EPA-450/3-74-032-a
May 1974
IMPACT OF MOTOR GASOLINE
LEAD ADDITIVE REGULATIONS
ON PETROLEUM
REFINERIES AND ENERGY
RESOURCES - 1974-1980
PHASE I
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Water Programs
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 21711
-------
EPA-450/3-74-032-a
IMPACT OF MOTOR GASOLINE
LEAD ADDITIVE REGULATIONS
ON PETROLEUM
REFINERIES AND ENERGY
RESOURCES - 1974-1980
PHASE I
by
Arthur D . Little, Inc.
Acorn Park
Cambridge, Massachusetts 02140
Contract No. 68-02-1332 Task No. 4
EPA Task Officer: David R. Patrick
Prepared for
ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Water Programs
Office of Air Quality Planning and Standards
Research Triangle Park, N . C . 27711
May 1974
-------
This report is issued by the Environmental Protection Agency to report
technical data of interest to a limited number of readers, Copies are
available free of charge to Federal employees, current contractors and
grantees, and nonprofit organizations - as supplies permit - from the
Air Pollution Technical Information Center, Environmental Protection
Agency, Research Triangle Park, North Carolina 27711 , or from the
National Technical Information Service, 5285 Port Royal Road, Springfield,
Virginia 22151.
This report was furnished to the Environmental Protection Agency by
Arthur D. Little, Inc. , Cambridge, Massachusetts 02140, in fulfillment
of Contract No. 68-02-1332. The contents of this report are reproduced
herein as received from Arthur D. Little, Inc. The opinions, findings,
and conclusions expressed are those of the author and not necessarily
those of the Environmental Protection Agency. Mention of company or
product names is not to be considered as an endorsement by the Environ-
mental Protection Agency.
Publication No. EPA-450/3-74-032-a
ii
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ABSTRACT
The report presents results of a study to assess the impact
on operations of petroleum refineries and on energy resources of two
regulations promulgated "by the Environmental Protection Agency to
control the level of lead additive in motor gasoline. The first of
these regulations requires the availability of low-octane, lead-free
gasoline for vehicles which will be equipped with lead sensitive
catalytic converters designed to meet 1975 automotive emission
standards. For health reasons, the second regulation requires a
gradual phase-down of the lead content of the total gasoline pool
(including higher octane gasoline to satisfy the remaining high-
compression ratio engines). The study considers separately the
impact of each regulation. Effects on overall refinery yields,
refinery operation flexibility to maximize production of gasoline
and/or heating oils, and on energy resources requirements have been
considered. Other parametric studies evaluate suppositions of a
need for a higher octane lead free' gasoline and a higher demand for
lead free gasoline than now forecast.
iii
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ACKNOWLEDGMENTS
In preparing this report, several people in addition to
the principal author, Arthur D. Little, Incorporated, made
significant contributions. We wish to acknowledge the guidance
and direction provided by the Petroleum Refinery Task Force including
Messrs, David R, Patrick, Richard K. Burr, and Gilbert H. Wood,
Throughout the project, considerable technical assistance
was obtained from Dr. James R. Kittrell, Associate Professor, and
Dr. William L". Short, Professor, both of the Chemical Engineering
Department, University of Massachusetts, Their assistance in both
defining the areas of concern and analyzing the results is especially
appreciated.
