STUDY OF THE FUTURE SUPPLY
OF LOW SULFUR OIL
FOR ELECTRICAL UTILITIES
Hittman Associates, Inc.
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STUDY OF THE FUTURE SUPPLY
OF LOW SULFUR OIL
FOR ELECTRICAL UTILITIES
HIT-499
February 1972
Prepared Under
Contract No. EHSD 71-43
Environmental Protection Agency
Office of Air Programs
HITTMAN ASSOCIATES, INC.
COLUMBIA, MARYLAND 21045
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ii
LEGAL NOTICE
This report was prepared as an account of Government sponsored work.
Neither the United States, nor the Environmental Protection Agency, Office of
Air Programs (EPA-OAP), nor any person acting on behalf of EPA-OAP:
A. Makes any warranty or representation, expressed or implied with
respect to the accuracy, completeness, or usefulness of the information con-
tained in this report, or that the use of any information, apparatus, method,
or process disclosed in this report may not infringe privately owned rights;
or
B. Assumes any liabilities with respect to the use of, or for damages
resulting from the use of any information, apparatus, method, or process
disclosed in this report.
As used in the above, "person acting on behalf of EPA-OAP" includes
any employee or contractor of EPA-OAP, or employee of such contractor, to
the extent that such employee or contractor of EPA-OAP, or employee of such
contractor prepares, disseminates, or provides access to any information
pursuant to his employment or contract with EP A -OAP, or his employment
with such contractor.
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T ABLE OF CONTENTS
LEGAL NOTICE. . . . .
T ABLE OF CONTENTS
LIST OF TABLES.
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LIST OF FIGURES. . . .
I.
II.
III.
IV.
V.
VI.
VII.
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. . . .
. . . .
INTRODUCTION. .
. . . . .
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SUMMARY AND CONCLUSIONS. .
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OIL PRODUCTION AND CONSUMPTION. . . . .
A.
B.
C.
D.
E.
. . . .
Growth of World Petroleum Supply and Demand. .
Reserves and Their Near-Term Effects on . . . .
Production
Sulfur Content of Domestic and Imported Oils. . .
Regional Consumption of Residual Oil . . . . . . .
Imports Required to Meet Present Demand. . . .
PREDICTIONS 01<" FUTURE DEMAND FOR RESIDUAL.
OIL .
LOW SULFUR RESIDUAL OIL ALTERNATIVES. . . . .
A.
B.
C.
D.
E.
F.
A.
B.
C.
Naturally Occurring Low Sulfur Residual Oil . . .
Crude or Topped Crude Oils. . . . . . . . . . . .
Blended Residual and Crude Oils. . . . . . . . . .
Distillate Cutter Stock. . . . . . . . . . . . . . .
Desulfurized Residual Oil. . . . . . . . . . . . . .
Flue Gas Desulfurization Systems. . . . . . . . .
PROJECTIONS OF LOW SULFUR RESIDUAL OIL. . . .
AVAILABILITY
Dome stic Supply of Low Sulfur Fuel. . . . . . . .
Foreign Supply of Low Sulfur Fuels. . . . . . .
Comparisons of Supply and Demand. . . . . . . .
REFERENCES. . . . . . . . . . . . .
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. APPENDIX A - IMPORT RESTRICTIONS. .
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APPENDIX B - ECONOMICS OF RFO DESULFURIZATION
AND OIL TRANSPORTATION. . . . . . . . .
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Page
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iii
iv
v
1-1
II-1
III - 1
III - 1
III - 3
III - 5
III-11
III -14
IV-1
V-1
V-1
V-2
V-3
V-4
V-4
V-6
VI-1
VI-1
VI-3
VI-6
VII -1
A-1
B-1
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1-
Table
No.
1
2
3
4
5
6
7
8
9
10
11
A-1
A-2
B-1
B-2
LIST OF TABLES
Title
Trends in Free-World Refining Crude Oil Capacities
in 1000 bid for January 1 of Each Year
Sulfur Distribution of Domestic and Foreign Crude
Oils Based on Analyses of Oils Produced in 1966
Percent of Refinery Yield Throughout the Free World
1970 Data
Sulfur Distribution of Domestic Residual Oils Based
on Analyses of Oils Produced in 1965
Regional Growth of Residual Oil Demand
(Millions of Barrels Per Year)
Residual Fuel Oil Production, Imports. and
Consumption (Millions of Barrels Per Day)
Imports in 1969 (Thousands of Barrels Per Day)
Crude Versus Residual Oil Factors for U. S.
Consumption (Quantities in 1000 bid)
Oil Consumption and Predicted Demand (Millions
of Barrels per Year)
Present and Planned Fuel Desulfurization
Facilities and Capacities
Comparison of Supply and Demand Forecasts
Allowable Refinery Import Quotas for District V
Allowable Refinery Import Quotas for Districts I - IV
Domestic Desulfurization Data for United States
PAD Districts
Miles (Days Round Trip) to U. S. A., East
Coast, From: (Locations listed)
iv
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III - 2
III - 6
III - 8
III - 9
III -1 2
III -16
III - 16
III-17
IV-4
V-7
VI-8
A-3
A-3
B-7
B-11
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v
LIST OF FIGURES
Figure
No. Title Page
1 Expected Growth in Resid Consumption by III - 1 3
United States Electrical Utilities
2 Imports Into the United States III - 15
3 Forecast of Total U. S. Generating Capacity IV-2
4 Forecast of U. S. Electrical Generation by Fuels IV-2
5 Residual Fuel Oil Consumption by the U. S. IV-3
Electrical Utilities
6 Oil Consumption and Predicted Demand IV-5
7 Growth of South American Residual Production VI-5
and Desulfurization Capability
8 Current Cumulative Generating Capacity vs. VI-9
Plant Size for Oil Burning Utilities
9 Case I REsidual Oil Supply and Demand - No VI - 1 0
Additional Desulfurization
10 Case II Residual Oil Supply and Demand - VI -10
Desulfurization of 60% of Imports
A-1 Coordination Districts for Petroleum Industry A-2
B-1 Determination of Fixed Charge Rate B-3
B-2 Fixed Cost of Caribbean Oil Desulfurization Plant B-4
B-3 Variable Cost of Caribbean Oil Desulfurization B-4
Plant
B-4 Fixed Cost of Domestic Oil Desulfurization by B-9
PAD District
B-5 Variable Cost of Domestic Oil Desulfurization B-10
by PAD District
B-6 Oil Transport Costs Via Tanker B-12
B-7 Typical Oil Transportation Costs for Rail. B-14
Barge. and Pipeline
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I-I
1. INTRODUCTION
This report examines the future supply and demand of low sulfur
fuel oil. Of all the fuels, residual oil (resid, No.6, or "Bunker C") is the
most difficult to study. It is used to "fill the gaps" left by the other fuel types
(coal, gas, and nuclear). Its growth will depend upon the "alternate opportu.-.
nities." If the alternates are expanded, the demand for resid is reduced; if
alternates shrink, the demand for resid increases. The present situation and
the situation throughout most of the 1970s appear conducive to the growth of
oil. The utility companies, through a vigorous construction campaign, are
attempting to meet the rapidly growing electrical needs of their customers.
At the same time, gas is becoming scarce and coal more expensive. Added to
these factors, are the present and expected sulfur emission standards that
will grow more restrictive in the next few years. These standards may hurt
coal and force more coal-fired plants to switch to low sulfur fuels.
The currently available predictions on the supply and demand for elec-
tricity and fuels were collected and studied. Construction plans of the utilities
were obtained. Data on United States and foreign production of residual oil
were gathered including the availability of low sulfur fuel. Total demand for
residual fuel was predicted along with the demand for low sulfur fuels. The
potential supply of low sulfur fuels was predicted. The effects that import
regulations have on this supply were studied (Appendix A). The costs of
direct desulfurization of resid were estimated along with the costs of oil trans-
portation (Appendix B).
The supply and demand quantities for residual oil were compared for the
1970-1980 time period and conclusions were drawn as to what steps must be
taken to satisfy the 1980 demand for low sulfur fuels.
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II-1
II.
SUMMARY AND CONCLUSIONS
In the study of the factors influencing the supply and demand of low
sulfur residual oil, the following major conclusions were determined:
.
Based on currently accepted projections and upon an
independent review of the factors affecting near-term
demand it was determined that the demand for residual
oil by all domestic markets including the utilities will
increase from 2.25 million barrels per day (bbl/day) in
1970 to 3.90 million barrels per day in 1980.
.
Electrical utilities' share of the total demand will increase
significantly in the 1970s. The utility industry's demand will
increase from 0.64 bbl/day to 2.24 million bbl/day (see
Figure 2, page III -15). This growth rate is an unprece-
dented increase. It stems primarily from the fact that
other major f11el alternatives (gas, coal, nuclear) are
afflicted by many problems; e. g., scarcity of natural gas,
many coals cannot meet upcoming emission standards with-
out undergoing treatments that are not yet fully developed,
and intervenors in safety reviews have slowed nuclear
power station construction. Despite slightly rising costs,
oil has become the fuel of choice in many areas.
.
About 3.20 million bbl/day or 83 percent of the total demand
for residual oil will be under Federal or local regulations
by the year 1980.
.
Assuming historical growth rates, refinery yields, and no
change in the current foreign V. S. import-toOproduction
ratios, total resid supply is estimated to equal demand with
only a minor increase in imports over the current import
trend line.
.
..
Low sulfur resid, however, will not meet regulated demand'
without an intense effort beyond ~easonable expectations. A
large percentage of South American ,resid must be desulfurized.
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11-2
.
Significant domestic resid desulfurization will also be neces-
sary. The minimization of what is termed detrimental
blending of domestic oils is necessary. A moderate use of
beneficial blending of foreign crudes and domestic cutter
stocks will be required in some locales. Also, stack gas
S02 removal systems, in all likelihood, will be used in large,
base-loaded oil-burning plants in order to utilize the high
sulfur resid which cannot be directly desulfurized economically.
.
Finally, domestic refineries should be encouraged to increase
their yield of residual oil and to more effectively utilize
domestic low sulfur crude feedstock.
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III - 1
III.
OIL PRODUCTION AND CONSUMPTION
A.
Growth of World Petroleum Supply and Demand
Oil is an international commodity. The United States is only one of
many countries bargaining for foreign oil. International demand will, in
the future, be the primary factor in determining price and availability of
oil and its products.
Worldwide production and refining of oil has increased at an average
rate of 6.7 percent per annum. This growth has occurred primarily outside
the United States. This overall growth is expected to continue into the
future (Refs. 1 and 2). Table 1 shows historic as well as projected trends
in world refining. Note that the United States growth rate is the least of all
other countries.
Worldwide demand follows the increase in productive capacity in a
fairly consistent manner. Total demand between 1960 and 1969 increased
by 6.7 percent. Increase in demand inside the United States was 3. 1 percent,
while outside the United States was 8.9 percent over the same period (Ref. 2).
These trends are expected to continue in the future.
These demand trends must be factored into any projections which show
significant growth in United States oil imports. In 1970 the United States
demand for all petroleum products amounted to 14.7 million barrels daily of
which 3.4 million were imports. Thus, imports satisfy 23 percent of the
United States demand. Spokesmen for the oil industry have testified that by
1980 imports may make up as much as 50 percent of the United States demand
for petroleum (Ref. 3). This will occur during a period where other countries
will also be scrambling for additional supplies of petroleum. Thus, an energy
crisis may very well exist during the coming ten years.
