont.
T4
M, DAN. \ MINN.
1 MC.
; wvo.
Jt.OAK.
i
"•->4 tow*
\ Wl».
> / »->¦.
V-—
N f
< >«N
COLO.
# *e*.
NANS.
MO.
4
OKLA.
AUK-
-I
TIX
LA.
L-
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14
Exhibit 2
DOMESTIC DEMAND FOR PETROLEUM PRODUCTS
Thousand Barrels Per Day
P.A.D. DISTRICT
Product
Year
I
II
III
IV
V
U.S.
1973
2,221
2,311
966
204
971
6,673
Automotive
1972
2,161
2,206
884
188
937
6,376
Gasoline
1971
2,041
2,080
825
199
869
6,014
1970
2,000
2,008
729
186
861
5,784
1969
1,904
1,930
705
170
817
5,526
1973
62
36
46
8
65
217
Jet Fuel
1972
64
45
40
7
86
242
Naphtha
1971
77
49
40
6
88
260
Type
1970
66
43
37
7
94
247
1969
80
46
59
8
104
297
1973
349
169
53
23
239
833
Jet Fuel
1972
332
167
50
19
235
803
Kerosene
1971
303
158
48
19
223
751
Type
1970
284
150
50
20
212
716
1969
265
145
50
19
215
694
1973
90
64
53
5
4
216
Kerosene
1972
119
67
38
6
4
234
(Ex Jet)
1971
130
77
32
5
5
249
1970
126
83
43
6
5
263
1969
144
83
39
6
3
275
1973
1,426
910
339
95
310
3,080
Distillate
1972
1,396
883
278
84
272
2,913
Fuel Oil
1971
1,326
783
206
82
264
2,661
1970
1,308
738
191
71
232
2,540
1969
1,272
715
176
72
231
2,466
1973
1,918
236
193
26
421
2,794
Residual
1972
1,876
219
87
26
321
2,529
Fuel Oil
1971
1,715
181
76
26
297
2,295
1970
1,643
190
87
25
257
2,202
1969
1,412
173
78
35
281
1,979
Source: Bureau of Mines, Mineral Industry Survey - Petroleum
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Exhibit 2a
U. S. SALES OF DISTILLATE FUEL OIL, BY USES 1969 - 1973
(Thousands of Barrels)
Electric
Oil
Diesel Engine
Utility
Company
Fuel (Excl.
Year
Vessels
Companv
Railroads
Fuel
Industrial
Railroads)
1973
26,645
76,110
1C2,930
14,965
67,166
273,385
1972
21,900
68.255
96,725
13,505
60,225
238,710
1971
20,959
35,329
86,251
14,086
49,558
213,906
1970
19,503
2h,770
8 : , <4-16
11,518
43,668
194,919
1969
18,877
12,158
86,429
13,867
42,456
188,253
Total Domestic Sales
Excluding
Fuel for
Oil
Miscel-
Company
Heating
Military
laneous
Use
All Uses
1973
535,820
19,710
5,475
1,109,235
1,124,200
1972
541,660
20,075
2,190
1,049,740
1,063,245
1971
523,648
17,427
10,154
957,232
971,320
1970
521,135
12,447
10,8 74
915,732
927,250
1969
511,768
13,958
12,534
886,433
900,300
Source: Bureau of Mines, Mineral Industry Surveys, "Sales of Fuel Oil and
Kerosine," Annual.
Ui
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Year
1973
1972
1971
1970
1969
1968
1973
1972
1971
1970
1969
1968
Exhibit 2b
U. S. SALES OF RESIDUAL FUEL OIL, BY USES, 1968 - 1973
(Thousands of Barrels)
Vessels
91,980
77,745
78,727
89,850
83,481
87,575
Electric
Utility
Company
509,540
434,350
371,820
312,420
247,634
184,956
Railroads
1,095
1,095
1,262
2,222
3,381
4,296
Oil
Company
Fuel
50,735
44,165
32,626
38,318
36,559
39,329
Industrial
150,380
141,985
135,647
139,647
133,754
135,664
Total Domestic Sales
Excluding
Heating
Military
Miscel-
laneous
Fuel for
Oil
Company
Use
All Uses
187,975
190,530
182,639
185,831
178,095
174,326
19,345
24,455
29,217
28,704
31,750
34,990
9,125
8,760
6,109
7,295
7,875
8,348
969,440
878,920
805,243
765.969
685.970
630,155
1,020,175
923,085
837,869
804,287
722,529
669,484
Bureau of Mines, Mineral Industry Surveys, "Sales of Fuel Oil and
Kerosine," Annual.
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Prior to the oil embargo, in the four years from 1969
to 1973, the volume of gasoline produced had increased at
an average annual rate of 5.1 percent. Intermediates con-
sumption had grown at 5.5 percent per year. Residual pro-
duction in domestic refineries had been stable, but consump-
tion had increased at about 8.6 percent per year. Since
19 73, due to the embargo, it is pointless to compare recent
data with historical growth rates.
Prior to the oil embargo of 1973/74, oil product prices
had increased at a slower rate than either consumer or whole-
sale price indices, largely because the industry had been
able to utilize improved technology to offset increases. In
the absence of price controls, important short-term price
changes do occur, mostly associated with changes in refinery
utilization and with seasonal factors. Also, since crude
oil accounts for over two-thirds of the cost of oil products
at the refinery gate, product prices change with the price
of crude. In recent years, product price changes have been
largely the result of crude oil cost increases.
C. Government Influence on Market
Foreign, Federal, state and local governments all in-
fluence the oil product market. In the recent past, the
Federal government's major influence has been through taxes,
price controls and tariffs (fees) on imports of crude oil
and products. Price controls hold prices down and discourage
investment. It is not clear now what type of program will be
in force for the next decade. From 1957 to April, 1973, im-
portation of crude oil was limited by a quota system, and
products imports, except for residual oil, were held at very
low levels. Foreign crude prices had, until 1973, been
lower than domestic, so import rights normally had had con-
siderable value. These rights were allocated among refining
firms according to their size. Although large firms had
bigger quotas than small ones, the latter were given a
larger allocation per unit of throughpi:'.. Currently,
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18
imports are not quantitatively limited and, indeed, are
somewhat encouraged by the combination of domestic price
controls and the way in which the entitlements to purchase
domestic crude oil are allocated.
All levels of government purchase large quantities and
a wide range of oil products. One of these purchases,
military grade jet fuel (JP-4), is important to some small
refiners. A gasoline boiling range material, JP-4 requires
little processing beyond separation from crude. In contrast,
automotive gasoline is produced in a complex processing
scheme.
Government also influences the market for petroleum
products through imposition of environmental standards.
This can take the form of direct specification of product
characteristics, e.g., sulfur content in residual oil. Or
it may take the form of imposing environmental standards
on petroleum product users which in turn affect the nature
of the product. For example, control of auto emissions
has resulted in a demand for unleaded gasoline. In both
cases probable costs for changes in product characteristics
exceed the cost of EPA environmental standards regulating
direct emissions from refining operations.
Government policy in pricing and regulation of natural
gas also affects refining costs. This is because natural
gas is a refinery fuel, a hydrogen plant feed stock, a
refinery product, and a substitute in use for other refinery
products.
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CHAPTER II
SUPPLY
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A. Industry Operations
1. The production process.
Although a typical oil refinery is technically complex,
the manufacturing process is conceptually simple.
Crude oil is the primary raw material used in re-
fining. Crude oils are liquid mixtures of many carbon-
containing chemical compounds. Crudes differ from one
another in the relative concentration of the various
compounds. In refining, crude oil is first separated
into several groups of varying molecular sizes known
as cuts. The chemical composition of some of these cuts
is then altered by changing the average moleaular size.
Some cuts are further processed to alter the shape or
structure of the molecules. Most of the original and
the altered cuts are "treated" to make innocuous or to
remove impurities, notably sulfur. Treated cuts are then
blended to produce finished products. To these may be
added various substances, known as additives, to impart
certain desirable properties. Exhibit 3 classifies various
refinery processes according to their principal function
in the refining of petroleum: separation, alteration of
molecules by size or shape, or treating. A schematic
flow diagram of a refinery is shown in Exhibit 4.
In refinery operation, certain polluting materials
may be released into the environment. The pollutants
are by-products of the various refinery processes.
The principal ones arise in operations as follows:
a. Hydrogen sulfide (l^S) is present in many crude
oils and is formed in hydroprocessing (catalytic
reforming, hydrotreating, and hydrocracking) and
-------
21
cracking (catalytic and thermal, including coking).
Only trivial amounts, which can be ignored, are
formed in other processes. Because is highly
poisonous, it is either recovered (and converted to
elemental sulfur) or burned. Burning forms sulfur
oxides, which are air pollutants.
Sulfur oxides are also formed in the combustion
of sulfur containing liquid refinery fuels. If
these fuels also contain nitrogen compounds, the
formation of NO is enhanced. This NO , as well as
X X
the small amount of SO^ formed from sulfur compounds
in the fuel, tend to be the principal cause of stack
plumes in refinery furnaces. Burning coal would, of
course, also add to the problem of particulates
emission. An additional source of SO emissions are
the incinerated tail gases from sulfur recovery units.
b. Hydrocarbon vapors can escape from refinery
tanks containing crude oil, gasoline, and volatile
intermediate products. Other sources of hydrocarbon
vapor emissions are tank truck and tank car loading,
volatiles unloading facilities, and oil separators
in the aqueous effluent treating system.
c. Carbon monoxide emission in refineries is confined
to the flue gases from catalytic cracker regenerators
and fluid coker coke heaters.
d. Particulate emission in a refinery is significant
only from catalytic crackers and fluid cokers unless
a refinery burns coal or coke as fuel.
e. Substances which create a biological oxygen demand
(BOD) in waste water are formed in catalytic and
-------
22
Exhibit 3
FUNCTIONAL CHARACTERIZATION
SF
PETROLEUM REFItTERY PROCESSES
HYDROCARBON REFINING PROCESSES
z
o
a-
Q
w
H
U
<
t—t
H
LO
t-<
pi
W
H
U
<
5|
O
<5
~J
u
w
o
s
-C
W -4
nj a;
w 12
CO
-------
GAS
CRUDE
Oil
| DESALT-
ING
NATURAL
GAS LIQuTdS
f
STRAIGHT RUN
fl50f>£*lZATI©A/'
— r T
CRUDE
OIL
DISTILLATION
GASOLINE
STRAIGHT
LIGHT
ENDS
PROCESSING
r
HYDROGEN
TREATING
CATALYTIC
REFORMING
RUN NAPHTHA
-LIGHT STRAIGHT RUN GAS OIL-
—HEAVY STRAIGHT RUN GAS OIL-
STRAIGHT * I
, RUN RESIDUE
• HYPROTREMINSi
-i
LUBRICATING
OIL
MANUFACTURE
I
•r
VACUUM
DISTILLATION
.1
VACUUM
DISTILLATE
*-}
X
CATALYTIC
CRACKING
T
CAT. CRACKED
naphtha-"""""
CAT. CRACKED
J H2S
MOVAlJ
BUTAK't
TREAT
(I)
ALKYL
ATION
[ALKYLATE
STRAIGHT ruh
6asoli;;e
TREAT
(1)
CATALYTIC
REFORMATS
CAT. CLACKED
TREAT
m
6AS0UKE
TREAT
12)
. J
| HYDRO-
. CRACKING
TREAT
(2)
LIGHT 6AS OS.
> GAS
> TO 6AS0LIHE BLfJiDIWO
"U""* T0 CATALYTIC REFORUIN0
I
TREAT
(2)
J-
RIHNMY
FUEL OAS
f'kOPANE (IPG)
PREMIUM
GASOLINE
REGULAR
GASOLINE
KEROSENE &
JET FUEL
-+ DIESEL FUEL
-CHEATING OIL
vacuum
BOTTOUS
CAT. CRACKED
HEAVY CAS OIL
PRODUCTS
COKING
OR
• THERMAL .
| CRACKING «-
"T"
> CAS
TO NAPHTHA HYtSOOEM TREATER
-> TO CATALYTIC OR HYDRO CRACKER
COKE OR RESIDUE. FUEL OIL
RESIDUAL
FUEL OIL
M
g*
H*
W
(-*•
rt
ro
to
TREATING PROCESSES
(1) AQUEOUS LIQUID
(2) AQ.LIQ.OR HYDROGEN
-» ASPHALT
LUBRICATING OILS
WAX
— OPTIONAL. PRODUCTS
r ¦
i
i !
j OPTIONAL PROCESSES
-------
24
thermal cracking and in sulfuric acid treatment of
petroleum products (notably naphthenic and Pennsylvania
lubricating oils). Also most of the solvents (phenol,
furfural, etc.) used in manufacturing solvent-refined
lubricating oils create BOD.
f. Entrained hydrocarbons and dissolved contaminants
such as ammonia, light mercaptans and salt (from crude
and cooling water treatment) are found in refinery
waste water streams. These contaminants may also cause
the pH of the water to be outride permissible limits.
Processes used to control the emission of these
pollutants are shown in Exhibit 5. The schematic flow
diagram in Exhibit 6 shows the collection and treatment
of pollutants produced in each process.
The foregoing classification can be summarized as
follows:
Refining Processes Installed Effluent Control Required
Large Thermal or Hydro- Air Water
Cat. Small Cat. Proces- Lube CO &
Cracker Cracker ses Mfg. Cat. BOD
X XXX
X XX
X X
X X
The imposition of environmental controls on the
quality of refinery products adds additional processing
complexity to refineries. For example, much more cata-
lytic reforming, as well as some other processes, will
be introduced to make unleaded gasoline. Intermediates
will require hydro-desulfurization. The manufacture of
low-sulfur residual will require installation of consider-
able equipment. At the moment, the low-sulfur residual
-------
Exhibit 5
REFINERY ENVIRONMENTAL CONTROL PROCESSES
25
Environmental Problem
Hydrogen sulfide is highly 1.
toxic. Reacts to form sul-
fur oxides if burned.
2.
Sulfur oxides. Emitted to the 1.
atmosphere with flue gases
from burning fuels containing
sulfur. Irritating to eyes
and respiratory system. Also,
SO^ causes opaque "plume."
Control Process(es)
Gases containing hydrogen sul-
fide (H2S) are treated with a
liquid (usually an amine solu-
tion) which preferentially ab-
sorbs H2S. The H2S is recovered
by stripping it from the liquid.
It is subsequently converted to
sulfur and recovered.
Sour water stripping. Aqueous
effluents from refinery processes
which contain are steam
stripped to remove the I^S.
(The recovered is gen-
erally converted to sulfur or
burned, if within permissible
emission limits.)
Hydrodesulfurization. The sul-
fur-containing oil is reacted
with hydrogen at elevated tem-
peratures and pressures in the
presence of a solid catalyst.
Sulfur in organic compounds is
converted to I^S. (Hydrogen
for the hydrodesulfurization
process is generally recovered
as a by-product of catalytic
reforming or manufactured by
converting either natural gas
or refinery by-product gases.)
-------
Exhibit 5 (Cont'd)
26
Environmental Problem
2.
Control Process(es)
Sulfur plant (Claus Plant) vent
gas containing unrecovered SC^
and H2S is incincerated with
extra fuel to SO2 where emission
rules permit. If not, tail gas
recovery processes are available
which either convert the sulfur
components to sulfur or to con-
centrated H2S for recycling to
the Claus Plant.
Carbon monoxide. Present in
stack gas from catalytic
cracking units. Poisonous
to animal life.
1.
Revising cat cracker regenerator
conditions to higher temperatures
(1350-1450 F) permits complete
combustion of CO to CO2. Alter~
nately, the stack gas is enriched
with fuel and burned totally to
CO2 in an external furnace which
may either be a steam generator
or process heater.
Smoke. Produced when in-
sufficient air is used in
firing boilers and furnaces
or by incomplete incineration
of process materials vented
and flared because of upsets.
1. Proper control of boilers and
furnaces.
2. Incinerate vented materials in
a "smokeless flare."
Hydrocarbon vapors. Evapo-
rated from tanks or small
leaks and spills. React
in atmosphere to cause smog,
Install floating roofs or vapor
recovery system on tanks.
Good housekeeping practices -
leaks, maintain pump seals, c]ean
up spills, etc.
-------
Exhibit 5 (Cont'd)
27
Environmental Problem
Oil (and water insoluble non- 1.
hydrocarbon liquid organic
compounds) entrained in re-
finery waste water. Harmful
to aquatic life and dirty. 2
Control Process(es)
API Separator. Oil is allowed
to rise to the surface of the
contaminated water and is
skimmed off.
Aeration. Air is blown through
the contaminated water. Oil
rises to the surface as froth
and is skimmed off.
Water-soluble organic com-
pounds. Dissolved in re-
finery waste water. Many
compounds toxic to aquatic
life. Also reduce oxygen
content of receiving water
body which leads to aquatic
life damage. May also
smell badly.
1. Biological treatment.
a) Trickle filter. Contamin-
ated water is trickled through
a pile of rocks on which live
colonies of bacteria. The
bacteria convert the contamin-
ants into harmless compounds
(mostly water and carbon dioxide).
b) Activated sludge treater.
Contaminated water is contacted
with a suspension of bacterial
colonies, nutrients and air. The
bacteria convert the contaminants
into harmless compounds. Clean
water is separated by settling
of bacterial sludge.
Phenolic compounds. Produced
in cracking processes and ex-
tracted from cracked products.
Toxic to aquatic life.
1. Sold to Chemical industry.
2. Incinerated.
3. Pumped into underground forma-
tion which is sealed to prevent
contaminating fresh water.
-------
Exhibit 5 (Cont'd)
28
Environmental Problems
4.
5.
6.
Fluid catalyst. Entrained in 1.
stack gas from catalytic crack-
ing units.
2.
Soot and fly ash. Entrained 1.
in stack gas from furnaces or
boilers fired with residual,
coal or coke.
Control Process(es)
Hydrotreat the cracked product
to eliminate the need to ex-
tract phenols.
Recovery by solvent extraction
or solution adsorption.
Oxidation in cooling towers oir
over a catalyst.
Centrifugal separation. The
stack gas is passed through a
stationary centrifugal device
(cyclone) at high speed. The
resultant force throws the
dust to the outside wall from
which it is collected.
Electrostatic precipitation.
The stack gas is passed between
metal plates which are elec-
trically charged to a high
voltage. The dust is attracted
to, and settles on, the plates
from which it is recovered.
Electrical precipitation.
-------
SCHEMATIC FLOW DIAGRAM 01- H-TROLEOM ftf-RNERY
B. POLLUTANT COLLECTION AMD TREATMENT
SOUR GAS
SOUR
WATER
STRIPPER
CRUDE
CcSAlT-
ING
DISTILLATION
LUBRICATING
OH
MANUFACTURE
*
VACUUM
DISTILLATION
WATER < <
f ct- \
I CLONE f
1 M
CATALYTIC
CRACKING
ucoe
WASTC WATER
SOU* WATER
SOU* GAS
WVC*OG£N SULFIDE {HjS)
SURFACE AND &
STORM DRAINAGE «
•
i
COOLING J
TOWER BLOWDOWNi WASTE
SULFUR
REMOVAL
SULFUR
PLANT
LIGHT
TREAT
ALKtL*
ATION
SOUR GAS
TREAT
(1)
! waste], J
"wvteY
CATALYTIC
REFORMING
HYDROGEN
TREATING
TREAT
TREAT
WATER
TREAT
(2)
HYDRO-
CRACKING
TREAT
(2)
WASTE
WATER
TREATMENT
COKING
WATER
M
S-
H*
U'
H-
rt
cr>
V CLEAN
WATER
ho
-------
30
picture is complicated by wide variations in crude oil
composition and varying sulfur content restrictions.
Residual desulfurization is expected to be expensive.
These matters are of compelling economic importance to
many refiners.
Type and location of raw materials.
Crude oil is the most important raw material used by the
refining industry. Natural gasoline, a liquid product of
the natural gas industry, furnishes about 5 percent of
refinery intakes. Butanes contribute about 1.5 percent
of refinery intake. There are no other significant raw
materials. About 73 percent of industry raw material is
of domestic origin; 27 percent is imported. The imports
originate in Canada, South America (largely Venezuela),
Africa, Indonesia, and the Middle East. Because Canada
has plans to eliminate exports to the U.S. and Venezuela
production appears to have topped out, an increasing
fraction of imports is likely to come from the Middle East.
The major crude-producing states are Texas, Louisiana,
California, Oklahoma, Wyoming and New Mexico, although 30
of the 50 states have some production. Texas and Louisiana
together account for about two-thirds of the domestic
industry's crude oil production. Large Alaskan deposits
will be exploited when a transportation system for them is
completed.
Because most refining is done by firms who also produce
crude oil, a large fraction (roughly 60%) of crude used fc>v
refiners is not purchased by refiners. But, in order to
U.S. Bureau of Mines, Mineral Industry Surveys - Crude
petroleum, August 1974.
-------
31
minimize transportation and other costs, there exists
a well developed crude oil exchange system. As a result,
crude oil produced by one company is most likely to be
processed by another. In addition to using own produced
(and exchanged) crude oil, refiners also purchase both
domestic and foreign crude oil on a spot and contract basis.
3. Number and location of firms and of plants.
There are about 139 firms in the oil refining industry.
They own some 277 refineries located in 40 states and 3
possessions. Refinery locations are concentrated along
the Mississippi-Louisiana-Texas Gulf Coast; near Los
Angeles, Bakersfield, and San Francisco; in the Pacific
northwest; near Chicago, St. Louis, and Detroit; near
Philadelphia, and in New Jersey; in Appalachia; and in
Oklahoma-Kansas. Refineries are also located in Guam,
the Hawaiian Foreign Trade Zone, Puerto Rico, and the
Virgin Islands.
4. Types of firms.
Firms in the oil refining industry can be classified
according to size, extent of integration with crude
oil production and marketing, and the number and size
of refineries owned. All refineries are necessarily
multi-product and all perform the entire process of
converting crude oil into salable products. Most large-
and medium-size firms, and some small ones, have diver-
sified into chemical manufacturing. Very few have
further diversified into other industries. The fraction
of total capital employed in non-oil or chemical activities
generally is small, but is rapidly growing and taking on
increased significance in a few firms.
-------
32
5. Types of plants.
Oil refineries are categorized by size and by the range of
their products. There is also considerable variation in
age of refineries. But classification by age of initial
operations is not useful because additions to and modifi-
cations of plants are the industry's principal form of
expansion.
Exhibit 7 shows the distribution of refineries by size
as of December 1, 1974. Refineries of over 100,000 barrels
per day capacity account for about 61 percent of U.S. refinery
capacity (a barrel is 42 U.S. gallons). About 17 percent, or
47 of the total of 277 plants, are in this size group. Very
few new refineries have been built in the last seven years and
few have been abanadoned. Of a total population of 273 seven
years ago, 4 have been merged into other plants, 36 appear to
have been shut down, 41 new and/or reactivated plants have been
added. As a result of the Federal Energy Administration's
mandatory allocation regulations, the data base has been ex-
panded to include 3 refineries in Guam, the Hawaiian Foreign
Trade Zone, and the Virgin Islands, as well as the 3 refineries
in Puerto Rico.
Exhibits 8 and 9 show the distribution by size of refineries
on January 1, 1968, and January 1, 1974. Exhibits 9A and 9B
compare the refineries in operation on these dates by size
classes and by total refining capacity. Exhibits 10 and 11
show the refinery shut-downs and new/or reactivated additions
in the past seven years. Exhibits 11A and 11B compare the
shut-downs and additions over the past seven years by refinery
size class and by total capacity. The recently-built
plants, which appear to be fairly complete refineries,
vary in size from 10,000 to over 150,000 barrels
-------
33
Exhibit 7
Refineries
Distribution By Size
12/1/74
Refineries Capacity
Refinery
Capacity
1000 B/CD
No.
Per-
cent
Of
Total
Cum.
Per-
cent
1000
B/CD
Per-
cent
Of
Total
Cum.
Per-
cent
Below 4.0
36
13.0
70.6
0.4
0.4
4 to 6.9
31
11.2
24.2
157.7
1.0
1.4
7 to 14.9
38
13.7
37.9
382.3
2.4
3.8
Median (26)
50
8.1
15 to 29.9
46
16.6
54.5
1015.6
6.4
10.2
30 to 49.9
38
13.7
68.2
1,598.0
10.1
20.3
50 to 69.9
19
6.9
75.1
1,121.5
7.1
27.4
70 to 99.9
22
7.9
83.0
1,863.0
] 1.8
39.2
100 to 199.9
32
11.6
94.6
4,525.0
28.6
67.8
200 and up
5.4
100.0
5,092.11)
32.2
100.0
TOTAL
277
100.0
15,825.8
100.0
Source: NPRA Compilation of Statistics reported by refiners to
FEA Office of Crude Oil, Refinery Yield, and Petro-
chemical Feedstocks for the Allocation Quarter Com-
mencing December 1, 1974. Refineries in Guam and
Virgin Islands included.
Note: Total includes - 271 refineries in U.S.
3 refineries in Puerto Rico
1 refinery in Hawaiian Foreign Trade Zone
1 refinery in Guam
1 refinery in Virgin Islands
277 Total
1J TEe FEA statistics for U.S. refinery capacity as of 12/1/74
indicate the Atlantic Richfield refinery at Houston to be 18"/,500
barrels per day while the BOM statistics for 1/1/74 and 1/1/75
indicate 213,000.
-------
34
Exhibit 8
Refineries
Distribution By Size
1/1/68
Refineries
Capacity
Refinery
Capaci ty
1000 B/CD
No.
Per-
cent
Of
Total
Cum.
Per-
cent
1000
B/CD
Per-
cent
Of
Total
Cum.
Per-
cent
Below 4.0
56
20. 5
113
1.0
4 to 6.9
30
11.0
31. 5
153
1.4
2.4
7 to 14.9
33
12.1
43. 6
337
3.0
5.4
Median (20)
50
8.1
15 to 29.9
45
16.5
60.1
953
8.4
13.8
30 to 49.9
40
14.6
74.7
1,551
13.7
27.5
50 to 69.9
19
7.0
81.7
1,121
9.9
37.4
70 to 99.9
19
7.0
88.7
1,583
13.9
51.3
100 to 199.9
23
8.4
97.1
3,210
28.3
79.6
200 and up
8
2.9
100.0
2,324
20.4
100.0
TOTAL
273
100.0
11,345
100.0
Source: Bureau of Mines Mineral Industry Surveys, "Petroleum
Refineries in the United States and Puerto Rico,"
August 16, 1968, with minor adjustments.
Note: Total includes - 271 refineries in U.S.
2 refineries in Puerto Rico
273 Total
-------
35
Exhibit 9
Refineries
Distribution By Size
1/1/74
Refineries
Refinery
Capacity
1000 B/CD
"No.
Per-
cent
Of
Total
Cum.
Per-
cent
1000
B/CD
Per-
cent
Of
Total
Cum.
Per-
cent
Below 4.0
37
14.0
73
0.5
4 to 6.9
31
11.7
25.7
152
1.0
1.5
7 to 14.9
33
12.5
38.2
345
2.3
3.8
Median (27)
8.1
15 to 29.9
44
16.6
54.8
994
6.6
10.4
30 to 49.9
31
11.7
66.5
1,260
8.4
18.8
50 to 69.9
18
6.8
73.3
1,036
6.9
25.7
70 to 99.9
25
9.4
82.7
2,086
13.9
39.6
100 to 199.9
30
11.3
94.0
4,074
27.1
66.7
200 and up
16
6.0
100.0
4,996
33.3
100.0
TOTAL
265
100.0
15,016
100.0
Source: Bureau of Mines Mineral Industry Surveys, "Petroleum
Refineries in the United States and Puerto Rico,"
July 22, 1974, with minor adjustments.
Note: Total includes -
259 refineries in U.S.
3 refineries in Puerto Rico
1 refinery in Hawaiian Foreign Trade Zone
1 refinery in Guam
1 refinery in Virgin Islands
265 Total
-------
4
50.
40
30
20
10,
0
-------
Exhibit 9B
5000
Refinery Capacity
By Size Class
1968 - 1974
4000
3000
2000
1000
Q 1/1/68
nro
12/1/74
fl
r->
L M 11 lAAljl
111^
15 - 29.9
50 - 69.9 70 - 99.9 100
>200
Refinery Capacity
Thousand Barrels Per Calendar Day
u>
-------
38
Refinery
Capacity
1000 B/CD
No.
Per-
cent
Of
Total
Below 4.0
15
41.7
Median (6.0)
4.0 to 6.9
4
11.1
7.0 to 14.9
6
16.7
15.0 to 29.9
1
2.7
30.0 to 49.9
6
16.7
50.0 to 69.9
4
11.1
TOTAL
36
100.0
Exhibit 10
Refinery Shut-Downs
1/1/68 to 12/1/74
Refineries Capacity
~ Per-
Cum. Cent Cum.
Per- 1000 Of Per-
Cent B/CD Total Cent
22.6 3.9
50.0 5.1
52.8 21.5 3.7 7.6
69.5 65.4 11.3 18.9
72.2 24.0 4.1 23.0
98.9 218.1 37.6 60.6
100.0 228.9 39.4 100.0
580.5 100.0
Source: Bureau of Mines Mineral Industry Surveys, January 1968
and FEA Allocation Statistics December 1, 1974. '
Note: All refineries located in United States
-------
39
Exhibit 11
New or Reactivated Refinery Additions
United States,
Puerto Rico,
Guam, Haw&iifeik FTZ,
Virgin
Islands
1/1/68
to 12/1/74
Refineries
Capacity
Refinery
Capacity
1000 B/CD
No.
Per-
cent
Of
Total
Cum.
Per-
cent
1000
B/CD
Per-
cent
Of
Total
Cum.
Per-
cent
Below 4.0
14
31.8
21.5
1.2
4 to
6.9
5
11.3
43.1
25.4
1.5
2.7
Median
(9.0)
50.0
4.1
7 to
14.9
9
20.4
63.5
89.6
5.2
7.9
15 to
29.9
5
11.4
74.9
102.5
5.9
13.8
30 to
49.9
4
9.1
84.0
141.6
8.1
21.9
50 to
69.9
1
2.3
86.3
54.8
3.1
25.0
70 to
99.9
3
6.8
93.1
269.0
15.4
40.4
100 to
199.9
2
4.6
97.7
340.1
19.5
59.9
200 and up
_1
2.3
100.0
700.0
40.1
100.0
TOTAL
44
100.0
1,744.5
100.0
Source: Bureau of Mines Mineral Industry Surveys, January 1968,
and FEA Allocation Statistics December 1, 1974.
Note: Total includes -
40 refineries in U.S.
1 refinery in Puerto Rico
1 refinery in Guam
1 refinery in Hawaiian Foreign Trade Zone
1 refinery in Virgin Islands
44 Total
-------
Exhibit 11A
Number of Refineries Additions & Shut-Downs
By Refinery Size Class
1/1968 - 12/1974
15
X
I
* 10
,i c
5 —
Additions 44
Shut-Downs
E
100
to
199.9
Refinery Capacity
thousand Barrels Per Calendar Day
>
O
-------
Exhibit 11B
Additions & Shut-Downs In Refinery Capacity
By Size Class
1/1968 - 12/1974
800
o
cx
• ,
o
o
s
600
Additions ~ 1744.5
400
Shut-Downs
200
to \0
st m
r-i CM
•O i~l
CM CM
CM CM
r -kxxi
1
4
4.0
to
6.9
580.5
\D 4
• •
o> m
oo \o
D
-------
42
per day of throughput. It appears that size is not
a characteristic which in itself accounts for turnover.
Certain firms have realigned the geographical pattern
of their refining operations and have offset shut-downs
of relatively large refineries with either new re-
fineries or extensive expansions of others.
The 41 new or reactivated refineries in the U.S.
and Puerto Rico (Exhibit 12) added in the last seven
years had a total capacity of 960,000 barrels per day
and the median size was 7500 barrels per day. However,
21 of them, with a capacity of about 165,000 barrels
per day, have been added since 1973, and some of them
undoubtedly are old refineries which were shut down,,
but have now been reactivated, following the establish-
ment of the FEA mandatory crude oil allocation program.
This program is designed not only to allocate the supply
of both domestic and imported foreign crude oil, but to
distribute as well the supply of lower-cost, price-
controlled domestic crude oil.
Multiple plant operations are commonplace in the
industry. As of December 1, 1974, the 19 largest firms,
each of which has a capacity of over 200,000 barrels
per day, operated 111 refineries. These 111 plants
accounted for 79 percent of the industry's capacity,
even though 16 of them had capacities of less than
26,000 barrels per day. Half of all industry re-
fineries (138 plants) are smaller than 26,000 barrels
per day. They account for only 8 percent of industry
capacity. (Exhibit 7).
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43
Exhibit 12
New or Reactivated Refinery Additions
United States, Puerto Rico, Guam, Hawaiian FTZ, Virgin Islands
1/1/68 to 12/1/74
Refineries
Capacity
Refinery
Capacity
1000 B/CD
No.
Per-
cent
Of
Total
Cum.
Per-
cent
1000
B/CD
Per-
cent
Of
Total
Cum.
Per-
cent
Below 4.0
14
34.2
21.5
2.2
4 to 6.9
5
12.2
46.4
25.4
2.7
4.9
Median (7.5)
6.5
7 to 14.9
9
22.0
68.4
89.6
9.3
14.2
15 to 29.9
4
9.7
78.1
73.0
7.6
21.8
30 to 49.9
4
9.7
87.8
141.6
14.8
36.6
50 to 69.9
0
-
70 to 99.9
3
7.3
95.1
269.0
28.0
64.6
100 to 199.9
2
4.9
100.0
340.1
35.4
100.0
200 and up
0
-
TOTAL
41
100.0
960.2
100.0
Source: Bureau of Mines Mineral Industry Surveys, January 1968,
and FEA Allocation Statistics December 1, 1974.
Note: Total includes - 40 refineries in U.S.
1 refinery in Puerto Rico
41 Total
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44
A large number of these smaller refineries are located
within isolated crude producing areas or near small market!
far from alternate product supply sources. However, these
refineries are generally near crude supplies, either from
the ground or near crude oil pipelines, and they serve
local, moderately-sized marketing areas.
Technological progress in the past 20 years has
induced construction of larger, lower-unit-cost process
units. Consequently, there has been a trend toward
larger plants. No new grassroot plants of over 200,000
barrels per day have been built. Rather, the industry's
net growth in capacity has been the result of plant
expansion within, and to, this very large-size class.
In the last several years, quite a few large new re-
finery projects were announced and subsequently cancelled.
One large new plant of about 200,000 barrels per day
capacity is now under construction, and two or three
smaller refineries have recently been built.