iv
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TABLE OF CONTENTS page
ABSTRACT iii
ACiCN OWLTCDGEMENTS iv
X. SUMMARY AND CONCLUSIONS . 1-1
II. INTRODUCTION II-l
III. MODEL RESULTS
A. BASE CASES T.II-1
B. PARAMETRIC STUDIES 1.11-3
C. IMPACT OF LEAD PHASE-DOWN 111-12
IV. MODEL CONSIDERATIONS
A. INPUT DATA IV-1
B. MODEL VALIDATION AND CALIBRATION IV-7
V. DETAILED DATA V-l
A. BASIC DATA TABLES V-3
B. REDUCED DATA TABLES V-l4
C. ECONOMIC SUMMARY TABLES V-25
D. ENERGY BALANCES TABLES V-35
E. REFINERY FLOW DIAGRAMS V-46
VI. ANALYSIS OF REFINERY OPERATION VI-1
A. CRUDE PENALTIES VT.-l
B. ECONOMICS VI-11
C. REFINERY FLEXIBILITY VI-19
D. ENERGY PENALTIES VI-25
VII. RECOMMENDATIONS FOR FUTURE STUDIES VII-1
v
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LIST OF TABLES
1-1 Refinery Impact of EPA Lead Regulations I-U
II-l
Gasoline Grade Requirements by Percent
II-2
III-l
Summary - Crude '
Intake Requirements
111-9
III-2
Summary - Energy Balances
111-10
III-3
Summary - Economics
III-ll
IV-1
Input/Output Summary - MB/CD
IV-2
V-l
Basic
Data
Case
1
Actual Refinery
V-3
' V-2
. Basic
Da£e
Case
2
Actual Refinery
V-4
V-3
Basic
Data
Case
3
Actual Refinery
V- 5
V-4
Basic
Data
Case
4
Actual Refinery
V-6
V-5
Basic
Data
Case
5
Actual Refinery
V-7
V-6
Basic
Data
Case
6
Actual Refinery
V-8
V-7
Basic
Data
Case
7
Actual Refinery
V-9
V-8
Basic
Data
Case
1
Complex Refinery
V-10
V-9
Basic
Data
Case
2
Complex Refinery
V-ll
V-10
Basic
Data
Case
3
Complex Refinery
V-12
V-ll
Basic
Data
Case
4
Complex Refinery
V-13
V-12
Reduced Data
Case
1 Actual Refinery
V-14
V-13
Reduced Data
Case
2 Actual Refinery
V-15
V-14
Reduced Data
Case
3 Actual Refinery
V-16
V-15
Reduced Data
Case
4 Actual Refinery
V-17
V-16
Reduced Data
Case
5 Actual Refinery
V-18
V-17
Reduced Data
Case
6 Actual Refinery
V-19
V-18
Reduced Data
Case
7 Actual Refinery
V-20
vi
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V-19
Reduced Data Case 1 Complex Refinery
¥-21
V- 20
Reduced Data Case 2 (
Complex Refinery
¥-22
¥-21
Reduced Data Case 3 Complex Refinery
¥-23
¥-22
Reduced Data Case 4 Complex Refinery
¥-24
¥-23
Economic
Summary
Case
1
Actual Refinery
¥-25
¥-24
Economic
Summary
Case
2
Actual Refinery
¥-26
¥-25
Economic
Summary
Case
3
Actual Refinery
¥-27
¥-26
Economic
Summary
Case
4
Actual Refinery
¥-28
¥-27
Economic
Summary
Case
5
Actual Refinery
¥-29
¥-28
Economic
Summary
Case
7
Actual Refinery
¥-30
¥-29
Economic
Summary
Case
1
Complex
Refinery
¥-31
¥-30
Economic
Summary
Case
2
Complex
Refinery
¥-32
V-31
Economic
Summary
Case
3
Complex
Refinery
¥-33
V-32
Economic
Summary
Case
4
Complex
Refinery
¥-*34
¥-33
Energy
Balances
Case
1
Actual
Refinery
¥-35
¥-34
Energy
Balances
Case
2
Actual
Refinery
¥-36
¥-35
Energy
Balances
Case
3
Actual
Refinery
¥-37
¥-36
Energy
Balances
Case
4
Actual
Refinery
¥-38
¥-37
Energy
Balances
Case
5
Actual
Refinery
¥-39
¥-38
Energy
Balances
Case
6
Actual
Refinery
¥-40
¥-39
Energy
Balances
Case
7
Actual
Refinery
¥-41
¥-40 .