"What part will the growth of oil burning power plants (both new plants
and conversions) play in the demand of imported oil? I' is one of the questions
to be answered in this study. The data on projection of supply and demand
which have been collected for this study will show whether the growth of
U. S. demand for residual oil (especially low sulfur oil) is a significant portion
pf total petroleum demand. It will also show the effects that this portion of
petroleum demand will have on the demand for foreign oils.
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TABLE 1
TRENDS IN FREE-WORLD REFINING
CRUDE OIL CAPACITIES IN 1000 bid FOR JANUARY 1 OF EACH YEAR
Area Recorded Projected Average Growth
1966-1975
1966 1967 1968 1969 1970 1971 1972 1973* 1974* 1975* % Per Annum
Asia Pacific 3,473 3, 996 4,265 4, 920 5,554 6,061 6,661 7,511 8, 200 8,700 9.6
Africa 615 700 732 756 785 925 995 1,017 1, 100 1,200 6.9
Canada 1,174 1, 207 1,230 1, 355 1,439 1,450 1,450 1,617 1,800 I, 900 4.9
Middle East 1,900 1,960 2,053 2,296 2,438 3,170 3,172 3,219 3,500 3,700 6.8
Latin America 4,196 4,370 4,675 4, 984 5,113 5,679 5, 900 6, 335 6,900 .7,300 5.7
United States 10,721 10,952 11,658 12,079 12, 651 13, 293 13, 686 14,826 16, 100 17, 100 4.8
Western Europe 8,586 9, 695 11,085 12, 884 13, 941 15,177 16,471 16,475 17, 900 19, 100 8.3
TOTAL 30,665 32, 880 35,698 39,294 41,921 45,757 48,335 51,000 55,500 59,000 6.7
*Extended Oil and Gas Journal (Ref. 1) projections, based on free-world trend line.
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III - 3
B.
Reserves and Their Near-Term
Effects on Production
America's proven recoverable reserves of liquid hydrocarbons were
,
estimated by the American Petroleum Institute q.nd American Gas Association
at the end of 1966 to include 31. 5 billion barrels of crude oil. In addition,
the American Petroleum Institute estimates that additional reserves of crude
oil whose economic recovery has not yet been established conclusively, but
whose location has been determined, amount to about 7.6 billion barrels.
The Oil and Gas Journal (Ref. 1) estimates U., S. recoverable reserves in
1970 to be 37 billion barrels.
In general, the domestic oil industry has managed to increase reserves
and producing capacity as required to meet increases in demands. In 1930,
proved recoverable reserves were 13 billion ba1frels (Ref. 4). In 1946,
recoverable reserves increased to 24 billion barrels or approximately 12
times the 1946 production. Over the following 17 years, 44 billion barrels
were produced, or 20 billion barrels more than had been estimated as proved
recoverable liquid petroleum reserves in 1946. Yet proved reserves on
January 1, 1967,had increased to 31. 5 billion barrels.
In part, this results from the definition itself. The term"proved re-
serves"applied to crude oil is used to denote the amount of oil in known de-
posits which is estimated to be recoverable under current economic and
operating conditions. In general, they include only the producible content of
the explored portions of reservoirs - -an underground inventory, so to speak.
As the reservoir is further explored, substantial amounts may be added to the
quantity proven.
Another point which may be helpful in understanding the situation is the
improved recovery rate. The U. S. Department of the Interior has called
attention to this factor as follows:
"The crude oil recovery rate was estimated
to be 30 percent at the end of 1965 and is believed
to be increasing at an annual rate of 0.5 percent of
total original oil in place. The basis for this in-
crease is not well delineated, and there is no cer-
tainty that it can be continued at the current rate.
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III - 4
On the assumption that it will be, however, the
improvement of 7.5 percent in recovery rate to
37.5 percent by 1980 would yield an additional
29 billion barrels of economically recoverable
reserves even if no new discoveries were made. II
(Ref. 5)
The report also made the following points:
I'The calculated trend of crude oil discoveries
from 1920 through 1980 will result in discoveries of
72 billion barrels of oil in place between 1965 and 1980.
On the basis of 37.5 percent recovery, these dis-
coveries will yield 27 billion barrels of reserves.
When reserves acquired by discovery are added
to those obtained through increased recovery, the
resulting 56 billion barrels will be adequate to offset
anticipated production and increase the reserve level
by 4 million barrels; however,
The calculated discovery rate is 4. 8 billion
barrels annually between 1965 and 1980. Discoveries
actually reported since 1957, adjusted to compensate
for partially developed fields since 1957, have averaged
3.3 billion barrels annually, approximately two-thirds
the calculated rate. At the end of 1966 cumulative
reported discoveries were seven billion barrels below
the calculated trend line.
The departure of reported (adjusted) discoveries
from the historic trend since 1957 coincides with large
declines in activity indices normally identified with the
discovery of oil: geophysical crew months worked,
exploratory drilling, and numbers of new oilfields
found. II
The report concluded as follows:
"It, therefore, appears that the discovery rate
observed since 1957 will not be sufficient to offset
withdrawals from proved reserves between 1965 and
1980 on the basis of anticipated recovery rates. Speci-
fically, either the recovery rate must improve even
faster than the 0.5 percent annual improvement pro-
jected, or discoveries must be increased above the
levels that have prevaile d s inc e 1957. "
Potential remaining domestic crude oil reserves are considered by the
United States Geological Survey and the Interstate Oil Compact Commission
to be larger than the current proven levels by at least a factor of five.
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III - 5
Their estimate of about 200 billion barrels of additional potential reserves
is based on the fact that the ground favorable for the occurrence of petroleum
is as yet explored to only a minor degree.
It is concluded, therefore, that for the critical time period between
1970 and 1980 petroleum reserves will decline moderately but that there
are more than sufficient reserves to satisfy any possible increase in demand.
This statement can also be extended to the year 2000 with some confidence.
Beyond 2000, however, a significant decline in reserves is predicted.
C. Sulfur Content of Domestic and Imported Oils
1.
Sulfur Content of C rude Oils
The Bureau of Mines, refineries, and petroleum associations have
published data on the sulfur content of domestic and foreign crude oils.
The most detailed studies have been issued by the Bureau of Mines. These
include special topical reports as well as yearly summaries.
Oil and coal suffer from a similar problem. A given oil or coal field
will produce a product having substantially different sulfur contents. Ap-
parently, products from different geological formations will have different
levels of sulfur. Thus, in the case of oil, samples taken from a field may not
necessarily give an accurate characterization of the remaining oil. This
has and continues to be a major problem with any sampling program. Until
more thorough testing has been accomplished, there remains the possibility
of error in the data.
The major reference work (Ref. 6) published by the Bureau of Mines
is based on 1060 routine analyses of domestic oils and 201 analyses of
foreign oils. Table 2 summarizes the major findings of this study. Note
that the United States, Canada, and Africa oils have relatively low sulfur
contents, whereas South America and Middle East oils have high levels of
sulfur.
When reviewing the above data, the Committee on Public Works of
the United States Senate (Ref. 7) concluded that:
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TABLE 2
SULFUR DISTRIB ~r~:ON 0<' )OMESTIC AND FOREIGN C ~ J)~ 0 :LS
BASED ON ANALYSES OF OILS PRODUCED IN 1966
Sulfur Weight Percent Avg.
Sulfur
0.00-0.25 .25-.50 .51-1.00 1.01-2.00 >2.00 Total Content
Percentage Basis
United States 40.4 25.4 13. 1 13.0 8. 1 100.0 0.67
Canada 35.1 5.8 33.7 12.7 12.7 100.0 0.85
South America 1.6 1.3 3.5 15.2 78.4 100.0 2.26
Africa 63.7 14.4 21. 6 0.3 100.0 0.32
Middle East 44.8 55.2 100.0 2.13
Production Basis
(thousand barrels per day)
United States 3370 2120 1090 1080 680 8340
Canada 310 50 290 110 110 870
South America 60 50 140 620 3180 4050
Africa 1750 390 590 10 2740
Middle East 4140 5100 9240
Note: Based on Ref. 6 data.
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III - 7
"There exists a paradox concerning the availability
of low-sulfur fuel oil. Based on 1966 values of the
production of crude oil in the free world, the largest
supply of low-sulfur crude oil (that containing less than
one-half percent sulfur) was produced in the United
States. At the same time domestic refineries are
dec reasing (or at best, maintaining) the production level
of residual fuel oil used by power plants. "
Historically, domestic refineries have increased their yield of gasoline and
distillates at the expense of residual production. At present, the yield of
domestic residual oil stands at about 6. 8 percent of total U. S. refinery output
(Table 3). Thus, the industrial and utility markets have benefited less and
less from the potential domestic sources of low sulfur oil. This trend,
predicted to continue by some (Ref. 9), is likely to level off or reverse in
the future, as the price of residual fuels continue to climb due to the pre-
dicted unprecedented demand for residual oil. For the purposes of this
study, the refinery yields as displayed in Table 3 are assumed to remain
fixed during the 1970's.
2.
Sulfur Content of Residual Oils
a. Domestic Oils. The sulfur content of a residual oil is typically
higher than that of the c rude used as feed stock. This is because the majority
of the sulfur is bound in compounds having low volatility. Thus,as the gaso-
lines and distillates are removed, the sulfur weight percent of the remaining
residual oil is increased. This increase is highest, as in the case of
domestic refineries, when the yield of the lighter products is maximized.
Table 4 reports the sulfur distribution of domestic oils as a function of
region. The table consolidates data on residual oil production from 99 per-
cent of the operating refineries in this country for 1965. The values listed
under central states include those from the Rocky Mountain area as well as
for what is normally called the Central United States. These data compare
favorably with production data interpreted from Ref. 11. Note that the
average sulfur content for the total United States is 1.76 weight percent.
This is compared to the average sulfur in domestic crude oil of O. 67 weight
percent (see Table 2). A gross relation between the sulfur content of domestic
,crude and residual oils can be estimated by using the ratio 1. 76/0.67. Thus,
it can be stated that domestically produced residual oil has a sulfur content
approximately 2.6 times greater than the crude oil feed.
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TABLE 3
PERCENT OF REFINERY YIELD THROUGHOUT THE FREE WORLD
1970 DATA
Total Output Gasoline and Distillate Residual Othe r
{Millions of Barrels) Jet Fuels Fuels Fuels Products
Free World 12, 198 32.0 21. 6 27.3 19.1
United States 4,063 55.3 20.7 6. 8 17.2
North America 761 33.9 23.4 22. 2 20.5
Central America
Caribbean
South America 1299 23.6 15.6 47.3 11. 7
Western Europe 3621 17.0 27.3 34.1 21. 6
Middle East 712 18.8 20.0 43.6 17.6
Africa 212 22.4 22.0 33.4 22.2
Asiatic Area 1530 18.9 15.3 41. 1 24.7
Note: Based on Ref. 8 data.