The trends in the industry most significant to this
study are that the number of refineries has remained
constant but their average size has increased. As
mentioned previously, a large number of the new and
reactivated small capacity plants are viable only as a
result of the Federal crude oil allocation program.
In general, very small refineries with intakes below
about 10,000 barrels per day have few processing units
and manufacture only a narrow range of products. Some
small refineries in Pennsylvania, southern Arkansas,
Oklahoma, and south Texas take advantage of local crude
quality to manufacture lubricants.
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45
Asphalt is also an important product for many
small refineries. It is costly to transport, especially
overland. A relatively large fraction of the industry's
asphalt output is produced in small refineries, and over
a third of the plants with capacities below 10,000 barrels
per day produce asphalt as a principal product.
As regards refinery differentiation by product slate,
many small refineries are designed to process crude oil
(often low-sulfur) into the naturally occurring portions of
gasoline, intermediates and residual, or asphalt which is
essentially a special grade of residual. Such a refinery
requires only a crude oil distillation unit, a catalytic
reformer with feed pretreater (if gasoline is manufactured),
two or three additional distillation columns and treating
units. Some small refiners in southern California, due to
the characteristics of local crude oil, manufacture military
jet fuel and residual with a crude oil unit only. On the
other hand, a large refinery, manufacturing a full range of
fuel products, plus lubricants, industrial solvents,
liquefied petroleum gas, and a few common chemicals, will
have a score or more of process units.
A common technology is used throughout the industry.
The differences that do exist are small and probably not
significant in terms of a plant's ability to meet environ-
mental standards economically. There are important differ-
ences in the extent to which environmental control equip-
ment has been installed to date. This will be discussed
in Part II of this study.
6. Employees
Data on employment and earnings are presented in Exhibit
13. About 60 percent of petroleum refining employees
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46
are production workers. Their hourly and weekly earn-
ings are considerably above the average for all manufact-
uring. Hourly earnings of production workers in 1973 in
petroleum refining were estimated at $5.54 versus $4.07
for all manufacturing.
Refinery employment as a whole has been fairly stable.
In 1964, there were 150,000 employees and in 1973, 147,000.
Perhaps one-third of refining industry employees have
skills which are not readily transferable to other in-
dustries. While it was beyond the scope of this study to
make a detailed analysis of the transferability of the
skills required by the industry, an examination of the
occupational titles indicates that two-thirds of the em-
ployees have skills which are not special to the industry
or they are unskilled.
Detailed occupational data for the petroleum refining
industry are available for the year 1971. In that year,
153,000 people were employed in the petroleum refining
industry, 90,000 of whom were production workers. These
figures include employment in central offices, research
laboratories, etc. of refining firms as well as in
refineries. Refinery employment itself was about 98,000,
including about 70,000 production workers. A Bureau of
Labor Statistics study''"' of a representative sample of
50,000 of the 70,000 showed that almost one-third of
refinery production workers were maintenance workers and
85 percent of these were skilled craftsmen, such as welder^
mechanics, machinists, electricians, etc. One-half of
production workers were skilled refinery operators, such
Industry Wage Survey, Petroleum Refining, April 1971,
Bulletin No. 1741, U.S. Department of Labor. Bureau of
Labor Statistics, p. 12.
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47
Exhibit 13
EMPLOYMENT, EARNINGS AND PAYROLLS
IN PETROLEUM REFINING, 1964-1973
Production and Related Workers"^
Total Average
Number of.
Employees^)
(Thousands)
Number of
Workers
(Thousands)
Average
Weekly
Earnings
Hours
Worked
Weekly
Average
Hourly
Earnings
1973
147
89
$231.02
41.7
$5.54
1972
151
89
219.45
41.8
5.25
1970
154
90
189.93
42.3
4.49
1968
151
92
166.27
42.2
3.94
1966
148
89
151.56
42.1
3.60
1964
150
90
139.52
41.4
3.37
T) Includes non-salaried workers.
2) Includes both salaried and non-salaried employees.
Source: Bureau of Labor Statistics, "Employment and Earnings."
Reprinted in Petroleum Industry Statistics 1964/73,
American Petroleum Institute, September 1974, p. 50.
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48
as stillmen, treaters, compounders, testers, etc. These
men's skills are probably transferable only to other
similar industries, such as chemical manufacturing or
food processing. The balance of the production workers
are either unskilled, or are helpers or have general
skills such as stock clerks or truck drivers.
Thus, it appears that about one-third of the people
in the industry (probably a smaller fraction in small
plants that purchase laboratory and some maintenance
services from outside contractors) are skilled workers
whose job opportunities at a comparable skill level are
dependent on reemployment in the "process" industries.
The other two-thirds are employable in other industries
at their present skill levels if job opportunities exist
for them.
Recent changes in refinery labor utilization include
a trend to increased use of "contract maintenance" and
the classification of operating labor as "staff" rather
than "hourly." These changes tend to reduce labor trans-
ferability to other industries but improve productivity lr,
refineries.
B. Financial Structure and Trends
It is impossible to analyze the financial structure of the
petroleum refining industry using published data. Too few
firms, and none that are typical of the industry, are ex-
clusively or even primarily in the refining business. To
discuss the financial characteristics of the industry,
price data will be used which reasonably reflect the
values of products made by typical refiners, and the
cost data considered appropriate for crude oil will be
estimated based on experience.
1. Costs - fixed and variable.
No data are published which break down refinery costs
in a manner useable for this study. An estimate has
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49
therefore, been made for a plant manufacturing fuel
products (no lubricants). The reader is cautioned
that no actual refinery will exactly match these
figures. Refining costs are characterized by a very
high ratio of raw material costs to total costs. Fix-
ed costs make up most of the balance. The illustrative
estimate of costs follows:
Costs - Fixed and Variable (1974 prices)
Percent of
Cost/Barrel of Total Costs
Item Refinery Intake Fixed Variable
Raw Materials (Average)
$
9.30
76%
Fuel and Utilities
.90
1%
6%
Labor
.35
3%
Chemicals, Catalysts,
Additives & Materials
.35
3%
Insurance and Taxes
.10
1%
Capital Recovery
1.20
10%
TOTAL
$
12.201)
15%
85%
2. Profits.
No data on refinery profitability are available. But
it is reasonable to assume that in the absence of
price controls or product allocations, refining opera-
tions are, on the margin, neither more nor less profit-
2)
able than the rest of a typical oil company's business.
The effect of price controls on refining profitability
cannot be ascertained. Exhibit 14 gives some relevant
financial data for the oil industry.
1) Equivalent to about 29 cents per gallon of salable product.
2) In the absence of this equality prudent oil company's managers
would re-allocate investments until the equality is re-
established.
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50
Exhibit 14
RATE OF RETURN ON NET
MANUFACTURING,
IN THE U.S.
WORTH FOR PETROLEUM
AND ALL INDUSTRY
, 1964-1972
J .
Year
Petroleum
Industry
All
Manufacturing
Industry
All
Industry
1972
10.8
12.1
10.5
1971
11.2
10.8
9.7
1970
11.0
10.1
9.0
1969
11.9
12.4
10. 3
1968
13.1
13.3
10.8
1967
12.8
12.6
10.6
1966
12.6
14.2
11.3
1965
11.9
13.9
11.1
1964
11.5
12.6
10.3
Source: First National City Bank, "Monthly Economic Letter,"
May, 1973.
12/74
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51
While profitability of the business as a whole has
been subject to some variability, industry earnings
have been Adequate to attract capital to finance
growth and replacement.
Cash flows.
Due to the uncertainties about future demands which
were discussed earlier in this report, it is impractical
to make a detailed estimate of the refining industry's
capital requirements for expansion and plant moderniza-
tion in the years to come. But a recapitulation of
industry plans (which are subject to change) is shown
in Part II of this study. In 1973, the thirty largest
petroleum companies invested about $1.3 billion in
refineries and chemical plants^ in the U.S. If normal
growth rates were to prevail, then capital expenditures
on these plants in the next 10 years would be about
$15 to $20 billion. But energy conservation measures,
as well as the recent increases in crude oil prices,
may depress capital requirements. But if government
provides incentives to decrease dependence on foreign
sources of products there may be an increase in capital
investments.
It is useful to put the estimates of capital re-
quirements for refineries in perspective with oil
company capital expenditures for all purposes. Data
on a group of 30 large oil companies show that roughly
17 percent (about $1.3 billion of $7.6 billion) of
domestic capital expenditures by this group represents
2)
investment in refineries and chemical plants in 1973. '
Total domestic investment in that year for the same
group of companies is about 52 percent of world-wide
investment.
The Chase Manhattan Bank, N.A., Financial Analysis of a
Group of Petroleum Companies, 1973, p. 29.
Ibid., p. 29.
Ibid., j). 18.
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52
C. Refinery Technology and Technological Trends.
Petroleum refining has been a high-technology industry
since World War I. The technology of the industry has
steadily improved. During the last 30 years a few major
breakthroughs, notably catalytic cracking, alkylation,
hydrocracking, catalytic reforming, hydrotreating, and
several new lubricating oil manufacturing processes, have
had profound effects. Similarly new chemical manufacturing
processes have broadened the range of refinery products sub-
stantially. But of almost equal importance in the long run
has been the improvement in existing processes. Technolo-
gical improvements are utilized industry-wide because
industry members traditionally license the use of signifi.
cant new technology to competitors. There are no import-
ant trade secrets in the refining industry.
A combination of product quality competition and
economies of building and operating larger plants has
served to push oil refining firms toward bigger and more
complex refineries. Product quality competition has been
achieved by the use of additives and of quality-improving
processes like catalytic reforming to increase gasoline
octane number, and by catalytic hydrogen treatment to re-
duce sulfur content of intermediates. This has led to
an increase in the amount and value of processing equip-
ment per unit of output. Relatively low residual prices,
which have encouraged investment to reduce residual yields
also raise the value of equipment per unit of output.
Recent changes in import policies allow domestic residual
oil to be priced competitively with other domestic products
Consequently, some recent refinery expansions, and the one
large new plant under construction, no longer emphasize the
minimization of residual yields.
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53
Thus, larger refineries and larger units within
existing refineries and increasing integration of the
many process steps into a network mark the industry's
development. Once the possibility exists to build and
operate larger plants, there will be a strong economic
incentive to do so. Large plants cost less to build per
unit of intake than smaller ones. Typically, it only
costs about 65 percent more to build a plant with 100
percent more capacity (the "two-thirds power rule").
This does not mean that an existing small plant is
necessarily unviable. Existing small plants can often
be effective competitors. But typically, new small
plants are only being built for local, special marketing
conditions. Reactivation of old refineries or modifica-
tions of existing facilities which have not previously
been called crude oil refineries are taking place so that
the owners of these plants may secure allocations to
purchase price-controlled crude oil from FEA.
Industry Utilization Rates.
It is important to differentiate between a refinery's
capacity to process crude oil and its capacity to manufac-
ture a particular product. Almost all refineries have the
flexibility to alter their product mix. They can to some
extent increase the output of gasoline at the expense of
intermediates, or they can produce more intermediates at
the expense of gasoline. Nearly all refineries could in-
crease residual manufacture above the design level. Publish-
ed data on capacity utilization cannot reflect the industry's
ability to alter yields or adjust crude slates. Hence, they
are not useful in estimating the industry's ability to in-
crease output of specific products.
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54
Requirements to manufacture products with specific
properties further influence capacity. For example, a
refinery chat can manufacture a given quantity of 94
octane leaded gasoline might be able to make only 70
percent of that quantity of lead-free 94 octane, with
the same equipment.
Producing low-sulfur residual also presents special
problems. In the U.S., residual has been essentially a
by-product of the refining process.^ Its sulfur content
was predominately dependent on the sulfur content of the
crude the refinery uses. It follows that most refineries
have no "capacity" to produce low-sulfur residual from a
high-sulfur crude stream. Some desulfurizing capacity is
now being installed.
Availability of fuel of acceptable quality for in-
ternal refinery use also affects refinery capacity. In
their internal operations refiners normally burn the
lowest-valued material available. They first use the
gases produced as a by-product of refining operations
because these gases generally have no market. The next
choice is purchased natural gas, if available, because
it is priced below liquid fuels (per BTU) in most parts
of the U.S., and the facilities needed to burn gas are
cheaper than those needed to burn liquids. A small amount
of coal is also used in Pennsylvania and West Virginia.
The remaining requirement, currently about 135,000 barrels
2 )
a day, ' is met largely with residual fuel. Residual and
coal frequently contain considerable sulfur.
Similarly, the availability of gas in some instances
affects capacity. Refineries with no facilities for burnir^o
^~In the rest of the world this product is an important refinerv
outturn and is called heavy fuel oil. y
^ Mineral Industry Surveys, oj>. cit., April, 1974.
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55
liquid or solid fuels would have to install new equipment
if gas were not available in sufficient quantity. This
would be expensive as well as requiring time to convert.
Competition.
Were it not for price controls, the domestic market for
wholesale oil products would be competitive in the econo-
mist's meaning of the term. That is, the price elasticity
of demand facing individual firms would be high. Despite
a strong and continuing industry effort to establish brand
differentiation for retail consumers, the wholesale market
operates on a commodity basis. Perhaps one-third of gas-
oline, ^ about 50 percent of intermediates, and almost all
residuals are sold as commodities. With such large volumes
sold by many refiners, an active brokerage business exists.
Non-brand marketers maintain aggressive purchasing staffs,
and oil companies compete vigorously on various "bid"
markets.
Prices on the various unbranded markets typically
are close to short-run marginal costs. This indicates
that the industry is highly competitive. The normal
competitive nature of the refining industry would affect
its ability to pass cost increases on to consumers in
the short run. But with price controls and allocations,
normal market forces do not necessarily determine prices,
product distribution or profitability.
Prior to 1972, foreign crude oil was less expensive
than domestic. Although the domestic price was protected
by an import quota, production failed to keep pace with
demand. In mid-1973, prices became equal, due to the
success of the oil cartel (Organization of Petroleum
Exporting Countries). Price controls have been in effect
So-called unbranded sales at retail by independent oil com-
panies, commercial sales direct to users and sales to govern-
ment aggregate to somewhat over 30 percent of total gasoline
sales.
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56
on domestic products most of the time since 1971. In
1972 the Executive branch of government announced a
program to encourage domestic production and refining
by imposition of a tariff system. This program's
legality has been challenged in court on grounds that
tariff protection can only be granted by the Congress.
Prior to the oil embargo, the industry was in tran-
sition from a quota system to a tariff system via a price
control system. As a result of domestic price control,
a significant disparity bet-ween -world and average domestic
prices now exists. And the combination of a two-price
(new and old crude oil) market, with a system of entitle-
ments to purchase "old", lower-priced, crude oil, makes
it impossible to generalize about current market conditions.
The price control system is slated to terminate in less
than four years. Consequently, projections made in this
study are made on the assumption that normal competitive
market forces will prevail by the end of the period under
study (about 1983).
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57
APPENDIX
GROWTH IN REFINING CAPACITY 1968-1975
On the basis of Bureau of Mines and Federal Energy
Administration statistics, the changes in refinery population
and capacity that have occurred in the almost seven-year
period from January 1, 1968, to December 1, 1974, have been
analyzed and summarized in Exhibit 15.
From a total refinery population of 273,"^ 36 refin-
eries operating in 1968 which had ceased operating by December 1,
1974,^ were identified. Of these, 27 apparently made fuel
products and the remaining 9 were primarily asphalt plants and
lube plants.
The viability of an asphalt refinery is greatly
dependent on the local asphalt market, and a reduced local
demand may be met more economically by shipment of product
into the area. In addition, some asphalt plants are shut
down during the winter months; hence, some of the reported
shut-downs may be seasonal in nature. All of the asphalt
plants which were reported closed, with one exception, were
very small.
Of the 27 fuel-producing refineries, 11 reported no
equipment except a crude distillation unit. Of the other
16, 11 refineries, owned by 6 different companies, were
closed as a result of realignment of the geographical pattern
of the refining operations of these firms, and were offset by
*¦' Mineral Industry Surveys-U.S. Department of the Interior-
Bureau of Mines, Petroleum Refineries in the United States/
Puerto Rico, January 1, 19b8, August lb, 19bB.
2)
As reflected from The National Petroleum Refiners Association's
Compilation of Statistics reported by refiners for the alloca-
tion quarter commencing December 1, 1974, from the FEA's Office
of Crude Oil, Refinery Yields and Petrochemical Feedstocks.
-------
EXHIBIT 15
Refineries Operating
1/1/68
-113-
10764.5
Expanded Capacity
1/68 - 12/74
3316.8
New & Reactivated
Refineries
960.2
U.S. &
Puerto Rico
Added Data Base
-1
784.3
22±
11345.0
Refineries Operating
1/1/68 & 12/1/74
2H.
14081.3
I
274
15041.5
2IL
15825.8
Growth of Refining Capacity and Changes
in Numbers of Refineries
1968 - 1974
Plants Closed
Since 1/1/68
All Refineries
Closed
Since 1/1/68
All Fuel
Refineries
Closed
Simple Fuel
Refineries
Closed
40
2 7
1 1
580.5
580.5
551.7
29.0
'
}
1
A
9
16
11
No Capacity
LQ&L..J
28
.8
522.7
471.0
Plants Merged
Into Other
Refineries
Asphalt &
Lube Plants
Closed
I
51 .7
Fuel Refineries
Closed by Six
Large Firms
Other Fuel
Refineries
Closed
KEY
Nr>. of Rpfinpripa
Combined Capacity
Thousand Barrels
Per Calendar Day
Guam, Hawaaian FTZ,
Virgin Islands
Refineries Operating
12/1/74
VI
00
-------
expansions of other plants owned by the same firm. These re-
fineries tended to be the larger of the group of closed plants,
and all but one exceeded the median U.S. refinery size of
26,000 barrels per day. Several were located in metropolitan
areas, and the closure of some of these could have been instigat-
ed by land and/or zoning limitations.
Deducting these 11 plants, there remained a group
of 5 fuel-producing refineries which were closed in the seven-
year period. The largest of them had a throughput of 14,000
barrels per day. Their total was 51,700 barrels throughput
per day. These 5 refineries account for about 0.3 percent of
industry capacity. The closing of 25 refineries, including
9 asphalt or lube plants in seven years, out of a population
of 273 refineries, is a small percentage. Consequently, it
is reasonable to conclude that small firms are, on the whole,
viable business enterprises.
Of the total refinery population of 273 on January 1,
1968, 233 were still in operation on December 1, 1974. Over
the seven-year interval, the capacity of these 233 refineries
had been increased some 33 percent, from 10,765,000 barrels
per day to 14,081,000 barrels per day.
In the U.S. and in Puerto Rico, a total of 41 new
and/or reactivated refineries with a total capacity of some
960,000 barrels per day was added over the seven years. The
median-size refinery added had a capacity of 7,500 barrels per
day* Twenty-one refineries with a total capacity of some
166,000 barrels per day were opened or reactivated within the
last two years, encouraged to some extent by the mandatory Crude
Oil Allocation Program.
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60
Also, as a result of the Federal Energy Administra-
tion's regulations, the data base has been broadened to
include refineries in the Hawaiian Foreign Trade Zone, Guam,
and the Virgin Islands. As of December 1, 1974, the total
refinery population of 277 refineries in the U.S. and its
territories has a capacity of 15,825,850 barrels per calendar
day; this is an increase of some 4.5 million barrels, or about
40 percent, over the seven years (about 5 percent per year)
under review.
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PART TWO
TECHNICAL ANALYSIS
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1
PART TWO
INTRODUCTION
Part Two consists entirely of work done by the
technical sub-contractor, for this project. Included are
engineering cost estimates for processes used to conform
to EPA's regulations and estimates of what fraction of the
industry already conforms to each of the several control re-
quirements. These estimates underlie the analysis in Part
Three where industry and competitive impacts are developed.
Two supplementary tables entitled Attachment 1 and Attach-
ment 2 are included at the end of this Part. They present
data that were developed after the sub-contractor's report
had been completed.
All the economic data presented in this study are
based on mid-1974 costs. The technical sub-contractor assumed
that petroleum raw material and product prices, where employed
represent marginal 1974 levels rather than average costs which
would have reflected the impact of petroleum shortages and
embargo pricing experience. Marginal 1974 product prices are
defined as those required to profitably produce refined products
from Light Arabian crude oil acquired at an average acquisition
cost of 12.75 dollars per barrel.
All capital investment data are based on U.S. Gulf
Coast construction costs. To convert investment costs to an
annual cost basis, the technical sub-contractor used a pre-tax
annualized capital charge of 25.82 percent of the total invest-
ment. For a "typical" project cash flow pattern over time and
for a "typical" corporate tax position, this level of capital
charge results in about 12 percent discounted cash flow rate
of return after tax.
Revenue bonds, the interest on which is not subject
to Federal income tax, are used to finance a portion of the in-
vestments required by petroleum refiners as a result of EPA's
-------
2
regulations. These bonds may be used to finance pollution
control, but not process, facilities. They are not likely
to be used for small projects nor to finance projects by firms
whose capital projects are subject to abnormal risks. The "tax
free" feature results from the financing method used: the bonds
are issued by local governmental units, typically municipalities,
with payment of interest and principal being made by the company
whose effluent is being treated. No government guarantee of
either interest or principal is involved.
Because the bonds' interest payments are tax exempt,
the interest expense paid by the petroleum refining company is
somewhat less than the rate it pays on other debts. But because
these bond issues typically are somewhat smaller than the usual
petroleum company issues ( 100 to 250 million dollars), there
may be a small bloc-size premium involved.
It is easy to overstate the cost savings resulting
from the use of these tax exempt bonds. They represent a debt
of the benefitted company. And they reduce that company's cost
of capital only to the extent that the cost of the debt portion
of total capital is reduced by the fraction of total debt rep-
resented by tax-free debt. For example: suppose that the firms*
debt is 1/3 of capital; that normal debt costs 9 percent before
tax (4-1/2 percent after corporate tax deductions); that "tax
exempt" bonds cost 6 percent before tax (3 percent after corporate
tax deduction); and that exempt bonds represent 1/4 of new debt.
In this case the corporate cost of capital after tax is reduced,
on average, by only 1/8 of one percent as a result of the use
of tax exempt bonds'^. This percentage is too small to affect
the estimates made in this report and falls well within the range
of error in the basic cost of capital estimates.
1) 1/3 x (4-1/2 percent - 3 percent) x 1/4 « 1/8 percent.
-------
3
In addition to basic engineering and cost estimates,
the sub-contractor's report contains other information, e.g.,
total industry costs, relative impacts on small refiners, etc.
In order to maintain its technical integrity, the report is
included in its entirety.
Part Three following consists of Sobotka & Company,
Inc.'s analysis and conclusions. That work rests on the cost
and conformance estimates of Part Two, but incorporates a broader
economic prespectlve and an understanding of some subtleties of
this impact analysis that have developed since the sub-contractor's
work was completed.
-------
AN ANALYSIS OF THE
ECONOMIC IMPACT OF EPA'S
REGULATIONS ON THE PETROLEUM REFINING INDUSTRY
COST OF POLLUTION ABATEMENT
TECHNICAL VOCUMENTATION
EPA CONTRACT NO. 68-01-2830
June 24, 1975
-------
PREFACE
The calculation of investment and cost impacts resulting from
environmental regulation of the petroleum refining industry has
been significantly affected by the major increase in petroleum
prices which occurred in 1973. Few, if any, environmental facili-
ties added prior to 1973 afforded a significant return on invested
capital. However, by mid-1974 petroleum prices had essentially
quadrupled. Conversion to floating-roof product tanks not only
reduced airborne emission for 1974, but recovered valuable hydro-
carbons and reduced the volume of $12.75 per barrel foreign crude
oil which must be purchased. Similarly, the addition of carbon
monoxide boilers to fluid catalytic cracking units not only re-
duced emissions of carbon monoxide, but reduced the need for con-
sumption of refinery fuel which may be costing over $2 per million
BTU's. Thus, by 1974 economic standards, many environmental ex-
penditures result in profit-making investments for the domestic
refining industry.
The dilemma for the investigator is whether to continue count-
ing all investments as environmentally inspired and employ the new-
found credits to offset annual costs or to exclude all profit-making
environmental projects completely from the tabulation. The former
approach results In a larger Investment total and a smaller annual
cost, while the latter method has the opposite effect. The most
accurate approach would probably be to evaluate each individual in-
vestment and exclude from the tabulation only those that meet the
industry's accepted return on investment criteria for risk invest-
ments, but such detail is clearly beyond the scope of this study.
For purposes of this portion of the study, the authors have
elected tp count any investments made in response to environmental
regulations and properly credit recovered products and fuel savings
at marginal price levels. This tends to emphasize the investment
demands placed upon industry in the next few years. We believe it
is the most valid approach at present since the rapid change in petro-
leum costs has been moderated to some extent by long-term, low-price
natural gas supply contracts and uncertain energy policies. However,
if the refining industry were free to make long-term investment de-
cisions based on the industry prices that have prevailed for the past
eighteen months, it is apparent that many atmospheric emission-control
projects would be attractive to pursue even in the absence of environ-
mental regulations.
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TABLE OF CONTENTS
Page No.
SECTION I. SUMMARY
A. OBJECTIVE 1-1
B. WASTEWATER CONTROLS 1-1
C. AIRBORNE EMISSION CONTROLS 1-1
D. PRODUCT QUALITY CONTROLS 1-2
E. OVERALL INDUSTRY EFFECTS 1-3
SECTION II. STUDY CRITERIA
A. SCOPE II-l
B. ANALYTICAL APPROACH II-l
C. ECONOMIC BASIS 11-2
D. BASIC INDUSTRY FACILITIES II-3
E. DEMAND FORECAST 11-4
F. REQUIREMENTS FOR FUTURE REFINING CAPACITY II-4
REFERENCES
SECTION III. COST IMPACT OF WASTEWATER REGULATIONS
A. BACKGROUND AND SCOPE III-l
B. CONCLUSIONS III-2
C. GUIDELINE BASIS III-3
D. INDUSTRY CHARACTERIZATION III-4
E. ESTIMATING BASIS 111-5
F. INVESTMENT ESTIMATES III-ll
G. ANNUALIZED COSTS . . III-17
REFERENCES
SYMBOLS & ABBREVIATIONS
TABLES
III-l WATER EFFLUENT LIMITATIONS, PETROLEUM REFINING
(POINT SOURCE) CATEGORY
111-2 LIMITATIONS ON ADDITIONAL DISCHARGE ALLOWED
II1-3 SUBCATEGORIZATION OF THE PETROLEUM REFINING INDUSTRY
II1-4 SIZE AND PROCESS FACTORS
II1-5 APPROXIMATE CAPACITIES OF EFFLUENT AND WATER-QUALITY
LIMITED REFINERIES
111-6 RECALCULATED INVESTMENTS FOR MISCELLANEOUS FLOW
REDUCTIONS - SAMPLE OF CLASS B REFINERIES
1
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TABLE OF CONTENTS (CONTINUED)
Page No.
TABLES (CONTINUED) - SECTION III
111-7 INVESTMENT SUMMARY - 121 LARGE REFINERIES ON
CURRENT STUDY BASIS
II1-8 SAMPLE INVESTMENTS - SMALL REFINERIES
111-9 TOTAL INVESTMENT - ALL SMALL REFINERIES
III-IO INVESTMENTS FOR NEW CAPACITY
III-ll DIRECT OPERATING COSTS FOR 121 LARGE REFINERIES
SECTION IV. CONTROL OF AIRBORNE EMISSIONS
A. BACKGROUND AND SCOPE
B. SUMMARY
C. REGULATIONS ....
D. CONTROL TECHNOLOGY
E. INDUSTRY CHARACTERIZATION
F. INVESTMENTS
G. ANNUAL COSTS
IV-1
IV-2
IV-3
IV-6
IV-7
IV-13
IV-13
REFERENCES
TABLES
IV-1
IV-2
IV-3A
IV-38
IV-3C
IV-4
IV-5
IV-6
IV-7
IV-8
IV-9
IV-10
IV-11
IV-12
ADDITIONAL INVESTMENT FOR AIRBORNE EMISSION
CONTROL MEASURES
ANNUAL COSTS FOR AIRBORNE EMISSION-CONTROL
MEASURES
STATE POLLUTION REGULATIONS FOR HYDROCARBONS
STATE POLLUTION REGULATIONS FOR CATALYTIC CRACK-
ING UNITS
STATE POLLUTION REGULATIONS FOR SULFUR OXIDES
FORECAST OF ADDITIONAL CAPACITY INSTALLATIONS
AND PRODUCTS PRODUCTION
CAPACITIES TO BE CONTROLLED (ABOVE BASELINE
VOLUMES)
REFINERY AND SULFUR PLANT CAPACITIES
UNIT COSTS FOR BUILDING OR CONVERTING TO
FLOATING-ROOF TANKS
TYPICAL COST OF API SEPARATOR MODIFICATIONS
TYPICAL COST OF VAPOR RECOVERY AT LOADING RACKS
UNIT COSTS FOR BUILDING A CO BOILER
TYPICAL COST FOR ADDITION OF A CO BOILER TO
EXISTING CATALYTIC CRACKING UNITS
UNIT COSTS FOR CATALYTIC CRACKING UNIT
PRECIPITATORS
ii
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TABLE OF CONTENTS (CONTINUED)
Page No.
TABLES (CONTINUED) - SECTION IV
IV-13 TYPICAL COST FOR ADDITION OF A PRECIPITATOR
TO EXISTING CATALYTIC CRACKING UNITS
IV-14 TYPICAL COST OF AMINE PLANT ADDITIONS
IV-15 TYPICAL COST OF CLAUS PLANT ADDITIONS
IV-16 TYPICAL COST OF CLAUS PLANT TAILGAS
CLEANUP UNITS
IV-17 BASIS FOR ESTIMATING TANK LOSSES
IV-18 TYPICAL COST OF TANKAGE MODIFICATIONS
SECTION V. REFINED PRODUCT QUALITY REGULATIONS
A. SCOPE
B. CONCLUSIONS
C. PRIOR LEAD ADDITIVE STUDIES
D. CURRENT REGULATORY OUTLOOK
E. ANALYTICAL TECHNIQUES
F. DETERMINATION OF 1973 INDUSTRY FACILITIES
G. COST OF LEAD ADDITIVE REGULATION PROGRAMS
H. RESIDUAL FUEL SULFUR REGULATIONS ....
I. HISTORIC RESIDUAL FUEL OIL MARKET ....
J. FUTURE FUEL OIL MARKETS
K. FUEL OIL DESULFURIZATION TECHNOLOGY . . .
L. ESTIMATED COST OF FUEL SULFUR REGULATIONS
REFERENCES
TABLES
V-l CUMULATIVE CAPITAL REQUIREMENTS TO IMPLEMENT
UNLEADED GASOLINE AND LEAD PHASEDOWN PRO-
GRAMS ABOVE 1973 REFERENCE LEVEL
V-2 ADDED REFINING COSTS IMPOSED BY UNLEADED GAS-
OLINE AND LEAD PHASEDOWN PROGRAMS
V-3 CUMULATIVE CAPITAL REQUIREMENTS Tn IMPLEMENT
UNLEADED GASOLINE PROGRAM ABOVE 1973
REFERENCE LEVEL
V-4 ADDED REFINING COSTS IMPOSED BY UNLEADED GAS-
OLINE PROGRAM
V-5 1973 RESIDUAL FUEL CONSUMPTION BY SULFUR LEVEL
V-6 ESTIMATED RESIDUAL FUEL DEMAND THROUGH 1985 BY PAD
V-7 PHYSICAL PROPERTIES OF LIGHT ARABIAN CRUDE AND ITS
TBP CUTS
V-l
V-2
V-3
V-4
V-7
V-7
V-9
V-9
V-10
V-ll
V-l 3
111
-------
TABLE OF CONTENTS (CONTINUED)
Page No.
TABLES (CONTINUED) - SECTION V
V-8 DESULFURIZATION INVESTMENT ESTIMATES
V-9 ANNUAL DESULFURIZATION COSTS
APPENDIX
TABLES
A-l U.S. REFINING CAPACITIES AND WASTEWATER
CHARACTERIZATION (AS OF 1/1/74)
A-2 DOMESTIC PETROLEUM DEMAND FORECAST
A-3 DOMESTIC PETROLEUM REFINING CAPACITY RE-
QUIREMENTS
A-4 SCHEDULED REFINERY EXPANSION PROJECTS
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1-1
SECTION I. SUMMARY
A. Objective
This analysis has been designed to measure the costs imposed
on the petroleum refining industry by Federal Environmental Protec-
tion Agency regulations affecting refinery effluent, refinery emis-
sions to the atmosphere, and product quality restrictions. All in-
vestment and operating cost data are presented on a 1974 economic
basis and represent only additions forecast for the period 1974-1983.
B. Wastewater Controls
Wastewater requirements have been defined by Best Practicable
Control Technology Currently Available (BPCTCA) to be implemented
by July 1, 1977, Best Available Technology Economically Achievable
(BATEA) to be implemented by July 1 , 1983, ar.d Best Available Demon-
strated Technology (BADT) regulations which apply to new facilities.
Consideration of zero pollutant discharge which has been proposed
for 1985 is specifically excluded from this analysis. Major find-
ings indicate:
• EPA regulations will impose investment requirements of
$1.9 billion by 1977, resulting in annualized industry
costs of $744 million in that year. About 60% of the
annualized costs represent fixed charges, while 40% re-
sult from direct operating expenses.
• By 1983 water effluent control investments are expected
to total $2.9 billion, imposing a cumulative cost of
$1.15 billion on the industry annually. About 75% of
the total investment will be expended to improve exist-
ing refining facilities, while the balance will be asso-
ciated with new refining capacity.
• The expected investment for refiners with capacity of less
than 10,000 barrels per day is $312 per daily barrel of
capacity - more than twice the level forecast for large
refiners.
t 1983 annual costs expressed on a unit basis are 30 cents
per barrel for refiners processing 10,000 B/D or less
and an average of 16 cents per barrel for plants with
capacities in excess of 10,000 B/D.
C. Airborne Emission Controls
Refining industry controls of hydrocarbons, carbon monoxide, par-
ticulates and sulfur oxides have been examined in this analysis. Reg-
-------
1-2
ulatory bases considered include not only Federal new-source perform-
ance standards, but also the estimated impact of State Implementation
Plans designed to satisfy ambient air quality standards. Maior find
1ngs are:
• Industry investments for control of airborne emissions
will total $740 million by 1977 and almost $1.3 billion
by the end of 1983. Hydrocarbon control accounts for
13% of the total, carbon monoxide and particulates repre-
sent 34%, and sulfur oxide recovery facilities represent
the largest portion at 53%. About 65% of total investment
will be associated with existing refining facilities,
while the balance represents additional investment in new
refining capacity.