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TABLE 4
SULFUR DISTRIBUTION OF DOMESTIC RESIDUAL OILS
BASED ON ANALYSES OF OILS PRODUCED IN 1965
(Thousand Barrels Per Day)
Sulfur Weight Percent % Avg.
of Sulfur
<0.7 0.7-1.0 1.0-1.5 1.5-2.0 2.0-3.0 >3.0 Total Total Content
East Coast 2.5 6.0 42.9 51. 4 10.6 2.44
Gulf States 9.1 13.0 42.4 11. 0 25.6 6.0 107.1 22.0 1. 61
Central States 24.0 35.4 52.8 0.5 69.9 5.8 188.4 38.8 1. 70
Pacific Coast 5.4 22.3 14.2 67. 3 18.1 11. 8 139.1 28.6 1. 72
Total 38.5 73.2 109.4 84. 8 156.5 23.6 486.0 100.0 1. 76
Percent of Total 7.9 15.1 22.5 17.4 32.2 4.9 100.0
Note: Based on Data Obtained From Ref. 10.
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III - 1 0
The comparison of Tables 2 and 4 can be used to demonstrate
another important point. Table 4 indicates that 7. 9 percent of the total
residual oil produced in 1965 had a sulfur content of less than 0.7 weight
percent. The data in Table 2 appear to contradict this statement.
After c:onverting the sulfur contents in Table 2 using the 2.6 factor, it is
found that 40.4 percent of the residual oil should have a sulfur content of
less than 0.65 percent (0.25 x 2.6). This apparent disagreement can only
mean that a significant amount of blending is occurring. Thus, a low sulfur
oil is blended with a high sulfur oil prior to or during refinement. Blending
of this kind further reduces the amount of "naturally occurring" low sulfur
residual available to the domestic market.
b. Imported Oil. Residual oils which are imported into the United
States have their sulfur contents measured upon entry. The greatest majority
of imported residual oil comes from Venezuela. Most Central and South
American oils have high sulfur contents. Venezuela oil has typical sulfur
contents of about 2.7 weight percent. Columbia imports oils with sulfur
contents ranging from 1. 6 to 2.2 weight percent. The oils having the highest
sulfur content come from Mexico, 4.5 weight percent. Very little oil «5 per-
cent is imported from the Eastern Hemisphere. Small amounts are received
from Saudi Arabia. The sulfur content of these oils are typically 3. 5 weight
percent (Ref. 12). In recent years the average sulfur content of imported oils
has been within the range of 2.4 and 2.6 weight percent.
Because of the much higher yield of residual oils in foreign
refineries (see Table 3) sulfur is not concentrated in the resid to the same
extent as it is in domestic oils. A typical ratio between the sulfur content
in foreign resid and in foreign feed stock is about 1.7 as compared with the
domestic fact.or of 2. 6.
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III - 11
D.
Regional Consumption of Residual Oil
Regional consumption patterns of residual oil were studied with the
objective of identifying those regions having the greatest demand for residual
oil. Based primarily on fuel and transportation economics, coastal regions
consume the major portion of the residual supply. The central states show
little demand, present or future, for residual oil. Table 5 summarizes the
historical growth of residual consumption. Note that the New England, Middle
Atlantic, South Atlantic, and Pacific states consumed over 83 percent of the
residual oil in 1970, with the Central and Mountain states consuming the
balance. Looking at the consumption by electrical utilities, the four major
regions accounted for 96 percent of the utility demand. Also, it was found
that future growth will occur solely in these regions. Figure 1 depicts the
present consumption and expected consumption by 1975 on a regional basis.
The graph indicates that within the next five years resid consumption by
utilities in four major regions will double present consumption. The signifi-
cant increase in demand will no doubt place a strain on the utilities and their
fuel supplies. This is especially true when one considers the fact that many
of the utilities in these regions will be the primary target for new or strength-
ened sulfur emission regulations. Thus, shortages in low sulfur fuel supplies
will be felt strongest in the four major oil consuming regions.
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TABLE 5. REGIONAL GROWTH OF RESIDUAL OIL DEMAND
(Millions of Barrels Per Year)
1960 1965 1970
Total~ectrical TotalElectrical Tota~lectrical
Location Residual Utility Residual Utility Residual . Utility
New England 71 17 86 22 120 50
Middle Atlantic 162 25 190 40 290 110
South Atlantic 88 13 110 27 170 46
East North Central 66 58 69 4
East South Central 5 4 8
West North Central 14 11 18 2
West South Central 33 23 28
Mountain 12 2 13 2 15 3
Pacific 100 27 92 21 102 19
Total 551 85 587 113 820 235
Based on References 1 and 13
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..... C) U U U
'0 s:: ."" U
.....
s:: ro S:: ..s:: ..s:: ..s::
ro ~ ro ..s:: .....
~ ..... ""' ..... .... "'"
b.O ..... :3 ro ro (]) (]) 0 ro
~ ;;E 0 f:ij f:ij ~ ~ ;;E !it
if)
Figure 1.
Expected Growth in Resid Consumption by United States Electrical Utilities
~
~
~
I
~
I:.A)
-------
III - 14
E. Imports Required to Meet Present Demand
Future availability of residual fuel oil will be heavily dependent upon
foreign sources. It is, therefore, necessary to define what the present import
structure is. The present major importers must be identified and their rela-
tive importance quantified.
It has been forecasted that, in 1971, total U. S. petroleum demand will
stand at 15.2 million barrels per day. Sixteen percent of this demand, or
2.4 million bbl/day, will be residual oil. Total imports required to meet this
demand will be 4.0 million bbl/ day. Thus, over 26 percent of total demand
will be satisfied by imports. Of the 4.0 million bbl/ day of imported products,
1. 66 million bbl/day will be residual oil. This means that in 1971 about 69
percent of the residual oil demand will be satisfied by foreign imports. .
Figure 2 depicts the growth of imports since 1950. Note that since 1968
importation has accelerated. All indications show that for the next few years,
this accelerating trend will continue. The ever-increasing reliance on imports
of residual fuel is clearly indicated by Table 6. This table shows the continued
decline in domestic residual oil supply and the rapid growth in foreign imports.
There are presently three major importers of petroleum products. They
are: Venezuela, Canada, and The Netherlands (Antilles). They account for
well over 60 percent of the imports. For example, Table 7 gives the import
summary for 1969 (Ref. 16). There is no, or very little, importation from
. Asia-Pacific, Africa, or the Middle East. .
A significant factor in analyzing foreign imports is the relative importance
of U. S. trade. That is, what portion of the nation's productive capacity is
presently pinpointed for the U. S. market? Table 8 answers this question. First,
the refinery capacity of the major world regions was obtained from 1968-69
averages. From Table 3 the ratio of residual to total production was obtained.
The product of these numbers gives the potential residual oil production. Knowing
the U. S. import figures, the ratio 'of the oil sold to the U. S. over the potential
production of residual oil (import-capacity ratio) was calculated. Thus, one
can see that Latin America sells about 43 percent of its residual oil to the U. S.
w?ile all other foreign countries presently sell much smaller fractions of their
product to the U. S. These import-capacity ratios will be utilized in predicting
future foreign supplies (see Section VI).
-------
. 4.2
3.0
>,
C'O
Q
~
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p.,
U) 2. 6
......
0)
~
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.....
o 2.2
U)
s::
o
.....
......
......
.....
~
3. 8
Based on Refs. 14, 15, and 16
3.4
1.8
1.4
1.0
Imports of
Residual
Oil
0.6
50
62
66
70
Figure 2. Imports Into the United States
III - 15
-------
III - 16
TABLE 6. RESIDUAL FUEL OIL PRODUCTION,
IMPORTS, AND CONSUMPTION
(Millions of Barrels Per Day)
Imports as
a Percent of
Domestic Foreign . Domestic Domestic
Year Production Imports Consumption Consumption
1950 1. 16 0.33 1. 52 22
1955 1. 15 0.42 1. 53 27
1960 0.91 0.69 1. 53 45
1965 0.74 0.95 1. 61 59
1970 0.74 1. 49 2.25 66
NOTES: Columns do not add due to stock changes.
Based on References 17 and 18.
TABLE 7. IMPORTS IN 1969
(Thousands of Barrels Per Day)
All Petroleum Residual
Products Oil
Venezuela 979. 1 479.4
Canada 602.8 22.5
Netherlands (Antilles) 373.8 306.3
All others 1116.5 426.5
Total 3082.2 1234.7
-------
TABLE 8
CRUDE VERSUS RESIDUAL OIL FACTORS FOR U. S. CONSUMPTION
(Quantities in 1000 bl d)
Import-Capacity Ratio
(Ratio of U. S.
1968-69 Average Ratio of Residual Residential Usage
of C rude Oil Production to Potential U. S. to Potential
Refinement Total Crude Residual Residual Residual
Area Capability Throughout Production Usage Production)
Asia Pacific 4,593 0.411 1,888 0 0
Africa 744 0.334 248 2.55 0.010
Canada 1, 293 0.182 235 22.5 0.096
Middle East 2,175 0.436 948 2.05 0.002
Latin America 4, 830 0.491 2,370 980.50 0.429
United States 11, 869 0.068 807 807.00 1.000
Western Europe 11, 985 0.341 4,090 125.60 0.030
TOTAL 37,489 0.323 10,586 1,940 0.189
average
Based on Refs. 1, 8, and 16.
I-t
I-t
I-t
I
......
-:J
-------
IV-1
IV.
PREDICTIONS OF FUTURE DEMAND FOR RESIDUAL OIL
The total demand of electrical power in the contiguous states is
nominally projected to increase from about 1. 9 x 1012 Kw-hr/yr in 1970
to about 9.2 x 1012 KW-hr/yr in the year 2000, nearly a factor of five
increase. The confidence in this estimate is rated as good because popu-
lation, Gross National Product, and industrial growth are predictable in a
relatively accurate manner. The division of this gross demand among
nuclear and the fossil fuels is somewhat less definite. Projections of
nuclear supply are the most indefinite. Projections made by reactor
suppliers differ widely from those made by the petroleum industry, with
estimates from Senate committees and utilities falling in between. Figure
3 shows the forecast of total U.S. generating capacity. The projected
nuclear capacity is based on nominal values taken from Ref. 19. Knowing
the nominal heating rates and load factors for each type of power system
and the projected breakdown between coal, oil, gas, and hydro, Figure 4
was constructed. Note the rate at which nuclear power is projected to
grow. Also, note that oil burning plants increase significantly between
1970 and 1980 and level off thereafter. Coal, gas, and hydro plants are
predicted to increase relatively steadily throughout the period.
The growth of oil fired plants between 1970 and 1980 is a rather firm
forecast. The planned construction of oil fired plants is known to 1976.
The planned construction was projected to 1980 resulting in Figure 5. New
oil burning plants include not only single fuel plants, but 70 percent of the
coal-oil convertible plants and 50 percent of the gas-oil convertible plants.
Also, additional conversions of existing coal and gas utilities are accounted
for.
The growth of the demand for residual oil for electrical utilities is
unprecedented. The growth will result in residual oil becoming an increasing-
ly more significant petroleum product. Table 9 summarizes the historic
and projected growth of residual oil. Note that by 1980, 2.0 percent of the
total petroleum demand will be residual oil. Note also that in that year
electrical utilities will be using 56 percent of the residual supply. Figure 6
'graphically illustrates this growth. This dramatic increase in the require-
ment of residual fuel oil will have a significant effect on U. S. import policy
-------
Generating
Capacity
(MWe)
""lectrical
Generation
(Kw-hr /yr)
3 x
Figure 3.
6 x
1011
8
1010
1
Figure 4.
*Based on Refs.
IV-2
Total Capacity
106
8
6
5
4
3
2
'-I
I
I
105
1970
1980
1990
2000
Year
Forecast of Total U. S.
Generating Capacity*
1013
Total Generation
Nuclear
- Coal
2
8
6
5
4
3
-; Oil
~ Gas
'~"~I ;
Hydro
2
~
'r-
;.::i-
t=1-:=:J::+" :
-~.
-
-t--.,
.L
,-
Forecast of U. S.
19,
20,
22,
and 23
21,
-------
Consumption
(106 bbl/yr)
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1964
IV-3
500
300
1968
1972
Year
1976
1980
Figure 5.
Residual Fuel Oil Consumption By The
U. S. . Electrical Utilities
-------
TABLE 9. OIL CONSUMPTION AND PREDICTED DEMAND
(Millions of Barrels per Year)
1960* 1965* 1970** 1975*** 1980***
All Petroleum Products 3611 4202 5360 5820 6925
Residual Oil 550 586 829 1300 1421****
(percentage of petroleum products) (15) (14) (16) (22) (20)
~
Breakdown of Residual Oil
Electrical 85 115 315 715 815****
(percentage of residual oil) (15) (20) (38) (55) (56)
Industrial 202 175 176
(percentage of residual oil) (37) (30) (21)
Household and Commercial 125 156 197 585. 606****
(perc entage of re sidual oil) (23) (27) (24) (45) (44)
Other 138 140 139
(percentage of residual oil) (25) (23) (17)
* References 13 and 24
** References 28 and 24
*** References 20, 22 and 24 .
****See Table II, (p. VI -8, and Figure 7.
p. VI - 9
......
<:
I
~
-------
IV-5
104
9
8
7
6
5
4
3 Cons umption
I of All Other
Petroleum Products
~
~ cd
Q) 2
~
~
Q)
p... 1
rn
......
Q)
~ /
~ 103
cd
(:Q
...... 900
0 800
rn
g 700
.....
o-f
:::: 600
:;s
500
400 Consumption of
Residual Oil
(Others)
300
,.
200
-
-~
Consumption of
Residual Oil
(Electrical Utilities).
100
60
72
Year
Figure 6. Oil Consumption and Predicted Demand
64
68
76
80
-------
IV-6
and will force domestic refineries to revise their plans for the future.
will be discussed in the following sections, this growth will also make it
virtually impossible to satisfy the projected demand for low sulfur resid
without instituting a vigorous desulfurization program.
As
-------
V-1
V.
LOW SULFUR RESIDUAL OIL ALTERNATIVES
During the early and mid-1970s, local and Federal regulations will come
into effect which will limit the sulfur content allowed in residual fuel oil. By
1980, the major portion of resid consumption will be regulated. Excluding
the alternative of converting to an entirely different low sulfur fuel such as
natural gas, there are six basic alternatives which can be used to satisfy
these regulations. This section introduces and briefly discusses these
alternatives, listed below:
.
Naturally occurring low sulfur residual oil
Crude or topped crude oils
Blended residual and crude oils
Distillate cutter stock
.
.
.
.
Desulfurized residual oil
Flue gas desulfurization systems
.
It is expected that all of the above alternatives will be used in varying
degrees, depending on local economic factors.
A. Naturally Occurring Low Sulfur Residual Oil
The Bureau of Mines wellhead measurements of domestic oil constituents
indicate that the largest potential source of naturally occurring crude oil is
located within the boundaries of the United States. Over 40 percent of the crude
. contains less than 0.25 percent sulfur. The residual oil produced from this
crude is estimated to have less than 0.7 percent sulfur. Unfortunately, the
present oil transportation-refinery-distribution system is operated in a manner
such that the low sulfur oil is blended with high sulfur oil to yield a product
which is above 1. 0 percent sulfur. Thus, the single most significant source
of low sulfur residual is not available presently. Only careful segregation of
low and high sulfur oils will make this source available. Whether segregation
is economically or even physically possible is a question which can be answered
only'with the cooperation of the petroleum industry.
Oil from the North Slopes of Alaska is a potential source of low sulfur
oil, but only well into the future. The earliest deliveries of one million bbl/day
cannot be expected until later in the 1970s. An 800-mile, $2 billion pipeline
-------
V-2
from Prudhoe Bay on the North Slope to Valdez must be built before the first
barrel of oil is shipped. The oil would then be transported by freighter to
U. S. markets.
Residuals produced from low sulfur resids will have characteristics
which are different from typical reside This is a concern if the fuel cannot
be burned or handled without costly modifications, especially if the consumer
is small. Federal specifications (VV -F- 815a) for burner fuel oils prescribe
their viscosity, pour point, flash point, and water, sediment, and ash content.
However, changing refinery practices and requirements for low sulfur residual
fuel oil may require that the American Society for Testing and Materials. Code
and Federal specification for residual fuel oil (No.6) be modified with refer-
ence to these characteristics. Problems associated with actual usage of low
sulfur oils have not been clearly defined. Whether or not these practical prob-
lems will be widespread cannot be determined without a detailed study of the
oils in question. It is known, for instance. that residual oils produced from
Africa crudes are highly paraffinic. High wax concentrations mean high pour
points (105-1150F). Thus, fuel handling systems must be modified to assure
that the oil is kept at 120-130oF to avoid solidification. Such handling problems
must be factored into the overall question of availability.
B.
Crude or Topped Crude Oils
The burning of low sulfur crude presents a significant alternative. Experi-
ments have shown that the refinery can be completely bypassed and that crude
can be burned efficiently in existing oil-fired utility boilers after modifications
are made. Crudes with less than 0.3 percent sulfur are available from Libya
and Nigeria. Crudes with less than 1. 0 percent sulfur are available from
Canada. These offer some hope of easing the supply problem.
A number of U. S. east coast utilities are now converting power plants
to burn low sulfur Libyan crude oil, starting in 1971. This fuel will be burned
not only in boiler plants but in some cases will be used in gas turbines for
power generation. Florida Power has ordered four 50- Mw gas turbines for
1972 delivery. These will fire Libyan crude and will be the first gas
turbines to go onstream to fire crude oil. Consumers Power has recently
-------
V-3
announced that it has signed a contract with Imperial Oil Ltd. of Canada to
supply two of its power plants near Bay City. Michigan. with low sulfur crude
starting in 1972. The well-publicized results of burning crude oil in Japanese
power plants for a number of years has no doubt encouraged this move. In
1970. the Japanese power industry burned over 40 million bbl of crude oil and
will burn over 70 million bbl in 1971 (Ref. 20).
High volatility of crudes prove to be the most difficult property to deal
with. especially if the system is leak-prone. Generally, Philadelphia electric
Company engineers feel several precautions must be taken. including the
following: (Ref. 25)
(1)
(2)
(3)
(4)
(5)
(6)
Locate pumps - a possible source of leakage - outdoors
Monitor fireroom with explosive-mixture sensing instruments
Provide adequate ventilation
Specify explosion-proof electrical components
Install positive fuel- shutoff controls
Provide adequate grounding and bonding of fuel-oil system
to prevent static charge buildup
For economic and safety reasons. it may make sense to top the crude of
the more volatile components to be converted to gas or sold on the open market
as a refined product. Currently. this practice is not allowed in the case of
imported oils. (Refer to Appendix A which discusses current import regulations.)
C.
Blended Residual and Crude Oils
A low sulfur oil can be blended with a high sulfur oil to produce a product
which just meets the sulfur specifications. The quantity of high sulfur oil
which may be blended can be found as follows:
(S - Sls)
Qhs = Qls (Shs - S)
where:
Qhs and Qls
Shs and Sls
S
=
quantities of high and low sulfur oils, respectively
=
sulfur contents of high and low sulfur oils, respectively
=
sulfur content required by regulation
-------
.--
V-4
The careful blending of domestic and Venezuelan resids or crudes with
low sulfur African oil will net a significantly increased supply of fuel which
will meet specifications. This technique can be significantly beneficial in
making up short-term deficiencies since blending can be carried out without
significant capital investment or lead time.
D.
Distillate Cutter Stock
The premium cost of low sulfur resids will no doubt continue to rise.
As this happens, the blending of the more expensive distillate oils with residual
fuel will begin to make sense. Distillate fuels are very low in sulfur, averaging
about O. 2 percent sulfur. Blending a O. 2 percent sulfur distillate with a 1. 7
percent sulfur domestic resid (50-50 blend) will result in a product which will
satisfy a 1.0 percent sulfur limit. The cost of this product will be the average
of the costs of the distillate ($5/bbl) and the resid ($2/bbl) or about $3,. 50/bbl.
In certain locales, bids for low sulfur resids have already exceeded this price
per barrel. Thus, it should be expected that the use of cutter stocks will be
on the increase.
Blending a distillate and a resid may not be straightforward. For instance,
various chemical compounds in resid form a protective film around the
asphaltenes, maintaining their equilibrium. When distillates are added,this
film is broken and the asphaltene drops out of solution and settles as sludge.
, Caution is also warranted when certain mixtures of waxy and nonwaxyresids
are blended with a distillate. Unusual pour behavior can result. Pour points
after aging of such a mixture can be 40 to 500F higher than when freshly mixed.
Thus, blending must be performed under instructions of a petroleum chemist
to assure no mistakes occur (Ref. 26).
E.
Desulfurized Residual Oil
Much of the resids used today are high in sulfur. The source of these
resids cannot be turned off: the supply is necessary - even critical. The only
way to satisfy demand and at the same time meet the coming sulfur restrictions
i1? to desulfurize this oil. Fortunately, this can be accomplished by the use of
several relatively new processes to desulfurize residuum: vacuum gas oil (VGO)
-------
V-5
or deasphalted oil (DAO). The characteristics of the resultant fuel will, in
turn, be determined to a large extent by the process used and the final sulfur
level.
Residuum desulfurization treats all the crude boiling above 6500F by
h;ydrogenation over a catalyst at high temperature and pressure. With crudes
of higher metal content, such as those from Venezuela, some form of pre-
treatment is required to reduce the metal content of the feed before desulfur-
ization. One way to do this is to vacuum distill the fuel oil and desulfurize only
the distillate, which is known as VGO. Another way to reduce the metal con-
tent of the feed is to eliminate the asphaltenes. The deasphalted fraction may
then be desulfurized in a process very similar to residuum desulfurization.
If the very low sulfur fuel is made by residuum desulfurization, the
viscosity will be lowered, but probably not to as low a level as that of products
comprised primarily of VGO. It would be more like a heavy No.5 oil.
If VGO is desulfurized to a low (0.5 percent) sulfur content, it will be
much lower in viscosity than the current No.6 fuel oil and more similar to
No.4. This low viscosity fuel will also be low in ash and asphaltenes, since
the VGO contains neither. As a result, problems of superheater deposits
and corrosion caused by vanadium and sodium in the ash, as well as solid
emissions in the flue gas, should be essentially eliminated.
As discussed on pages VI-ll and B-2 for resid, a more economical
alternative to desulfurizing all VGO is to maximize VGO production (desulfur-
ize to a very low level (0.2 - 0.5 percent) and use the high sulfur residual
in a flue gas controlled furnace or convert to a clean fuel.
The low viscosity of either the desulfurized VGO or residuum products
may cause problems in existing pumps due to the large clearances normally
allowed for handling the more viscous No.6 fuel. Thus, some pumps may
have to be replaced. The poorer lubricity of the less viscous fuel may also
increase wear rate. As with the lower viscosity naturally low sulfur fuels,
some changes in metering devices and preheat temperatures may be required
to compensate for the lower viscosity. The pour properties of the desulfurized
fuels will not be greatly changed from those of current fuels from the same
source. They should, therefore, present no additional handling problems.