• Annual capital charges total $161 million in 1977 and
$280 million by 1983. However, a large part of these
costs is offset by credits resulting from improved prod-
uct recovery and thermal efficiency which amount to $117
million in 1977 and $206 million in 1983. The resulting
net annual costs attributed to airborne emission control
total $44 million in 1977, rising to $74 million in 1983.
• Investment requirements as a function of refinery size
vary from $318 per barrel for refineries with 10,000 bar-
rels per day of capacity to $101 per barrel for refineries
with 200,000 barrels per day of capacity.
• Impact per barrel of product in 1983 will vary from a
cost of 16.5 cents for refineries of 10,000 barrels
capacity to a savings of 3.1 cents for 200,000-barrel
refineries.
D. Product Quality Controls
Two areas of product quality restrictions were investigated for
industry impact - use of lead additives 1n gasoline and residual fuel
sulfur levels. Since lead phasedown regulations are currently under
litigation, a separate analysis of that restriction was also com-
pleted. The limitations of available studies provide lead additive
analysis data only for the years 1974, 1977, 1980 and 1985, and do
not differentiate between investment requirements for existing faciH
ties and those associated with new refineries. These data have been
Interpolated to provide 1983 data for consistency with other portion,
of the report to yield the following conclusions:
• Industry investment to provide unleaded gasoline and meet
a lead phasedown regulation 1s estimated at $1.2 billion
by 1977, rising to about $2.7 billion by 1983. If only
unleaded gasoline regulations are considered, the 1977
investment Is expected to total about $400 million, risino
to about $2.2 billion 1n 1983. 9
-------
1-3
• Annual industry costs resulting from both unleaded gas-
oline and lead phasedown programs will approximate $330
million by 1977 and $580 million by 1983. Elimination
of lead phasedown will reduce annual costs of lead regu-
lations by about $270 million in 1977 and about $170 mil-
lion in 1983.
• Residual fuel desulfurization investments are forecast
at about $590 million by 1977, rising to $1,100 million
by 1983. The reader is cautioned to note that this may
overstate near-term investment since some 1977 low-
sulfur fuel demand may be satisfied by increased pro-
cessing of premium-priced, low-sulfur crudes or distil-
late blending. However, we believe this approach leads
to a correct assessment of long-term industry effects.
t Fuel desulfurization costs are expected to require a
premium of about $1.77 per barrel for 0.7 weight per-
cent sulfur fuel and $2.08 per barrel for 0.3 weight
percent sulfur fuel compared to high-sulfur product.
E. Overall Industry Effects
The estimated impact of combined EPA pollution abatement programs
on the petroleum refining industry is shown below:
Added Invest- Added Annual
ment, $MM Costs, $MM
1977 1983 1977 1983
Wastewater Controls
1,880 2,870 750 1,150
Airborne Emission
Controls
740 1,280
44
74
Product Quality Restric-
tions (Includes Lead
Phasedown)
1,790 3,800 620 1,110
Total
4,410 7,950 1,414 2,334
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11-1
SECTION II. STUDY CRITERIA
A. Scope
The primary aim of this study is to measure the investment and
operating costs which will be incurred by the petroleum refining
industry as a result of the pollution abatement requirements estab-
lished by the Feder«l Environmental Protection Agency. Specific
areas of regulations which have been investigated include the fol-
1owi ng:
• Refinery wastewater effluent guidelines.
• Atmospheric emissions from refineries.
• Product quality regulations.
The base period against which all investment and operating cost
tabulations are measured is calendar year 1973. Costs which have
been incurred in 1973 and prior years have not been detailed in the
investigation. This is not to suggest that pollution abatement ef-
forts to date have not been formidable. Rather, those costs are
a matter of history and cannot be changed by future revisions in
environmental regulations. This study focuses on the 1974 through
1983 time period and will be employed to aid the Government in mak-
ing decisions with respect to future environmental regulations.
B. Analytical Approach
The three major areas of pollution abatement regulations were
investigated independently in this analysis. In each instance, the
analytical approach conformed to the following guidelines:
1. Definition of the regulatory bases.
2. Identification of the required control technology.
3. Determination of 1973 industry capability.
4. Development of investment requirements to meet future
regulatory deadlines.
5. Calculation of annualized costs of operating control
equipment.
6. Allocation of investments and operating costs to
various sectors of the refining industry.
The primary approach was to review published studies of pollu-
tion control techniques, investment levels and operating costs which
-------
11—2
have been completed in the past few years under industrial or gov-
ernment sponsorship. The bases employed in the earlier studies
were then updated to account for changes in regulatory requirements
facilities in place by 1973, changes in control technology, and new'
economic conditions. While no original research was conducted by
the authors of this study, considerable effort was expended to in-
sure the indicated results represent a realistic view of the costs
imposed upon the petroleum refining industry. The authors visited
with several representative small or independent refineries to dis-
cuss regulatory impacts, current operating and control procedures
and anticipated future pollution abatement investments. In addition
information available from previously completed proprietary studies '
was incorporated into analysis of control technology investments and
operating costs for the entire petroleum refining industry.
The approach employed in this study should lead to a reasonably
accurate assessment of the total investment and operating cost impact
incurred by the petroleum refining industry, in addition, we believe
that the allocation of costs to individual industry sectors offers
reasonable indication of costs to be borne by the various categories
of petroleum refineries. However, we should note that the techniques
employed in this study, while valid for industry characterization,
cannot be expected to indicate the specific investment or operating
cost impact for any individual refinery. Only detailed engineering
and economic studies which are specific to an individual refinery can
be expected to describe the exact investment and operating cost impact
Economic Basis
All economic data presented in this study are based on mid-1974
costs. Petroleum raw material and petroleum product prices, where em~
ployed, represent marginal 1974 cost levels rather than average costs
which would have reflected the impact of petroleum shortages and em-
bargo pricing experience. Marginal 1974 product prices are defined"
as the estimated refinery prices which are required to allow profit-
able processing of Light Arabian crude acquired at FEA's reported
average 1974 foreign crude acquisition cost of $12.75 per barrel into
refined products. All capital investment data a>-e based on U.S. qU|2
Coast construction costs. ' * '
In each instance, capital charges have been estimated as follows'
t 12% discounted cash flow rate of return after 50% Federal
Income Tax.
• Straight-line depreciation taken over 16-year life.
• 4% allowance for insurance and ad valorem taxes.
This results in an annualized capital charge of 25.82% of the total
capital investment. Some consideration was given to lower return on
investment as representative of future refinery investment criteria
-------
11 - 3
Since the pollution abatement investments will be imposed uniformly
across the industry, an investment of this type would normally be
considered a low-risk opportunity. However, we feel it is unrealis-
tic to expect the industry to raise significant amounts of new in-
vestment capital if the rate of return on investment even for secure
facilities is any lower than 12% DCF.
D. Basic Industry Facilities
A major effort of this study has been to properly describe the
impacts of pollution abatement regulations on different sectors of
the petroleum refining industry. The primary features of the petro-
leum industry which have been employed to divide the industry into
sectors are:
• Primary refined products.
• Refinery capacity.
• Raw material supply.
§ Major market area.
Technical data used to define the petroleum industry facilities avail-
able for operation in the 1973 base period were adapted from the Oil
& Gas Journal. These data are presented in detail on Table A-l in
the Appendix. Since the specific pollution abatement regulations
have varying impacts on refiners as a functio . of product output,
capacity or raw material source, the specific 1973 capabilities will
be defined in each subsection of the report. However, in general,
the following industry sectors have been selected for analysis:
Crude
Processing
No. of Capacity
Category Refiners (B/SD) _
Non-Gasoline Refiners (Primary
Products Are Jet Fuel, Asphalt
and Lubes)
Gasoline Refiners Under 20,000 B/D
Gasoline Refiners'from 20,000 to
70,000 B/D Excluding California
Gasoline Refiners Between 70,000
and 150,000 B/D Excluding Calif.
Gasoline Refiners Over 150,000 B/D
Excluding California
California Gasoline Refiners Over
20,000 B/D
68 700,000
42 396,000
64 2,657,000
34 3,496,000
25 6,926,000
18 1,690,000
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II-4
Demand Forecast
After extensive review of five major energy studies completed
in the past four yearsO ,2,3,4,5), we have concluded that the 1974
National Petroleum Council (NPC) study entitled "Emergency Prepared-
ness: Interruption of Petroleum Imports into the United States"
is the most valid for use at this point in time. A major strength
of the NPC study is its analysis of the embargo experience and the
presentation of a long-range demand forecast predicated on post-
embargo government policies and industry pricing experience. A
domestic petroleum demand forecast which has been developed based
upon this study is presented in Table A-2 of the Appendix. Forecast
1985 domestic petroleum demand is set at 21.8 million barrels per
day, reflecting a growth rate of 2.4% annually for the period 1974-
1985. While this does not require federally imposed conservation
programs or demand management, the outlook does assume that no new
power plants are constructed which consume either petroleum or
natural gas in the future. Thus, new petroleum demand is primarily
oriented toward gasoline and distillate products. When considera-
tion is given to product imports and products supplied by natural
gas plants, the projected crude run in domestic refineries in 1985
is estimated at 17.2 million barrels per day, as outlined on Table
A-3 in the Appendix.
Requirements for Future Refining Capacity
The announced and reasonably secure refinery capacity projects
scheduled for completion by 1979 are presented in Appendix Table A-4.
The major expansion projects scheduled for completion through 1976
are all well under way and not likely to be deferred or cancelled.
The few large 1977 and 1978 projects could still be deferred, but
would not significantly affect total refining capacity available to
the industry in 1985. An analysis of scheduled capacity additions
shows the following pattern:
% of 1975-1978
Capacity Additions
Grassroots Refineries 17.0
Reactivation of Idle Plants 0.2
Major Expansions (Over 50%
Increase) 39.3
Minor Expansions 43.5
We anticipate that this trend toward expansion at existing sites will
continue due to industry economic considerations, as well as the en-
vironmental restrictions and general community resistance toward new
refining centers.
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11-5
A comparison of refinery capacity requirements with projected
industry capacity yields the following estimate of new capacity addi-
tions by 1985:
Million Barrels Per Calendar Day
1974
1978
1980
1985
Refi nery
Capaclty
Requlrements
13.6
16.4
17.2
19.1
Refining Industry Requlred
Capacity, Capacity
January 1 Additions
14.25
17.1
17.8*
17.8* 1.3
*FEA Capacity Forecast as of 1/1/79
If the pattern of refinery capacity additions evidenced in the
1975-78 time period continues, only one or two new grassroots refin-
eries should be expected in the 1980-1985 penod with the balance of
all new refining capacity being added to existing plants.
Assuming that product imports remain unchanged and new utility
plants are not based on petroleum residual fuel, the following prod-
uct slate will be required from incremental new domestic refining
capacity:
Demand Growth
1974-85, MB/i) % of Total
Gasoline 1,368 36.9
Jet Fuels 739 14.6
Distillate Fuels 734 14.5
Residual Fuel 428 8.4
Petrochemical
Feedstocks 551 10.9
Other Products 744 14.7
Total 5,064
This implies that new refining capacity will include less extensive
naphtha processing units compared to today's 50% gasoline yield
domestic refinery. However, the major growun in petrochemical feed-
stock and distillate yields suggests that facilities will be required
to upgrade residual stocks to distillate products.
It may be of interest to note the effect of not restraining the
construction of petroleum-based utility plants. An earlier NPC study
conducted prior to the 1973 embargo forecast residual fuel demand for
1985 at 4.2 million barrels dally. If such a demand materialized and
were supplied by domestic refining capacity, 1985 refining capacity
requirements would be Increased by one million barrels daily and re-
sidual fuel yield would Increase to 23.5% of total growth 1n demand.
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11-6
This would further reduce the severity of future refinery operations.
Though this may provide an important test case for parametric stud-
ies, one should also consider the opposite extreme. Two of the major
projects already under construction (Exxon - Baytown and ECOL) are
directed primarily toward the residual fuel market. Assuming a 5056
residual fuel yield from these ventures, over half of the new domes-
tic residual fuel refining capacity requirements forecast by NPC may
already be committed. Thus, residual fuel yields from the remaining
new refining ventures would average only 4$ of refinery input - only
half the level produced by the existing domestic refineries.
-------
REFERENCES - SECTION II
1. U.S. Energy Outlook - An Initial Appraisal 1971-1985, National Petro-
leum Council, July 1971.
2. U.S. Energy Outlook - A Report of the National Petroleum Council,
National Petroleum Council, December 1972.
3. U.S. Energy Prospects - An Engineering Viewpoint, National Academy
of Engineering, May 1974.
4. Project Independence Report, Federal Energy Agency, November 1974.
5. Emergency Preparedness: Interruption of Petroleum Imports into the
United States, National Petroleum Council, September 1974.
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III-l
III. COST IMPACT OF WASTEWATER REGULATIONS
A. Background and Scope
The Federal Water Pollution Control Act Amendments of 1972
(Public Law 92-500) provided the basis for, and required that, EPA
promulgate guidelines for the discharge of "pollutants" by industry.
Accordingly, EPA has designated the petroleum refining industry as one
of several "point source" categories to be regulated, and has pro-
mulgatedv3) existing-source effluent guidelines based on Best Prac-
ticable Control Technology Currently Available (BPCTCA) to be imple-
mented by July 1, 1977, and based on Best Available Technology
Economically Achievable (BATEA) to be implemented by July 1, 1983.
New-source guidelines for Best Available Demonstrated Technology
(BADT) have also been established. This report documents updated
estimates of refining industry costs that can logically be expected
to result from these established regulations, using published data
and information available as of January, 197b.
We have not considered the cost impacts of potential regulations
that may be promulgated by EPA after January, 1975. Estimated costs
for those regulations, such as pre-treatment standards, would there-
fore have to be added to estimates developed herein. More specifi-
cally, the scope of -this study is limited to estimation of the cost
influence of BPCTCA, BATEA and BADT effluent guidelines together with
assumed levels of refinery wastewater flow rates. Excluded are
potential cost impacts of:
• Pre-treatment standards for existing sources dis-
charging to publicly-owned facilities (pre-treatment
standards for new sources are implicitly assumed
equivalent to BADT guidelines).
• Possible future limitations on discharging heavy
metals, such as cadmium.
• Elimination of Discharge of Pollutants (LOOP) guide-
lines, to be effective by July 1, 1985. These are
yet to be developed since a definition of E00P will
probably not be available until October, 1975.
• Revised guidelines for each refinery, such as those
resulting if EPA promulgates the more specific size
and process factors proposed in the October 17,
1974, Federal Register. However, we would expect
these to have little effect on total industry costs.
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111—2
• Local, state and federal water quality statutes.
Determining their effects on individual refineries
and the industry would require more than the re-
sources committed to this study.
It is worthwhile to note that current petroleum refining industry
effluent guidelines and many of their implications are now in liti-
gation. One of the major issues seems to be whether or not certain
technology is in fact "currently available" (BPCTCA), "economically
achievable" (BATEA) or "demonstrated" (BADT) in treating petroleum
refinery wastewater. Also at issue is the correct interpretation
of the word "guidelines". In our opinion, application of the specific
combination of treating technology used in this and prior studies may
or may not result in guidelines compliance for any given refinery.
However, we do believe the model sequence of in-plant practices and
end-of-pipe treating adopted in referenced studies and this one should
result in a reasonable estimate of expected industry-wide investments
and operating costs.
Because of unique terminology, we have included definitions of
symbols and abbreviations on page 111-20.
B. Conclusions
Using the best available information on costs and refinery
wastewater control and treating practices, we have estimated the
impact of EPA's current effluent guidelines and their underlying
assumptions. In particular, cost estimates are almost entirely a
function of wastewater flow rates. Individual-refinery compliance
with guidelines, stated as pounds of pollutants per 1,000 barrels
of crude charge, will of course depend on a combination of flow rate
and final effluent pollutant concentrations. We have thus included
a brief discussion of the guidelines, and refinery characterization
under them, even though their direct influence on estimated costs
is minimal.
Our review of prior studies and independent analysis indicate
that:
• Total industry investment required by the application
of commonly assumed technology should approach $1.9
billion in the 1974 through 1977 period, rising to
a 10-year total of almost $2.9 bill.un by 1983.
§ In existing refineries affected by either effluent
guidelines or water quality regulations, investments
are projected at about $2.2 billion through 1983. New
capacity should account for another $0.7 billion, pro-
portioned as 19% for grass-roots plants and 8H for
expansions.
-------
111-3
• Small existing refineries, i.e., those under 10 MB/SD
in capacity, will be required to spend less than 4%
of the industry total during the 10-year period.
However, their average investment of about $310 per
daily barrel of capacity is more than twice the large-
refinery figure of about $150.
• Alternatives for small refineries in seeking relief
from this projected burden seem to be:
• refinery-specific studies that might in-
dicate relatively cheap ways of reduc-
ing pollutant loadings and/or flow rates.
• unique financing for required investments.
• EPA-granted relief from guidelines com-
pliance if other alternatives fail.
Unfortunately, small refineries usually do not have
the technical manpower required to provide them with
cost-effective solutions.
• Annualized industry costs of about $750 MM by 1977, and
$1.15 billion in 1983, are composed of about 60% fixed
charges and 40% direct operating costs. Per barrel
of refining capacity, small refineries' annual costs
should be almost twice those for o'l'.er refineries at
about 30 cents versus 16 cents.
• Our estimates should be adjusted when potential regu-
lations such as pre-treatment standards for existing
sources and ED0P are promulgated. It is likely that
their projected cost impacts can be added to those
developed in this study.
C. Guidelines Basis
Actual effluent guidelines as published in the Federal
Register^' have not explicitly been used as a basis for cost
estimates since they are in regulatory ter-.s of maximum one-day
and thirty-day average allowances. InsteM, annual average daily
figures, detailed for all pollutants in Tables III-l and 111-2,
were used as a more rational basis for characterizing the Industry
and estimating certain investments.
In developing guidelines for the Industry, EPA has adopted a
general classification of refineries similar to that of API. Des-
ignated subcategories are topping, cracking, petrochemical, lube and
integrated, as defined 1n Table 111-3. Additionally, EPA analysis
led to categorization of refineries by size and configuration™'
-------
111-4
and to development of sets of size and process configuration factors
These factors, listed 1n Table III-4, should be applied to the basic'
discharge limitations (shown In Table III-l) 1n calculating target
annual average dally allowances for Individual refineries.
D. Industry Characterization
Each operating refinery in the United States, as of January 1
1974, 1s listed in Appendix Table A-l together with published data'
on processes and capacities. This list includes not only those
refineries 1n the lower-48 states, but also contains two refineries
in Hawaii, four in Alaska, one 1n Guam, three in Puerto R1co and
one 1n the Virgin Islands. These remote refineries have been in-
cluded since they are within the jurisdiction of EPA 1n regulatlna
and controlling pollution abatement practices.
In developing information needed to estimate the cost Impact
of wastewater guidelines, we have calculated allowable pollutant
discharge levels of BOD5 for aggregated refining subcategories 1n
both 1977 and 1983 to be used 1n estimating sludge handling costs.
Further stratification of refineries 1s necessary to account
for certain influences on industry-wide cost estimates. Accordingly,
• Zero dischargers and those refir.&ries discharging
to offslte treatment facilities were excluded.
• The cost influence of Amerada-He?c' refinery at
St. Croix, V.I., was estimated separately since
the plant accounts for almost 40% of topplng-
subcategory capacity.
• Small refineries, i.e., those with less than about
10 MB/D capacity, were segregated.
Table 111-5, summarized below, shows the domestic refining
population adjusted for the above influences and assumptions.
Cap.-si0 MB/SD
Cap.^10 MB/SD
Total
No. MB/SD
No. MB/SD
No.
MB/ar
70 340
180 14,900
250
IS,240
17 70
35 1,755
52
1,825
53 270
145 13,145
198
13.415
Refineries
Total
Zero Discharge &
Offsite Treatment
Effluent & Water-
Quality Limited
Note: Excluding the Amerada-Hess refinery at St. Croix, V.I.
-------
III-5
Estimated allowable discharge levels for BOD5 were adjusted for
the above considerations and are summarized below.
BOD5. M#/Day
1977 1983
All Refineries 72.0 15.30
Less -
Non-dischargers 8.3 1.70
Dischargers-siOMB/SD 0.7 0.12
Amerada-Hess(V.I.) 1.5 0.25
Subtotals TO "27737"
Dischargers ^10MB/SD 61.5 13.23
The resulting 1977 and 1983 figures for dischargers over 10 MB/SD
capacity were used for estimating sludge handling costs in Section
III-F-2.
E. Estimating Basis
1. Approach
We have relied heavily on relevant studies that used
published data 1n combination with a specific cost-
estimating procedure. Of the two published studies that
deal comprehensively with expected costs, we have chosen
Brown & Root's(2) instead of the one by Roy F. Westonl')
because:
• The level of detail included in the Brown & Root study
allows adjustment of their cost estimates for major
differences in such key parameters as target flow
rates for 1977 and 1983.
• A corollary to the Brown & Root studycontains
specific data from the 1972 RWL Survey on several
small refineries. Combined with certain new in-
dependent estimates, these data supported a more
detailed estimate of cost impacts on the small re-
finery group.
• The Weston study included neither an estimate of
in-plant control and flow-reduction costs*, nor
credit for then-existing, end-of-pipe treating
facilities. The Brown & Root study attempted to
account for both of these important cost Influences.
*A more recent EPA study^2^ did Include an aggregate estimate
of such costs.
-------
111-6
• The Brown & Root study, in addition to previously
published investment and operating cost data, In-
cluded new case-history data that either filled
a void or expanded on available information.
Since our basic approach has been to update and modify the
Brown & Root study, it should be assumed as the basis for
discussion in following sections unless references in-
dicate otherwise.
2. In-Plant Practices and Treatment Technology
The 1973 Brown & Root study was based on technology then
assumed to be available for BPCTCA and BADT requirements,
and on activated carbon adsorption as the add-on treatment
process most likely to be proven in attempting to meet BATEA
guidelines by 1983. Essentially no new alternatives to these
assumptions have developed to the point of being proven 1n
treating refinery wastewater. However, we note that current
alternatives within a class of treating processes existed
even then. For example, trickling filters, aerated lagoons,
bio-oxidation (cooling) towers and oxidation ponds are alter-
natives to the selected activated sludge process. But, we
believe the basic referenced approach of applying the same
set of in-plant and end-of-pipe steps to each refinery, if
required, remains valid as a computational procedure intended
only to measure potential industry-wide costs.
Available in-plant pollution control practices, flow
reduction techniques and end-of-pipe treating technology
have been extensively discussed in the literature™^'*/.
Therefore, excepting certain alternatives discussed in a'
following section on small refineries, our review of specific
practices is limited to a listing below and a brief statement
of key assumptions adapted from the Brown & Root study.
-------
111-7
LEVEL 1:
(1977)
LEVEL 2:
(1983)
IN-PLANT CONTROL/FLOW REDUCTION
Conversion of Barometric to
Surface Condensers
Sour-Water Stripping
Storm Water Handling and
Segregation
Miscellaneous Flow Reductions
Collection of Multiple Effluents
for Common Treatment
Elimination of Once-Through
Cooling Water (OTCW)
Water Reuse, Including
Softening and Redistribution
Cooling Tower Blowdown
Treatment for Reuse
END-OF-PIPE TREATING
Equalization
Dissolved Air Flotation
Activated Sludge
Final Filtration
Indirect, Associated
Steps
Sludge-Handling Facilities
Auxiliary Facilities
Final Filtration
Activated Carbon Adsorption
Additional Sludge Handling
0ff-Spec1f1cation Handling
and Reuse Basin
The figures on pages 8 and 9 Illustrate resulting wastewater
flow sequences for Level 1 and Level 2 treating in a hypothetical
refinery. Complete details and extensive discussion of practices
and underlying treatment technology assumptions are available In
Reference 2.
With the exception of when OTCW must be eliminated, BPCTCA and
BATEA treating practices are assumed in this study to be equivalent
to Level 1 and Level 2 as defined above.
3. Flow Levels
Wastewater flow levels assumed in the Brown & Root stu
-------
WASTE
oOUPCES
in-plant tbeatm bkit
Qg CONTROL
tSALLAST
V.VAT EE
SQUAUZATION
~ STTDRASE and
OIL &K.IMWOMG
l,"jTOOM
PUNOFF
|COLiJKTlONt»TQ,j
'OIL SKJMMINC5 1
AND PLO*
E4UA.LIZA.TIOM
WASTE \VA.T«B9
WASMOOWVI AND
PUMP SEAL.
VATSEk
PBC7CKS«
comovmsatcs
&V-PMSS MOW-
COWTAMIUA.TBO
ftTOBM «ATK
FUJ*' HBOUCTION
A. ADOITIOMAL-
MISCEl-UAM«OU%
IH.OVV PEDUCTIQS*
5. COUVCABION O*
fcABOMBTBIC
CONDtMgBBC
OCSALTBB
mTCB
POS&16LY 6V-PAM
TMATMBMT 3Y»T
coouma
tov/bss
}
*
posaifcLv ttr-WfcS©
TBBAtVBWT *vst.
i
SOUA
Sour
VATBR.
«T*IPI»IN®
v^xen
sanitary
TOMLTNIOPAL
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VASTBS
TlfATMBMT
M
t
I
I
t
I
A) IHU.UOF.S VASTCVATBft »ucw AO TANK D«MVa, 3PBNT CAUBTIC
SPHNfACIOS, FLARE SEAt-ft, ACCUMULATOR V*erKQt»CBU6eH<
WAtTCO.4 ITC'
(V) OIRIK.T ¦S.TBAM OIST|LLATIOW OVeBMEAO COHD«M
-------
II1-8
IAV1TV
[ftAQATIQNI
EQUALIZATION
ADDITIONAL OIL
ANO SU5PBNP6P
SOLIDS REMOVAL
ORGANIC^
REMOVAL
to fetq-oaicAu
SUUOQiC MAMriUNa
TO OILY WJUD6B
i oily sludge
HDUNS system
I RUT HAT I OH
A. I a RJOTATIOH*
CLARIFICATION
FtWAL DISCHAOOK
EQUALIZATION
feMMki VV1TW
MIKIKiq
TO blOLOSlCAL,
0UUOOB HAMDUMQ
3LUOGC
sotjpg&s
; eiOUCOlCAL
I wxiook
OIUTWrfUUMOMS
AHO 9UJ04C9
SLUDGE HANDLING
THlC*CNq*5 PWATgRlKiq
F1HAL
falSPOfeAl
A.12 FCfifTATlON
OB GOAV1TV
TU1CKKNIWG
1
4 SHALL g«f IN
•MULSIOM ftUAK-
wa tmrnfOKimo
OCCAWTIWa
I
I
CENTttlPUa*
rlthatkx
ihohMatiom amo
LAUOfma. cm a.«w
NOM-OtC
¦9UIO'
-------
WASTE
5CUHCES
IN-PIANT
TBCATMCKIT
5tt CONTR5L
&AILAST
WATEB
fe
EQUALIZATION
STORAGE AMD
OIL SltlMMINS
s
STOPM
RUNOFF
" fc
COLLECTION ,»tq.
OIL SKIMMING
AND FLOW
EQUALIZATION
EFFLUENT
SKU&E
WATER
WASWOOWN A wo
PUMP SEAL
VATEO
'V
PROCCS9
COWOBNSATES
OESALTER
V/ATER
PLOV SEDUCTION
A. CONVERSION
OF bABOMSTRIC
CDNOENS6RS
&. ELIMINATION
OP ON«1 REUSE
eoiLsa
6LOWDOWN
3
J
WATER TREATmbut
REGENERATE v V i £
k evaporation
w 6ASIN
SOUR
WATERS
J \
SOUS
WATE.i*
STRIPPINCi
1
SAN I TARV
WATiTEG
NOy£i_
f|) IWCLUnE'5 WA.'iTFWAI CU Vilini
SPENT AC I nr. |
WATER-?. ETC
J| WMUniciOAL
Joa ^t."4JATF; I
H Tlit ATMLMT I
TO ACTUATED ^.UUOaC
AO rANUC ')HAVj,'iPrNt r.AIJSTIC'j
PLABC CVt'AL' 1, Arr i IMIM Arfiw V> i I W( 'jr. »u 'p
11) OIRKCT ilEAM ni^T It,LA I ION , ( >VI .Hit /\r> l.fiWOl Nrvxri •„
-------
II1-9
EEm
EQUAL1ZATIQM
CTIOM
APOITIOUAL OIL
END fflJgPCNPCQ
SOL-IPS BSMOVAL
QgQAKHCf-.
REMOVAL
TO SLOP OIL
BECO^iHrf system
t wateb
Niavroaa
1-
'
fc oii_y
Iw.'X.IWG SV3TBM
EQUALIZATION
bASIN SVlTH
MINING
5U3P5NP5P.
§ouo3_
removal.
TO OILY SUJOGC
HAMOUING
TO MOU3GICAL
PILTOATIOM.AIB
FLOTATIOtJ OR
CMCMICAL
COA.aULA.TION
SUJOSK MAMDUINCi
>
ACTIVATtfO
ftLUOCM, OB
AMATK3 LAGOON*
FINAL
OPGAKIIC
PEMQVAL
Be^fcirioM
1»
filtration
Aia P LOT AT ION
Oft CLABIFICATON
CABCiON
ADeOBPTlON
TO btOLOSICAL
SLUOdW HAMOLIMS
BIUM
SCUM AMD 0«M*
SP*C1*1CATlO*4
fcAMM
FINAL
TP^ATV4gHT PQR
wnwim and
OtSt HCVCTIOM
OWKWL'
5LUOO£.
SOUPCES
, &IOUOOIC.AL
! 3LliO<3*
'.Oi'_v EMULSIONS
amo suuoses
Mel
£r
SLUOGC WANPUNG
thickEN INQ QgWATgglNG.
A\a flotation
OH GBAVITY
TWCK-KNIUG
SMALL. UBFINCB.IES
EMULSION 6BEAK- I
IMG STORAGE WO I
OSCAMTINO I
cBNTttip-uae
FILTRATION
FINAL.
DISPOSAL.
INCtNtBATtOU
TO LA«4D«*ll_l_ I
I
;HOM-OIL.-f
: SOLID
J W»ST«9
OEVVATERING
TO LAMOBILU |
.iMe
saioG«s
BBCACCINATION
amo aeusc
bLOQlC_PROCE55 FLOW DIAQ«AM
3ECOMP LEVEL- TBEATMSKJ~r~
SOUGCS • SSFCaEKICS «
-------
111-10
Except for oily, biological and lime-sludge handling
facilities, the size and required investment for almost all
in-plant and end-of-pipe facilities are primarily dependent
on hydraulic loadings. Refiners therefore have a basic
tradeoff available to them since increased in-plant invest-
ments to reduce flows will allow lower investments in end-
of-pipe treating facilities. Recognizing that the most cost-
effective combination of flow rate and effluent concentrations
will be determined by studying individual refinery situations,
we have assumed that the above BPCTCA and BATEA flows for re-
fining subcategories will be met by each corresponding refinery
unless the available 1972 RWL Survey data indicated an exist-
ing lower level.
4. investments and Operating Costs
Compared below are Brown & Root's bases for investments and
operating costs with those used in this study.
Assumption
Time Reference
Const. Costs
Location
Land Required
Existing Facil-
ities
Operating Costs
Fixed Annual
Costs, % of In-
vestments
Current Basis
1974 through 1983
1974 dollars
B & R Area 3 (roughly
equivalent to U. S.
Gulf Coast)
Assumed available at
no cost
Credited,based on 1972
RWL Survey data and
estimated 1973^'"'
investments
Related to invest-
ment
Capital charge equiva-
lent to 12% DCFf21.8:2
Taxes & Ins., 4.0%
Brown & Root Study
1973 through 1985
1972 dollars
Five cost areas
Assumed available at
no cost
Credited, based on
1972 RWL Survey
data
Related to invest-
ment
Amortization, 6.67%
Interest cost, 10.0%
Taxes & Ins., 1.0%
-------
in-n
F. Investment Estimates
1. Cost Estimating Procedure
To determine required investments, Brown & Root divided the
industry into four basic categories:
• Existing refineries over 10 MB/SD capacity,
t Existing refineries under 10 MB/SD capacity.
• New grass-roots capacity to 1985.
t Expansions to 1985.
Then, from the sample responding to the 1972 RWL Survey, they
selected 121 refineries, larger than 10 MB/SD capacity, on
which sufficient and consistent data were available. Invest-
ments, if required, were estimated for each refinery, totaled
for the 121 refineries, and extrapolated to all 156 existing
large refineries. Total investment for refineries under
10 MB/SD capacity was scaled, using average capacities, to
complete the estimate for existing plants. Investments for
then-projected new refineries and expansions were developed
and added to existing-refinery requirements to obtain an
industry total.
By adjusting the large-refinery estimates to the bases
for this study, we implicitly adopt certain assumptions
about contingencies, indirect costs and excess capacity that
are more generous than those we would have assumed. However,
we believe the degree of detail and integrity of approach
utilized in the Brown & Root study justify it as the primary
basis for a current estimate.
2. Refineries Over 10 MB/SD Capacity
Beginning with Brown & Root's refinery-by-refinery investment
estimates for 121 larae.refineries, we first adjusted them
to an Area 3 basis^2,10'. Also, estimates for eliminating
0TCW were shifted from Level 2 to Level 1 since we believe
this conversion will be required to meet BPCTCA effluent
guidelines.
Next, estimates were adjusted to conform with the bases
for current effluent guidelines. The procedure used was:
-------
II1-12
t Investments for converting OTCW, sour-water
stripping, storm-water handling, converting
barometric condensers, collecting multiple
effluents and auxiliary facilities were left
unchanged since they are primarily a function
of individual refinery characteristics.
• Differences between BPCTCA and Brown & Root's
Level 1 target flow rates for refining classes
B, C, D and E dictated recomputation for each
refinery of investments for miscellaneous in-
plant flow reductions. Example calculations
for a sample of Class B refineries are shown in
Table III-6.
t All other investments, except sludge handling
facilities, were adjusted to current flow
basis assumptions using appropriate combina-
tions of original and recalculated average
refinery-class flows. These are tabulated and
compared below.
• Investments for sludge handling facilities were
assumed to be a function of BOD5 removed. Accord-
ingly, We developed the following aggregate in-
dustry estimates:
Refinery
Class
Average Flow, "ial./Bbl.of Crude
B&R B&R ~~
Level 1 Level 2 BPCTCA BATEA
A
B
C
D
E
14.5 2 '0 14.5 9.1
29.5 4.63 20.7 13.1
38.5 4.40 25.7 17.7
42.0 4.80 36.9 28.6
63.7 7.20 42.5 34.7
BOD5 Discharge Level
#/MBbls.
B&R Level 2
BATEA
1972 Existing
B&R Level 1
BPCTCA
31.75
13.23
4.73
3.08
1.02
Note: All BOD5 discharge. levels exclude
OTCW effects.
-------
II1-13
Using logic similar to that for making flow-
dependent adjustments above, we recalculated
sludge handling investments.
Resulting modified investments for the 121-refinery
group based on BPCTCA and BATEA target flow rates and BOD5
discharge levels are contained in Table II1-7 and summarized
below.
Refinery Investment, MM$
Class BPCTCA BATEA Totals
A
19
8
27
B
385
112
497
C
258
85
343
D
81
37
118
E
256
JA
334
Totals -
999
320
1,319
Basis: Area 3, 1972 $.
Comparisons between refinery classes should be avoided since
adjusted investments for sludge handling are based on average
BOD5 discharge levels for the entire group of 121 refineries.
3. Refineries Under 10 MB/SD Capacity
We have devoted significant attention to potential problems
faced by the group of 53 small refineries (excluding 17
zero dischargers and offsite-treatment refineries) in
attempting to meet 1977 and 1983 effluent guidelines. In
particular, we have reviewed current treating facilities
and plans for guidelines compliance with the management of
9 plants. Unfortunately, this has not particularly
sharpened cost estimates since almost none have specific
plans. Our review did, however, provide insight to support
the following opinions:
• With few exceptions, in-hous_ technical personnel
are not available to evaluate treating alternatives
and identify opportunities to reduce pollutant loads
through good water-use practices and flow-reduction
projects.
• While uncommon, at least one small refinery has
already installed cooling towers to eliminate
OTCW, has instituted other flow-reduction
practices, and projects a 75 to 80% reduction.
-------
III-l*
• Installation of several small API separators
ahead of an existing single unit may cost less
and be a more effective use of scarce land than
flow equalization facilities to protect against
process unit spills.
• The two most common methods of effluent treating
seem to be direct discharge from API separators,
and 12 to 24-hour holding ponds sequenced between
API separators and discharge points.
• Several small topping-subcategory refineries, in-
cluding some in the 10 to 30 MB/SD range, are
already zero-dischargers and face no problems
unless they plan significant capacity expansions.
We are aware of at least one planned refinery
being designed for zero discharge.
Although the same treating proce^es have been assumed
as model technology for small refineries, it is entirely
possible that novel technology could find application in the
refining industry - particularly for those plants with low
potential discharge rates. Brine concentrators using a vapor-
compression cycle are commercial in tii(. electric utility
industry, and this technology is being tested on refinery
wastewater. If such commercial technology were proven for
treating API separator effluent, a 3,600 B/D refinery
at the BPCTCA-level of 20 gal/Bbl. cc-Jd approach or even
achieve zero discharge with a brine concentrator capacity
of about 50 gpm. This treating scheme could supplant
the need for bio-treatment, air flotation, filtration and
activated carbon adsorption--while meeting 1983 guidelines
now. Required investment for this hypothetical example would
be in the range of $350-550M (Area 3, 1972 $), or about $125
per B/D of crude capacity. Annual energy costs should be less
than 3% of investment since existing installations use only
about one-tenth the energy required for conventional
multiple-effect evaporators.
These observations serve as a useful background in
evaluating the potential impact of r"A's effluent guidelines.
In particular, our discussions indicted that small refineries
will continue to be more cost-conscious than large ones in
such areas as indirect costs, control schemes and excess
capacity. Our estimation of investments accordingly reflects
this traditional, small-refiner posture. We stress that,
even though investments were individually calculated for a
sample of small refineries, our purpose was to develop an
aggregate estimate. A specific study would be required to
develop definitive estimates for any one refinery.
-------
II1-15
Results for a sample of six Class A and five Class B
small refineries are listed in Table III-8. Average re-
sults of these sample estimates were extrapolated to all
small refineries, as indicated in Table II1-9 and summarized
below.
EPA
Capacity,MB/SD
Total Investment
Subcat.
No.
Total
Avg.
MM$
$/B/D
MM$/Ref.
A
42
206
4.9
41
199
1.0
B
11
64
5.8
19
300
1.8
Totals
53
270
5.1
60
223
1.1
Basis: Area 3, 1972 $.
In developing these estimates, we modified the procedure used
by Brown & Root in calculating investments for larger re-
fineries. Specifically, we have:
• Not included any provision in sour-water
stripping investments for high-nitrogen
crude effects, or for extra steam.
• Scaled storm-water and sludge handling in-
vestments based on averages for several
10 to 20 MB/SD plants^).
• Included no investment for auxiliary
facilities.
• Not sized treating facilities for 25% excess
hydraulic capacity.
We recognize the potential inaccuracy of extrapolating in-
vestment curves based on projects for much larger refineries.
However, short of resorting to specific studio of individual
small refineries, we believe the data and assumptions used
are the best currently available information.
4. New Capacity
Projected new refining capacity from 1974 through 1983 has
been divided into grass-roots and expansion capacity. Be-
ginning with 1974 additions, this projection is tabulated
below as the basis for estimating wastewater-related invest-
ments.
-------
II1-16
Capacity Added, MB/SO
Year
Grass-Roots
Expansions
Total
1974
684
684
1975
50
523
573
1976
222
1,200
1,422
1977
111
405
516
1978
167
555
722
1979
148
64
212
1980
-
212
212
1981
148
64
212
1982
-
212
212
1983
-
212
212
Totals
846
4,131
4,977
Estimates for new grass-roots capacity were based on the follow-
ing assumptions:
• Average capacity for the seven projected plants
would be about 120 MB/SD.
• In-plant expenditures would be required to forego
the use of OTCW, reduce estimated pre-guideline
flow from 33 gal/Bbl. to the 3ADT level of 14,
handle storm water, collect multiple effluents
and provide for sour-water stripping.
• Auxiliary facilities, BPCTCA treating processes
and activated carbon adsorption would be necessary
to meet BADT guidelines and, eventually, 1983 BATEA
guidelines.
Basic investment curves from Reference 2 were used with the
above assumptions resulting in an estimated investment of
about $13.2 MM for a hypothetical 120 MB/SD refinery.
Investments required for capacity expansions were cal-
culated to be $51.7/B/D for BPCTCA and $44.1/B/D for BATEA.
These are based on reported^) figures, adjusted to conform
to our assumptions.
Applying these estimates to tf.j previously-listed time
series of capacity expansions results in the estimates shown
in Table 111-10, also summarized below.
Investment MM$
Period Srass-Roots Expansions Total
1974-77 42 145 187
1978-83 50 251 301
Totals 92 396 488
Basis: Area 3, 1972 $.
-------
111-17
5. Investment Summary
An accumulation of investments for existing large and small
refineries together with those for new capacity, adjusted to
account for inflation between 1972 and 1974, provides the
following industry summary:
MM$ $/B/D
1974-77
1978-83
1974-83
Existing Capacity
Over 10 MB/SD
1,550
529
2,079
151
Under 10 MB/SD
60
24
84
312
Subtotal
1,610
553
2,163
154
New Capacity
Grass-Roots
59
71
130
154
Expansions
189
366
555
135
Subtotal
248
437
685
138
Total Industry
1,858
990
2,848
150
Basis: Area 3, 1974 $.
This summary excludes an estimated refining industry capital
expenditure in 1973 of about $77 MM (Ref. 11, adjusted). The
remaining $1,610 MM needed for BPCTCA requirements in existing
capacity must be spent prior to July 1, 1977 - - a rate of
about $460 MM per year for 3 1/2 years. The estimate of
$553 MM for BATEA-imposed capital requirements in existing
refineries indicates average annual capital expenditures of
about $90 MM during the 1978-83 period. These drastically
different rates of expenditure nevertheless seem indicated by
underlying study assumptions.
G. Annualized Costs
Annual industry costs in 1977 and 1983 were developed by adding
a fixed charge for capital recovery, insurance and taxes to
estimated direct operating costs. Based on assumptions dis-
cussed earlier, 25.82% of investment was assumed to represent
fixed charges. Direct operating costs we>c calculated by:
• estimating expenses, shown in Table III-ll, for
the 121 large refineries used in Reference 2.
• extrapolating this estimate to all effluent and
water-quality limited refineries with over
10 MB/SD capacity.
• adding estimates for affected small refineries
and new capacity.
-------
in-18
Results, summarized below, indicate annualized costs of about $750 MM
in 1977, rising to a total of almost $1.2 billion by 1983.
MM$/Year
1977 198?
Di rect
Oper.
Fixed
Total
Di rect
Oper.
Fixed
Total
Existing Capacity:
Over 10 MB/SD
Under 10 MB/SD
Subtotal
209
5
214
388
15
403
597
20
617
285
8
293
520
21
541
805
29
834
New Capacity:
Grass-Roots
Expansions
Subtotal
7
58
65
15
47
62
22
105
127
15
126
141
33
139
172
48
265
313
Total All Refineries
279
465
74"
434
713
1,147
Basis: Area 3, 1974 $.
Results in both years will be highly sensitive to fixed charges
since these represent over 60% of the total for all refineries and
more than 70% for small refineries. When operating at capacity,
average product price increases required to fully recover annualized
costs would have to be:
Refineries $/Barrel i/Gallon
Existing Over 10 MB/SD 0.16 0.4
Existing Under 10 MB/SD 0.30 0.7
New Grass-Roots 0.16 0.4
Expansions 0.18 0.4
The average smaller refinery thus seems to face a relative cost dis-
advantage of about 0.3 cent per gallon on its lifined products.
-------
II1-19
REFERENCES - SECTION III
1. Draft. Development Document for Effluent Limitations Guidelines
and Standards of Performance, Petroleum Refining Industry,
Supplement A: Cost Information, U. S. Environmental Protection
Agency, June, 1973. Prepared by Roy F. Weston, Inc. under
contract no. 68-01-0598.
2. Economics of Refinery Waste Mater Treatment, Committee on
Environmental Affairs, American Petroleum Institute, August, 1973
(API Publication No. 4199). Prepared by Brown & Root, Inc.,
Houston, Texas.
3. - ' , Vol. 39, No. 91 - Thursday, May 9, 1974,
4. Development Document for Effluent Limitations Guidelines and New
Source Performance Standards for the Petroleum Refining Point
Source Category, U. S. Environmental Protection Agency, April,
1974 (EPA-440/1-74-014-a).
5. "Refining Capacity Registers Largest 'Nickel and Dime' Jump in
History", The Oil & Gas Journal, April 1, 1974.
6. "Lube Capacity in U. S. and Canada", Hydrocarbon Processing,
June, 1973, p. 113.
7. International Petroleum Encyclopedia - 1974, Petroleum Publishing
Company, Tulsa, Oklahoma. Copyright, 1974.
8. Analysis of the 1972 API-EPA Raw Waste Load Survey Data, Division
of Environmental Affairs, American Petroleum Institute, July, 1974,
(API Publication No. 4200). Prepared by Brown & Root, Inc., Houston,
Texas.
9. Beychok, Milton R., Aqueous Wastes from PetT:eum & Petrochemical
Plants. John Wiley and Sons, New York, 1967.
10. Private Communications.
11. Environmental Expenditures of the United States Petroleum Industry,
1966-1973, Division of Environmental Affairs, American Petroleum
Institute (API Publication No. 4233). Compiled by Haskins & Sells,
Washington, D. C.
12. Economic Analysis of Proposed Effluent Guidelines - Petroleum
Refining Industry, Office of Planning and Evaluation, II. S.
Environmental Protection Agency, September, 1973 (EPA-230/1-73-020).
-------
SYMBOLS & ABBREVIATIONS - SECTION III
II1-20
API - American Petroleum Institute
B/D - Barrels per day
B&R - Brown & Root, Inc.
B/SO - Barrels per stream day
BADT - Best Available Demonstrated Technology
BATEA - Best Available Technology Economically Achievable
Bbl. - Barrel(s)
BOD5 - Five-day biochemical oxygen demand
BPCTCA - Best Practicable Control Technology Currently Available
COD - Chemical oxygen demand
Cr - Chromium
DCF - Discounted cash flow
EDOP - Elimination of Discharge of Pollutants
EPA - Environmental Protection Agency
Gal. - Gallon(s)
M - Thousands
mg - Milligram(s)
MM - Millions
N - Nitrogen
NH3 - Ammonia
NPDES - National Pollutant Discharge Elimination System
OTCW - Once-through cooling water
ROR - Rate of return
RWL - Raw waste load
TOC - Total organic carbon
TSS - Total suspended solids
-------
TABLE III-l
WATER^) EFFLUENT LIMITATIONS
PETROLEUM REFINING (POINT SOURCE) CATEGORY
(Annual Average Daily Pounds of Pollutants per MBbls. Feedstock^))
BPCTCA
(1977)
BATEA
(1983)
BADT
(New Source)
A-Toppinq Subcategory
B0D5 t
2.5
0.44
1.3
C00(3)
13.3
1.75
7.0
TOC
5.5
1.3
2.9
TSS
1.7
0.44
0.88
Oil & Grease
0.83
0.088
0.44
Phenolic Cpds.
0.017
0.0018
0.0088
NH3 as N
0.3
0.12
0.3
Sulfide
0.017
0.0087
0.0088
Total Cr
0.042
0.022
0.022
Hexavalent Cr
0.0008
0.00044
0.00044
•Cracking Subcategory
BOD5 v
3.1
0.58
1.8
COD w)
24.0
3.4
13.4
TOC
6.8
1.75
4.0
TSS
2.1
0.58
1.2
Oil & Grease
1.0
0.12
0.58
Phenolic Cpds.
0.021
0.0023
0.012
NH3 as N
2.0
0.8
2.0
Sulfide
0.021
0.012
0.012
Total Cr
0.052
0.029
0.029
Hexavalent Cr
0.001
0.00058
0.00058
-Petrochemical Subcategory
B0D^
3.8
0.79
2.4
CODI3)
24.0
3.8
15.2
TOC
8.3
2.4
5.3
TSS
2.5
0.79
1.6
Oil & Grease
1.3
0.16
0.79
Phenolic Cpds.
0.025
0.0032
0.016
NH3 as N
2.5
1.0
2.5
Sulfide
0.025
0.016
0.016
Total Cr
0.063
0.04
0.04
Hexavalent Cr
0.0013
0.00079
0.00079
-------
TABLE II1-1
5.6
1.3
3.8
41.0
6.9
28.0
12.4
3.8
8.4
3.8
1.3
2.5
1.9
0.25
1.25
0.038
0.0051
0.025
2.5
1.0
2.5
0.038
0.025
0.025
0.094
0.063
0.062
0.0019
0.0013
0.0013
(continued)
BPCTCA BATEA BADT
0977) (1983) (New Source)
D-Lube Subcategory
B0D5
COD(3)
TOC
TSS
Oil & Grease
Phenolic Cpds.
NH3 as N
Sulfide
Total Cr
Hexavalent Cr
E-Integrated Subcategory
B0D5
C0D(3)
TOC
TSS
Oil & Grease
Phenolic Cpds.
NH3 as N
Sulfide
Total Cr
Hexavalent Cr
All Subcategories
pH 6.0 to 9.0 6.0 to 9.0 6.0 to 9.0
Source: Reference 4
6.0
1.5
4.6
44.0
8.4
33.5
13.2
4.6
10.1
4.0
1.5
3.0
2.0
0.3
1.5
0.04
0.0061
0.03
2.5
1.0
2.5
0.04
0.03
0.03
0.10
0.076
0.076
0.002
0.0015
0.0015
(1) Once-through cooling water is excluded. It may be segregated and
discharged with a TOC limit of 5 mg per liter of discharge (flow).
(2) Combined crude oil and natural gas liquids charged to the "topping"
units in a given refinery (for all subcategories).
(3) If effluent chloride-ion concentration exceeds 1,000 mg per liter
(1,000 ppm), TOC may be used in lieu of COD. Without adequate data,
use TOC/BOD5 = 2.2/1.0.
-------
TABLE II1-2
LIMITATIONS^1) ON ADDITIONAL
DISCHARGE ALLOWED
(Annual Average Daily Pounds of Pollutants per HGals. of Flow)
BPCTCA BATEA BADT
(1977) (1983) (New Source)
Runoff^)
BOD 5
0.125
0.042
0.125
C0D(3)
1.0
0.12
1.0
TOC
0.275
0.13
0.275
TSS
0.083
0.042
0.083
Oil & Grease
0.042
0.009
0.042
Ballast(4)
B0D5 4
0.125
0.042
0.125
C0D(3)
1.25
0.16
1.25
TOC
0.275
0.13
0.275
TSS
0.083
0.042
0.083
Oil & Grease
0.042
0.009
0.042
Source: Reference 4
NOTE: pH, for runoff and ballast (each), 1s limited to a range
of 6.0 to 9.0 for BPCTCA, BATEA and BADT.
(1) Apply to all refining subcategories.
(2) Process area runoff treated 1n the main treatment system.
All other runoff, segregated for discharge, must meet
maximum limitations of 35 mg per liter for TOC and 15 mg
per liter for oil & grease.
(3) If effluent chloride-ion concentration exceeds 1,000 mg per liter
(1,000 ppm), TOC may be used in lieu of COD. Without adequate
data, use TOC/BOD5 » 2.2/1.0.
(4) Those waters, from a ship, actually treated at a refinery.
-------
TABLE III-3
SU8CATES0RIZATION OF THE PETROLEUM REFINING INDUSTRY
Subcategory
Topping
Cracking
Petrochemical
Lube
Integrated
Basic Refinery Operations Included
Topping and catalytic reforming, whether
or not the facility includes any other
processes.
This subcategory is not applicable to
facilities which include thermal processes
(coking, visbreaking, etc.) or catalytic
cracking.
Topping and cracking, whether or not the
facility includes uny processes in
addition to topping and cracking, unless
specified in one of the subcategories
listed below.
Topping, cracking and petrochemical operations,
whether or not the facility includes any pro-
cess in addition to topping, cracking and
petrochemical operations,* except lube oil
manufacturing operations.
Topping, cracking and lube oil manufacturing
processes, whether or not the facility in-
cludes any process in addition to topping,
cracking and lube oil manufacturing processes,
except petrochemical operations.*
Topping, cracking, lube oil manufacturing
processes, and petrochemical operations,
whether or not the facility includes any
processes in addition to topping, cracking,
lube oil manufacturing processes and *
petrochemical operations.*
Source: Reference 4.
The term "petrochemical operations" shall mean the production of
generation petrochemicals (i.e., alcohols, ketones, cumene, stvren® * *
or first generation petrochemicals and isomerization products (1 • StvJ
olefins, cyclohexane, etc.) when 153! or more of refinery production^
as first generation petrochemicals and isomerization products
T
-------
TABLE II1-4
SIZE AND PROCESS FACTORS
Size Facte
Process Factor
A-Topping
Subcategory
B-Cracking
Subcategory
C-Petrochemical
Subcategory
D-Lube
Subcategory
E-Integrated
Subcategory
Range
No.(2)
Feedstock I1>
MB/SD
Factor
Range,
No.*2)
Configuration
Factor
1
0
to
49.9
1.02
1
1.0 to
3.99
0.60
2
50
to
99.9
1.21
2
4.0 to
6.99
1.00
3
100
to
149.9
1.44
3
7.0 to
9.99
1.66
4
150
+
1.57
4
10.0 to
12.99
2.77
5
13.0 +
4.09
1
0
to
34.9
0.89
1
1.5 to
3.49
0.58
2
35
to
74.9
1.00
2
3.5 to
5.49
0.81
3
75
to
109.9
1.14
3
5.5 to
7.49
1.13
4
110
to
149.9
1.31
4
7.5 to
9.49
1.60
5
150
+
1.41
5
9.5 +
1.87
1
0
to
49.9
0.73
1
3.25 to
4.74
0.67
2
50
to
99.9
0.87
2
4.75 to
6.74
0.91
3
100
to
149.9
1.04
3
6.75 to
8.74
1.27
4
150
+
1.13
4
8.75 +
1.64
1
30
to
69.9
0.71
1
6.0 to
7.99
0.88
2
70
to
109.9
0.81
2
8.0 to
9.99
1.23
3
110
to
149.9
0.93
3
10.0 to
11.99
1.74
4
150
to
199.9
1.09
4
12.0 +
2.44
5
200
+
1.19
1
70
to
144.9
0.69
1
6.0 to
7.49
0.78
2
145
to
219.9
0.89
2
7.5 to
8.99
1.00
3
220
+
1.02
3
9.0 +
1.30
Source: Reference 4
(1) Combined crude oil and natural gas liquids charged to the "topping" units
in a given refinery.
(2) Range numbers are used to define a shorthu.id notation for refinery type.
For example, a type B24 refinery would be one in the cracking subcategory
(B) with a feedstock capacity in the range of 35 to 74.9 MB/SD(2) and a
process configuration in the range of 7.5 to 9.49(4).
Note: The formula for calculating a refinery's configuration is given on
pages 148 - 150 in Reference 4.
-------
TABLE III-5
APPROXIMATE CAPACITIES OF EFFLUENT AND
WATER-QUALITY LIMITED REFINERIES
Refineries •£
10 MB/SD
Refineries ^10 MB/SD
All Refineries
Capaci ty,MB/SD
Capaci ty,MB/SD
Capacity,MB/SD
Subcategory
No.
Total
Avg.
No.
Tota 1
Avg_.
No.
Total
Avg.
All
Topping
A
58
272.0
4.7
30
666.1
21.5
88
938.1
10.7
Refineries
Cracking
B
11
66.1
6.0
101
6,129.7
60.7
112
6,195.8
55.3
Petrochemical
C
0
-
-
23
3,045.1
132.4
23
3,045.1
132.4
Lube
D
1
3.7
3.7
17
2,932.7
172.5
18
2,936.4
163.1
Integrated
E
0
-
-
9
2,127.1
236.3
9
2,127.1
236.3
Totals
70
341.8
4.9
180
14,900.7
82.8
250
15,242.5
61.0
Zero Discharge
Topping
A
16
66.2
4.1
9
192.8
21.4
25
259.0
10.4
& Offsite Treat-
Cracking
B
1
5.5
5.5
20
839.3
42.0
21
844.8
40.2
ment Refineries
Petrochemical
C
0
-
-
3
341.4
113.8
3
341.4
113.8
Lube
D
0
-
-
2
146.3
73.2
2
146.3
73.2
Integrated
E
0
-
-
1
233.5
233.5
1
233.5
233.5
Totals
T7
71.7
4.2
35
1 ,753.3
50.1
5?
1,825.0
35.1
Effluent & Water
Topping
A
42
205.8
4.9
21
473.3
22.5
63
679.1
10.8
Quality Limited
Cracking
B
10
60.6
6.1
81
5,290.4
65.3
91
5,351.0
58.8
Refineries
Petrochemical
C
0
-
-
20
2,703.7
135.2
20
2,703.7
135.2
Lube
D
1
3.7
3.7
15
2,786.4
185.8
16
2,790.1
174.4
Integrated
E
0
-
-
8
1,893.6
236.7
8
1,893.6
236.7
Totals
53
270.1
5.1
145
13,147.4
90.7
198
13,417.5
67.8
Basis; As of January 1, W4.
Note: The Amerada-Hess refinery at St. Croix, V.I., has been excluded from the Topping subcategory and all
affected totals.
-------
TftBlE 1II-6
FOR MISCELLANEOUS FLOW REDUCTIONS-
—sample or CUSS 6 REFinEMES—
Gal./Bbl.
1972 RefJ1)
Cap..MB/SD
RWL
Survey
Flow, g/B
OTCW
Bar.(2)
Cond.
Assumed Flow
After Elim.
OTCW & B.C.
Flow After
Misc. Flow
Reductions
New
Percent
Reduction
Investment
Original
B & R
, MM$
New
Area 3
105.0
1,144.19
Yes
40.0
25.0
37.5
.
0.18
12.7
11.05
-
Yes
4.75
4.75
-
-
-
51.0
13.53
-
-
13.53
13.53
-
-
-
165.0
111.56
Yes
-
83.0
25.0
69.9
2.50
7.90
125.0
174.24
Yes
-
91.0
25.0
72.5
3.45
9.12
11.5
14.07
-
-
14.07
14.07
-
-
-
11.2
199.66
Yes
-
40.0
25.0
37.5
-
0.05
110.0
85.82
-
-
85.82
25.0
70.9
1.90
6.97
76.0
34.56
-
-
34.56
25.0
27.7
-
0.05
Basis: References 2 and 8. Original target flow was 40 gal./Bbl; BPCTCA target is 25 gal./Bbl. 1972
dollars.
Notes: (1) For some refineries, it was necessary to use the "run on date" figure since capacities were
missing from the data in Reference 8.
(2) The flow redjction effect of converting barometric condensers to surface condensers was assumed
by Brown & Root to be an average of 6.3 gal./Bbl.
-------
TABLE II1-7
INVESTMENT SUMMARY -
121 LARGE REFINERIES
ON current study BASIS
(RHST
In-Plant
Other End-of-Pipe Treating
Convert Misc. Flow In- Treatment Sludge Aux.
OTCM Reductions Plantl') Processes Handl. Facll. Totals
BpCTCA
Class A
3
1
6
4
4
1
19
Class B
47
138
57
73
45
25
385
Class C
76
25
52
56
23
26
258
Class D
18
9
19
15
10
10
81
Class E
56
10
52
78
26
34
256
Totals
200
183
186
226
108
96
999
In-Plant
Wastewater
Flow
Reduction^)
End-of-Pipe
Treating
Treatment
Processes
Sludge
Handl.
Totals
BATEA
Class A 2 5 18
Class B 27 76 9 112
Class C 19 60 6 85
Class D 9 26 2 37
Class E 15 _5l _6 _78
Totals 72 224 24 320
Basis: Area 3, 1972 $.
(1) Includes sour-water stripping, storm-water handling, conversion of
barometric condensers, and collection of multiple effluents.
(2) Includes recycling of cooling tower blowdown and effluent treatment
for reuse.
-------
TABLE III-8
SAMPLE INVESTMFNTS .
EPA
BPCTCA
SMALL REFINERIES (Mil
In-Plant
' r n\ "owiienc iiudqe
In-Plant[ ) Processes Handling Totals
j'i-nant End-of-Pipe Treating
Crude EliminateMisc. FlowOther treatment Sludge
Cat. Cap., B/SD OTCW Reductions In-Plant'') Pmroc<-«c
2,200
0
129
159
4,000
5,000
-
c
3
360
54
255
377
430
111
159
242
681
5,200
10,000
10,400
395
634
163
47
394
415
109
20
275
282
326
322
1,441
1,761
2,500
3,500
5,500
5,500
10,400
312
340
278
*
123
774
217
416
412
372
553
146
190
80
265
493
181
221
290
425
884
1,105
492
1,362
2,245
EPA
Cat.
batea
Crude
Cap., B/SD
2,200
4,000
5,000
5,200
10,000
10,400
2,500
3,500
5,500
5,500
10,400
Basis: Area 3, 1972 $.
* Less than $1,000.
In-Plant
wastewater
Flow Reduction(2)
94
135
63
165
247
113
140
152
183
275
End-of-Pjpe Treating
Trea tment Sludge
Processes
97
146
120
38
265
280
125
156
212
212
325
Handling Totals
34
225
48
329
9
192
-
38
84
514
86
613
62
300
75
371
99
463
99
494
145
745
(1)
Includes sour-water stripping, storm-water handling, conversion of barometHr r™
densers, and collection of multiple effluents Barometric con-
(2) Includes recycling of cooling tower blowdown and effluent treatment for reuse.
-------
TABLE III-9
TOTAL INVESTMENT - ALL SMALL REFINERIES
BPCTCA
EPA
Capacity,
MB/SD
Investment
Subcat.
No.
Total Avg.
M$
$/B/D
1
A
B
42
1JL
205.8 4.9
64.3 5.8
29,246
13,900
142
216
Totals -
53
270.1 5.1
43,146
160
BATEA
A
B
42
11
205.8
64.3
4.9
5.8
11,710
5,418
57
84
Totals -
53
270.1
5.1
17,128
63
TOTAL
A
B
42
11
205.8
64.3
4.9
5.8
40,956
19,318
199
300
Totals -
53
270.1
5.1
60,274
223
Basis; Area 3, 1972 $.
Note: The only subcategory-D (Lubes) refinery with less than 10 MB/SD
capacity has been included in Category B for these computations.
-------
TABLE 111-10
INVESTMENTS FOR NEW CAPACITY
MM$
Year
Grass Roots
Expansions
Total
1974
_
35
35
1975
6
27
33
1976
24
62
86
1977
12
21
33
1978
18
74
92
1979
16
27
43
1980
-
41
41
1981
16
27
43
1982
-
41
41
1983
_
41
41
Totals
92
396
488
Basis: Area 3, 1972 $.
Assumptions:
• Expansions prior to 1978 will be designed to meet
BPCTCA guidelines. The added investment to meet
BATEA guidelines will be expended uniformly from
1978 through 1983.
• Expansions after 1977 will be designed to meet
BATEA guidelines.
• All new refineries will be designed for BADT flow
and BPCTCA technology, plus activated carbon
adsorption.
-------
TABLE II1-11
DIRECT OPERATING COSTS FOR
121 LARGE REFINERIES
% of Investment
Cost Associated With - Investment MM$
Elimination of OTCW N/A 200
Miscellaneous Flow Reductions 15.0 183
Sour-Water Stripping 48.8 40
Storm-Water Handling 5.0 125
Bar.Cond./Mult. Eff. 10.0 21
Equalization 5.0 30
Dissolved Air Flotation 18.9 34
Activated Sludge 17.3 90
Filtration 18.9 29
Conting. & Sewer Revisions 0.0 47
Sludge Handling 25.0 131
Auxiliary Facilities 11.0 %
Recycle of CT Blowdown 11.0 11
Effluent Treatment/Reuse 5.0 61
Carbon Adsorption 17.2 195
Reuse Handling 5.0 27
Totals 1,320
~nr
1977
MM$/Year
increment
for BATEA
total ~
In 1983
5
-
5
27
-
27
20
-
20
6
-
6
2
-
2
2
-
2
6
-
6
16
-
16
5
1
6
0
-
0
27
6
33
11
-
11
-
1
1
-
3
3
-
34
34
-
J.
1
127
46
173
Basis: Area 3, 1972 $.
Source: Percentages were adopted or estimated based on data in
Reference 2.
-------
IV-1
IV. CONTROL OF AIRBORNE EMISSIONS
A. Background and Scope
Three major categories of airborne emissions were selected for
study:
• Hydrocarbon emissions from storage tanks, API
separators, and loading racks
• Carbon monoxide and particulate emissions from
catalytic cracking units
• Sulfur oxide emissions from combustion of gaseous
fuels and from Claus sulfur plant effluent
Information pertinent to each of these sources is presented sequen-
tially under each report topic. The control of sulfur oxide
emissions from liquid fuels is included in Section V.
B. Summary
The control areas covered in this report include direct Federal
new source regulation along with state regulation of existing
facilities and some new facilities which are not federally controlled.
The state regulations were suggested by EPA wh-n State Implementation
Plans were being developed.
The total investment requirements over the period 1974 through
1983 and the total annual costs of these regulations for 1983 are
summarized below:
Investment Annual Costs
($MM) ($MM)
Hydrocarbon Control
Tankage
API Separators
Loading Racks
75.3 (9.8)
24.3 (19.4)
66.? (0.3)
Sub-Total
~1W.S (293)
Catalytic Cracking Control
Carbon Monoxide
Particulates
Sub-Total
218.2
217.5
435.7
(70.0)
68.0
1270)
Sulfur Oxide Control
Fuel Gas Burning
Sulfur Recovery Plants
Sub-Total
325.7
352.8
"6TO
(17.4)
123.3
TOO
Total
1,280.0
\
74.4
-------
IV-2
Yearly investments and costs are shown in Tables IV-1 and IV-2, re-
spectively.
In addition to overall industry effects, we investigated the
effect of refinery size. The following table illustrates that the
unit investment cost becomes much greater as the refinery size de-
creases:
Refinery Size, B/SD 10,000 61,900 200,000
Investment, $MM
Hydrocarbon Control
Tankage 0.72 1.88 4.85
API Separator 0.03 0.08 0.17
Loading Racks 0.14 0.22 0.32
Sub-Total 0.89 2.18 T.14
Catalytic Cracking Control
Carbon Monoxide 0.92 2.76 5.57
Particulates 0.37 1.10 2.23
Sub-Total T7?9 3786 7.80
Sulfur Oxide Control
Fuel Gas Burning
0.71
2.31
4.94
Sulfur Recovery Plants
0.25
0.96
2.05
Sub-Total
1.00
3.27
6.59
Total
3.18
9.31
20.13
Investment, $/Bbl/Day
318
150
101
Thus, the 10,000 barrel per day refinery experiences more than three
times the investment requirement of a 200,000 barrel per day refinery
on a barrel of capacity basis. As another point of perspective,
the required investment for pollution abatement is essentially equal
to the cost of a new atmospheric crude distillation unit for each of
the refinery sizes.
Annual costs as a function of size were also determined:
Refinery Size, B/SD 10,000 61,900 200,000
Annual Costs, $M
Hydrocarbon Control
Tankage 61.4 (258.0) (1,113.6)
API Separator (6.7) (65.8) (240.7)
Loading Racks 32.3 1.0 (117.1)
Sub-Total 87.0 (320") (1,471.4)
-------
IV-3
Catalytic Cracking Control
Carbon Monoxide
Particulates
Sub-Total
56.2 (526.6) (2,702.0)
112.2 341.0 703.7
T60" (TO) (T^gSCT)
Sulfur Oxides Control
Fuel Gas Burning
Sulfur Recovery Plants
Sub-Total
206.4 440.9 619.8
110.9 335.2 725.4
31773" 776TT 1 ,345.2
Total
572.7 267.7 (2,124.5)
Annual Costs, {/Barrel
16.5
1.2
(3.1)
The effect of refinery size on annual costs is even more dramatic
than the investment effect.
While we feel that the values in this report give an accurate
assessment of average industry effects, we caution that specific
refineries may present significant deviations from the average. Some
individual refiners may be affected even more severely than in-
dicated by the above illustration. As an example, we know of a
facility equipped with numerous small cone-roof tanks. These tanks
are all much smaller than one would predii.i from industry statistics,
thus compounding the economy-of-scale problem. While the tanks are
structurally adequate, they have settled on their foundations and
are out-of-round. Thus, even if the economies-of-scale problem could
be overcome it would be impossible to equi,, these tanks with float-
ing roofs. Similar individual problems exist in the other control
areas.