-------
V-6
Briefly explained, these processes treat resid by separating and desul-
furizing the lighter fraction which is then blended back into the bottoms. The
problem in hydrodesulfurization treatment of high metals residuals is that
they foul the catalysts. This means that Venezuelan residuals which are high
in metals are more difficult to desulfurize than Arabian residuals which are
higher in sulfur content but which have low metal contents. Fortunately
Caribbean refineries have already started a vigorous construction program
for desulfurization plants. The projected capacity for Caribbean desulfurization
plants amounts to 645,000 bbl/day by 1972. Table 10 summarizes the
important desulfurization facilities existing and under construction. Much of
this oil will be imported into the U. S.
F.
Flue Gas Desulfurization Systems
Regardless of the quantities of low sulfur fuel made available through
the combined use of the above alternatives, there will always exist an amount
of high sulfur resid. In fact, there is a distinct possibility that high sulfur
resid will be sold at attractive bargain prices. In this event, it may be
desirable to install flue gas desulfurization systems which will remove the sul-
fur after the combustion process. In a sense, the use of these systems will
depress the regulated demand for low sulfur fuels. The more stack gas
systems. used, the lower the demand will be for low sulfur fuels.
The S02 removal processes fall into two categories: product producing
(where some form of marketable sulfur is obtained) or throwaway (where the
extracted sulfur and the scrubbing material are treated as wastes). Of the
many potential product-producing processes that have been shown to be
technically feasible, only three have been successfully tested on actual plant
gas flows. These are:
( 1)
An alkalized absorption system developed by the Bureau
of Mines whereS or H2S04 is recovered;
A catalytic oxidation approach developed by Monsanto
where H2S04 is recovered;
( 2)
( 3)
Chemico Magnesium Oxide scrub where H2S04 is recovered.
-------
TABLE 10. PRESENT AND PLANNED FUEL DESULFURIZATION
FACILITIES AND CAPACITIES
Capacity bId Total Production
1970 1971 1972 1970 1971 1~72
Operating Additions Additions 106 bbl 106 b bl 10 bbl
Shell Curacao 3~~.000 12.78 12.78 12.78
Hess, V. 1. 125,000 45.63 45.63 45.63
Shell, Cardon 50,000 18.25 18.25 18.25
Creole Amuay 100,000 9.13':' 36.50 36.50
Bahama Oil 125,000 22.82 45.63 45.63
Lago, Aruba 80,000 7. 30*~" 29.20
Amerada Hess 60,000 5. 48':'>:' 21. 90
Bahama Oil 40,000 14.60
Texaco Trinidad 90,000 32.85
Cities Service U. S. A. 2,500 0.91 0.91 0.91
Humble Oil U. S. A. 16,000 5.84 5.84 5.84
American Oil U. S. A. 3,500 1. 28
Cities Service U. S. A. 3,500 1. 28
Pemex (Mexico) 18,500 6.75
Operating 1970 453,500 115.36
Additions 1971 140,000
Operating 1971 593,500 178.32
Additions 1972 155,500
Operating 1972 749,000 273.40
* In operation only part of 1970
**Assumed to be in operation during only three months of 1971
<:
I
-oJ
Reference: Oil and Gas Journals
-------
V-8
It must be determined if these initial pilot plant successes can be duplicated
when operating on full-sized operational plants. It will probably be the mid-
1970s before any of the control devices will have been commercially
demonstrated.
Two basic throwaway processes use limestone for 802 removal. These
systems have progressed more rapidly than the others. It is reasonable, if
future testing leads to success, that these systems may be available before
1975.
-------
VI-1
VI. PROJECTIONS OF LOW SULFUR
RESIDUAL OIL AVAILABILITY
Section IV summarized the demand forecast for residual oil. The vari-
ous sources of residual oil supply will now be studied and compared with
demand.
A. Domestic Supply of Low Sulfur Fuel
Total domestic production of residual oil amounted to O. 74 million bbl/
day in 1970. This is 6.8 percent of the total refinery yield. Since demand as
well as the price of residual oil is expected to increase in the future, the down-
ward trend of this percentage is likely to be reversed. To be conservative, it
was assumed that the 6.8 percent figure will remain constant throughout the
19708. Growth rate of U. S. refinery throughput has averaged 4.8 percent per
annum. If this trend continues and if the 6. 8 percent refinery yield holds
constant, by 1980 residual production will stand at 1. 18 million bbl/day.
Two sulfur limits will now be introduced so that we may estimate the
portion of the above production rates which can be considered low sulfur fuel.
A high limit of 1. 0 weight percent of sulfur was selected (equivalent to approxi-
mately 0.6 lb of sulfur per million Btu). A low sulfur limit of 0.5 weight per-
cent of sulfur was also selected (equivalent to approximately O. 3 lb of sulfur
per million Btu).
Low sulfur fuel availability can be estimated based on sulfur measure-
ment of residual oils (Table 4) or sulfur measurements of crude oils (Table 2)
with the stipulation that the sulfur content be increased to account for the
effects of refining. As stated previously, these methods result in substantially
different numbers because of the apparent inadvertent blending of oils. That
is. a great deal of the low sulfur oil is being blended with very high sulfur oil
before it is distributed. This detrimental blending results in much lower
amounts of low sulfur fuel than is possible if care is taken in segregating low
and high sulfur oils. As an example, if we use the sulfur distribution in
Table 4. the following percentages can be calculated:
-------
VI-2
Residual Oil Data
Percent of Residual Production
Meeting Sulfur Criteria
0.5%S 1. 00/0 S
Present availability
(no blending) 6 23
Blended 8 31
It is possible to carefully blend oil which exceeds the sulfur limit with
oil which is below the limit to obtain an oil which just meets the criteria.
This technique was used to arrive at the "blended" percentages. A similar
set of numbers were calculated using crude oil data, Table 2 (the sulfur
categories were increased a factor of 2. 6 to account for the concentrating
effect of domestic refinement):
Crude Oil Data
Percent of Residual Production
Meeting Sulfur Criteria
Blended
0.5% S 1. 0% S
30 60
40 80
Present availability
(no blending)
For purposes of our analysis, two possible directions were assumed
possible. Case A assumed that no change in the detrimental blending prac-
tices would occur during the 197 Os while Case B assumed that detrimental
. blending would be alleviated somewhat, making it possible to approach the
higher percentages indicates in the second set of numbers above. These
assumptions result in the following projections:
Domestic Low Sulfur Fuel Availability Forecast
1970
1980
Case A
0.5% S
Percentage of total production
Production, 106 bbl/day
6
0.044
23
0.170
8
0.095
1.0
Percentage of total production
Production, 106 bbl/ day
31
0.366
-------
VI-3
1970
1980
Case B
O. 5% S
Percentage of total production
Production, 106 bbl/day
6
0.044
24~:<
0.284
1. 0% S
Percentage of total production
Production, 106 bbl/day
23
0.170
48~:<
0.567
These forecasts will be utilized to predict total availability of low
sulfur residual oil once the foreign imports have been defined.
Desulfurization of domestic residual oils, though a distinct possibility,
will not be covered here in a quantitative manner. A significant change in the
petroleum demand/price structure or other incentive will be necessary before
domestic desulfurization plants are built (Ref. 27). Another impetus to
domestic desulfurization will be the Federal Emission Standards. Obviously,
if these standards allow only low sulfur fuel oil to be burned, domestic re-
fineries will be forced to desulfurize their resid or lose the market.
B. Foreign Supply of Low Sulfur Fuels
South America
Currently, South America (S. A. ) supplies over 50 percent of the
residual fuel oil consumed in the U. S. It is, therefore, as important if not more
important, than domestic supplies. South America oils differ in two important
ways from domestic oil. First, the residual oil currently imported to the U. S.
contains large amounts of sulfur. Venezuelan resid contains on the average 2.7
percent sulfur. Thus, the major source of S02 pollution from burning of
residual oil is attributable to S. A. imports. The second, and most important
difference is that S. A. refineries are apparently willing to invest in, construct,
and operate desulfurization plants. The preceding section stated that by 1972
the. Caribbean desulfurization capability would stand at 645,000 bbl/ day for a
1.
,., .
"assumes that 60 percent of the ideal production can be achieved by 1980
-------
VI-4
1. 0 percent sulfur product. Note what results when both the S. A. residual pro-
duction and its desulfurization capacity is projected based on historical trends
(see Figure 7). Current S. A. residual production stands at 3.05 million bbl/
day. Projected at the growth rate of 5.7 percent per annum results in a 1980 pro-
duction rate of 5. 32 million bbl / day. The desulfurization facilities are pro-
jected to grow at the rate of 15 percent per annum until 1980. This results
in a capacity of 1. 95 million bbl/day by 1980. Thus, 37. percent of S. A.
residual oil will be desulfurized by 1980. This assumes, of course, no slowing
of the rate of construction of these plants. The dotted lines show what portion
of the S. A. production is destined for the U. S. It was assumed that no more
than 75 percent of the low sulfur fuel would be imported to the U. S. With
these data, the availability of S. A. low sulfur fuel can be predicted:
S. A. Low Sulfur Fuel Availability Forecast
0.5% S>.I: 106 bbl/day
1. 0% S Imports, 106 bbl/day
1970
1980
0.34
1. 09
0.44
1. 42
2.
Western Europe
Imports of residual fuel from Western Europe (W. E.) amount to less
than seven percent of total domestic consumption. In 1970, a total of O. 17
million bbl/day was imported. Keeping the percentage of W. E. refinery
capacity which is destined for the U. S. market constant and assuming the
. historical growth rate of production, 8. 3 percent per annum, will prevail
through the 1970s, a projected import quantity of O. 35 million bbl/ day is
calculated. Utilizing the same assumptions and methods as in the previous
cases, the following availability of low sulfur residual oil is projected (based
solely on naturally occurring low sulfur fuel, no desulfurization):
W. E. Low Sulfur Fuel Availability Forecast 1970 1980
0.5% S 106 bbl/day 0.05 O. 10
1. 0% S 6 0.07 0.14
Imports, 10 bbl/day
*Using blending equations, it was calculated that output at 0.5 % S equals
77 percent of the 1. 0% S output.
,
I-
I
-------
i.
6.0
5.0
4.0
3.0
~ 2.0
et!
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1970
VI-5
=~~~~~~~.==~:--. ~~-~ ~~~~~~IT~~~f~
~::-t- ::t=t=E .. r--c;.-, :i-=f-' --.~. _.. .... -- ----,-:=--+- -- - -;--, -;.~-=;-j_I---t-:-~ ~
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Total S. A.