C. Regulations
EPA has promulgated standards of performance for new or substan-
tially modified storage tanks, fluid catalytic cracking unit regen-
erators and refinery fuel gas systems.™) New or substantially modi-
fied has been interpreted to mean any physical cMnge in or change in
method of operation which increases the emissions of any air pollutant
or which results in emission of any new air pollutant.^' These regu-
lations became effective on February 28, 1974, and they apply to fa-
cilities on which construction or modification began after June 11,
Storage vessels for crude petroleum, condensate and finished or
intermediate refinery products with capacities greater than 40,000
gallons are covered by the regulation. A vapor recovery system or
equivalent control is required for liquids with true vapor pressures
greater than 11 psia. A floating-roof tank or equivalent control is
required if tank contents have a vapor pressure between 11 and 1.5
psia. Products with vapor pressures less than 1.5 psia can be stored
in conventional fixed-roof tanks. (The major products with vapor
1973.
-------
IV—4
pressures greater than 1.5 psia are gasoline, crude oil and naphtha
type jet fuel. Products such as kerosene, No. 2 fuel and heavv fuoi
oil all have vapor pressures less than 1.5 psia.) EPA has not issmL
any standards dealing with API separators or loading racks.
Carbon monoxide emissions are limited to a maximum concentration
of 500 ppm (0.05% by volume) in the fluid catalytic crackinq unit
regenerator effluent gas. The opacity of effluent gases may not
exceed 30% except for three minutes in any one hour Particulate
matter (catalyst fines) is also restricted to less than one kiloaram
per 1,000 kilograms of coke burned in the regenerator If a carbon
monoxide (CO) boiler is utilized along with supplemental liquid or
solids fuels, the particulate standard is increased to account for
the allowable particulates formed from the supplemental fuel Pro
visions are made for temporarily exceeding the maximum opacity limit
during periods of startup, shutdown or equipment malfunction.
Sulfur oxide_emissions from the refinerv fuel gas system are
1 i mi ted by prohibiting combustion of fuel gas with a hydrogen sulfide*
content greater than 0.1 grains per dry standard cubic foot The
fuel gas combustion system is defined to include process heaters
boilers and flares. Combustion of process upset gases in flares'
and operations involving fluid coking unit coke burner fuel qas and
fluid catalytic cracking unit catalyst regenerator fuel gas are
exempt. Facilities in which gases are burned to produce sulfur or
sulfuric acid are also exempt. (Thus, sulfur recovery plants arp
not covered by the EPA regulations.)
In addition to specific new source performance standards EPA
also has influenced application of state controls to both new'and
existing refining facilities. In assisting in preparing State
Implementation Plans, EPA suggested that states should consider both
the above and additional emission 1 imitations.Since existinq
facilities are controlled under the SIP's, this had the effect of
extending EPA's regulations for new sources to existing refineries
The additional suggested limitations for hydrocarbons include vapor
collection and disposal systems at truck and tan^ . or ioadinq racks
installation of vapor-control devices on API separators, equippina
pumps and compressors handling volatile organic compounds with mechan
ical seals, and incineration of waste gas streams. Limiting emissions
of sulfur oxides from sulfur recovery plants to a level of 0.01 pound
per pound of sulfur processed was also suggested.
In order to determine the degree of acceptance of EPA's suqqes
tions in current SIP's, we selected a representative sampling of re"
finery pollution-control practices. The ares? included California
Kansas, Oklahoma, Texas, Louisiana and Illinois. As of January 1 *
1974, these states included 51% of the U.S. refineries and 65% of'the
refining capacity. Summaries of the information obtained from the
state plans are shown in Tables IV-3A, IV-3B and IV-3C for hvdrocar-
bons, catalytic cracking units, and sulfur oxides, respectively U-15)
-------
IV-5
Except for the Midwest, state hydrocarbon regulations apply
to both new and existing facilities. All states have enacted essen-
tially the same regulation for storage tanks as EPA's new source
performance standard. In addition, most of the states have specified
controls for loading racks, API separators, and burning of waste gases.
However, we know of no installations in which significant quantities of
hydrocarbon waste gases are continuously emitted without burning be-
cause of safety considerations.
For purposes of this report, then, all new refineries are as-
sumed to be built with floating-roof tanks for gasoline, crude oil
and naphtha jet fuel. Vapor recovery facilities are provided at tank
car and tank truck loading racks. API separators include hydrocarbon
recovery facilities. We also forecast that all existing refineries
not already in compliance will upgrade their facilities with respect
to these control areas over the five year period 1974-1978.
State regulations for catalytic cracking units apply to both
new and existing units in most cases. Unlike EPA's standard, the
state regulations apply to catalytic cracking units or petroleum
processes; they are not limited to fluid catalytic cracking units.
Thus, Thermofor and Houdriflow catalytic cracking units are in-
cluded under the state regulations.
Both carbon monoxide and particulate emission standards are ex-
pressed in several ways. Carbon monoxide is limited by specifying
a total yearly emission rate, a maximum concentration, or specifying
that secondary combustion must be utilized, "articulates are con-
trolled by imposition of opacity (or Ringleman) limits and hourly
emission rates based on "process weight tables". The practical ef-
fect is to require addition of controls to existing units for both
carbon monoxide and particulates.
Based on these considerations, we provided that all new cata-
lytic cracking facilities will include equipment to limit both carbon
monoxide and particulate emissions to the specified Federal levels.
We also assumed that all existing catalytic cracking units which are
not in compliance with respect to carbon monoxide and particulates
will add facilities to achieve compliance. Addition of the necessary
equipment to all existing units is forecast by 1978.
State sulfur oxide regulations also generally cover existing
facilities, both for refinery fuel gas and sulfur recovery plants.
Again the state regulations are stated in a variety of ways. Sulfur
oxide emissions from refinery fuel gas systems are limited by ground
level concentrations, exhaust gas concentrations or specific limits
on hydrogen sulfide concentration in the fuel gas system. Sulfur
recovery plant controls range from concentration limits in the ex-
haust gas to hourly emission limitations which are a function of
stack heights.
-------
IV—6
Me have assumed that all new refineries will be equipped with
amine scrubbing facilities capable of producing refinery fuel gas
with a maximum hydrogen sulfide content of 0.1 grains per dry stan-
dard cubic foot. The refinery will also be equipped with a sulfur
recovery plant to convert the hydrogen sulfide removed from the re-
finery fuel gas into sulfur. The sulfur recovery plant will be
equipped with a tailgas treating unit capable of effecting an overall
sulfur recovery of 99.5%. We have also assumed that all non-complying
existing refineries will install the same equipment over the five-year
period 1974-1978.
0. Control Technology
The control technology for minimizing emissions from storage
tanks is straightforward and well established. In the case of exist-
ing tanks, an internal floating roof can be installed Inside the
cone-roof tank. For new installations, either an internal or external
floating roof (depending on local climatic conditions) can be supplied
in the initial construction. Technology for controlling vapors at
loading racks through absorption of hydrocarbons from the hydrocarbon
air mixture is also relatively straightforward. This system Involves
collecting the vapor with a vapor recovery loading arm. The recovered
vapors are then compressed and absorbed in a special vapor recovery
unit. Control of emissions from API separators consists of installing
a floating cover on the API separator. Several different types of
covers and cover materials have been utilized.
Carbon monoxide emissions from catalytic cracking units can be
controlled in two ways. The regenerator car be equipped with mate-
rials necessary to withstand high-temperature regeneration in the
area of 1,300 to 1,500°F. At these temperatures, carbon monoxide 1s
essentially all converted to carbon dioxide. The second method 1s
to burn the carbon monoxide from conventional regenerators (1,000 to
1,200°F.) in a carbon monoxide boiler. The former method is rela-
tively new and looks promising. The increased regenerator metal -
urgy cost is at least partially balanced by eliminating the need for
a CO boiler and by increased performance of the catalytic cracking
unit due to better catalyst regeneration. We provided for control
of carbon monoxide by CO boilers. This should tciiJ to give high
values of investment and operating costs. Catalyst fines from a
catalytic cracker can be controlled by additional cyclones, electro-
static precipitators or filters. Electrostatic precipitators are
utilized in most cases and we have applied +his type of equipment In
this report.
Several processes exist for removing hydrogen sulfide from re-
finery gas and converting 1t to sulfur. Some of the processes accom-
plish this 1n a single step. For purposes of this report, we have
utilized an absorption unit with dlethanolamine as the absorption
medium (amine plants). The recovered hydrogen sulfide is converted
in a conventional Claus sulfur plant. The effluent from the Claus
plant can also be treated by several processes. Since all of these
are relatively new, we derived average levels of investment and
operating costs for the various processes and used a hybrid process
(tailgas plants).
-------
IV-7
E. Industry Characterization
There are no statistics which indicate the amount of construc-
tion yet to be performed by existing refineries to control hydrocar-
bon emissions. Inspection of the effective dates in Table IV-3A could
lead one to conclude that most existing facilities have already in-
stalled the equipment covered in this report. However, we are ac-
quainted with numerous existing plants which have not yet completed
installation of all of the required equipment. The causes for the
delay normally involve requirements for additional design and equip-
ment procurement lead time. The delays are effected through variances
granted by local authorities.
While it is difficult to arrive at a quantitative estimate of the
current status of hydrocarbon emission control in existing refineries,
we are confident that essentially all facilities in District V have
installed this equipment. We have assumed that all existing refineries
not located in District V will have to add controls. This treatment
will tend to give high investment and operating estimates.
Based upon the assumption of total compliance in District V,
criteria for additional base refinery controls then become:(16,17)
Percent in
Districts I-IV
Refinery Capacity 83.7
Crude Oil Tankage 73.5
Gasoline Tankage 85.8
Naphtha Jet Fuel Tankage 66.9
A forecast of future petroleum demand and additional refinery
capacity requirements is presented in detail in Section II and III.
Table IV-4 summarizes this information with respect to forecast
refinery capacity installations and additional gasoline and naphtha
jet fuel production.
We assumed that 75% of both new and existing uankage for crude
oil and jet fuel would have been constructed as floating-roof tankage
in the absence of any pollution regulations due to the beneficial
economic effect of increased product recovery.(18) For gasoline
storage the recovery economics are better t*>an for crude oil or naphtha
jet fuel, and a base tankage distribution of 90% floating-roof tanks
and 10% fixed-roof tanks was used for this product.''9/
Storage tank capacity at refineries for crude oil, finished
gasoline, finished naphtha jet fuel and totol unfinished oils are
available from industry statistics.In addition to finished pro-
ducts, unfinished components of both gasoline and naphtha-type jet
fuel are also covered by tne tankage regulations since their vapor
pressures are generally greater than 1.5 psia. The total unfinished
-------
IV-8
oil volume in inventory as of September 30, 1973, was determined from
Bureau of Mines statistics*-^ for the U.S. refining industry. Un-
finished oil inventories for Puerto Rico, Virgin Islands and Guam
were estimated. The portion of the total unfinished oil inventory
assignable to gasoline and naphtha jet fuel was determined on the
basis of the proportion of the inventory of these products to total
product inventories. A factor of two barrels of storage capacity
per barrel of stored product was applied to the unfinished oil
volume to determine the unfinished oil tankage in accordance with re-
cent petroleum industry experience.('/) These adjustments result
in the following estimate of existing tankage at refineries as of-
January 1, 1974:
H Barrels
Crude Oil 154,364
Finished Gasoline 191,209
Unfinished Gasoline 73,44b
Total 264,654"
Finished Naphtha Jet Fuel 7,785
Unfinished Naphtha Jet Fuel 3,359
Total TT7FW
Neither distribution nor marketing facilities are included in
this report. Focusing on storage at refineries, the following data
were developed:v16,17,21,22)
U.S. Refinery Capacity
U.S. Refinery Runs
Crude Oil Storage at U.S.
Refineries
U.S. Gasoline Production
Finished Gasoline Storage
at U.S. Refineries
U.S. Naphtha Jet Fuel
Production
Finished Jet Fuel Storage
at U. S. Refineries
1970-1974
Growth Rate
%/Year
4.0
4.1
4.4
3.3
3.3
-10.9
-8.4
Days of Crude
Oil Capacity
at 9/30/73
10.1
12.8
0.5
TL. th,t rrude oil, gasoline and naphtha jet fuel tankage vol-
™! at rpfineries have al 1 grown at almost the r.an» rate as the re-
active commodity to be sJed. This indicates that refineries ha,e
reached the minimum tankage configuration.
-------
IV-9
Thus, historical trends were used to develop an estimate of addi-
tional tankage to be constructed at refineries. For crude oil, we
estimated that storage capacity equal to 10.1 days of crude capacity
would continue to be provided. (While increased storage may be re-
quired for increased delivery of imported crude in large tankers, we
have assumed that this storage would be provided at deepwater
terminals. Thus it would be included in the distribution system
but would not affect refinery tankage facilities.) We utilized
storage capacity for gasoline equal to 39.1 days of gasoline pro-
duction, including both finished and intermediate tankage. The re-
sulting aggregate amount of new tankage for each product through 1983
is as follows:
M Barrels
Crude Oil 50,264
Finished Gasoline 49,970
Unfinished Gasoline 19,190
Total 69,160
Finished Naphtha Jet Fuel 0
Unfinished Naphtha Jet Fuel 0
Total " 0
Existing crude oil tankage to be converted to floating-roof tank-
age was derived from the total installed tankage as of 1/1/74 com-
bined with the 75% baseline factor and the p.-eviously derived 73.5%
proportion which we estimate has not been converted. We estimated
that this volume would be converted equally over the five-year period
starting with 1974. The resulting volumes of existing crude oil
tankage to be converted to floating-roof are summarized in Table IV-5.
Additional crude oil tankage associated with new refinery construction
is also shown. These volumes also reflect a 75% baseline factor. Ex-
isting gasoline tankage to be converted was determined using a factor
of 90% for baseline control and a factor of 85.8% to reflect units
not already converted. Again the conversion was assumed to be even
over five years. Additional gasoline tankage was also estimated us-
ing a baseline factor of 90%. Existing naphtha jet fuel conversion
to floating-roof was estimated with a baseline factor of 75% and a
factor of 66.9% reflecting current conversion practice. No new
naphtha jet fuel tankage is forecast, reflating a zero product growth
forecast.
Previous investigators(23) have estimated average size distri-
butions for both crude oil and gasoline and naphtha jet fuel tankage.
This gives a weighted average size of 80,400 barrels for crude oil
tanks and 60,800 barrels for tanks containing gasoline and naphtha
jet fuel.
-------
IV-10
No statistics are available for the number of loading racks at
various refineries in the United States. While admittedly a simpli-
fication, we estimated that each refinery on the average has two
loading racks - one for tank trucks and one for tank cars. We also
assumed that this position would prevail for future refineries. The
throughput was assumed to be 10% of refinery capacity for both exist-
ing and new refineries. In our opinion, no loading rack hydrocarbon
recovery facilities would have been installed in the absence of
pollution regulations. Thus, the baseline factor is zero. We do
think that essentially all refineries in District V are in compliance
with this regulation. The refinery capacity in District V was de-
ducted in order to establish the amount of control still to be applied
to existing refineries. We selected a refinery capacity of 61,900
barrels per stream day as our sample facility. This is the approxi-
mate average U.S. refinery size as of 1/1/74. This size was used
for both existing and new refineries.
We were unable to locate any statistics which established base-
line levels for installation of hydrocarbon recovery facilities on
API separators. In our experience, very few refineries have moved
to install this equipment. We do not think that facilities of this
type would have been constructed in the absence of pollution con-
trols. Thus, we used a baseline control level of zero. In terms
of controls already applied to existing refineries, we utilized a
conservatively large estimate by assuming that all existing
refineries not located in District V would be required to add these
facilities.
Unlike the hydrocarbon situation, some data on baseline in-
dustry characteristics are available for catalytic cracking units.
An EPA survey in August 1971 indicated that 69/1 of the total domestic
U.S. fluid catalytic cracking unit capacity was eauipped with CO
boilers and 29% had electrostatic precipitators.^' We assumed
that the installed catalytic cracking capacity as of 1/1/74 is con-
trolled to the same degree which will tend to overstate the required
investment and operating cost to some degree.
The forecast of future petroleum demand in Section II indicates
that the percentage yield of products heavier than distillate will
remain essentially constant over the 1974-1985 timeframe. This
suggests that no dramatic shift in utilization of gas oil conversion
capacity as a proportion of crude charging capacity should be antici-
pated. As of 1/1/74, catalytic cracking capacity represented 31%
of U.S. domestic refinery capacity.116' This value has been used in
this report. A summary of forecast catalytic cracking capacity addi-
tions is included in Table IV-4.
A total catalytic cracking capacity as of 1/1/74 of 4,667 MB/D
was developed from industry statistics.* ,b»*A> Using this capacity
and a baseline installation factor of 69% enabled us to estimate the
existing catalytic cracking unit capacity as of 1/1/74 which will
-------
IV-11
have CO boilers installed in the future. We have assumed that these
installations occur linearly over the five-year period 1974-1978.
The resulting catalytic cracking unit capacities are summarized in
Table IV-5. Likewise, utilizing the forecast catalytic cracking unit
capacity additions from Table IV-4 and the 69% baseline factor, the
amount of new catalytic cracking unit capacity to be equipped with
CO boilers as a pollution-control measure can also be derived. These
volumes are also summarized in Table IV-5.
Using the 1/1/74 installed capacity and the assumption that 29%
of this volume is equipped with precipitators leads to the volumes
yet to be equipped shown in Table IV-5. In this case, we have also
assumed that the precipitators would be installed over the five-year
period 1974-1978 in a uniform pattern. Additional capacity which
will also be equipped precipitators is shown in Table IV-5. These
values were obtained from the forecast of additional catalytic crack-
ing capacity in Table IV-4. In both cases, a baseline factor of
zero was used since installation of a precipitator is essentially
all attributable to pollution control.
The current average catalytic cracking unit size is 31,100 bar-
rels per stream day. We have utilized this average value in develop-
ing the unit costs in this report. This tends to understate to some
extent the cost involved in installing CO boilers and precipitators
on existing equipment since the units yet to be converted tend to be
smaller than the average size. On the other hand, it tends to over-
estimate the cost for new refining units sine1 these units would
probably have a capacity greater than the average value.
No statistics exist which establish the number of refineries
which are equipped with amine absorption units or other equivalent
processes for the removal of hydrogen sulfide from refinery fuel gas.
However, removal of this material has beneficial effects for the
refiner in terms of personnel safety and furnace corrosion. We esti-
mate that essentially all U.S. refineries are equipped with amine
scrubbing facilities. The exceptions would be small refineries uti-
lizing sweet crude with low intensity processing. For purposes of
this report, we assumed that 95% of the existing refinery capacity
is equipped with amine absorption facilities. We have also adopted
this value as the baseline control criteria. Some existing amine
plants will have to be upgraded to achieve lower levels of hydrogen
sulfide in refinery fuel gas systems. To approximate this effect,
we reduced the baseline factor to 85%. In effect, we are forecast-
ing that sums equivalent to replacing approximately 10% of existing
capacity will be sufficient to upgrade existing plants to new perfor-
mance levels.
Other investigators have determined that the average crude mix
processed in the United States refineries in 1970 was 30°API with a
sulfur content of 0.92 weight percent.(25) ye have applied these
values to industry capacity as of 1/1/74. A recovery factor 1n the
-------
IV-12
fuel gas of 70% of the sulfur in the incoming crude oil was utilized/19)
These assumptions led to the estimate of existing amine plant capacity
to be controlled above baseline capacity shown in Table IV-5. We
assumed that the capacity to be converted as of 1/1/74 would be in-
stalled evenly over the period 1974 through 1978.
Amine plants associated with new refinery construction are also
shown in Table IV-5. In this case, we assumed that crude utilized
in new refining capacity would have a sulfur level of 2.0 weight per-
cent, reflecting higher sulfur contents of Arabian Gulf crudes. We
continued to use a 95% baseline factor and to assume that 70% of the
sulfur in the incoming crude would be removed into the fuel gas sys-
tem. We again selected an average refinery size of 61,900 barrels
per stream day for both existing and new refineries.
A study conducted for EPA established the individual location
and capacity of Claus sulfur recovery plants utilized by petroleum
refineries as of mid-1972We combined this data with industry
statistics for individual refinery locations and capacities^27.28)
to derive the listing of refineries and sulfur plants in Table IV-6.
This indicates that approximately 8.5 million barrels per day of re-
fining capacity, or about 61% of industry capacity, was equipped with
sulfur recovery facilities. We have extrapolated the percentage of
industry capacity which is equipped with sulfur recovery facilities
to the 1/1/74 timeframe to approximate the existing capacity which
is not equipped with sulfur recovery facilities. We feel that this
gives conservatively high values of investment and operating costs.
A baseline factor of zero was applied.
We used the same assumptions relative to crude gravity, crude
sulfur content and recovery factor of hydrogen sulfide as were uti-
lized in developing the amine plant capacity requirements. These
factors, along with the survey value of S\% for industry capacity
equipped with sulfur plant facilities, lead to the additional plant
capacity requirements shown in Table IV-5. Capacity requirements
for Claus plants associated with new refineries are also shown in
this table.
A survey by other investigators^29) identified installed capacity
of approximately 964 metric tons per day of Claus plant tailgas treat-
ing facilities as of 1974. We assumed that all other existing Claus
plants as of 1/1/74 would require installation of tailgas cleanup
facilities. We also assumed that all new plants would be built with
this equipment. In our opinion, none of these facilities would have
been added in the absence of pollution-control regulations. There-
fore, we have utilized a baseline factor of zero.
In developing the capacity requirements shown in Table IV-5, we
used the same assumptions relative to crude gravity, crude sulfur
content, and recovery factor of hydrogen sulfides as we had previ-
ously utilized in developing the amine plant capacity requirements.
An average refinery size of 61,900 barrels per stream day was selected
for both new and existing refineries.
-------
IV-13
Investments
The differential investment for building a floating-roof tank
and the cost of converting an existing cone-roof tank have been esti-
mated by several investigators.('*30,31) Values from these sources
were adjusted to the desired mid-1974 cost basis and utilized to
obtain the investment values included in Table IV-7. Unit costs from
this table were then combined with the tankage volumes to be con-
trolled to arrive at the overall industry effects summarized in
fable IV-1.
Typical investments for API separator modifications are presented
in Table IV-8. We were guided in developing these estimates by con- ,
sideration of previous Investigations and reported installation data.1'
The values in Table IV-1 were obtained using these unit costs. Invest-
ment values for vapor recovery facilities in Table IV-9 were estimated
based upon results reported by industry investigators.)
Cost estimates for CO boilers were; available from several sources.
(19,33,34) utilizing data in these studies and information in our
files, we developed investment values based on the desired mid-1974
timeframe. The values shown in Tables IV-10 and IV-11 resulted. Data
from other investigators were combined with information in our files
to arrive at consensus values for precipitator investment.H9,33)
This information is shown in Tables IV-12 and IV-13. For existing
units, we estimated that the required investment would be 2055 greater
than a grassroots unit for both CO boilers and precipitators.
Typical investment requirements for amine plants are shown in
Table IV-14. These values were determined by surveying several other
investigators' results combined with information in our files.(26)
The values shown for Claus plants in Table IV-15 were derived in a
similar manner. The same sources were also used for the Claus plant
tailgas cleanup costs shown in Table IV-16.
Annual Costs
Maintenance costs for tanks, API separator modifications and
vapor recovery systems were estimated at 2% of investment per year.
Annual maintenance expenditures for other control equipment were set
at 4% of investment. Taxes and insurance were estimated at 4% per
year. An annual capital charge of 21.82% of investment was applied.
This value is the before-tax sum required to obtain a 12% discounted
cash flow rate of return on the total project investment with an in-
come tax rate of 50%, 16-year life, and straight-line depreciation.
The product recovery figures for floating-roof tanks shown 1n
Table IV-7 were estimated 1n accordance with standard industry pro-
cedures. (35,36) The product values are based on products costs de-
rived from incremental Imported crude at the $12.75/B acquisition
cost which prevailed 1n the petroleum industry 1n mid-1974. Tank
losses are quite sensitive to assumptions of vapor pressure, turn-
over rate and average liquid temperatures. The loss calculation
-------
IV-14
bases are summarized in Table IV-17. Cost variation with refinery
size is shown in Table IV-18. This indicates that installation of
floating-roof tanks is profitable except at small refinery sizes.
Product recovery estimates for API separators were derived
from previous studies.0»32) Since the recovered material is re-
cycled through the crude unit, a price of $12.75 per barrel
corresponding to the incremental mid-1974 foreign crude price was
applied. Again values were developed for two refinery sizes in
Table IV-8 in addition to the base facility in order to show the
effect of refinery size. Installation of these facilities is
profitable in all cases, but installation at the smaller refinery
generates less profit on a unit basis.
Product recovery volumes for vapor recovery at loading racks
shown in Table IV-9 were also taken from industry studies.Tl) The
product value approximates the cost of incremental petroleum pro-
ducts at mid-1974. Utilities (electricity and fuel) were estimated
based upon similar facilities. Installation of vapor recovery at
loading racks results in a cost to the smaller refinery and small
credit to a large refinery.
Values for steam generation by CO boilers in Tables IV-10 and
IV-11 were developed from literature correlations.(34) in using
these correlations, we assumed a feed density of 300 pounds per
barrel, 6 weight percent coke yield, and 90% line losses 1n the
steam system. Seventy-five percent of the calculated steam
generation was applied as a project credit. )his was done to account
for inefficiencies in heat level utilization and temporary steam
system imbalances which would not allow full utilization of the steam
from the CO boiler. Installation of a CO boiler is profitable for
larger refineries, but becomes a cost item as refinery size de-
creases.
Utility requirements for the precipitator units shown 1n Tables
IV-13 and IV-14 were derived from industry studies.('9.33) Installa-
tion of this equipment results in a cost in all refinery sizes. The
impact is greater for smaller facilities.
Utilities for amine plants in Table IV-14 and for Claus plants
in Table IV-15 were estimated from consensus values.(26) Labor and
supervision for the Claus plant was included at one-half man per
shift at $5.60 per hour with a 20% charge for supervision. A credit
for sale of sulfur at a price of $30.00 per long ton was utilized.
The $30.00 per long ton represents about 75% of the Gulf Coast load-
ing port price as of mid-1974. The plant netback would be less than
the Gulf Coast sales price due to transportation differentials. Again
the effect of size can be seen from this data.
-------
IV-15
Tailgas unit operating expenses are shown in Table IV-16.
Utilities were estimated from consensus values. Labor and super-
vision was included at one-fourth man per shift. Credit for sales
of sulfur at $30.00 per long ton was included. These units re-
sult in a cost in all size ranges.
-------
REFERENCES - SECTION IV
1. Hydrocarbon Emissions From Refineries, American Petroleum Institute,
Publication No. 928, July 19?3.
2. Compilation of Air Pollutant Emission Factors (Second Edition), U.S.
Environmental Protection Agency, Publication No. AP-42, April1973.
3. Financial Analysis of a Group of Petroleum Companies, The Chase Man-
hat taF~BanirriOrr7_T5TJI
4. Federal Register, Volume 39, No. 47, March 8, 1974.
5. Federal Register, Volume 36, No. 247, December 23, 1971.
6. Federal Register, Volume 36, No. 158, August 14, 1971.
7. Regulation 2, Bay Area Air Pollution Control District, May 4, 1960.
8 Regulation 3, Bay Area Air Pollution Control District, January 4,
1967.
9. Air Pollution Emission Control Regulations, State of Kansas, January 1,
T5W.
10. Oklahoma Clean Air Act and Air Pollution Cortrol Regulations, Oklahoma
State Department of Health, Bulletin No. 0550, July 1, 1973.
11. Regulation I, Control of Air Pollution from Smoke, Visible Emissions,
and Particulate Matter, Texas Air Control Board, January 26, 1972.
12. Regulation II, Control of Air Pollution from Sulfur Compounds, Texas
Air Control Board, March 5, 1972.
13. Regulation V, Control of Air Pollution from Volatile Carbon Compounds.
Texas Air Control Board, April 10, 1973.
14. Regulations of the Air Control Commission, State of Louisiana, Jan-
uary 18, 1972.
15. Air Pollution Regulations, State of Illinois Pollution Control Board,
February 7, 19747
16. "Annual Refining Survey", Oil & Gas Journal, April 1, 1974.
17 Petroleum Storage Capacity, National Petroleum Council, September 10,
Tg__
18. Duprey, R.L., "Compilation of A1r Pollutant Emission Factors", Public
Health Service, PB-190-245, 1968.
-------
REFERENCES - SECTION IV (CONTINUED)
34. Alexander, W.H. and Bradley, R.L., "Can You Justify a CO Boiler?",
Petroleum Refiner, Vol. 37, No. 8, pg. 107, August 1958.
35. Evaporation Loss from Fixed-Roof Tanks, American Petroleum Institute.
Bulletin 2518, 1962.
36. Evaporation Loss from Floating-Roof Tanks, American Petroleum Insti-
tute, Bulletin 2517, 1962.
-------
TABLE 1V-1
AOOITIONAL INVESTMENT FOR AIRBORNE EMISSION-CONTROL MEASURES
(SMM)
uyHrnrarbon Emissions
Tankage
Crude Oil
Crude Oil
Gasoline
Gasoline
Naphtha Jet
Sub-Total
Existing
New
Existing
New
Existing
Pp_1_ Separators
~ Existing
New
Sub- Tota 1
loading Racks
~Txisting
New
Sub-Total
Total
rarhnn Monoxide and
Particulate Emissions
CO Boilers
Existing
New
Sub-Total
1974
1975
1976
1977
6.0
6.0
6.0
6.0
1.3
1.1
2.7
1.0
5.5
5.5
5.5
5.5
0.8
0.8
0.8
0.8
0.5
0.5
0.5
0.5
TO
T375
TO
TO
3.5
3.5
3.5
3.5
0.9
0.8
1 .9
0.7
T74
""O
174
""O
9.6
9.6
9.6
9.6
2.5
2.1
5.1
1.9
T27T
TT77
TO
TO
1978 19/9 1980 1981 1982 1983 Total
34.2
6.5
4CT7
34.2
5.4
39.6
34.2
13._5
47". 7
34.2
4.9
39 .T
6.0
1.4
5.5
0.7
0.5
TO
3.5
1.0
't:s
9.6
2.6
TO
34.2
6.0
4i n
0.4
0.7
"T.l
0.8
TO
2.0
2.0
0.4
0.3
O
0.8
1575
0.4
0.3 0.3
0.4
0.3
2.0
T70
0.3
O
0.8
TTB
0.3
T75
0.8
"O
2.0
~275
0.4
0.3
T7 "17 "O 17
0.3
"O
0.8
"O
2.0
2.0
30.0
9.5
27.5
5.8
2.5
TO
17.5
6.8
20
48.0
18.2
Z.O
165.8
171.0
47.2
"TfO
Precipitators
Existing
New
Sub-Total
Total
31. i 31.3
8.4 _L0
30 38.3
31.3
17.4
4877
31.3
6.3
37.6
31.3
8.9
AO
2.6
T.6
2.6
T.6
2.6
T.i
2.6
"576
2.6
156.5
61.0
TIT5
435.7
SulfurJVyirie Emissions
Amine Plants
Existing
New
Sub-Total
8.4
1.0
"9.4
8.4
O.fl
9.1
8.4
2.1
TO
8.4
0.8
9.2
8.4
1.1
975
0.3
O
0.3
'"673
0.3
"071
0.3
T5T3
0.3
1571
42.0
7.3
TO
Claus Plants
Existing
New
Sub-Total
23.4 23.4
21.9 18.4
*573 4T. 8
23.4
45.5
6"0
23.4
16.5
SO
23.4
23.1
415.5
6.8
T.l3
6.8
O
6.8
67~8
6.8
"O
6.8
tts
117.0
159.4
"7TO
Tailqas Plants
Existing
New
Sub-Total
Total
GRAND TOTAL
45.1 45.1
17.5 14.7
6276 SO
45.1
36.4
3T5
45.1
13.2
SO
45.1
13.5
6375
5.4
T."4
5.4
"574
5.4
T75
5.4
TT5
5.4
"TT
225.5
127.3
~35n
678.5
1.280.0
-------
Hydrocarbon E_mi scions
Tankage
" Crude Oi 1 - Existing
Crude Oil - New
Gasoline - Existing
Gasoline - New
Naphtha Jet - Existing
Sub-Total
APi ^efa/at^rs
Existing
New
Sub-Total
Loading Racks
Existing
New
Sub-Total
Total
Carbon Monoxjde and
Particujate Emissions
CO Boi jerj,
Existing
New
Sub-Total
Prec i jji_ t_a tor
Exis'ting*
Now
Sub-TotaI
Total
SuJ fur Ox i tic t mi ssions
Amine. P I a_nts
~ ExTstinq
New
Sub-Total
Clams Plajits
~ Existing "
New
Sub-Total
Tai 1 qas__Plajits
TxTsting
New
Sub-TotjI
lot. a 1
TABLE IV-2
ANNUAL COSTS FOR AIRBORNE EMISSION-CONTROL MEASURES
(SMM/Year)
1974 1975 1976 1977 1978 1979 1980 1981 1982 1983
(0.49) (0.98)
(0.29) (0.54)
(0.77) (1.54)
(0.26) (0.52)
0.09 0.18
(i.72) ntiijy
(1.47) (1.96)
(1.15) (1.37)
(2.31) (3.08)
(0.78) (1.04)
0.27 0.36
(5.44) T7T09T
(2.45) (2.45)
(1.68) (1.77)
(3.85) (3.85)
(1.25) (1.46)
0.45 0.45
(8.78) (97087
(2.45) (2.45)
(1.86) (1.95)
(3.85) (3.85)
(1.57) (1.68)
0.45 0.45
I9.2§T TOt)
(2.45) (2.45)
(2.04) (2.13)
(3.85) (3.85)
(1.79) (1.90)
0.45 0.45
IW768) rosv
(2.82) (5.64) (8.46) (11.28) (14.10) (14.10) (14.10) (14.10) (14.10) (14.10)
(0.73) (1.34) (2.85 (3.40) (4.17) (4.40) (4.63) (4.86) (5.09) (5.32)
13715] toil (11.317 TT4768] 118.777 TiOoT T18773T "(T05) ni.Tfl [797477
(0.04) (0.08) (0.12) (0.16) (0.20) (0.20) (0.20) (0.20) (0.20) (0.2C)
(0.01) (0.02) (0.04) (0.05) (0.06) (0.06) (0.06) (0.06) (0.06) (0.061
tost TFTray W7T67 (OTT 707267 To72TT 707767 707267 707267 [072S7
(29.56)
(10.11) (20.22) (30.33) (40.44) (50.55) (50.55) (50.55) (50.55) (50.55) (50.55!
(2.68) (4.92) (10.47) (12.48 (15.30) (16.13) (16.96) (17.79) (IB.62) (19.45J
TT7775T TT57T47 [4007 (577927 7637857 (667681 I6775T) 7687347 [69717] HOST
9.76
2J3
12.39
19.52
4.84
24.36
29.28
10. 31
39.59
39.04
12.29
5T. 33
48.80
L5_.07
63.87
48.80
15.89
6?. 69
48.80
16-21
65". ST
48.80
12-53
66 733
48.80
IS. 35
67 75
48.80
19. J 7
67.97
: .03)
3.97 7.94
0.55 1.01
4.52 8.95
11.91 15.88
2.15 2.56
147 06 1 8.44
19.85 19.85
3.14 3.31
22799 23.16
19.85 19.85
3.48 3.65
23.33 23.50
19.85 19.85
3.82 3.99
23.67 23.84
(1.63) (3.26) (4.89) (6.52) (8.15) (8.15) (8.15) (8.15) (8.15) (8.15)
" (31.62) (33.03)
(39.77) (4T7T87
bwh fstsj m fits} m
15.73 31.46 47.19 62.y2 78.65 78.65 78.65 78.65 78.65 78.65
6.13 1 1.27 24.02 28_.65 35.13 37.03 38.93 40 83 42 73 44 63
21.85 472773 71.17 91 ,T7 fT377ft 173.6ft 117758 115 4ft 173.7ft
GRAND TOTAL
74.35
-------
TABLE IV-3A
STATE POLLUTION REGULATIONS FOR HYDROCARBONS
Controls Applied
Area
Effective
Date
Existing
Facilities
Exempt?
Storage
Loading
Racks
API
Separator
Mechanical
Seals
Burning
Waste
Gas
California
1/4/68
No
Yes
Yes
Yes
No
Yes
Kansas
1/1/72
Yes
Yes
No
No
No
Yes
Oklahoma
7/1/72
YesO)
Yes
Yes
Yes
Yes
Yes
Texas
12/31/73(2)
No
Yes
Yes
Yes
No
Yes
Louisiana
1/18/72(3)
No
Yes
Yes
Yes
Yes
Yes
111inois
12/31/73(4)
No
Yes
Yes
Yes
Yes
Yes
Notes: (1) Unless located in Air Quality Maintenance Area for hydrocarbons.
(2) Only applied in !"ore populus counties and does not apply to crude oil production and transportation
facilities.
(3) Crude oil and condensate facilities exempt.
(4) Illinois-produced crude oil exempt.
-------
1 ABLE IV-3B
STATE POLLUTION REGULATIONS FOR CATALYTIC CRACKING UNITS
Carbon Monoxide
Particulates
Area
Cali fornia
Kansas
Effective
Date
1/4/68
1/1/72
Existing
Facilities
Exempt?
Ok1ahoma
7/1/72
No
Yes (as of
1/1/72)
No
Texas
5/12/73
fiC
jtei^atM)ns_
300 pr>m total carbon
Burned at 1,300°F. for at
least 0.3 seconds.
Complete secondary com-
bustion (at least 93i
remova1).
Maximum of 5 tons/year
unless burn &1,300°F.
Effective
Date
5/4/6C
1/1/71
Existing
Faci1i ties
Exempt?
No
No
4/15/71
12/31/73
Yes
(Until
10/15/72)
No
Regulations
Less than No. 1 Ringleman ex-
cept for 3 mins in 1 hr.
Process weight @E = 4.10P®-®7.
Less than 0.15 gr/DSCF.
Less than 20% opacity.
Rapping allowed for 5 mins/
hr. Process weight PE =
4ip0.67 for ]ess than 30
T/hr. and E = {55)(P®•'*'') -
40 when greater than 30 T/hr.
Less than No. 1 Ringleman.
Rapping allowed for 5 mins/hr
or 20 rains/day at No. 3
Ringleman. Process weight
PE = 4.1p0-®7 for less than
30 T/hr and E = 55POH - 40
when greater than 30 T/hr.
Less than 20% opacity for
units with construction begun
after 1/31/72. Less than 30%
opacity for existing. Rap-
ping allowed for 5 mins/hr.
or 6 hrs/IO days. Process
weight @E = 3.12P°-985 for
less than 20 T/hr. and E =
25.4p0.28/ wf,pn greater than
20 T/hr.
Louisiana
111inois
1/18/72
12/31/73
No
No
New source must be burned.
Existing not to cause
ambient air standards to
be exceeded.
200 ppm corrected to 50',
excess air.
i/18/72
New
12/31/72;
Existing
5/30/75
No Less than 20% opacity can be
exceeded 4 mins/hr. Process
weight @E = 4.1P0.67 for less
than 30 T/hr. and E - 55p011
- 40 when greater than 30 T/hr.
No Less than 30% opacity except
for 8 mins/hr for 3 times in
24-hr. period. New sources
process weight "?E = 2.54P°-534
for less than 450 T/hr. and
E = 24.8P"'b when greater
than 450 T/hr. Existing
sources process weight (?E =
4.1p0.67 f0r jess than 30 T/hr
and E = 55P^-'^ - 40 when
greater than 30 T/hr.
-------
TABLE IV-3C
STATE POLLUTION REGULATIONS FOR SI
Area
Effective
Date
Refinery Gas
Existing
Facilities
Exempt?
California 5/4/60
Kansas
Oklahoma
Texas
1/1/72
7/1/72
3/5/72
Louisiana
1/18/72
Regulations
No Ground level concentration
of H2S limited to 0.06 ppm
(3 min. avg.) and 0.03 ppm
(60 min. avg.). Ground
level concentration of SO2
limited to 0.5 ppm (60 min.
avg.) and 0.04 ppm (24-hr.
avg.) 300 ppm maximum con-
centration of SO2 in ex-
haust gas.
Yes (as of Maximum of 10 gr H2S/IOO
1/1/72) DSCF.
No Ground level concentration
of S0^ limited to 0.46 ppm
(60 min. avg.) and 0.05 ppm
(24-hr. avg.).
No Ground level concentration
of H2S limited tc 0.08 ppm
(30 min. avg.). Ground
level concentration of SO2
limited to 0.32 ppm (30 min.
avg.).
No Ground level concentration
of SO2 limited to 0.03 ppm
(annual arith. mean) or
0.14 ppm (24-hr. avg.)
Illinois 2/1/73 Yes (Until
5(3Q<75\
Maximum SO2 concentration
Qf 2.QQQ
OXIDES
Sulfur Recovery Plant
Effective
Date
11/5/70
Existing
Facilities
Exempt?
No
Regulations
Maximum sulfur emission
equivalent to 0.08 gr. of
H2SO4 per DSCF of exhaust
gas.
- - No Specific Regulations - -
7/1/72 Yes Maximum of 20 lbs SO2 per
ton of sulfur processed.
3/5/72 No Varies, depending on stac
height.
1/18/72 No New - maximum SO2 emissio;
of 0.01 lb per lb of sulft
processed (1300 ppm).
Existing - maximum SO? coi
centration of 2000 ppm.
2/1/73 Yes Maximum SO2 concentration
-------
TABLE IV-4
FORECAST OF ADDITIONAL CAPACITY
INSTALLATIONS AND PRODUCTS PRODUCTION
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
Refinery, MB/SD
684
573
1,422
516
722
212
212
212
212
212
Catalytic Cracking, MB/SD
212
178
441
160
224
66
66
66
66
66
Sulfur Plant, LT/SD
1,310
1,097
2,723
988
1,383
406
406
406
406
406
Gasoline, MB/CD
244
244
244
245
200
200
98
98
98
98
Naphtha Jet Fuel, MB/CD
0
0
0
0
0
0
0
0
0
0
-------
TABLE IV-5
CAPACITIES TO BE CONTROLLED
(ABOVE BASELINE VOLUMES)
Tankage, M Barrels
Crude Oil:
Existing
Addi tional
Gasoline:
Existing
Additional
Naphtha Jet:
Existing
Additional
Catalytic Cracking Units, MB/SD
CO Boilers:
Existing
Additional
Precipitators:
Existing
Additional
Sulfur Recovery Facilities, LT/SD
Amine Plants:
Existing
New
Claus Plants:
Existing
New
Tailgas Plants:
Existing
New
1974 1975 1976 1977
5,673
5,673
5,673
5,673
1,727
1,447
3,591
1,303
4,541
4,541
4,541
4,541
954
954
954
958
373
373
373
373
289.4
289.4
289.4
289.4
65.7
55.2
136.7
49.6
662.7
662.7
662.7
662.7
212.0
178.0
441.0
160.0
412.1
412.1
412.1
412.1
65.5
54.9
136.2
39.4
,060.5
1
,060.5
1,060.5
1,060.5
,310.0
1
,097.4
2,723.4
988.2
557.8
2
,557.8
2,557.8
2,557.8
310.0
1
,097.4
2,723.4
988.2
1978 1979 1980
5,673
1,823 535 535
4,541
782 782 383
373
289.4
69.4 20.5 20.5
662.7
224.0 66.0 66.0
412.1
69.1 20.3 20.3
1,060.5
1,382.8 406.0 406.0
2,557.8
1,382.8 406.0 406.0
1981 1982 1983
535 535 535
383 383 383
20.5 20.5 20.5
66.0 66.0 66.0
20.3 20.3 20.3
406.0 406.0 406.0
406.0 406.0 406.0
-------
TABLE IV-6
REFINERY AND SULFUR PLANT CAPACITIES
(Mid-1972)
Crude Sulfur
(MB/D) (LT/D)
Arkansas
Monsanto - Eldorado 38.0 25
California
Monsanto - Avon - 132
Union Oil of California - Santa Maria - 55
Allied Chemical - Richmond - 200
Humble Oil & Refining - Benicia 95.0 270
Shell - Martinez 103.0 100
Union Oil of California - San Francisco 99.0 145
Allied Chemical - El Segundo 195.0 175
Atlantic Richfield - Wilmington 173.0 65
Continental Oil - Paramount 36.0 9
Fletcher Oil & Refining - Wilmington 15.3 7
Golden Eagle Refining - Torrance 7.0 4
Gulf Oil - Santa Fe Springs 52.0 30
Mobil Oil - Torrance 130.0 85
Powerine - Santa Fe Springs 30.0 20
Standard Oil of California - El Segundo 225.8 450
Texaco - Los Angeles 81.1 50
Union Oil of California - Wilmington 107.0 349
Sub-Total 1 ,349.2 "2,146
Colorado
Continental Oil - Denver 29.5 18
Delaware
Getty Oil - Delaware City 150.0 375
Hawai i
Dillingham Petroleum - Barbers Point 35.5 50
Illinois
Anilin Co. of Illinois - Wood River 103.7 150
Marathon Oil - Robinson 116.9 40
Mobil Oil - Joliet 164.0 300
Union Oil of California - Lemont 14/.4 79
Sub-Total 532.0 "569
Indiana
American Oil - Whiting 295,1 279
Atlantic Richfield - East Chicago 140.0 85
Sub-Total 435.1
-------
Page 2
TABLE IV-6 (CONTINUED)
Crude Sulfur
(MB/0) (LT/D)
Kansas
Farmland Industries - Coffeyville 34.5 6
Phillips Petroleum - Kansas City 89.5 38
Sub-Total 124.0 57
Louisiana
Cities Service - Lake Charles 237.5 100
Gulf Oil - Belle Chasse 170.0 40
Humble Oil & Refining - Baton Rouge 441.5 310
Stauffer Chemical - Baton Rouge - 30
Shell Oil - Norco 250.0 40
Texaco - Paradis 152.6 50
Sub-Total 1,251.6
Michigan
Leonard Refineries - Alma 33.5 12
Marathon Oil - Detroit 57.4 69
Sub-Total 90.9 §T
Minnesota
Great Northern Oil Co. - Pine Bend 95.0 130
Northwestern Refining Co. - St. Paul Park 54.5 40
Sub-Total 149.5 170
Mississippi
Gulf Oil - Purvis 30.0 30
Chevron - Pascagoula 285.0 25
Sub-Total 315.0 §5"
Missouri
American Oil - Sugar Creek 100.2 80
Montana
Farmer's Union Central Exchange - Laurel 33.0 28
Montana Sulfur & Chemical Co. - East Billings 48.0 120
Montana Sulfur & Chemical Co. - Billings 46.0 85
Sub-Total 127.0 —"231
New Jersey
Anil in Co. of New Jersey - Perth Amboy 82.5 50
Amerada Hess - Port Reading 75.0 40
Humble Oil & Refining - Linden 277.0 300
Freeport Sulfur - Westville 95.8 30
Mobil Oil - Paulsboro 97.8 185
Sub-Total ' 628.1 ~5C5
-------
Page 3
TABLE IV-6 (CONTINUED)
Crude Sulfur
OlB/D) (LT/D)
New York
Ashland - Buffalo 61.0 50
Ohio
Ashland Oil - Canton 61.0 50
Sun Oil - Toledo 118.0 39
Sub-Total 179.0 §5"
Pennsylvania
Atlantic Richfield - Philadelphia 165.0 73
BP Oil Corp. - Marcus Hook 105.0 52
Gulf Oil - Philadelphia 174.0 135
Sun Oil - Marcus Hook 176.0 30
Sub-Total 620.0 ~~
Texas
Sulpetro Corp. - Big Spring 60.0 10
Diamond Shamrock - Sunray 47.5 30
Phil lips Petroleum - Borger 97.4 33
Coastal States Petrochemical - Corpus Christi 138.4 85
Phillips Petroleum - Sweeny 89.5 25
Atlantic Richfield - Houston 220.0 30
Signal Oil & Gas - Houston 63.0 50
Shell Oil - Deer Park 274.0 400
Stauffer Chemical - Baytown 362.5 191
Atlantic Richfield - Port Arthur - 73
BP Oil Corp. - Port Arthur 68.0 35
Mobil Oil - Beaumont 350.0 50
American Petroflna - Mount Pleasant 26.5 16
Gulf Oil - Port Arthur 319.0 150
Sub-Total 2,115.8 T7T7S
Utah
Chevron - Salt Lake City 46.0 12
Virginia
American 011 - Yorktown 51.8 50
Wisconsin
Murphy Oil - Superior 35.3 15
Wyomi ng
Atlantic Richfield - Sinclair 33.7 26
TOTAL
8,498.2
7,095
-------
TABLE IV-7
UNIT COSTS FOR BUILDING OR
CONVERTING TO FLOATING-ROOF TANKS
New
Tank
Convert
Existing
Tank
Liquid Stored
Crude
Oil
Gasoline
Crude
Oil
Gasoline
Naphtha
Jet Fuel
Tank Size, Barrels
80,400
60,800
80,400
60,800
60,800
Investment, $
61,000
51,000
85,000
74,000
74,000
Product Recovery,
Bbls/Year
2,400
1,950
2,400
1,950
430
Product Value:
$/Barrel
^/Gallon
12.75
37.7
12.75
37.7
33.6
Annual Costs, $
Maintenance
1,220
1,020
1,700
1,480
1,480
Taxes & Insurance
2,440
2,040
3,400
2,960
2,960
Capital Charge
13,310
11,130
18,550
16,150
16,150
Product Recovery
Credit
(30,600)
(30,880)
(30,600)
(30,880)
(6,070)
Total
(13,630)
(16,690)
(6,950)
(10,290)
14,520
-------
TABLE IV-8
TYPICAL COST OF API SEPARATOR MODIFICATIONS
Refinery Size, B/SD
Investment, $
Product Recovery, Bbls/Year
Product Value, $/Barrel
Annual Costs, $/Year
Maintenance
Taxes & Insurance
Capital Charge
Product Recovery Credit
Total
Unit Cost, £/Bbl of Crude
10,000
61,900
200,000
27,800
82,800
167,300
1,130
6,970
22,530
12.75
12.75
12.75
560 1,660 3,350
1,110 3,310 6,690
6,070 18,070 36,510
(14,410) (88,870) (287,260)
(6,670) (65,830) (240,710)
(0.19) (0.31) (0.35)
-------
TABLE IV-9
TYPICAL COST OF VAPOR RECOVERY AT LOADING RACKS
Refinery Size, B/SD
10,000
61,900
200,000
Investment, $
144,000
224,000
320,000
Product Recovery, Bbls/Year
767
4,747
15,330
Product Value, ^/Gallon
35.7
35.7
35.7
Annual Costs, $
Uti1ities
860
5,340
17,300
Maintenance
5,760
8,960
12,800
Taxes & Insurance
5,760
8,960
12,800
Capital Charge
31,420
48,880
69,820
Product Recovery Credit
(11,500)
(71,180)
(229,860)
Total
32,300
960
(117,140)
Unit Cost, tf/Bbl of Crude
0.93
0
(0.17)
-------
TABLE IV-10
UNIT COSTS FOR BUILDING A CO BOILER
Catalytic Cracker Capacity, B/SD
Investment, $MM
Steam Generation, MMBTU/Year
Steam Value, $/MMBTU
Annual Costs, $
Utilities
Maintenance
Taxes & Insurance
Capital Charge
Steam Credit^)
Total
New Unit
31,100
3.07
1.14 x 106
2.67
Existing Unit
31,100
3.68
1.14 x 106
2.67
99,400
123,000
123,000
670,000
(2,283,000)
(1,267,600)
99,400
147,000
147,000
803,000
(2,283,000)
(1,086,600)
Note: (1) 75% of steam generation applied as a credit.
-------
TABLE IV-H
TYPICAL COST FOR ADDITION OF A CO BOILER
TO EXISTING CATALYTIC CRACKING UNITS
Refinery Size, B/SD
10,000
61,900
200,000
Catalytic Cracker Size, B/SD
3,100
19,200
62,000
Investment, $MM
0.92
2.76
5.57
Steam Generation, MMBTU/Year
0.114 x 106
0.704 x 106
2.28 x 10*
Steam Value, $/MMBTU
2.67
2.67
2.67
Annual Costs, $
Utilities
9,910
61,400
198,000
Maintenance
36,800
110,000
223,000
Taxes & Insurance
36,800
110,000
223,000
Capital Charge
200,700
602,000
1,220,000
Steam Credit
(228,000)
(1,410,000)
(4,566,000)
Total
56,210
(526,600)
(2,702,000)
Annual Costs, i/Barrel
1.6
(2.5)
(3.9)
-------
TABLE IV-12
UNIT COSTS FOR CATALYTIC CRACKING UNIT PRECIPITATORS
Catalytic Cracker Capacity, B/SD
Investment, $MM
Annual Costs, $
Utilities
Maintenance
Taxes & Insurance
Capital Charge
Total
New Unit
31,100
1.23
19,400
49,200
49,200
268,000
385,800
Existing Unit
31,100
1.47
19,400
58,800
58,800
321,000
458,000
-------
TABLE IV-13
TYPICAL COST FOR ADDITION OF A PRECIPITATOR
TO EXISTING CATALYTIC CRACKING UNITS
Refinery Size, B/SD
Catalytic Cracker Size, B/SD
Investment, $MM
Annual Costs, $
Utilities
Maintenance
Taxes and Insurance
Capital Charge
Total
Annual Costs,
-------
TABLE IV-14
TYPICAL COST OF AMINE PLANT ADDITIONS
New
Existinq
Refinery Size, B/SD
61,900
10,000
61,900
200,000
Sulfur Level, Wt.%
2.0
0.92
0.92
0.92
Plant Size, LT/SD
119
8.8
54.5
176
Investment, $MM
1.84
0.34
1.11
2.37
Annual Costs, $M
Utili ties
437.4
32.3
200.3
646.9
Catalyst and Chemicals
9.9
0.7
4.5
14.6
Maintenance
73.6
13.6
44.4
94.8
Taxes & Insurance
73.6
13.6
44.4
94.8
Capital Charge
401.5
74.2
231.1
517.1
Total
996.0
134.4
524.7
1,368.2
Unit Cost, tf/Bbl of Crude
4.6
3.9
2.4
2.0
-------
TABLE IV-15
TYPICAL COST OF CLAUS PLANT ADDITIONS
New
Existing Refineries
Refinery Size, B/SD
61,900
10,000
61,900
200,000
Sulfur Level, Wt.%
2.0
0.92
0.92
0.92
Plant Size, LT/SD
119
8.8
54.5
176
Investment, $MM
1.99
0.37
1.20
2.57
Annual Sulfur Production, LT
38,615
2,872
17,774
57,431
Sulfur Value, $/LT
30.0
30.0
30.0
30.0
Annual Costs, $M
Utilities
109.7
8.2
50.4
163.0
Catalyst and Chemicals
3.9
0.3
1.8
5.7
Labor and Supervision
39.4
39.4
39.4
39.4
Maintenance
79.6
14.8
48.0
102.8
Taxes & Insurance
79.6
14.8
48.0
102.8
Capital Charge
434.2
80.7
261.8
560.8
Credit for Sulfur Sale
(1,158.5)
(86.2)
(533.2)
(1,722.9)
Total
(412.1)
72.0
(83.8)
(748.4)
Unit Cost,
-------
TABLE IV-16
TYPICAL COST OF CLAUS PLANT TAILGAS CLEANUP UNITS
Refinery
Existing Refineries
Refinery Size, B/SD
61,900
10,000
61,900
200,000
Sulfur Level, Wt.%
2.0
0.92
0.92
0.92
Plant Size, LT/SD
119
8.8
54.5
176
Investment, $MM
1.59
0.29
0.96
2.05
Annual Sulfur Production, LT
2,466
183
1,135
3,666
Sulfur Value, $/LT
30.0
30.0
30.0
30.0
Annual Costs, $M
Utilities
133.8
9.9
61.6
198.9
Catalyst and Chemicals
3.7
0.3
1.7
5.5
Labor and Supervision
19.7
19.7
19.7
19.7
Mai ntenance
63.6
11.6
38.4
82.0
Taxes & Insurance
63.6
11.6
38.4
82.0
Capital Charge
346.9
63.3
209.5
447.3
Credit for Sulfur Sale
(74.0)
(5.5)
.(34.1)
(110.0)
Total
557.3
110.9
335.2
725.4
Unit Cost, £/Bbl of Crude
2.6
3.2
1.6
1.0
¦>N
-------
TABLE IV-17
BASIS FOR ESTIMATING TANK LOSSES
Tank Parameters
Tank Size
20,000
80,000
140,000
Tank Dimensions
60 x 40
110 x 48
145 x 48
Average Outage
20
24
24
Paint Factor
1.0
1.0
1.0
Tank Type Factor
0.045
0.045
0.045
Seal Factor
1.00
1.00
1.00
Tank Content Factor:
Crude Oil
Naphtha Jet Fuel
Gasoline
0.75
1.00
1.00
0.75
1.00
1.00
0.75
1.00
1.00
Reid Vapor Pressure:
Crude Oil
Naphtha Jet Fuel
Gasoline
5.0
3.0
10.5
5.0
3.0
10.5
5.0
3.0
10.5
True Vapor Pressure^)
Crude Oil
Naphtha Jet Fuel
Gasoline
3.1
1.5
6.2
3.1
1.5
6.2
3.1
1.5
6.2
Turnover Rate(2)
Crude Oil
Naphtha Jet Fuel
Gasoline
36.9
6.4
9.3
36.9
6.4
9.3
36.9
6.4
9.3
Average Liquid Temperature, °F.(3)
66
66
66
Average Daily Temperature
Difference, °F.(4)
18
18
18
Wind Velocity, MPH(4)
10
;o
10
Notes: (1) API Bulletin 2518.
(2) Based on average production and storage capacities.
(3) Average ambient temperature for Houston, Los Angeles, Oklahoma
City, and Philadelphia plus 5°F. per API Bulletin 2518 recom-
mendation.
(4) Average for Houston, Los Angeles, Oklahoma City and Philadelphia.
-------
TABLE IV-18
TYPICAL COST OF TANKAGE MODIFICATIONS
Refinery Size, B/SD
Tanks to be Converted
to Floating-Roof, Aver-
age Number and Size
Crude
Gasoline
Naphtha Jet Fuel
Investment. $M
Crude
Gasoline
Naphtha Jet Fuel
Total
Investment, $/Bb1/Day
Annual Cost, $M/Year
Crude
Gasoline
Naphtha Jet Fuel
Total
Annual Costs, ^/Barrel
10,000
61,900
200,000
5.0 @20,000 Bbls
8.9 020,000 Bbls
0.4 @20,000 Bbls
7.8 @80,000 Bbls
13.7 @80,000 Bbls
0.6 @80,000 Bbls
14.4 @140,000 Bbls
25.3 @140,000 Bbls
1.0 @140,000 Bbls
252.5 664.3 1,717.0
451.7 1,165.1 3,012.0
18.2 47.0 121.6
722.4 1,876.4 * 4,850.6
72.2 30.3 24.3
31.8 (53.4) -(285.1)
24.8 (214.2) (848.8)
4.8 9.6 20.3
61.4 (258.0) (1,113.6)
1.8 (1.2) (1.6)
-------
V-l
SECTION V. REFINED PRODUCT QUALITY REGULATIONS
A. Scope
The investment and operating cost effects imposed by two product
quality regulations were examined in this study:
• Lead additive levels in motor gasoline.
• Residual fuel oil sulfur levels.
The restriction of unleaded gasoline sulfur level has been recently
discussed but is not regulated at the time of this study and has been
specifically excluded from consideration.
B. Conclusions
The investment and operating cost impacts of unleaded gasoline
manufacture alone and in combination with a lead phasedown program
have been approximated by updating studies completed by TM&S in
1972 to a 1974 economic basis. Comparative investment and
operating costs are shown below:
Added Refininq Industry Costs
Incurred As A Result of Lead
Regulations During the Period
1974 and Later
1977 ~ 1980 ~ 1985
Cumulative Industry
Investment, $MM
Unleaded Gasoline With
Lead Phasedown
Unleaded Gasoline Alone
1,200
400
1,970
1,360
3,190
2,830
Added Annual Costs, $MM
Unleaded Gasoline With
Lead Phasedown
Unleaded Gasoline Alone
330
60
420
220
690
540
The indicated 1985 investment in the higher case is expected to be
well within the capability of the process construction industry but
represents about twice the level of expenditure required to meet
reference case growth requirements. Perhaps the most striking im-
pact indicated in this effort is that small refiners (7,500 B/D)
must endure an investment per barrel of gasoline production that
is more than double that imposed on the refiners with capacity in
excess of 100,000 barrels per day. The elimination of lead phase-
down regulations is shown to primarily result in deferral of about
-------
V-2
$610 million of capital investment for the industry to the post-1980
period.
Residual fuel sulfur level restrictions by both Federal and
state regulations are expected to result in an additional luw-sulfur
fuel oil demand of 400,000 barrels per day by 1977 and an additional
350,000 barrels per day by 1983. The indicated overall industry
impacts are shown below:
Additions During Time Period
1974-1977 1977-1983
Investment, $MM 590 510
Annual Costs, $MM 290 240
This analysis suggests that small refiners cannot efficiently com-
pete in the desulfurized fuel market and will be forced to rely on
low-sulfur feedstocks or compete for dwindling high-sulfur fuel oil
customers.
C. Prior Lead Additive Studies
The original contract document specified that a new analysis
of lead additive usage would be available for incorporation in this
study. However, revisions to the scope of the analysis and priority
reassignments have delayed the completion date past the deadline for
this study. As a result, previously published analyses of this topic
have been reviewed for adaptation to the current study criteria.
In 1971 The PACE Company completed a multi-client evaluation of
lead additive regulations.(0 PACE employed nine separate mathe-
matical models to describe the refining environment for the period
1970 to 1980. A major conclusion of the analysis was the expecta-
tion of a totally unleaded gasoline market by 1980. The total addi-
tional investment for the decade was estimated at $4.3 billion on a
1970 Gulf Coast investment basis. The expected average added cost
for motor gasoline was estimated at 1.3$ per gallon.
EPA commissioned a study by Bonner & Moore Associates in 1971
to evaluate the impact of proposed lead additive controls.(2) Bonner
& Moore employed two mathematical refinery models and evaluated both
the separate production of unleaded gasoline and a combination with
several proposed lead phasedown schedules. The studies were all di-
rected at a 1970 to 1980 time period. Bonner & Moore estimated in-
vestment requirements for unleaded gasoline production as $1.5 billion
by 1980, while lead phasedown (Schedule 0) was expected to add an ad-
ditional $1 billion. These values would be expected to vary from the
PACE study since the Bonner & Moore analysis accounted for elimina-
tion of only 77% of the lead additives employed in 1970. One case
analyzed in the Bonner & Moore study was premised on total lead
-------
V-3
elimination, resulting in an investment requirement of $3.5 billion,
but was found to exceed construction industry capabilities.
Turner, Mason & Solomon completed a multi-client analysis of
lead additive regulations in 1972.(3) The TM&S study employed five
mathematical refinery models to analyze the lead regulations in
force at the time, including lead phasedown. Investments for the
1970-1980 time period were estimated as $3.6 billion. Again this
analysis covered elimination of less than 80% of the lead additive .
levels employed by the industry in 1970. Later in 1972, TM&S com-
pleted a study of unleaded gasoline production^) without the lead
phasedown regulations. Added refinery investments were reduced to
$3.0 billion by 1980 with significant relief indicated in early years
for small refiners.
In 1974 Arthur D. Little, Inc., completed Phase I of an EPA-
sponsored update of lead additive restrictions on the refining in-
dustry.^) The ADL study employed a single mathematical model to
prepare an overview of the industry impact to 1980, but the model
was not validated against industry operating data. Added investment
by 1980 was estimated at $1.5 billion at 1974 investment levels.
The Phase II ADL effort currently underway is expected to be sub-
stantially expanded in scope, but will still exclude consideration
of the impact on small refiners.
Though all of the previously mentioned analyses addressed the
topic at hand, none is appropriate for direct incorporation in this
study.
• No single study covers the 1974-1983 period.
• Only ADL is based on 1974 investment costs.
t No study is based on current petroleum demand outlooks.
• None anticipated current lead phasedown considerations.
While the conclusions would only be approximate, it is possible to
adapt the results of an earlier analysis to the current situation
by adjustment of demand forecast, investment levels, lead removal
rates, and extrapolation to later time periods. Such adjustments
would require the availability of all details of the previous anal-
ysis. Since the only studies for which all detailed calculations
are readily available to us are those previously completed by TM&S,
we have elected to adapt them to the current study criteria.
D. Current Regulatory Outlook
In accordance with EPA regulations, essentially all gasoline
marketers must offer an unleaded gasoline grade with a minimum qual-
ity rating of 91 Research Octane Number (RON). In addition, EPA had
-------
V-4
promulgated lead phasedown regulations which have been suspended
following a review by the Federal Courts. The rescinded regula-
tions posed the following phasedown schedule:
Since the Federal Court ruling is currently under review, this
analysis will consider the impact of unleaded gasoline both with and
without companion lead phasedown regulations.
E. Analytical Techniques
The technique employed in the 1972 TM&S studies basically in-
volved the following steps:
1. Five linear programming models '.°re constructed to rep-
resent various industry sectors.
2. Historic industry operating data were imposed upon the
models to validate process descriptions and blending
data.
3. Forecast product demands were imposed on the models for
the years 1974, 1977 and 1980 to determine investment,
and operating parameters in the absence of lead additive
regulations.
4. Gasoline forecasts were revised to reflect the use of
catalyst-equipped cars and lead phasedown regulations.
These revised forecasts were then imposed on the models
to determine investment and operating parameters re-
quired to satisfy EPA regulations.
5. A comparison of the reference and EPA-regulated en-
vironments indicated the investment, raw material con-
sumptions and added operating costs imposed by lead
additive regulations.
Thus, to adapt the 1972 studies to the current study criteria, the
models must be reviewed, reference environment demand forecasts re-
vised, gasoline forecasts updated, and all economic results must be
converted to a 1974 basis.
Effective Date
Average TEL Level,
Total Gasoline Production
(Grams/Gallon)
1/1/75
1/1/76
1/1/77
1/1/78
1/1/79
1.7
1.4
1.0
0.8
0.5
-------
V-5
The 1972 TM&S refinery models represented all industry capacity
that produced gasoline in 1970. Those models are compared with in-
dicated 1974 capacity from the previous study belov:
Model
M-l
Location and
Crude Rate Represented
All Gasoline Refineries
Than 15 MB/D
Less
1970
Model
Capaci ty
(B/D)
7,500
f-orecast
1974
Model
Capaci ty
(B/D)
7,500
M-2 Gasoline Refineries 15 to 60
MB/D Excluding California 35,000 40,000
C-l Gasoline Refineries 60 to 140
MB/D Excluding California 90,000 105,000
C-2 Gasoline Refineries More Than
140 MB/D Excluding Calif. 225,000 267,000
W-l California Gasoline Refin-
eries More Than 15 MB/D 85,000 90,000
Industry Capacity Represented 11,927,000 1 J,735,000
The 1974 forecast of 13,735,000 barrels of gasoline refining
capacity plus the 700,000 barrels per day of actual 1974 specialty
plant capacity shown on Table A-l compares favorably with the actual
domestic refining capacity reported by FEA for January 1, 1974, of
14,250,000 shown on Table A-4. While not an exact fit, this level
of agreement suggests that the 1972 study may be adapted to approxi-
mate an analysis of the 1973 industry base.
The 1972 TM&S analyses were based upon substantially higher
petroleum demand growth rates than those proposed in Section II of
this study and detailed on Table A-2. However, the prior studies
were also predicated on a substantial growth in future product im-
ports, while the most recent NPC study projects a leveling off of
product imports. A comparison of these bases indicates that capac-
ity additions forecast for the reference environment for a current
study would conform almost exactly to the projected increase fore-
cast in the 1972 TM&S report.
-------
V-6
Current NPC
1972 TM&S Report Outlook
1974 T9§0~ 1074' 1980
Domestic Petroleum
Demand 17,606 22,400 16,735 20,096
Product Imports and
Non-Refinery
Supplies (4,058) (5,527) (3,233) (3,233)
Net Refinery Output 13,548 16,873 13,502 16,863
Thus, it appears that the reference case solutions from the prior
study could be updated to 1974 economic bases and be reasonable ap-
proximations of the current NPC demand forecast.
Few investigators have agreed on the relative fuel economy to
be assigned to automotive emission-control systems. For purposes of
this analysis, we have assumed that catalyst systems will be employed
in the future and that 1975 emission-control regulations will pre-
vail throughout the time period. The fuel penalties assigned to
various model year autos are shown below:
Economy Loss Relative to
Model Year
1970 Automotive
1971
6.5
1972
8.4
1973-1974
13.0
1975+
8.0
These estimates are based on weighted average vehicle performance
attributed exclusively to emission-control systems.