Production
-
no
- ,
--
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i
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-. -H-+-i-- , Total Desulfurization
, -
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-- I
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- =-- ,,-=:;.~ -.- -- ~ - -::::F:=-:'~--=~:-::c-_''':'-::i= .- .....:.::_-- ==='----.,,,,'=---=-to -=.-=----
~ .'':i=--:c--E:.:::--?=-;:::''::-~~ :..~--:':_~.~-=-.;::::::E - - ~to=::~'~~c
~1: ~..:d=. ~~--~ =~_-:: :.-:::-.=-:::"-'='':: =::=:::~::::~==~:.:_- ::":: ==::-~2-~~::=:-=~:::: ~-. :':::':.'=: --,--.-
=:~""E ~:;::i~~ =EF':"~ r-;. :=----=-== :=-~:=~~:c::..:.::== ==--='_o~-'~:-:= ::-=~-=[=: =-::.-=::::::,...=
S:::i23- ~ '..:: - ~ ~-~. -- -:.~' :::F-"...-.":~ -'-:-'~: =:. - --:c: ' -s:i= -, ~
~ --+----+_.~~ - ~~
"",. r--!--''''''''''' -'-'-'- ~.' . +==~L -~ !-t-!--
- +-r-,-- +- . -t-j--t-:=:-~. ~-;- :!. =:==::::, -H- ~ r--t- :::t=!=t=,
~.- . of :=t:=t:::c
-
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=-+
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u. S. Low Sulfur
Imports at 1. 0% S
, l.o'
I_~ 1=Ft-~ *
-
~
-
f+
-1-
-~-
-~-'-~....
-.,......~-H-
--'-H' -,-+-,
_.
1975
Year
1980
Figure 7. Growth of South American Residual
Production and Desulfurizatioh Capability
-------
VI-6
3.
Others
Very little residual oil is presently imported by countries not already
discussed. A small amount of Canadian resid is imported and has been fac-
tored into the summary table which follows. No African oil is now being
imported. It was assumed, however, that if a shortage in supply was pro-
jected, the deficiency would be made up by importing low sulfur crude oil for
direct use as a burner fuel. It was assumed that this oil had a sulfur content
of O. 3 percent sulfur which is typical for African crude oil.
C.
Comparisons of Supply and Demand
Our analysis has shown that the total demand for residual oil will increase
from 2.25 million bbl/day in 1970 to 3.90 million bbl/day in 1980. The first
question which must be answered is whether our supply forecasts can satisfy
this total demand. The historical growth of the petroleum supply, if extended
to 1980, shows that demand for resid can be satisfied with a nominal increase
in imports over and above the historical import trend line. It was assumed
that the small deficiency would be satisfied by African importation of low
sulfur crude oil. As shown in Table 11, 0.08 million bbl/day must be imported
from Africa (or similar foreign source). In order to satisfy low sulfur regu-
lations, African importation may be increased above this level as will be dis-
cussed later.
The next logical questions are: What portion of the projected-demand will
be placed under low sulfur regulations and what will the sulfur limitations be?
These, of course, are difficult questions. First, there will be a variety of
sulfur limitations depending on the decisions made by local governments. It
is hoped that our selection of 0.5 percent sulfur and 1. 0 percent sulfur will
typify these limits.(Reference 26 contains a comprehensive summary of cur-
rent regulations.) In addition to local regulations, the Federal government
plans to release Federal Emission Standards which will be applied nationwide.
The details of these standards are not presently available. This, of course,
does not prevent us from assuming a certain mix of regulations for our present
purposes. To be practical, it must be assumed that not all users of residual
oi:l will be regulated. Certain industries, utilities, and private individuals will
-------
VI-7
escape regulation. Also "new" and "existing" plants are likely to be handled
differently. Based on the trends in current regulations, the following are:
projected for 1980:
(1)
(2)
All utilities over 200 Mw, built before 1973, will be regulated.
All utilities, independent of size, built dur ing and after 1973
will be regulated.
(3)
Seventy-five percent of the resid burned as heating oil, as
industrial fuel, and for miscellaneous purposes will be under
regulation.
Figure 8, along with utility construction schedules, were used to calcu-
late the 1980 regulated demand, which amounted to 3.20 million bbl/day or
83 percent of the total demand.
Next, consider', the supply of low sulfur fuel. Two sets of assumptions
were used to predict a worst case and expected case for low sulfur supply.
Case I assumed that the projected desulfurization capability of South America
would not be achieved and that only a minimal increase in the current capacity
would apply to 1980. Also, domestic Case A was assumed. Case II, on the
other ha rrl, assumed that the desulfurization schedule in Figure 6 would be
achieved and that domestic refineries would handle their low sulfur resources
more effectively (Case B). The 1980 supply resulting for these cases was
calculated assuming a 0.5 percent sulfur criteria and then assuming a 1. 0
percent sulfur criteria. The results show a wide disparity between the
demand and supply of low sulfur fuel in either case. Figure 9 shows that
demand quickly exceeds supply during the early seventies. Of course, the
linearity in growth of these factors shown in the figure will not necessarily
be the case, but there is no question that by 1980, under Case I, supply will
not meet demand for low sulfur fuels.
Case II represents a reasonable picture of what may happen in the future.
South American desulfurization facilities are presently growing at a rapid rate.
Though there are questions about where the South Americans are going to find
all the hydrogen they need in the desulfurization process and what they will do
with the immense quantities of sulfur, it was assumed that the schedule in
Figure will be carried out. If so, by 1980 the total supply of low sulfur
fuel would reach 2.59 million bbl/ day for the 1. 0 percent sulfur limit (see
I"
-------
TABLE 11. COMPARISON OF SUPPLY
AND DEMAND FORECASTS
Supply and Demand
(million bbl/ day)
1970 1980
Demand
Total residual demand
Electrical utility demand
Estimated regulated demand
2.25
O. 86
0.40
3.90
2.24
3.20
Supply
Total - no sulfur criteria
United States
South America
0.74
1. 31
0.17
0.03
1. 18
2.25
0.35
0.04
O. 08~~
Western Europe
Canada and Others
Africa (crude)
2.25
3.90
Case I - O. 5% S
Domestic Case A -no
change in detrimental
blending practices during
1970' s,projected desulfur-
ization capacity not 0.69
achieved
0.44
0.65
Case I - 1. 0% S
1. 13
Case II - O. 5% S Domestic Case B-detri- 0.44 1. 93
mental blending alleviated
S. A. desulfurization
Case II - 1. 0% S schedule met 0.69 2.59
Case III - O. 5% S Low sulfur demand 3.20
Case III - 1. 0% S completely satisfied 3.20
~'
-------
VI-9
225
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Figure 8.
Current Cumulative Generating Capacity
.Size for Oil Burning Utilities
vs.
Plant
-------
10)
o
1970
1980
1975
Year
Figure 9.
Case I Residual Oil Supply and Demand
No Additional Desulfurization
- -'
Year
'Figure 10. Case II Residual Oil Supply and Demand
Desulfurization of 60% of Imports
-------
VI - 11
Figure 10). This is a significant improvement over Case I, but the low sulfur
demand will still not be satisfied. Some 610,000 bbl/day more low sulfur
fuel is required at the 1. 0 percent sulfur limit. If the regulations are more
stringent, the deficit increases. If the regulations permit only 0.5 percent
sulfur to be burned then 1. 27 million bbl/day of low sulfur fuel must be found.
Apparently additional measures will have to be taken in order to supply
the low sulfur needs. In order to make up the deficit, a mix of all the alter-
natives mentioned in the last section must be utilized. South American desul-
furization must be maximized. It is possible, but difficult, to better the
desulfurization schedule used in Case II. But even if 90 percent of the S. A.
imports were desulfurized, we would not be able to meet 1980 requirements.
Thus, one basic conclusion is that U. S. desulfurization facilities will also be
necessary despite any resistance from the petroleum industry. Also, additional
naturally occurring low sulfur fuels may have to be found; e. g. additional
African imports, use of domestic cutter stocks, and low sulfur oil from Alaska.
Detrimental blending of domestic resid must be minimized and the high sulfur
resids desulfurized. A Case III can be hypothesized in which the low sulfur
demand is completely satisfied. A possible mix of alternatives which would
satisfy the 1. 0 percent sulfur level by 1980 would be to desulfurize 90 percent
of the S. A. imported resid, desulfurize 20 percent of the domestic resid, and
"find" an additional 100,000 bbl/day of low sulfur oil via imports and domestic
cutter stocks. Domestic desulfurization must be increased to at least 60 per-
cent of the domestic production if the 0.5 percent sulfur limitation is to be
satisfied. Additional cutter stocks or imports of low sulfur fuels (as much as
300,000 bbl/day) would also be necessary.
An alternate approach which would alleviate the need for large quantities
of low sulfur imports or cutter stocks involves the use of both fuel oil and
stack gas desulfurization processes. The economy of oil desulfurization is
dependent, in large part, upon the need for complete desulfurization. As
stated in Appendix B, the cost of desulfurization is markedly decreased if
only 75 percent of the product is desulfurized, leaving 25 percent of the
product with rather high percentages of sulfur. This high sulfur product can
then be burned and stack gas removal systems used to eliminate the sulfur
dioxide. If this high sulfur fuel was burned in large, base loaded plants (say
1000 Mw in size), the number of stack gas desulfurization units is minimized.
-------
VI - 12
A single 1000 Mw base loaded plant burns about 3.5 x 104 bbl/day. As one can
see, not very many of these plants are necessary to consume a significant
percentage of the residual supply.
-------
10.
11.
12.
13.
14.
15.
16.
17.
VII - 1
VII.
REFERENCES
1.
Oil and Gas Journal, December 28, 1970, pp. 89-132.
2.
World Oil, August 15, 1970, p. 70.
3.
Wright, M. A., Chairman of Humble Oil Company, Testimony before
the House Ways and Means Committee, June 3, 1970.
4.
Heavy Crude Oil, IC 8352, Bureau of Mines, 1966.
"United States Petroleum through 1980," U. S. Department of the Interior,
1968.
5.
6.
Sulfur Content of Crude Oils of the Free World, Bureau of Mines,
RI 7059, 1967.
7.
"Some Environmental Implications of National Fuels Policies, " Com-
mittee on Public Works, U. S. Senate, December 1970.
8.
9.
International Petroleum Annual, U. S. Bureau of Mines, February 1970.
Starmont, D. H., Oil and Gas Journal, April 6, 1970.
"Low-Sulfur Resid Supplies Fall Far Short of U. S. Needs," The Oil and
Gas Journal, August 15, 1966.
Burner Oils 1965, U. S. Bureau of Mines, September 1965.
"Residual Fuel Air Pollution - A Growing Problem, " The Oil and Gas
Journal, June 27, 1966.
"Supply and Demand for Energy in the United States by States and
Regions - 1960 and 1965," Bureau of Mines, IC 8434, 1970.
Mineral Yearbook, Volumes I-II, 1969, U. S. Department of the Interior.
"Oil Import Activity for the Year 1968. . .," Department of Interior,
Oil Import Administration News Release, April 21, 1969.
"Oil Import Activity for the Year 1969 . . .," Department of Interior,
Oil Import Administration News Release, April 1970.
Annual Statistical Review, U. S. Petroleum Industry Statistics, 1970.
18. . "Forecast/Review, I. Oil and Gas Journal, January 25, 1971.
19.
"Survey of Nuclear Power Supply Prospects," HIT-501, Hittman Asso-
ciates, Inc., August 1971.
-------
20.
21.
22.
23.
24.
25.
26.
27.
28.
VII - 2
Gambs, Gerard C., and Arthur A. Rauth, "The Energy Crisis, "
Chemical Engineering, May 31, 1971, pp. 56-68.
Steam-Electric Plant Factors, 1970 Edition, National Coal Association.
A Review and Comparison of Selected United States Energy Forecasts,
Battelle Memorial Institute, prepared for the Office of Science and
Technology, December 1969.
"Electrical Power Supply and Demand Forecast for the United States
Through 2050," HIT-498, Hittman Associates, Inc., August 1971.
Mineral Industrial Surveys, USMB, Fuel Oil Sales Annual as referenced
in RED 70-1248, M. W. Kellogg Company, December 31, 1970.
"Firing Crude Oil in Boilers," Power Magazine, September 1970.
"Low Sulfur Oil - Ways to Simplify Handling and Firing, " Power Maga-
zine, July 1971.
Conversation with Mr. Arne Gulrud, API, April 8, 1971.
Oil and Gas Journal, January 18, 1971, p. 32.
-------
APPENDIX A
IMPORT RESTRICTIONS
-------
A-1
APPENDIX A
IMPORT REST RICTIONS
The importation laws concerning oil and its products are summarized in
a presidential proclamation dated March 10, 1959. It is known as Proclamation
3279 and is continually amended to reflect current needs. The proclamation.
provides strict controls on all oil imports. This control is made possible
through the use of oil allocations. An eligible firm wishing to import oil must
first obtain an allocation through the Secretary of the Interior. This allocation
specifies the amount of crude oil or oil product which the firm is licensed to
import during a period of time. The time period is typically 12 months. The
level can be established by several different methods.
The specific method selected depends, in part, upon the local need. Resi-
dential oil is in great demand along the eastern coast, District 1. As a result,
the restriction is based solely upon need. A firm can obtain all the import
required to meet existing contracts. General crude, on the other hand, is
restricted to an absolute upper value for the entire nation. The levels of
importation for a specific district is arrived at through a complex set of rules.
To explain the method of distribution, one must first look at the subdivi-
sions for the petroleum industry. Figure A-1 shows the five coordination
districts. They are similar to the FPC regional divisions. For instance,
District I is the combination of New England, Middle Atlantic, and South
. Atlantic FPC regions. District V, however, differs slightly from FPC bound-
aries. It encompasses all of the Pacific region plus Arizona and Nevada. For
the crude and unfinished oils import regulation, the country is divided into two
regulatory regions, Districts I through IV and District V. Within District V
covering the time period January 1, 1971 through December 31, 1971, a total
of 229,000 barrels per day of crude oil may be imported for use as input into
oil refineries. Of this total, no more than 25 percent may be unfinished oils.
The total value is divided roughly among the eligible users by the percentage
shown in Table A-I. For example, a refinery having a capacity of 9,000 bid
could import 60 percent of the plant's required input. A larger plant, however,
would be eligible for a much lesser percentage.
-------
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-------
A-3
TABLE A-l. ALLOWABLE REFINERY IMPORT
QUOT AS FOR DISTRICT V
Average Plant
Capacity, bid
0-10,000
Allowable Import
Percentage of Plant
Capacity
60
10,000-30,000
15
30,000 Plus
5
The petrochemical plants are controlled by a slightly different method.
Their crude oil and unfinished oils import limit, is a straight percentage of
11. 9 percent of the plant input for the year ending September 30, 1970. This
level is for the 1971 calendar year.
Districts I-IV are regulated on a slightly different basis. The 1971 refinery
import quota is set at 600,000 bid of crude and unfinished oil. The distribution
is again based on plant size, but the allowable input percentage is lowered sig-
nificantly. The values are shown in Table A:-2.
TABLE A-2. ALLOWABLE REFINERY IMPORT
QUOTAS FOR DISTRICTS I-IV
Average Plant
Capacity, bid
0-10,000
Allowable Import
Percentage of
Plant Capacity
20
10,000-30,000
30,000-100,000
12
7
100,' 000- Plus
3.5
The petrochemical plants are limited to a 11. 2 percentage based on the
yearly plant input ending September 30, 1970. This is slightly lower than the
District V allocation.
-------
A-4
Crude oil imports are also limited by source. Mexico allocations are
negotiated each year and range between 30,000 and 50,000 bId. Canadian
imports go up each year. The 1971 level for Districts I-IV is limited to
450, 000 bl d.
An incentive was used during the first three months of 1971 to stimulate
low sulfur residual oil production in District V. An additional barrel of crude
oil allocation was added for each barrel of 0.5 percent sulfur residual fuel oil
produced. The allocation obtained by this manner is valid for only six months
rather than the customary 12 months. This offer, however, was withdrawn
on April 4, 1971.
Residual fuel oil importation limitations are approached from a slightly
different viewpoint. Crude oil quotas are limited to some fixed level. Residual
fuel oil, on the other hand, is limited primarily by demand. Both Districts I
and V have specific regulations. District I has demand-related allocations.
Allocations are given to an eligible applicant if he can show they are required
to meet obligations under firm existing contracts. He must also show that the
oil is being delivered without any significant storage periods. This regulation
makes no mention of sulfur content. District V residual fuel oil allocations
are slightly different. The most significant variant is the import limit on
sulfur content. All residual import must contain O. 5 percent sulfur or less.
The specific import level is based on 1957 levels but adjusted by the Secretary
of Interior to meet the basic objectives of the import regulations.
Crude oil which is utilized solely as a burner fuel is regulated as if it
were a residual fuel. No part of said crude oil is allowed to be sold as any
other product except as a burner fuel. The Oil Import Administration is con-
sidering an additional category of imported oil. That is crude oil which is
imported then tapped of some of its lighter products to be sold on the open
market. The remaining residual will then be used as a burner fuel. Presently,
this usage is not permitted. There is no way of knowing when or if regulations
will be adopted to allow such use.
District I also has allocations for No.2 fuel oil. This regulation limiits
the source of this import to the "Western Hemisphere." A maximum level of
40, 000 bId is specified for the 1971 calendar year. The distribution is based
on inputs for the year between October 1, 1969 and September 30, 1970. The
regulation also spells out that an eligible person cannot be a crude oil importer.
-------
A-5
Finally, the importation of finished products for 1971 is also regulated
under this proclamation. It provides for 27,500 bid to the Department of
Defense and 15,000 bid to other eligible applicants. As one can see, refined
products are not an encouraged import.
-------
1-------
APPENDIX B
ECONOMICS OF RFO DESULFURIZA TION AND
OIL TRANSPORTATION
-------
B-1
APPENDIX B
ECONOMICS OF RFO DESULFURIZATION AND OIL TRANSPORTATION
A. RFO Desulfurization
The economics of residual fuel oil (RFO) desulfurization lack the pre-
cision that has been achieved with respect to the normal oil processing costs.
In part, this is due to the absence of long-term operating data. Large-scale
desulfurization has emerged as a feasible operation only in recent years.
The prediction of incremental costs due to desulfurization processing is com-
plicated by the large number of independent variables. For example, RFOs
of similar sulfur contents which are desulfurized to the same levels can
exhibit significant differences in processing costs. Reactor size will vary
drastically from resid to reside Thus, capital investment and catalyst costs
can differ significantly. The rate of hydrogen consumption differs depending
on process parameters and extent of desulfurization. Metal content in the
resid determines catalyst life. Generally, specific desulfurization cost esti-
mates must be based on the characteristics of the feed stock, on the level of
desulfurization required, refinery size, and on regional factors such as
construction, labor, utility, and hydrogen costs.
With respect to appreciation of desulfurization cost with time, it is
believed that the savings due to process improvements will outweigh the in-
creased costs of labor and materials for some time to come. Catalysts with
ever increasing resistance to poisoning by sulfur, nitrogen, metals, coke-
forming materials, and other bad actors in RFO are being found (Ref. B-l).
It is expected that the cost of desulfurization will have a downward trend in the
foreseeable future assuming the present trend in technological improvements
continues.
One of the most extensive efforts in the evaluation of RFO desulfuriza-
tion costs to date was undertaken by Bechtel Corporation for the American
Petroleum Institute, API (Ref. B-2). The study analyzed 14 desulfurization
schemes with respect to a typical Caribbean fuel oil normally containing
2.6 weight percent sulfur. The usefulness of the results obtained in this
study derives from the fact that the bulk of the RFO imported into the United
States comes from the Caribbean refineries. For example, in 1966, about
3.4 million barrels from an import total of 3.8 million barrels were
Caribbean RFO (Ref. B-2). (See Figure 2).
The various constraints and considerations adopted by Bechtel in eval-
uating incremental desulfurization costs are summarized below:
.
Initial sulfur content of 2.6 weight percent.
.
Typical large Caribbean refinery size of 300,000 barrels
per stream day of crude oil.
.
A 57.4 volume percent yield of desulfurized No.6 residual
fuel oil.
.
Initial metal content of 500 ppm.
-------
B-2
.
Costs derived from incremental investment and operating
costs. Any taxes or transportation costs were not included
.
Costs include sulfur credit based on a market price of $32
per long ton. Sulfur credit had only a minor effect on the
overall incremental costs (maximum credit was about 11
percent of final incremental cost).
In order to provide a means of evaluating desulfurization costs for
Caribbean oils of slightly different sulfur contents, some extrapolation was
applied to the Bechtel cost estimates. Thus, there are three curves corre-
sponding to imported Caribbean oils in the nomograph (Figures B-1, B- 2,
and B-3). However, care should be taken not to venture too far from the 2.6
wt percent sulfur base line. Desulfurization costs are highly sensitive to
the type of processing facilities and the overall properties of the oil feed
stock. Whenever a process involves hydrogen, for example, a major cost
item is the hydrogen feed. This cost can vary drastically with facility
location.
The cost differentials shown in the nomograph are based on the assump-
tion that all of the residual oil must be desulfurized. It may be economically
advantageous to desulfurize only part of the reside One option presented in
Reference B- 3 is to desulfurize 3/4 of the resid and sell the other 1/4, which
is high in sulfur, to users which have stack gas controls. As shown by
Figure 7 in Reference B- 3, the premium cost of O. 5 percent sulfur oil where
all the oil has undergone hydro-desulfurization is about 90 cents/bbl, whereas
if the power station accepts 1/4 of the oil at 3. 2 percent sulfur, the premium
cost per bbl falls to 45 cents or 50 percent of that shown on the nomograph
(see page VI-ll). Another plan would concentrate the sulfur into a very
high sulfur coke which would be used by the refinery for process heat. With
the proper incentives, the refinery could install an efficient S02 removal
system. The overall economics of this alternative appears promising for
those refineries which are "energy poor, " having no immediate source of
inexpensive fuel. If such alternatives are instituted, then the cost of de-
sulfurization per barrel obtained from the nomograph must be considered as
being conservative.
To provide flexibility in treating capital finance, the nomograph allows
variation in the fixed char*e rate. Figure B-1 is used to determine the rate.
For a Ifiven "interest rate and "years amortized", "Capital Recovery
Factor I is read, followed over to the appropriate "Percent Insurance and
Taxes" curve, and "Fixed Charge Rate"is then read.
The Bechtel Corporation assumed that money would be available at six
percent interest with a payout time of five years. Allowing for about two
percent of recurring costs, a fixed charge rate of 25 percent results. Thus,
a typical refinery would fix its prices to recover 1 / 4 of its capital investment
every year.
Figures B-2 and B-3 are used to obtain the fixed and variable costs of
desulfurization. Variable and fixed costs must be added to obtain the total
'operating cost. For instance, if we require that the Caribbean oil (average
sulfur content = 2.6 wt%) be reduced to 0.5 pounds of sulfur per million Btu's
the following costs are calculated:
-------
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10
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20
30
40
Interest Rate (%)
Fixed Charge Rate (%)
Figure B-l.