With these fuel economy premises, new forecasts of gasoline
demand for a reference environment (no auto emission controls) and
a study case were prepared. Through a detailed analysis of changes
in gasoline volumes and pool octane requirements daveloped in the
1972 studies, investment and operating cost indicators were developed
for each individual refinery model. These indicators were combined
with the study case gasoline forecasts and updated to 1974 economic
bases to approximate the investment and operating cost effects to be
anticipated for the period 1974 through 1983 from Federal lead addi-
tive regulations.
-------
V-7
F. Determination of 1973 Industry Facilities
The 1973 domestic refining industry, for the most part, re-
flected the outlooks of the early 1970's for high gasoline demand
growth rate and anticipated unleaded gasoline and lead phasedown
programs. In practice, this resulted in a significant amount of
excess gasoline manufacturing capacity in 1973 and 1974. For pur-
poses of this analysis, we have assumed that all refiners under
20,000 B/D deferred octane improvement investments in anticipation
of a short-term exemption from EPA regulations. We have also as-
sumed 20% of the octane improvement investment requirements for re-
finers in the 20,000 to 70,000 B/D range was deferred to a later
period. All other refiners were assumed to have invested in refin-
ing facilities at the rate forecast in the 1972 TM&S analysis.
G. Cost of Lead Additive Regulation Programs
After adapting investment and operating cost data to a 1974
cost basis as previously described, incremental raw material values
were adjusted from the $3.26 per barrel typical of 1970 imported
crude cost to a marginal 1974 value of $12.75 per barrel. Then a
comparison of results for the case invoking unleaded gasoline with
lead phasedown to the forecast of requirements for the reference
case yielded the additional investment pattern detailed on Table V-l
and summarized below:
Cumulative Industry Investment
To Be Incurred As A Result
Of Lead Regulations In The
1977
1980
1985
920
1,520
2,460
100
150
250
110
180
300
70
120
180
1 ,200
1,970
3,190
Facility Cost
Royalty and Catalyst
Interest and Owner's Cost
Working Capital
Total Capital Requirement
The $3.2 billion investment to be expended over an 11-year period is
expected to be well within the capability of today's process construc-
tion industry. The $290 million average annual expenditure required
by these regulations compares with an industry totai capital addition
for refinery modernization and expansion of $950 million for the period
1968 through 1972.(11)
Of major importance in this analysis is the investment require-
ment as a function of refinery size:
-------
V-8
Model
1974
Capacity, B/D
1985 Gasoline
Volume, B/D
Investment/Annual
Barrel Gasoline, $
M-l
7,500
2,780
2.14
M-2
40,000
28,900
1.30
C-l
105,000
63,720
0.94
C-2
267,000
154,500
0.88
W-l
90,000
56,450
1.01
It is apparent that the investment burden associated with lead addi-
tive restriction falls unevenly in the industry. The smallest refin-
ers must invest more than twice as much capital per barrel of gasoline
as the over 100,000 B/D refiners.
Added refining costs resulting from the combination of unleaded
gasoline and lead phasedown programs are detailed on Table V-2 and
summarized below:
Added Refining Costs Above
1973 Reference Case, $MM/Year
1977
1980
1985
Revenue from Additional Gas-
oline Sales @37.7$/Gallon
(2,260)
(3,070)
(4,190)
Byproduct Revenue
(320)
(410)
(550)
Raw Materials
2,700
3,500
4,770
Operating Costs (Includ-
ing TEL)
(100)
(no)
(160)
Capital Charges
310
510
820
Net Added Cost
330
420
690
If all of these added costs are recovered as gasoline cost increases
on the total 130 billion gallons of forecast 1985 gasoline sales,
gasoline prices would be expected to rise by an average of about
one cent per gallon. The anticipated impact upon refiners ranges
from over 1.9$ per gallon for refineries processing less than 20,000
B/D to less than 0.5$ per gallon for refineries with capacity over
140,000 B/D.
-------
V-9
The investment and added refining costs associated with unleaded
gasoline requirements without lead phasedown regulations are shown
on Tables V-3 and V-4 and summarized below:
1977 1980 1985
Added Refining Industry Capital
Requirements, $MM 400 1,360 2,830
Added Refining Costs, $MM/Year 60 220 540
As one would anticipate, the elimination of lead phasedown shows a
substantial reduction in refining industry capital requirements in
1977. The smallest refiner modeled (M-l) is allowed to defer $560,000
of capital investment by elimination of the lead phasedown regula-
tions. Other segments of the industry which have essentially provided
for initial lead phasedown investments by 1974 would also find a
smaller investment requirement imposed by growing unleaded gasoline
demands until after 1977. Even by 1980 added industry investment
will be reduced by 31%, or $610 million, by elimination of lead
phasedown regulations. By about 1990, essentially all gasoline de-
mand will be unleaded under the premises employed in this study, so
the investment level and annual costs will ultimately show no effect
of the lead phasedown regulation.
H. Residual Fuel Sulfur Regu1ations
EPA regulations expressly limit sulfur oxide emissions from
major utility plants constructed after August 1971 to 0.8 pound S02
per million BTU's of oil fired. Assuming an average heat content of
6 million BTU's per barrel of residual fuel, this restricts fuel sul-
fur level to a nominal value of about 0.7 weight percent. However,
in addition to the EPA new source performance standards, the states
have established maximum fuel sulfur content regulations to insure
that Federal ambient sulfur oxide standards are satisfied. The state
standards call for widespread availability of fuel oil with 0.3 weight
percent sulfur level for East Coast locations, 0.5 weight percent sul-
fur fuel in California, and levels varying from 1 weight percent to
essentially unregulated levels for some existing facilities in other
locations.
I. Historic Residual Fuel Oil Market
The reported residual fuel consumption for 1973 detailed on Table
V-5 is summarized below:
-------
V-10
Total Volume
(MB/D)
PAD I 1,930
PAD 11 250
PAD III 190
PAD IV 30
PAD V 420
Total U.S. 2,820
Distribution of Market
By Sulfur Content
0 to 0.5
0.5 to 1
Over 1
37
23
40
4
44
52
12
20
68
8
25
67
55
_6
39
35
22
43
It may be noted that two-thirds of the total residual fuel consumption
occurs on the East Coast (PAD I), where stringent state sulfur stan-
dards are currently being imposed. The other major fuel market (PAD
V) had already achieved a large measure of control to 0.5% sulfur
level by 1973. On a nationwide basis about one-third of all residual
fuel was less than 0.5% sulfur, while almost one-fourth exceeded 2
weight percent sulfur content. An additional 120,000 barrels per
day of residual fuel of varying sulfur levels was consumed in re-
finery operations in 1973.
J. Future Fuel Oil Markets
Only a detailed analysis of the effect of Iccal regulations on
each fuel consumer would indicate the outlook for future residual
fuel sulfur levels. In the absence of such an approach, we have
adopted the following assumptions to examine the effect of fuel oil
regulations:
• All increased residual fuel volumes above the 1973 base
level must conform to 0.7 weight percent sulfur levels.
• Residual fuel consumed by existing plants in Petroleum
Administration for Defense District (PAD) I will meet the
following schedule:
0.3% or Less 0.3 to 0.7% Over 1%
1977 45% 25% 30%
1983 55% 25% ?.0%
• By 1977, 65% of all PAD V residual fuel consumed by exist-
ing plants is assumed to meet an 0.5% maximum sulfur con-
tent standard.
• No major reductions in fuel sulfur level are forecast for
existing plants in PADS II, III or IV.
-------
V-ll
• By 1977, 50% of the fuel oil consumed in refinery opera-
tions is assumed to be desulfurized to 0.7 weight per-
cent.
The attached Table V-6 details residual fuel demand forecasts
based on the NPC projections presented in Appendix Table A-2. The
consideration of the Table V-6 forecast plus the assumptions regard-
ing fuel regulations outlined above lead to the following fuel-sulfur
projections:
Residual Fuel Demand by Sulfur Level, MB/D
0.3 Wt..X 0.5 W't.f y ' Over 1 ¥t.%
1973 Actual
750
230
630
1 ,330
1977 Forecast
900
270
840
1,040
1983 Forecast
1,100
270
990
850
This forecast suggests that additional low-sulfur residual fuel de-
mand directly attributable to Federal environmental regulations will
total about 400,000 barrels per day between 1974 and 1977 and 350,000
barrels per day between 1977 and 1983.
This additional demand may be satisfied fcy increased processing
of premium-priced low-sulfur crude oils, blending desulfurized dis-
tillate fuel oils with residual stock, or direct desulfurization of
residual fuel. Low-sulfur crude processing and distillate blending
are likely to predominate before 1980 simply because few residual
desulfurization units are under construction. These practices repre-
sent extra-cost refinery operations, but do not require facility in-
vestments. Since the dominant supply of petroleum throughout the
world is high in sulfur content (over 1% sulfur), we believe the
premium for low-sulfur crudes and residual fuels will ultimately re-
flect the economics of residual desulfurization processes. Thus, we
have elected to calculate industry impacts as if all new low-sulfur
fuel demand required desulfurization of residual fuel from marginal
Arabian Light crude oil. We caution the reader to note that this
overstates the actual refining investment to be committed by the
domestic industry in the near term, but should approximate the cor-
rect annual costs incurred in satisfying environmental regulations.
K. Fuel Oil Desulfurization Technology
The common feature of all fuel desulfurization processes is
hydrogenation of the organic-sulfur compounds to hydrogen sulfide
(H2S) over a catalyst. Differences between processes relate pri-
marily to catalysts used - i.e., susceptibility to feed contaminants
and the tendency to crack rather than desulfurize the feed. Sulfur
removal is accomplished by contacting the liquid feed with hydrogen
-------
V-12
at elevated temperature arid pressure and passing the resulting mix-
ture downflow over a fixed-bed, trickle-flow reactor containing the
catalyst. Recycle gas quenching is employed to moderate the exo-
thermic temperature rise.
The costs employed in this study are based on desulfurizing
a fuel oil cut (650°+) from Light Arabian crude. Four cases were
developed to demonstrate the effects of capacity and product sulfur
level. Refinery capacities of 200,000 B/CD and 30,000 B/CD were
used to establish the effects of refinery throughput on costs. Fuel
oil product sulfur levels of 0.7 weight percent and 0.3 weight per-
cent were chosen to demonstrate the effects of severity on operating
economics. The 0.7 weight percent approximates the sulfur level al-
lowed by EPA new source S02 emission limits and the 0.3 weight per-
cent represents the sulfur level required by several East Coast
states.
The physical properties of Light Arabian crude are shown on
Table V-7. The refinery configuration on which calculations are
based is shown below:
>¦
MATUttAL-
3A&
.cttuoe
LT E.HQ3 gECOVECY
AND FJEL SUPPLY
¦{>
C;-C<
cj-s 75
Ci - 675
2
0
S
J
r
0)
o
PLAN"
Cv^7S ^APWT'riA
575-G&O
l
msTiwLATe
hi?
S50 +
-»J BESIO. HOS
}
0 8
1 /.
t'i D
Hi if.
O J
8?
&!
M ~)
Ul c,
?o
5S
DBNOTBB PACILITIEB
AOOBD to PeoOUCE L.Oxv
aUuPUB PUBL. Oiue
ir_i
SULP'w'R
R6COVB5V
PBODUCTS
~
SULP'JE
~i>
Capital requirements were calculated for a hydrogen plant, sul-
fur recovery plant and HDS plant sized to effect the fuel oil sulfur
limit. Then offsite investments, utility requirements, and other
operating costs were estimated. These were all compiled to dftormine
the cost of desulfurizing the fuel oil.
-------
V -1 3
This approach changed the original refinery yields by:
• Consuming some C5-375° naphtha as hydrogen f":an'.. feeJ.
• Changing the characteristics of the original 650°+
stream because of the small amount of cracking that
took place in the HDS reactor.
• Requiring some 375-650°F. desulfurized distillate as
blendstock with product fuel oil to meet, sulfur speci-
fications.
Investment estimates for the cases studied are detailed on Table
V-8. Table V-9 relates annual capital charges arid operating costs
for the same cases. Both tables are summarized here:
Investment and Operating Costs
Crude Run
Sulfur in Fuel
Investment
Cost to Desul-
(MB/D)
Oil (Wt.%J
Required ($MM)
furize ($/Bb_l|
200
0.7
108
1.77
200
0.3
146
2.08
30
0.7
25
2.35
30
0.3
3j
2.84
Investments shown here include capital for the HDS process, hydrogen
plant, sulfur recovery plant, and all associated offsites - in mid-
1974 timeframe.
It is evident from this analysis that the small refiner is un-
able to competitively desulfurize fuel oil. An evaluation of the
capital requirements per barrel of crude and per barrel of HDS feed
further underscores this fact, as shown below:
Fuel Oil
Sulfur
Crude Run Specification Desulfurization Capital Required
(MB/D) (Wt.%) $7W_.Crude Run $/B/D HPS Teed
200 0.7 540 1,210
200 0.3 730 1,630
30 0.7 830 1,860
30 0.3 1,100 2,460
L. Estimated Cost of Fuel Sulfur Regulations
Based on the technology analysis presented in the preceding sec-
tion, we anticipate that all residual fuel desulfurization facilities
-------
V-14
will be provided by large refiners either located within the U.S.
territories or by export refiners fully committed to the domestic
market. This assumption leads to the following projection of fuel
oil desulfurization projects:
Additions During
Time Period
1974-19771977-1983
Desulfurization Capacity, MB/D:
0.3 Wt.% Product 155 193
0.5 Wt.% Product 42 0
0.7 Wt.2 Product 218 150
Investment Requirements, $MM 590 510
Annual Costs, $MM 290 240
It may be of interest to note that these estimated costs for desul-
furization fall in the same range as is currently expected for flue
gas desulfurization. Thus, if flue gas desulfurization technology
is commercialized in the near term, some of the investment burden
may be shifted from the petroleum refining industry to the electric
utility industry. However, in either case, the costs imposed by
fuel oil sulfur regulations are expected to be represented by the
above estimates.
-------
REFERENCES - SECTION V
1. The Effect of Unleaded Gasoline Production on the Refining and
Petrochemical Industries, The PACE Company, Houston, Texas,
February 1971.
2. An Economic Analysis of Proposed Schedules for Removal of Lead
Additives from Gasoline, EPA Contract No. 68-02-0050, Bonner &
Moore Associates, Inc., Houston, Texas, June 25, 1971.
3. The Economic Impact of Automotive Emission Standards, Turner,
Mason & Solomon, Dallas, Texas, March 31, 1972.
4. The Impact of Alternate Lead Emission Control Programs, Turner,
Mason & Solomon, Dallas, Texas, May 5, 1972.
5. Impact of Motor Gasoline Lead Additive Regulations on Petroleum
Refineries~and Energy Resources - 1974-1980, Phase I, EPA-450/
3-74-032a, Arthur D7 Little, Inc., Cambridge, Massachusetts,
May 1974.
6. "Desulfurize Kuwait Reduced Crude", Hydrocarbon Processing, May
1973, page 89.
7. "Desulfurization Reactors Added to H-0IL Process", Oil & Gas Journal,
June 1972, page 59.
8. "Ecologically Acceptable Fuels from the Gulf HDS Process", AIChE
67th Annual Meeting, December 1974.
9. "Pilot Plant Proves Resid Process", Hydrocarbon Processing, May 1973,
page 93.
10. "Recent Advances in Residua Processing", NPRA 72nd Annual Meeting,
April 1974.
11. "Capital Investments of the World Petroleum Industry - 1972", Chase
Manhattan Bank, pp 24.
-------
TABLE V-l
CUMULATIVE CAPITAL REQUIREMENTS TO IMPLEKEwi
UNLEADED GASOLINE AND LEAD PHASEDOMN PROGRAMS
ABOVE 1973 REFERENCE LEVEL
Cumulative Investment, M$
1977 1980 1985
M-l Model: Capacity 7,500 B/D
Facility Cost
1,100
1,400
1,850
Royalty and Catalyst
60
80
100
Interest, Owner's Engineering and Startup
130
170
220
Working Capital
-
-
Total
1,290
1,650
2~J7U
M-2 Model: Capacity 40,000 B/D
Faci1ity Cost
3,580
6,600
10,450
Royalty and Catalyst
580
900
1,380
Interest, Owner's Engineering and Startup
430
790
1,250
Working Capital
240
400
640
Total
4,830
~8,690
13,720
C-l Model: Capacity 105,000 B/D
Facility Cost
7,170
11 ,540
16,970
Royalty and Catalyst
940
950
1,470
Interest, Owner's Engineering and Startup
860
1,380
2,040
Working Capital
520
880
1,410
Total
9,430
14,750
21,890
C-2 Model: Capacity 267,000 B/D
Facility Cost
14,140
21,240
38,280
Royalty and Catalyst
1 ,120
1 ,520
3,610
Interest, Owner's Engineering and Startup
1,700
2,550
4,590
Working Capital
1 ,270
2,140
3,420
Total
T8723U
27,450
4$,900
W-l California Model: Capacity 90,000 B/0
Facility Cost
5,230
9,930
16,050
Royalty and Catalyst
390
970
1,520
Interest, Owner's Engineering and Startup
630
1,190
1,930
Working Capital
460
780
1,250
Total
6,710
12,870
20,750
-------
TABLE V-2
ADDED REFINING COSTS IMPOSED BY UNLEADED
GASOLINE AND LEAD PHASEDOWN
PROGRAMS
($/Day)
1977
1980
1985
M-l Model: Capacity 7,500 B/D
Incremental Gasoline Revenue @37.7
-------
TABLE V-3
CUMULATIVE CAPITAL REQUIREMENTS TO IMPLEMENT
UNLEADED GASOLINE PROGRAM ABOVE 1973 REFERENCE LEVEL
(M$)
M-1 Model: Capacity 7,500 B/D
Facility Cost
Royalty and Catalyst
Interest, Owner's Engineering and Startup
Working Capital
Total
M-2 Model: Capacity 40,000 B/D
Facility Cost
Royalty and Catalyst
Interest, Owner's Engineering and Startup
Working Capital
Total
C-l Model: Capacity 105,000 B/D
Facility Cost
Royalty and Catalyst
Interest, Owner's Engineering and Startup
Working Capital
Total
C-2 Model: Capacity 267,000 B/D
Facility Cost
Royalty and Catalyst
Interest, Owner's Engineering and Startup
Working Capital
Total
W-1 California Model: Capacity 90,000 B/D
Facility Cost
Royalty and Catalyst
Interest, Owner's Engineering and Startup
Working Capital
Total
1977
1980
1985
490
40
60
900
70
no
1,660
120
200
590
1,080
1,980
2,040
530
240
240
3,050
5,080
1,020
610
400
7,110
8,900
1,620
1,070
640
12,230
920
110
110
520
1,660
5,690
810
680
880
8,060
14,460
2,100
1,740
1 ,410
T977T0
1,270
1,270
12,060
1,040
1,450
2,140
16,690
32,240
4,050
3,870
3,420
43,580
2,9bU
350
350
460
4,110
8,670
860
1,040
780
11,350
14,050
1,350
1,690
1,250
18,340
-------
TABLE V-4
ADDED REFINING COSTS IMPOSED BY
UNLEADED GASOLINE PROGRAM
($ Per Calendar Day)
1977
1980
1985
M-l Model: Capacity 7,500 B/D
Incremental Gasoline Revenue @37.7£/Gal.
~
-
-
Byproduct Revenue
140
320
400
Raw Materials
0
90
120
Operating Cost
(60)
(110)
(150)
Capital Charges
420
760
1,400
Total
500
1,060
1,770
M-2 Model: Capacity 40,000 B/D
Incremental Gasoline Revenue @37.7£/Gal.
(21,410)
(29,150)
(39,760)
Byproduct Revenue
-
-
-
Raw Materials
19,560
26,660
36,360
Operating Cost
30
(170)
(160)
Capital Charges
2,160
5,030
8,650
Total
340
2,370
5.09C
C-l Model: Capacity 105,000 B/D
Incremental Gasoline Revenue @37.7<£/Gal.
(47,250)
(64,270)
(87,610)
Byproduct Revenue
(12,180)
(9,340)
(12,740)
Raw Materials
62,180
76,140
103,790
Operating Cost
(700)
(2,790)
(2,440)
Capital Charges
1,170
5,700
13,940
Total
3,220
5,440
14,9 4 0
C-2 Model: Capacity 267,000 B/D
Incremental Gasoline Revenue @37.7
-------
TABLE V-5
1973 RESIDUAL FUEL CONSUMPTION BY SULFUR LEVEL (MT.%)
(Thousand Barrels Per Year)
0-0.5 0.5-1.0 1.0-2.0 Over 2.0 Total
PAD I
Domestic Source 14,700 25,200 16,800 11,500 68,200
Imported 232,900 130,300 74,900 160,800 598,900
PAD II
Domestic Source 2,000 35,700 26,800 15,300 79,800
Imported 1,700 2,000 1,700 800 6,200
PAD III
Domestic Source 7,800 11,100 8,400 34,700 62,000
Imported 200 2,300 500 1,400 4,400
PAD IV
Domestic Source 800 2,500 3,300 3,300 9,900
Imported -
PAD V
Domestic Source 71,400 8,100 47,500 7,800 134,800
Imported 9,500 - 1,500 200 11,200
Total U.S.
Domestic Source
Imported
Total Residual Fuel
96,700 82,600 102,800
244,300 134,600 78,600
341,000 217,200 181,400
72,600 354,700
163,200 620.700
235,800 975,400
Crude Burned as Residual Plus Inventory Adjustments 54,800
1,030^200
Sources:
Mineral Industry Surveys, "Availability of Heavy Fuel Oils by Sulfur Levels", U.S.
Bureau of Mines, December 1973.
Mineral Industry Surveys, "Crude Petroleum, Petroleum Products and Natural Gas Liquids",
U.S. Bureau of Mines, 1973 Final Summary.
-------
TABLE V-6
ESTIMATED RESIDUAL FUEL DEMAND
THROUGH 1983 BY PAD
(MB/D)
1973
1977
1983
PAD I
PAD II
PAD III
PAD IV
PAD V
Total
1,930
250
190
30
420
2,820
2,010
260
200
30
440
2,940
2,120
270
210
30
460
3,090
Source: Adapted from: Emergency Preparedness: Interruption of
Petroleum Imports into the United States, National Petroleum
Council, September 1974.
-------
TABLE V-7
PHYSICAL PROPERTIES OF LIGHT ARABIAN
CRUDE AND ITS TBP CUTS
TBP Range
Volume %
on CrudeO)
°API
Weight %
Sulfur
Whole Crude
100.0
34.2
1.65
Light Ends (C^ - C4)
1.58
_(2)
-(2)
Naphtha (Cg - 375°)
26.12
63.0
0.032
Distillate (375-650°)
27.6
39.6
0.7(3)
Fuel Oil (650°+)
44.7
17.0
2.89
Notes: (1) Volume percent yields were applied to 200 MBD and 30 MBD cases
to determine flow rates to downstream processes.
(2) Not determined for this study.
(3) In meeting the low-sulfur specifications on the fuel oil, some
of this material was blended into the fuel oil stream. For
purposes of those blends, it was assumed that the distillates
had been desulfurized to 0.1 weight percent sulfur.
-------
TABLE V-8
RESIDUAL FUEL DESULFURIZATION INVESTMENT ESTIMATES
Refinery Crude Feed Rate, MB/CD
200
200
30
30
HDS Unit Feed Rate, MB/CD
90
90
14
14
Sulfur Content of 650°F.+ Residuum, Wt.%
2.9
2.9
2.9
2.9
Sulfur Limit on Fuel Oil, Wt.%
0.7
0.3
0.7
0.3
Battery Limits Investments, $MM
Residual Desulfurization Unit
49
73
10
15
Hydrogen Generation
15
18
4
5
Sulfur Plant
6
7
2
2
Sub-Total
70
98
16
22
Offsites, $MM
Tankage and Tank Farm Piping
9
9
1
1
Interconnecting Piping
8
12
2
3
Sulfur Handling and Storage
6
7
2
2
Utilities Systems
6
7
2
2
Other Supporting Systems
9
13
2
3
Sub-Total
38
48
9
11
Total Investment Requirements
108
146
25
33
-------
TABLE V-9
ANNUAL DESULFURIZATION COSTS
Refinery Crude Feed Rate, MB/CD
200
200
30
30
Sulfur Limit on Fuel Oil, Wt.%
0.7
0.3
0.7
0.3
Residual Fuel Production Meeting
Sulfur Specification, MB/CD
87.2
87.5
13.1
13.1
Operating Costs, $M/Year
Labor
1,840
2,360
490
610
Plant Overhead and General &
Administrative Expense
920
1,180
250
300
Maintenance Materials
2,130
2,910
490
660
Utility and Energy Costs
23,100
21,800
3,460
3,'330
Operating Supplies and
Miscellaneous
540
720
120
160
Sub-Total Operating Costs
28,530
28,970
4,810
5,060
Capital Charqes
27,890
37,440
6,450
8,520
Total Annual Costs
56,420
66,410
11,260
13,580
Cost Per Barrel of Fuel Oil
Meeting Sulfur Specifications, $
1.77
2.08
2.35
2.84
-------
APPENDIX
-------
Table A-l
U. S. REFINING CAPACITIES AND
WASTEWATER CHARACTERIZATION
(as of 1-1-74)
Company - City
Specialty Refiners -
No Reforming or
Catalytic Conversion
State PAE
Crude 01T
Desalt. Atmos. Vac.
Processing Capacity, MB/SD
Cat.
Ref.
Wastewater Characterization*
Cracking Lube Asphalt
Process
Configuration
Refinery
Type
ProcessxSi
Factor
Amoco - Savannah
Ga.
1
-
12.0
-
Young Ref.-Douglasville
Ga.
1
-
2.5
-
Amoco-Baltimore
Md.
l
-
10.C
-
Chevron-Baltimore
Ma.
14.2
14.2
13.B
Seminole Asphalt-St.Marks
FU.
1
5.5
5.5
2.4
Valvoline/Ashland-Freedoir
Pa.
1
6.5
6.5
2.0
Pennzoil - Reno
Pa.
1
-
2.2
-
Sun-Yabocoa
P.R.
1
66.C
66.0
30.0
Crystal-Carson City
Mich.
2
6.5
6.5
2.8
Hi "^back-Plymouth
111.
2
-
1.5
-
Yetter-Colmar
111.
2
LI
1.1
1.0
Gladieux-Ft. Wayne
Ind.
t.
10.5
10.5
-
Laketon Asphalt-Laketon
Ind.
1
8.9
8.5
5.0
Ashland-Findlay
Ohio
n
c
20.0
20.0
8.0
Somerset-Somerset
*y.
-
3.0
-
Mi o-Ameri ca-Chanute
Kan.
o
c.
-
3.3
1.8
Allied Mat"Is.-Stroud
Okla.
2
5.8
5.8
2.8
Tonkawa Ref.-Amett
Okla.
n
5.3
6.3
-
Berry/Crysta 1-Stephens
Ark.
3
3.5
3.5
1 .0
Cross-Ssackover
Ark.
3
5.0
5.0
2.0
KacMi1lan-Norphlet
Ark.
3
4.5
4.5
2.8
Vulcan Asphalt-Cordova
Ala.
3
-
3.2
-
Warrior Asphalt-Holt
Ala.
3
-
2.6
-
Southland-Crupp
Miss.
3
4.2
4.2
-
South1and-Lumberton
Hiss.
3
6.0
6.0
-
Southland-Sandersvi lie
Miss.
3
U.O
11.0
6.0
Bayou State - Hosston
La.
3
3.7
3.7
2.0
Calunet - Princeton
La.
3
4.1
4.1
2.4
Kerr NcGee-Cotton Valley
La.
3
8.0
8.0
-
Marion-Hobile
Ala.
3
15.5
15.5
-
LaJet-St.James
La.
3
11.0
U.O
.
Adobe/Crysta1-LaBlanca
Tex.
3
5.0
5.0
-
Eddy-Houston
Tex.
3
-
3.4
_
Flint Chein.-San Antonio
Tex.
3
-
1.2
Texaco-Port Neches
Tex.
3
29.5
49.5
27.4
1.5
-
8.0
9.00
A13
1.693
-
1.3
7.24
A13
1.693
-
8.0
10.60
A14
2.825
-
11.0
12.27
A14
2.825
-
2.5
7.89
A13
1.693
1.3
-
4.91
A12
1.020
1.6
-
10.45
A14
2.825
IS.5
-
6.30
A22
1.210
-
-
2.43
All
0.612
-
-
1.00
All
0.612
-
-
2.91
All
0.612
-
-
2.00
All
0.612
2.6
6.07
A12
0.612
-
6.0
6.00
A12
1.020
-
2.5
11.00
A14
2.825
-
-
1.55
All
C.612
0.9
1.2
5.98
A12
1.020
-
-
2.00
All
0,612
-
1.0
5.71
A12
1.020
1.4
11.22
A14
2.825
-
1.3
6.09
A1Z
1.020
.
1.8
7.75
A13
1.693
-
1.7
8.85
A13
1.693
1.4
6.00
A12
1.020
-
2.3
6.60
A12
1.020
-
3.5
6.36
A12
1.020
1.3
0.5
11.16
013
1.235
1.7
0.5
9.44
A13
1.693
-
-
2.00
All
0.612
-
-
2.00
All
0.612
-
.
2.00
All
0.612
-
-
2.00
All
0.612
-
-
1.00
All
0.612
-
1.00
Hi 1
0.612
-
9.0
4.33
All
1.020
-------
Table A-l
(continued)
Crude Oil
Company - City
State
PAD
Desalt.
Atmos.
Vac.
Quintana/Howell-Corpus Christi
Tex.
3
10.5
10.5
Pride-Abilene
Tex.
3
14.7
14.7
_
Tesoro-Carrizo Springs
Tex.
3
13.5
13.5
-
Tex.Asphalt-Ft.Worth
Tex.
3
3.5
.
Three Rivers-Three Rivers
Tex.
3
_
1.6
0.8
Caribou 4 Corners - Kirtland
NM
3
_
2.2
_
Thriftway-Bloomfield
NM
3
_
2.2
_
Jet Fuel Ref.-Mosby
Mont.
4
1.1
_
Tesoro-Molf Pt.
Mont.
4
_
2.7
_
Nountaineer-LaBarge
Wyo.
4
-
0.5
-
Southwestern-LaBarge
Wyo.
4
-
0.3
-
Sound Ref.-Tacoma
Wash.
5
4.7
4.7
4.5
Socal-Richmond Beach
Wash.
5
-
5.0
5.0
Socal-Portland
Ore.
5
15.0
15.0
Ariz. Fuels - Fredonia
Ariz.
5
10.0
10.0
4.0
Champ1i n-Wilmi ngton
Cal.
5
-
30.0
18.0
Douglas-Santa Maria
Cal.
5
8.5
8.5
7.5
Edington-long Beach
Cal.
5
29.5
29.5
19.0
Edington-Oxnard
Cal.
5
_
2.5
_
GB/Witco-Oildale
Cal.
5
11.0
11.0
9.5
Golden Eagle-Carson
Cal.
5
13.0
13.0
-
Lunday-Thagard-South Gate
Cal.
5
5.2
5.2
3.0
MacMillan-Signal Hill
Cal.
5
10.0
10.0
-
Newhall Ref.-Newhall
Cal.
5
-
8.0
5.0
San Joaquin-Olldale
Cal.
5
18.0
18.0
7.0
Tenneco-Bakersfie1d
Cal.
5
-
1.3
-
«. Coast Oi 1-Bakersfield
Cal.
5
16.8
16.8
-
Hawaiian Indep.-Barber's Point
Haw.
5
31.6
31.6
-
Arco-lto. Slope
Alfe.
5
-
5.1
-
BP-No. Slope
Alk.
5
.
1.3
-
Socal-Kenai
Alk.
5
23.2
23.2
-
Tesoro-Kenai
Alk.
5
39.5
39.5
-
Sorco-Guam
Guam
5
30.0
30.0
-
Subtotal 68 Refine*les
55271F
m.2
2TT3
Capacity. MB/SD
Wastewater Characterization*
Cat.
Process
Refinery
Process;.Size
Ref. Crackinq Lube
Asphalt
Configuration
Type
Factor
2.00
All
0.612
_
2.00
All
0.612
_
2.00
All
0.612
-
_
1.00
All
0.612
0.8
0.1
8.75
A13
1.693
• - -
_
1.00
All
0.612
-
_
1.00
All
0.612
•
_
1.00
All
0.612
1.00
All
0.612
_
_
1.00
All
0.612
_
1.00
All
0.612
1.9
2.6
14.85
A15
4.172
-
4.0
11.60
A14
2.825
_
8.6
8.88
A13
1.693
• — —
-
2.40
All
0.612
10.0
-
3.60
B12
0.721
_ _ -
5.8
11.07
A14
2.825
_ _
7.5
5.69
A12
1.020
_ .. .
_
1.00
All
0.612
4.0
3.2
11.08
A14
2.825
_ _
-
2.00
All
0.612
-
1.6
6.27
A12
1.020
_ -
-
2.00
All
0.612
_
3.0
6.13
A12
1.020
_ -
3.4
4.66
A12
1.020
-
-
1.00
All
0.612
2.0
4.0
5.57
B13
1.006
-
-
2.00
All
0.612
-
-
1.00
All
0.612
-
1.00
All
0.612
-
0.3
2.16
All
0.612
_
-
2.00
All
0.612
.
_
2.00
An
0.612
— TJ7? 357T
TTfTS"
Gasoline Refiners.
under MH6/SD 155acity
Bradford/Wltco - Bradford
Pennzoil - Rouseville
Pa.
Pa.
7.8
10.4
7.8
10.4
3.3
1.5
3.6
5.7
8.6
11 .50
13.07
A14
A15
2.825
4.172
-------
Table A-l
(continued)
Processing Capacity, HB/SP Wastewater Characterization*
Crude Oil
Vac.
Cat.
Process
Refinery
ProcessxSize
Company - City
State
PAD
Desalt.
Atmos.
Ref.
Cracking
Lube
Asphalt
Configuration
Type
Factor
Quaker St. - Emlenton
Pa.
1
3.5
3.5
1.7
1.3
1.4
3.9
19.37
B15
1.664
Quaker St. - Farmers Valley
Pa.
1
6.8
6.8
2.8
1.9
1.4
6.5
-
16.07
B15
1.664
Pennzoil - Falling Rock
W. Va
1
5.5
5.5
2.5
2.0
-
3.4
-
10.49
A14
2.825
Quaker St. - Newell
W. Va
1
10.0
10.0
4.0
2.9
-
10.9
-
16.57
A15
4.172
Quaker St. - St. Mary's
W. Va
1
5.0
5.0
2.2
1.3
-
4.6
-
14.40
A15
4.172
Ind. Farm Bu. Coop - Mt. Vernon
Ind.