Determination of Fixed Charge Rate
b:1
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-------
Ultimate Sulfur Content
(percent by wt)
1.0
Fixed Charge Rate (%)
1.5
0.5
4
Fixed Cost (C:/million Btu)
Ultimate Sulfur Content
(Ibs / million Btu)
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Figure B-2.
Fixed Cost of Caribbean Oil Desulfurization Plant
-------
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Ultimate Sulfur Content
(lbs I million Btu)
bj
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Figure B-3.
Variable Cost of Caribbean Oil Desulfurization Plant
-------
B-6
Capital Investment 44 cents per million Btu per year
Fixed Cost (FCR-25 percent) 11 cents per million Btu
Variable Cost 3.4 cents per million Btu
Total Cost 14.4 cents per million Btu
This is equivalent to about 90 cents per barrel of oil having a heating
value of 6.3 x 106 Btu per barrel.
Incremental desulfurization costs for domestic RFO are based on
results of a study performed by Arthur G. McKee and Company (Ref. B-4).
In this study, incremental costs were evaluated for sulfur levels of 1. 0 weight
percent and 0.5 weight percent, according to the five individual PAD
(Petroleum Administration for Defense) districts. The basic approach in
the study was to establish an "average" refinery within each PAD district.
Each average refinery was characterized with respect to crude properties,
product slate, product characteristics, processing schemes, and RFO
blending requirements.
A major assumption was made with respect to the blending of the
heavy residuum with desulfurized cutter stock. It was assumed that the
desulfurized cutter stock was already available as part of the overall effort
in maintaining a constant sulfur level in the overall domestic RFO pool.
Thus, the incremental costs reflect only the processing necessary for de-
sulfurizing the heavy residuum.
In the case of PAD Districts 2 and 3, for example, the lower sulfur
content of the crudes obviates additional desulfurization processing. The
1. 0 weight percent sulfur level in these districts can be achieved simply
by blending with low sulfur cutter stock. Hence, the incremental desulfuri-
zation cost is zero. To obtain the 0.5 weight percent sulfur level, it is
necessary to partially desulfurize the heavy residuum in all five PAD districts.
Table B-1 summarizes the McKee data. Note that the processing scheme
used produced two products: No.2 and No.6 fuel oils. This complicates
the determination of desulfurization costs. If one assumes that there is a
strong market for the additional No.2 fuel oil, a credit can be applied to
the costs since No.2 oil may run as high as $9 per barrel as compared with
No.6 oil at $2 per barrel. However, any real credit is highly dependent on
local market conditions. Under ideal conditions, where No.2 oil can be sold
at a high price, the cost of desulfurization (allowing a No.2 oil credit) can
be reduced 50 percent or more depending on the PAD district. In construct-
ing the nomographs, no credit was given for the No.2 oil. . This conservative
assumption is partially counteracted by the fact that the McKee study assumed
the cutter stock was made available for blending at no cost. What in effect
has been done is to assume that No.2 and No.6 oils are essentially the same
and that all the costing is done on a per barrel of new product basis.
-------
TABLE B-l. DOMESTIC DESULFURIZATION DATA FOR
UNITED STATES PAD DISTRICTS
(Based on Arthur G. McKee and Company Data)
DISTRICT
1 2 3 4 5
Minimum Refinery Capacity (bid) 70,000 40,000 40,000 10,000 42,500
Crude Characteristics
API Gravity 29.7 35.1 34.0 32.6 27. 1
Sulfur (wt %) 1. 33 0.73 0.73 1. 39 1. 29
Resid Data
Sulfur Without Cutter (wt %) 2.6 1.3 1.3 2.7 2.5
Sulfur With Cutter (wt %) 2.0 1.1 1.1 2.25 1.9
Old No.6 Production (bl d) 11, 340 4,640 5, 600 2,810 10,631
1 % Sulfur Level
New No.6 Production (bid) 9,350 2,250 15, 470
No.2 Production (bl d) 2,570 730 4, 100
Total New Products (b I d) 6 11,920 2,980 19,570
Incremental Investment (10 $) 7.43 3. 19 10.49
Variable Cost ($ I day) 6 * 4,372 2,625 5, 627
Capital Investment
-------
B-8
The nomographs plot capital investment in terms of cents per million
Btu per year and variable cost in terms of cents per million Btu. These
parameters were obtained from the basic data as follows:
6 (100) II
Capital investment (cents per 10 Btu per year) = (6. 3)(365)TNP x PF
6 (100) VC
Variable cost (cents per 10 Btu) = (6. 3) TNP
where:
II =
TNP =
PF =
VC =
100 =
6.3 =
365 =
Incremental Investment (dollars)
Total New Product (barrels per day)
Plant Factor, assumed to be O. 94
Variable Cost (dollars per day)
Cents in a dollar
Million Btu' s in a barrel
Days in a year
Figures B-4 and B-5 are used t<;> obtain the fixed and variable costs
for desulfurization. Variable and fixed costs must be added to obtain the
total incremental cost for desulfurization. For instance, in PAD 1 if
require a limit of 0.5 pounds of sulfur per million Btu's to be maintained,
the following costs are calculated:
Capital Investment
Fixed Cost (FCR = 25 percent)
Variable Cost
Total Cost
32. 3 cents per million Btu per year
8.0 cents per million Btu
6.7 cents per million Btu
14.7 cents per million Btu
This is equivalent to about 93 cents per barrel of oil having a heating value
of 6.3 x 106 Btu per barrel.
Most desulfurization processes including the ones used in the Bechtel
and McKee studies rely on either thermal or catalytic treatment of RFO.
This leads to separation of lighter end products from the residual oil. The
result is a net loss in the oil's heating value. A typical heating value for
No'. 6 oil is 6.3 x 106 Btu per barrel. Desulfurization to low sulfur values
(- O. 6 percent sulfur) can lower the heating value to about 5 x 106 Btu per
barrel. This effect is included in the nomograph.
-------
1.5
Ultimate Sulfur Content
(percent by weight)
1.0
Fixed
0.5
10
Charge Rate (0/0)
15 20 25
30
Ultimate Sulfur Content
(lbs / million Btu)
Operating Cost = Fixed Cost + Variable Cost
Figure B-4. Fixed Cost of Domestic Oil
Desulfurization by PAD District
tJ:j
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-------
Ultimate Sulfur Content
(percent by weight)
1.0
1.5
0.5
18
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Ultimate Sulfur Content
(lbs'!million Btu)
Figure B-5. Variable Cost of Domestic Oil
Desulfurization by PAD District
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-------
B-ll
B. Oil Transportation
The cost of transporting oil involves the greatest variation of costs than
any other fuel. Costs may range from one cent per barrel per 100 miles for
long haul tankers to 45 cents per barrel per 100 miles for short hauls by rail.
1.
Oil Transport Costs Via Tanker (Fi~ure B- 6)
The tanker market is a highly volatile and competive market. Tonnage
is contracted on a voyage basis (" spot" market) or on short-term or long-term
charters.. The spot market can fluctuate from day to day over a wide range.
If spot prices are kept high for several weeks, they may have a decided infla-
tionary impact on the charter prices contracted during the period of high. spot
prices. Because rates fluctuate so erratically, it was decided to present what
is termed the "base rates" for tanker transport on the nom ograph. The cur-
rent rate structure can then be factored in using the "World Scale" factor.
Base rates have been placed on all the important runs; e. g., Caribbean-
United States, Persian Gulf- U. K., or Persian Gulf-Far East runs. These
base rates are equated to a World Scale of 100 (W100). If rates for a given
run happen to be twice the base rate, it would be termed as a rate of W200.
As an example, the Caribbean- United Sta,tes run is 2000 miles (see
Table B-2). The World Scale base rate at W100 is 25 cents per barrel. In
the last half of 1970, spot charter rates varied from W180 to over W320 with
an average near W240 (Ref. B-5). Current World Scale rates appear weekly
in the Oil and Gas Journal.
TABLE B-2. MILES (DAYS ROUND TRIP)
TO U. S. A., EAST COAST. FROM:
Persian Gulf
(via Capetown)
12,000 (65)
East Mediterranean
5,200 (30)
4,500 (28)
Libya
Caribbean
3, 800 (24)
2, 000 (13)
Algeria
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Notes:
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Current World Scale x Base Rate
100
Example: Caribbean-D. S. Run (2000 miles) at W200 Results in
$0. 50 per barrel tanker charge.
FigureB-6. Oil Transport Costs Via Tanker
=
Current Rate
(2)
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-------
B-13
Another important example is the Persion Gulf- U. K. run which is
11,300 miles. This run has significance because it largely influences the
rates of other runs. Its base rate at W100 is $1. 19 per barrel. Actual
rates have varied between W120 and W300 with an average of over W200 for
the last part of 1970. These rates are very high and are deemed unusual for
the industry. In coming years with the influx of the super tankers into the
fleet and the possible advent of the Suez Canal opening, demand should be
lessened and rates brought back to more "normal" levels. Under normal
market conditions, the super tankers in the 300,000 dwt class would probably
operate the Persian Gulf-U. K. run at below W50 which no doubt will sub-
stantially affect the total market price structure (Ref. B-6).
2.
Oil Transport Via Rail (Figure B-7)
The cost of rail transportation has generally decreased since the
beginning of the 1960s. Though it has been uncommon to ship crude or
residual oils in tanker cars in the past, this mode of transportation has been
on the increase. Canada has recently begun the first unit train operation
transporting well head oil from its northern provinces. Such unit trains
drastically cut the cost, operating below one-half the normal 25 cents per
barrel per 100 mile rate reported for long haul operation greater than 500
miles (Ref. B-7). Unlike the ocean tanker market, the rail market is less
volatile, being dependent on more long-term influences. Variations in rates
are due mainly to regional cost differences in such items as labor costs,
level of modernization, and local tariff structure. The rates used to con-
struct the nomograph represent average rates. Rates can vary + 10 percent.
Unit trains are excluded. Rates for this mode would be approximately one
half the indicated cost per barrel.
3.
Oil Transport Via Barge (Figure B-7)
Barge rates beyond 500 miles average about 16 cents per barrel per
100 miles. Significant cost reductions are foreseen in this area as barges
carrying 80 to 100 thousand barrels come into use. Long-term charters of
such large barges will significantly affect the cost structure bringing the cost
of oil transportation down to levels as low as five cents per barrel per 100
miles (Ref. B-7). Care should be exercised in using the average barge rate
shown on the nomograph because, as in the case of ocean tankers, rates
are highly variable.
4.
Oil Transport Via Pipeline (Figure B-7)
Pipeline transportation costs are presently averaging about five cents
per barrel per 100 miles for long distance pipelines which operate over
8000 hours per year at capacity (Ref. B-7). Costs sky rocket for short pipe-
lines which have low utilization. As an example, a 7.6 mile pipeline built by
-------
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200
300
400
600
800 1000
1500
Miles
Figure B-7.
Typical Oil Transportation Costs for
Rail. Barge. and Pipeline
tJj
I
......
~
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B-15
Consumers Power between Edmonton and Bay City, Michigan, costs the com-
pany 46 cents per barrel (Ref. B- 8). This is equivalent to a rate of $6.00 per
barrel per 100 miles which is about 120 times more costly than the basic long
distance rate. Thus, the nomograph which is based on high utilization pipe-
lines should not be used for short-run "connect" pipelines which are subject
to considerable variability in cost due to their intermittent operation.
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