2
15.2
15.2
6.0
3.0
5.8
-
-
4.68
B12
0.721
No. A«er. Pet. - Shallow Water
Kan.
2
5.3
5.3
2.5
.
4.5
-
-
7.57
B14
1.424
Bay Ref./Do* - Bay City
Mich.
?
17.9
17.9
-
-
8.3
-
-
4.78
B12
0.721
Lakeside Ref. - Kalamazoo
Mich
2
6.3
6.3
-
2.0
_
-
-
2.00
All
0.612
Osceola Ref. - W. Branch
Mi ch
2
S.5
9.5
-
1.4
-
-
-
2.00
All
0.612
CRA - Scottsbluff
Neb.
2
5.5
5.5
2.0
l.C
2.6
-
-
5.20
B12
0.721
Westland - Williston
N.l.
?
5.0
5.0
-
2.0
1.1
-
-
3.32
BU
0.516
Apco - Cyril
Gkla.
o
L.
12.S
12.5
5.0
1.0
7.5
-
1.3
7.25
B13
1.006
Midland Coop - Cushing
Okie.
•>
19.8
19.6
7.0
4.5
14.0
-
-
6.60
B13
1.006
Hunt Oil - Tuscaloosa
Ala.
"1
J
15.E
15.8
8.7
1.4
-
-
5.2
6.50
A12
1.020
Canal Ref. - Church Point
La.
3
2.6
2.6
-
1.5
-
-
2.00
All
0.612
Evangeline - Jennings
La.
3
4.3
4.3
-
0.6
-
-
.
2.00
All
0.612
Panariss - Monument
N.K.
-
5.3
-
0.7
-
-
-
1.00
All
0.612
Plateau - Bloonfielc
N.M
3
-
5.2
-
2.3
-
_
-
1 ,0C
AU
0.612
Howell Hydro - San Antonio
lex.
*?
3.3
3.3
-
0.5
-
-
-
2.00
All
0.612
Lonqview/Crystal - Longview
Tex.
-
7.5
-
! .5
-
-
-
1.00
All
0.612
Texaco - El Pasc
Tex.
3
17.9
17.S
-
3.5
14.6
-
-
6.8S
B13
1.006
Union Tex/Allied - Winnie
Tex.
-
lC'.O
-
6.2
3.0
-
-
2.80
Bit
0.516
Winston - Ft. Worth
Tex.
j
15.5
15.5
3.5
1.7
6.0
-
-
4.5j
812
0.721
S. Western (Gilsonite)Granc June.
Cola.
4
6.5
8.5
-
1.6
8 - 5
-
-
8.00
B14
1.424
Treco - Coranerce City
Colo.
4
18.4
18.4
3.5
3.6
14.5
~
-
6.92
B13
i.oce
Big West - Kevin
Mont.
4
5.5
5.6
0.8
1.0
1.2
-
0.3
4.11
B12
C .721
Phillips - Great Falls
Mont.
4
6.C
6.0
7.1.
0.6
3.0
-
0.8
6.9?
B13
1.006
Wfstco - Cut Bank
Mont.
4
5.0
5.0
-
1.0
2.2
-
-
4.64
B12
0. 721
Arizona Fuels - Roosevelt
Utah
£
11.0
I1.0
-
-
6.0
-
-
5.27
B12
0.721
Caribou Four Corners - Woods Cross
Utah
4
5^0
5.C
1.0
2.0
1.0
-
-
3.40
B1'
0.516
Husky - No. Salt Lake
Utah
4
12.0
12.0
3.8
1.0
6.9
-
-
5.77
B13
1.006
Husky - Cody
Wyo.
4
11.2
11.2
6.5
1.2
4.3
-
4.0
9.17
B'4
1.424
Sage Creek - Cowley
Wyo.
4
-
1.2
-
0.5
-
-
-
1.00
A1
0.612
Tesoro - Newcastle
Wyo.
4
11.0
11.0
-
-
8.0
-
-
6.36
BIS
1.006
Beacon - Hanford
Cal.
5
-
12.1
-
1.7
3.3
-
-
2.64
Bll
0.516
Fletcher - Carson
Cal.
5
16.2
16.2
-
4.5
-
-
-
2.00
ai:
0.612
Kern Co. - Bakersfleld
Cal.
5
13.6
13.6
-
2.5
6.2
-
-
4.74
BU
0.721
Sun land - Bakersfield
Cal.
5
9.0
9.0
-
1.0
-
-
-
2.00
AH
0.612
U.S.Oil & Ref. - TacoM
Wash.
5
16.8
16.8
3.2
3.0
-
-
3.0
4. 33
ai:
1.020
Subtotal 42 Refineries
354.6
395.9
72.0
74.7
135.3
43.6
14.6
-------
Table A-l
(continued)
Company - City
Crude Oil
Processing Capacity. MB/SD
State PAD Desalt, fltioos. Vac.
EatT
Ref.
Sasoline Refiners.
20 to 70 HB/SD Capacity,
Excluding California
Ashland - Tonawanda
Mobil - Buffalo
United - Warren
Carib.Gulf Ref. - Bayaaon
Anoco - Yorktown
Clark - Hartford
Mobil - E. Chicago
Rack Island - Indianapolis
Fina - El Dorado
APCQ - Arkansas City
CRA - Coffeyville
CRA - PhilUpsburg
Derby - Wichita
Mobil - Augusta
NCRA - McPherson
Ashland - Louisville
Marathon - Detroit
Total Leonard - Alna
Conoco - Wrenshall
No.Hestern/Ashland - St.Paul Park
Anoco - Mandan
Ashland - Canton
Gulf - Cleves
r,ulf - Toledo
Chaaplln - Enid
Kerr-McGee - Wynnewood
OKC - Okaulgee
Sun - Duncan
Texaco - W. Tulsa
Vickers - Ardaore
Delta - Memphis
Murphy - Superior
L1on - El Dorado
Atlas Proc. - Shreveport
Good Hope - Good Hope
Gulf - Venice
Cracking Lube Asphalt
NY.
1
67.0
67.0
25.0
11.5
26.0
-
10.0
6.45
C22
NY.
1
44.0
44.0
18.0
11.2
25.0
-
7.5
7.86
B24
Pa.
1
38.0
38.0
8.0
10.0
10.2
.
4.0
5.08
B22
P.R.
1
40.0
40.0
9.0
5.5
8.5
-
-
3.50
822
\li.
1
55.8
55.8
28.0
6.0
44.5
-
-
7.29
C23
111.
2
38.0
38.0
15.0
9.2
40.0
-
-
8.71
B24
Ind.
2
50.8
50.8
8.0
11.0
30.0
-
-
5.70
623
Ind.
2
31.0
31.0
14.0
8.0
19.5
-
3.0
7.39
B13
Kan.
2
26.3
26.3
9.0
4.0
11.5
-
2.0
5.88
B13
Kan.
2
26.0
26.0
5.0
6.3
15.0
-
1.4
6.30
B13
Kan.
2
36.0
36.0
12.5
8.6
22.7
5.6
-
8.15
D12
Kan.
2
21.0
21.0
7.5
3.5
7.4
-
2.0
5.61
813
Kan.
2
27.0
27.0
8.8
5.0
16.4
-
-
5.97
B13
Kan.
2
_
52.0
17.7
10.0
27.6
-
8.0
6.37
B23
Kan.
2
57.C
57.0
-
7.0
38.0
-
-
6.00
B23
Ky.
2
26.0
26.0
JO.O
3.0
11.7
-
3.5
6.70
813
Mich.
2
64.0
64. C
25.0
16.0
25.4
-
8.7
6.40
C22
Mich
2
43.0
43.0
17.0
13.4
14.3
-
3.0
5.23
B22
Minn.
2
24.0
24.0
-
3.6
9.5
-
-
4.38
812
Minn.
2
64.0
64.0
38.0
10.0
21.5
-
22.0
8.73
B24
N.D.
2
50.5
50.5
-
8.2
34.0
-
-
6.04
823
Oh.
2
62.0
62.0
24.0
11.0
28.6
-
10.c
7.09
B23
Oh.
2
43.5
43.5
13.3
10.0
27.0
-
2.9
6.82
B23
Oh.
2
51.0
51.0
12.5
11.0
22.0
-
2.0
5.30
B22
Okla.
2
52.0
52.0
18.0
15.0
25.2
5.7
1.4
7.00
Dll
Okld.
2
34.0
34.0
10.0
7.5
18.0
-
3.5
6.71
B13
Okla.
2
22.6
22.6
3.2
-
10.0
-
1.4
5.54
B13
Okla.
2
50.0
50.0
17.0
7.8
47.5
-
-
8.04
B24
Okla.
2
52.6
52.6
14.5
8.0
32.7
-
-
6.01
L?3
Okla.
2
32.0
32.0
11.0
6.5
15.5
-
5.0
7.13
B" 3
Tenn.
2
30.0
30.0
-
-
12.0
-
3.0
5.60
eu
Wis.
2
38.0
38.0
15.5
8.2
10.7
-
12.0
7.89
B24
Ark.
3
45.0
45.0
18.0
5.5
25.2
0.8
6.0
7.59
Oil
La.
3
30.5
30.5
0.6
10.0
-
-
-
2.02
An
La.
3
31.0
31.0
-
3.5
-
-
-
2.00
An
La.
3
29.1
29.1
-
18.0
11.5
-
-
4.37
D12
Wastewater Characterization*
Process Refinery ProcessxSue
Configuration Type Factor
0.792
1.600
0.810
0.8'Q
1.105
1.600
1.130
1.006
1.006
1.006
0.873
1.006
1.006
1.130
1. i 20
1.006
0.752
0.810
0.721
1.600
1.130
1.13-0
1.130
0.810
0.625
1. Quo
1.006
1.600
1.130
1.006
1.006
1.600
0.625
0.612
0.612
0.721
-------
Table A-l
(continued)
Crude OfT
Processing Capacity. H8/SD
EatT
Wastewater Characterszation*
Process Refiner
ProcessxSize
Company - City
State
PAD
Desalt.
Atmos.
Vac.
Ref.
Cracking Lube
Asphalt
Configuration
Type
Factor
Aaerada-Hess - Purvis
Miss.
3
30.0
30.0
5.7
28.6
7.72
B14
1.424
Havajo - Artesia
NM
3
22.0
22.0
4.5
1.9
8.0
-
1.4
5.15
B12
0.721
Shell - Ciniza
NM
3
21.0
21.0
8.0
7.0
10.5
-
0.8
5.84
B13
1.006
Fina - Mt. Pleasant
Tex.
3
27.4
27.4
15.0
3.0
11.8
-
8.0
8.64
B14
1.424
Champlin - Corpus Ch.
Tex.
3
-
63.0
9.2
26.3
10.1
-
-
2.11
B21
0.580
Charter - Houston
Tex.
3
66.0
66.0
22.0
13.5
39.0
-
4.0
6.61
B23
1.130
Cosden - Big Spring
Tex.
3
68.4
68.4
25.0
20.0
35.0
-
8.0
6.84
C23
1.105
Diamond Shamrock-Sunray
Tex.
3
49.0
49.0
14.5
14.0
29.5
-
2.5
6.52
B23
1.13C
LaGloria - Tyler
Tex.
3
29.0
29.0
-
9.5
30.0
-
-
8.21
B14
1.424
Marathon - Texas City
Tex.
3
63.0
63.0
20.0
8.0
33. C
-
-
5.46
C22
0.792
Shell - Odessa
Tex.
3
34.0
34.0
10.0
9.7
15.5
-
-
5.03
B12
0.721
Sun - Corpus Ch.
Tex.
3
60.0
60.0
10.0
24.0
34.2
-
-
5.59
C22
0.792
Texaco - Amarillo
Tex.
3
21.1
21.1
-
5.0
13.3
-
-
5.78
B13
1.006
Tex. City Ref.-Tex. City
Tex.
3
63.0
63.C
14.5
11.0
28.0
-
-
4.90
B22
0.810
Conoco - Commerce City
Colo.
4
26.0
31.C
7.0
6.5
14.5
-
3.3
6.15
B13
1.006
Amoco-Salt Lake City
Utah
4
41.1
41.1
-
5.5
22.0
-
2.5
5.94
B23
1.130
Chevron -Salt lake City
Utah
4
47.4
47.4
27.0
5.5
25.0
-
-
5.73
B23
1,130
Phillips - Hoods Cross
Utah
4
24.2
24.2
3.0
4.5
10.5
-
2.2
5.82
B13
1.006
Amoco - Casper
Wyo.
4
-
45.3
13.5
5.2
11.0
6.7
1.6
4.81
on
0.625
Husky - Cheyenne
Myo.
4
24.6
24.6
14.0
6.2
12.5
-
3.0
7.08
B13
1.005
Little Amer. - Casper
Wyo.
i
23.0
23.0
5.8
3.8
10.5
-
2.0
6.03
813
"i .006
Pasco - Sinclair
Wyo.
4
42.0
42.0
14.2
9.7
12.8
-
2.3
4.82
B22
0.810
Texaco - Casper
Wyo.
4
22.1
22.1
10.5
4.5
14.6
-
1.5
7.25
B13
1.006
Cenex - Laurel
Mont.
4
44.0
44.0
15.4
6.8
18.0
-
-
4.80
B22
0.810
Conoco - Billings
Hont.
4
38.0
56.0
12.2
13.0
21.0
-
3.5
4.90
B22
0.310
Exxon - Billings
Mont.
4
46.0
46.0
18.0
14.5
44.1
-
13.0
11.53
B25
1.870
Texaco - Anacortes
Mash.
5
66.3
66.3
23.7
8.0
36.1
-
-
5.62
B23
1.130
Socal - Barbers Pt.
Haw.
5
42.1
42.1
15.0
-
23.0
-
1.3
6.00
B23
1.130
Subtotal 64 Refineries
2,473.4
2,656.7
7BO
547.3 1,346.7
TTTJ
183.2
Gasoline Refiners,
70 to 150 HB/SD Capacity,
Excluding California
BP - Marcus Hook
tm. Hess.-Fort Reading
Chevron - Perth Amboy
Mobil - Paulsboro
Texaco - Hestville
Amoco - Mood River
Pa.
1
105.0
105.0
60.0
22.0
53.9
-
5.65
B33
1.288
NO
1
75.0
75.0
30.0
6.5
45.0
-
6.00
B33
1.288
NJ
1
92.0
92.0
50.0
14.0
38.0
25.0
8.28
B3-
1.824
NJ
1
100.5
100.5
62.6
23.5
56.2 30.8
-
9.96
D2-
0.996
NJ
1
92.6
92.6
31.1
14.5
72.2
-
7.01
C23
1.105
111.
2
112.6
112.6
40.0
12.3
42.0
10.8
5.74
C32
0.946
-------
Table A-l
(continued)
Company - City
State PAD Desalt. Atmos. Vac.
Processlnq Capacity. MB/SD
Crude Oil —Cat.
Ref. Cracking Lube Asphalt
Wastewater Characterization*
Process Refi nery ProcessxSize
Configuration Type Factor
Clark - Blue Island
111.
2
70.0
70.0
27.0
30.5
36.0
-
4.5
Texaco - Lawrencevilie
111.
2
68.4
88.4
25.3
26.7
54.8
-
3.0
Texaco - Lockport
111.
2
75.8
75.8
14.7
21.1
73.3
-
-
Phillips - Kansas City
Kan.
2
89.5
89.5
15.0
16.0
48.0
14.4
3.0
Skelly - El Dorado
Kar.
2
75.0
75.0
23.0
21.5
57.8
-
-
Arco - E. Chicago
Ind.
2
140.0
140.0
70.0
20.0
50.0
-
10.4
Ashland - Catlettsburg
Ky.
2
138.0
138.0
55.0
22.5
59.0
-
10.0
Koch - Pine Bend
Minn.
2
110.0
110.0
40.0
16.5
65.6
-
20.0
Amoco - Sugar Creek
Mo.
2
110.5
110.5
40.0
14.0
61.0
-
6.5
Sohio - Toledo
Oh.
2
125.0
125.0
43.0
47.7
120.3
-
7.0
Sun - Toledo
Oh.
2
130.0
130.0
22.0
41.0
83.5
-
-
Conoco - Ponca City
Okla.
2
120.0
120.0
34.5
31.3
90.0
7.7
3.0
Sun - Tulsa
Okla.
2
90.0
90.0
31.5
30.0
39.6
37.4
4.2
Conoco - Westlake
La.
3
85.0
85.0
8.0
18.5
54.0
-
-
Murphy - Heraux
La.
3
95.4
95.4
14.5
18.0
11.0
-
-
Tenneco - Chalmette
La.
3
97.0
97.0
23.0
35.0
55.6
-
-
Texaco - Convent
La.
3
147.4
147.4
36.8
33.4
114.4
-
-
Chevron - El Paso
Tex.
3
74.7
74.7
24.6
25.0
30.0
-
5.0
Coastal States - Corpus Ch.
Tex.
3
135.0
135.0
33.0
35.0
31.3
-
0.5
Crown Central - Houston
Tex.
3
103.0
103.0
38.0
22.0
61.5
-
-
Fina - Port Arthur
Tex.
3
88.4
88.4
28.0
12.5
38.0
-
-
Phillips - Borger
Tex.
3
100.0
100.0
-
26.0
70.0
-
-
Phillips - Sweeney
Tex.
3
89.5
89.5
17.0
32.0
35.0
-
-
So1 Western-Corpus Ch.
Tex.
3
150.0
150.0
24.0
15.0
12.0
-
-
Union - Nederland
Tex.
3
122.1
122.1
44.0
35.0
40.7
13.3
5.4
Arco - Ferndale
Hash.
5
100.0
100.0
55.0
35.0
64.0
-
-
Mobil - Ferndale
Hash.
5
74.5
74.5
7.0
10.0
34.5
-
-
Shell - Anacortes
Hash
5
94.0
94.0
33.)
20.0
53.0
-
-
Subtotal 34 Refineries
3,495.9
3,495.9 1
,130.6
804.0
1,851.2
103.6
118.3
6.24
6.41
8.00
7.88
6.93
5.53
5.83
8.12
6.38
8.79
6.02
7.92
?0.95
5.91
2.84
5.68
6.91
5.54
3.68
5.95
4.90
6.20
4.54
2.64
6.31
6.39
4.87
5.73
C22
B33
B34
El 2
C23
843
C32
B44
B43
B44
C32
D31
023
C22
B31
B33
643
B23
C31
B33
B32
C32
C21
B51
Ell
B33
B22
B33
0.792
1.288
1.824
0.690
1.105
1.480
0.946
2.096
1.480
2.096
0.946
0.818
1.409
0.792
0.661
1.288
1.480
1.130
0.697
1.288
0.923
0.946
0.583
0.818
0.538
1.288
0.810
1.288
fiasoline Refiners,
Oyer 150 HB/SD Capacity,
Excluding California
Getty - Delaware City
Exxon - Linden
Arco - Philadelphia
Gulf - Philadelphia
Del.
NJ
Pa.
Pa.
150.0
286.0
195.0
174.0
150.0
286.0
195.0
174.0
90.7
143.0
57.0
65.0
42.0 138.0
42.0 142.2
60.0 30.0
52.0 80.5
46.0
19.5
8.12
7.41
4.42
5.15
C43
C43
B52
B52
1.435
1.435
1.142
1.142
-------
Table A-l
(continued)
Processing Capacity,
, MB/SD
Wastewater Characterization*
Crude Oil
Vac.
Cat.
Process
Refinery
ProcessxSize
Company - City
State
PAD
Desalt.
Atmos.
Ref.
Cracking Lube
Asphalt
Configuration
Type
Factor
Sun - Marcus Hook
Pa.
1
180.0
180.0
48.0
45.0
97.0
45.6
12.0
9.59
E23
1.157
Conaonwealth - Penuelas
P.R.
1
185.0
185.0
92.5
70.0
74.0
1.0
4.96
C42
1.028
Amerada - Hess - St. Croix
v.i.
1
621.1
621.1
20.0
130.0
_
_
-
2.03
A41
0.942
Marathon - Robinson
111.
2
205.0
205.0
62.0
47.3
88.3
-
-
4.89
B52
1.142
Mobil - Joliet
in.
2
186.0
186.0
82.0
46.2
94.0
_
-
5.47
B52
1.142
Shell - Mood River
in.
2
268.0
268.0
91.5
87.0
152.5
22.4
22.5
7.85
D51
1.047
Union - Lemont
in.
2
160.0
160.0
55.0
32.0
79.5
-
2.0
5.48
852
1.142
Amoco - Whiting
Ind.
2
331.6
331.6
140.0
56.0
160.5
41.1
31.0
8.06
D52
1.464
Sohlo - LiM
Oh.
2
175.0
175.0
51.0
50.0
80.5
9.8
-
5.78
D41
0.959
Cities Ser. - Lake Charles
La.
3
282.1
282.1
60.0
46.0
173.0
29.8
-
7.27
051
1.047
Exxon - Baton Rouge
La.
3
460.0
460.0
165.0
99.5
274.0
88.4
28.9
9.18
E33
1.326
Gulf - Belle Chasse
La.
3
186.0
186.0
55.0
37.5
117.4
-
.
6.08
B53
1.593
Shell - Norco
La.
3
250.0
250.0
90.0
41.5
143.0
-
6.0
6.08
B53
1.593
Chevron - Pascagoula
Miss.
3
252.6
252.6
148.0
65.0
117.0
-
-
5.36
C42
1.028
Amoco - Texas City
Tex.
3
350.5
350.5
131.0
129.0
245.5
-
5.3
6.76
C43
1.435
Arco - Houston
Tex.
3
233.5
233.5
70.0
100.0
105.5
19.4
-
6.09
E31
0.796
Exxon - Baytown
Tex.
3
420.0
420.0
180.0
88.0
165.0
120.2
12.0
8.85
E32
1.020
6ulf - Port Arthur
Tex.
3
319.0
319.0
147.4
65.0
171.0
46.1
-
7.56
E32
1.020
Mobil - Beawmt
Tex.
3
335.0
335.0
103.0
94.0
185.5
31.4
0.1
6.85
D51
1.047
Shell - Deer Park
Tex
3
293.0
293.0
106.4
77.0
201.0
26.0
3.8
7.79
051
1.047
Texaco - Port Arthur
Tex.
3
427.4
427.4
149.5
66.6
268.3
52.6
-
7.72
D51
1.047
Subtotal 25 Refineries
6,925.8
6.925.8
2,403.0
1,668.6 3,383.2
532.8
190.1
California - Gasoline
fteflners Over gB~HE75)
Capacity
Mohawk - Bakersfield
Cal.
5
-
22.8
-
2.6
_
1.00
All
0.612
Socal - Bakersfield
Cal.
5
-
27.4
-
5.4
•
i.i
1.48
All
0.612
Toscopetro - Bakersfield
Cal.
5
-
27.0
17.0
14.5
32.3
_
8.81
814
1.424
Arco - Carson
Cal.
5
-
173.0
93.0
34.0
169.2
7.41
C43
1.435
Douglas - Paramount
Cal.
5
36.0
36.0
21.0
6.4
_
_
14.0
7.25
A13
1.693
Exxon - Benecia
Cal.
5
95.0
95.0
53.0
24.0
100.6
_
8.91
B3'
1.824
Gulf - Santa Fe Springs
Cal.
5
53.8
53.8
25.0
19.0
38.6
•
4.0
7.66
62',
1.600
Mobil - Torrance
Cal.
5
100.0
130.0
95.0
36.0
136.6
8.80
844
2.096
Phillips - Avon
Cal.
5
94.7
115.8
74.5
32.5
125.1
1.7
9.28
D32
1.144
Powerlne - Santa Fe Springs
Cal.
5
30.0
30.0
15.0
6.3
12.0
_
5.0
6.90
B13
1.006
Sequoia - Hercules
Cal.
5
28.3
28.3
5.9
15.8
2.9
-
_
2.82
Bli
0.516
Shell - Martinez
Cal.
5
85.0
103.0
55.3
25.0
105.0
13,1
10.4
11.34
El 3
0.897
-------
Table A-l
(continued)
Conpany - City
Shell - Wilmington
Socal - El Segundo
Socal - Richmond
Texaco - Wilmington
Union - Los Angeles
Union - San Francisco
Subtotal 18 Refineries
Total 251 Refineries
Crude Oil
Processing Capacity, HB/SD
TatT
Wastewater Characterization*
Process
ProcessxSize
State
PAD
Desalt.
Atmos.
Vac.
Ref.
Cracking Lube
Asphalt
Configuration
Type
Factor
Cal.
5
101.0
101.0
60.0
21.0
70.0
6.75
D21
0.713
Cal.
5
126.3
242.1
103.0
60.0
157.5
_
8.3
6.26
C42
1.028
Cal.
5
200.0
200.0
150.0
70.5
122.0
85.9
U.O
12.65
E23
1.157
Cal.
5
23.2
78.9
-
38.9
116.0
_
10.12
835
2.132
Cal.
5
86.0
111 .0
83.0
29.0
93.0
-
10.0
8.63
B44
2.096
Cal.
5
ns.o
115.0
38.5
26.0
72.5
23.2
6.2
9.39
D32
1.144
1,174.3
1,690.1
m.t
m:?
1,353.3
123.5
70.0
14,976.0
15,863.6 5,441.1
3,561.5
8,083.2
856.8
687.8
Sources:
(1) Development Document for Effluent Limitations Guidelines and New Source Performance Standards for
the Petroleum Refining Point Source Category, U. S. Environmental Protection Agency, April, 1974
(EPA-440/1-74-014-a).
(2) "Refining Capacity Registers Largest 'Nickel and Dime' Jtap in History", The Oil > 6as Journal,
April 1, 1974.
(3) "Lube Capacity in U. S. and Canada", Hydrocarbon Processing, June, 1973, p. 113.
(4) International Petroleum Encyclopedia - 1974, Petroleum Publishing Company, Tulsa, Oklahoma.
Copyright, 1974.
~Process configuration is calculated using capacity data and EPA's formula in Reference 4. Given a
configuration and refinery capacity, one can derive refinery type, process and size factors
from TabV 111-4 in Section III. These characterization factors are required to determine refinery-
specific guideline pollutant discharge levels.
-------
TABLE A-2
DOMESTIC PETROLEUM DEMAND FORECAST
Total Petroleum Demand, MBD
Preliminary
1974 Data
1978
1980
1985
1990
Motor Gasoline
6,560
7,531
7,928
8,414
8,448
Aviation Gasoline
42
48
51
56
58
Naphtha Jet
200
200
200
200
200
Kerosene Jet
780
1,010
1,135
1,519
1,939
Kerosene
160
173
175
179
183
Distillate Fuel
2,900
3,369
3,442
3,615
3,661
Residual Fuel
2,665
3,027
3,094
3,093
3,211
LPG
920
1,099
1,099
1,203
1,203
Petrochemical Feedstock
1,008
1,149
1,224
1,559
1,818
Lube and Wax
177
189
195
211
228
Coke
237
260
272
306
345
Asphalt and Road Oil
514
583
621
727
851
Still Gas
450
503
523
566
597
Other
122
132
137
151
167
Total
16,735
19,273
20,096
21,799
22,909
Source:
Preliminary 1974 Data - Oil & Gas Journalt January 27, 1975, pp 106.
1978 through 1990 Data - "Forecast of Domestic Refining Industry Capacity
Through 1985", Turner, Mason & Solomon, March 18,
1975, an adaptation of Emergency Preparedness:
Interruption of Petroleum Imports into the United
States, National Petroleum Council, September
1974.
-------
TABLE A-3
DOMESTIC PETROLEUM REFINING CAPACITY REQUIREMENTS
Basis: Product Imports to be held constant at preliminary 1974 levels.
1974 Net
Imports(')
Motor Gasoline
Aviation Gasoline
Naphtha Jet
Kerosene Jet
Kerosene
Distillate Fuel
Residual Fuel
LPG
Petrochemical Feedstock
Lube and Wax
Coke
Asphalt and Road Oil
Still Gas
Other
Total
NG Liquids & Other HC
Processing Gain
Crude Run
Indicated Capacity Re-
quirement (@90$
Uti1ization)
1974
Other
Supply(2)
Domestic Refinery Demand, MB/CD
1974 1978 1980 1985
1990
191
3
6,366
7,337
7,734
8,220
8,254
-
42
48
51
56
58
30
•
170
170
170
170
170
160
-
620
850
975
1,359
1,779
3
1
156
169
171
175
179
252
3
2,645
3,114
3,187
3,360
3,406
1,664
13
988
1,350
1,417
1,416
1,534
95
574
251
430
430
534
534
(5)
330
683
824
899
' 1,234
1,493
(35)
-
212
224
230
246
263
(115)
-
352
375
387
421
460
33
-
481
550
588
694
818
34
-
450
503
523
566
597
2
86
96
101
115
131
2,307
926
13,502
16,040
16,863
18,566
19,676
(770)
(750)
(750)
(750)
(750)
(475)
(560)
(590)
(650)
(689)
12,257
14,730
15,523
17,166
18,237
13.6
16.4
17.2
19.1
20.3
Notes: (1) Oil & Gas Journal, January 27, 1975, pp. 114.
(2) January-October 1974 Average from Mineral Industry Survey - Petroleum State-
ment, Monthly, U.S. Department of the Interior - Bureau of Mines, October
1974.
-------
TABLE A-4
SCHEDULED REFINERY EXPANSION PROJECTS
(MB/CD)
Capacity 1/1/74
Capacity 1/1/75
Socal - Perth Amboy, N.J.
Exxon - Bayway, N.J.
Bell - Ardmore, Okla.
Kerr-McGee - Wynnewood, Okla.
Clark - Hartford, 111.
Conoco - Ponca City, Okla.
CRA - Phlllipsburg, Kans.
Sigmor - Three Rivers, Tex.
Exxon - Baton Rouge, La.
LaLandExpl - Mobile, Ala.
Tesoro - Carrizo Springs, Tex.
Hunt - Tuscaloosa, Ala.
COPCO - Ventura, Calif.
HIRI - Oahu, Haweli
Douglas - Paramount, Calif.
Kern Co. - Bakersfleld, Calif.
Miscellaneous Net Additions (IX)
1/1/76 Capacity
Texaco - Lockport, 111.
Exxon - Houston, Texas
ARCO - Houston, Texas
ECOL - Garyville, La.
Champlin - Corpus Christi, Texas
Socal - Richmond, Calif.
Socal - El Segundo, Calif.
Miscellaneous Net Additions (2%)
1/1/77 Capacity
HIRI - Oahu, Hawaii
Dow - Freeport, Texas
Miscellaneous Net Additions
1/1/78 Capacity
(2*)
Shell - Gloucester Co., N.J.
Texaco - Convent, La.
Miscellaneous Net Additions (2X)
1/1/79 Capacity
Type*
PAD I
PAD II
PAD III
PAD IV
PAD V
1,674
3,889
5,933
506
2,248
1,677
4,013
6,256
532
2,388
E
80
E
30
E
30
E
35
E
45
E
6
E
5
R
5
E
8
N
30
E
7
E
14
N
15
E
11
E
15
E
3
17
40
63
5
24
1,604
4,174
6,3fi3
5"57
2,456
E
25
E
250
E
95
N
200
E
60
E
175
E
175
35
82
124
11
48
1,639
4,28V
?,H2
m
2,854
E
65
N
100
35
82
124
n
48
U74
4,365
7,m
553
2,467
N
150
E
200
35
82
124
11
48
2,05$
4,445
7,660
570
3,015
Tota '
U.S-_jU
14 250
14>6
15,36'
16,63'
17,09-
17,74'-
*Type: E - Expansion of Existing Capacity
N - New Grassroots Refinery
R - Reactivation of Idle Facilities
Source: Peer, E.L., "Trends 1n Refinery Capacity and Utilization - An Interim Update for U.S.
Portion Only", Federal Energy Administration, December 1974.
-------
ATTACHMENT 1
TYPICAL REFORMING PROCESS DATA
(200 PSIG Reactor Pressure)
Feedstock
P/N/A
Operating Severity, RON
Product Yield, Vol.%:
H2 SCF/B Feed
Fuel Gas FOE
C3
i C4
nC4
C5/430°F.
Utilities:
Fuel, Bbl/B Feed
Power, KWH/B Feed
Steam, Lbs/B Feed
Other Variable Costs, $/B
Standard Capacity Increment, B/SD
Stream Operating Factor, %
1974 Investment - ISBL, M$
Capacity Exponent
Initial Catalyst Charge, $M
Paid-Up Royalty, $M
Offsites As % ISBL
250°/325°F. Light
Arabian Naphtha
250 7 325° F.
Wilmington Naphtha
70/19/11
24/76/10
90
100
90
100
940
1,140
1,310
1,570
2.3
5.5
0.5
1.3
3.2
7.8
1.5
3.1
2.0
2.9
0.3
0.7
3.8
5.3
0.5
1.2
85.2
73.9
93.0
88.6
.035
.037
.035
.037
1.3
1.3
1.3
1.3
45.6
45.6
45.6
45.6
.015
.020
.015
.020
27,800
25,000
27,800
25,000
84
84
84
84
16,200
16,200
16,200
16,200
0.65
0.65
0.65
0.65
1,200
1,200
1,200
1,200
1,100
1,100
1,100
1,100
45
45
45
45
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ATTACHMENT 2
TYPICAL DESULFURIZATION PLANT DATA
Feedstock
Boiling Range, °F.
Weight Percent Sulfur
HOS Unit Feed Rate, B/CD
Battery Limits Investment, $M:
Desulfurization Unit
Hydrogen Generation
Sulfur Plant
Sub-Total
Offsi tes
Total Investment
Product Sulfur, Wt.%
Operating Costs, $M/Year:
Labor
Plant Overhead and General and
Administrative Expense
Maintenance Materials
Utility and Energy Costs
Plant Supplies
Catalyst & Chemicals
Sub-Total
Capital Charges
Total Annual Costs
Cost Per Barrel of Desulfurized Product, $
Arabian Light Fractions
375/500
500/620
1,000+
0.26
0.9
4.3
20,000
20,000
16,800
9,500
700
200
10,400
9,500
1,350
700
11,550
22,100
7,700
3,000
32,800
4,800
5,650
16,700
15,200
17,200
49,500
0.03
0.10
1.00
300
350
1,050
150
320
1,250
80
170
400
1,220
100
52b
1,220
7,320
315
950
2,100
2,240
11,380
3,920
4,440
12,780
6,020
6,680
24,160
0.875
0.915
3.94
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