Energy
Balances
Case
1
Complex
Refinery
¥-42
¥-41
Energy
Balances
Case
2
Complex
Refinery
¥-43
V-42
Energy
Balances
Case
3
Complex
Refinery
¥-44
¥-43
Energy
Balances
Case
4
Complex
Refinery
¥-45
vli
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VI-1
Gasoline Blending Summary
Case
1,
1974A
VI-5
VI-2
Gasoline Blending Summary
Case
1,
1976A
VI-6
¥1-3
Gasoline Blending Summary
Case
1»
1976B
VI-6
VI-4
Gasoline Blending Summary
Case
1,
1976C'
VI-7
VI-5
Gasoline Blending Summary
Case
1.
1979A
VI-7
VI-6
Gasoline Blending Summary
Case
1,
1979B
VI-8
VI-7
Gasoline Blending Summary
Case
1,
1979C
VI-8
VI-8
Gasoline Blending Summary
Case
6,
1976A Winter
VI-10
VI-9
Gasoline Blending Summary
Case
6,
1974A Summer
VI-10
VI-10
Cumulative New Capital Investment Above 1974
VI-11
vi-xi
Case 1 Actual vs. Complex
- 1979
VI-13
VI-12
Delta Intakes MB/CD
VI-14
VI-13
1976 Flexibility Analysis
-
VI-20
VI-14
Total Energy Consumed (Actual Refinery)
VI-26
VI-15
Total Energy Consumed (Complex Refinery)
VI-27
viii
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LIST OF FIGURES
Figure No. Page
V-l Simplified Flow Diagram - Actual Refinery ~ Case 1 1974A V-46
V-2 Simplified Flow Diagram - Actual Refinery - Case 1 1976A V-47
V-3 Simplified Flow Diagram - Actual Refinery - Case 1 1976B V-48
V-4 Simplified Flow Diagram - Actual Refinery - Case 1 1976C V-49
V-5 Simplified Flow Diagram - Actual Refinery - Case 1 1979A V-50
V-6 Simplified Flow Diagram - Actual Refinery - Case 1 1979B V-51
V-7 Simplified Flow Diagram - Actual Refinery - Case 1 1979C V-52
V-8 Simplified Flow Diagram - Actual Refinery - Case 5 1974A V-53
V-9 Simplified Flow Diagram - Actual Refinery - Case 5 1976A V-54
V-10 Simplified Flow Diagram - Actual Refinery - Case 5 1976B&C V-55
VI-1 Processing Unit Intakes - Actual Refinery - Case 1 VI-3
VI-2 Delta Cumulative Investment Summary - Complex vs. Actual VI-12
VI-3 Processing Unit Intakes - Complex Refineries - Case 1 VI-16
ix
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I. SUMMARY AND CONCLUSIONS
In February 1974, the EPA asked Arthur D. Little, Inc. (ADL) to review the
effects of the EPA regulations which require the availability of lead-
free gasoline and the gradual phase-down of the lead content of the
total gasoline pool. The EPA required that preliminary results be
reported to the EPA in early April, and the final written report be
completed by the end of April, 1974, Although previous studies have
been conducted and published for the EPA concerning the problems
associated with supplying lead-free gasoline and reducing lead content
of gasoline, the EPA felt that this review was needed for the following
reasons;
• Since the previous studies had been conducted, more recent
assessments of the status of mobile source emission standards
and lead-free gasoline requirements have become available.
• Rapid large increases in crude oil costs and associated
product prices have occurred recently due in part to increased•
national energy demand and limited supply. Since refinery
processing options are inherently sensitive to costs of raw
materials and products, and since these options can not be
fully analyzed manually without severe oversimplification,
the EPA felt that a computer analysis of the impact of the
lead regulations incorporating current prices was needed.
• Natural gas production has continued to decline since the
previous studies. This decline has caused increased
substitution of volatiles for this marginal supply with
associated increase in LPG prices.
• Assessments of results of recent EPA test programs and state-
ments by the automobile manufacturers indicate that the fuel
economy increase for catalyst-equipped vehicles will be great-
er than previously projected. Not only will the fuel economy
benefits compensate for the previous 3.5% penalty due to low-
ered compression ratios to reduce N0X emissions and prepare
for low-octane, lead-free gasoline but the benefits also will
offset the entire 10% penalty for the total of all of the air
pollution controls. This change in fuel economy greatly aff-
ects projections of gasoline demand and, thus, refinery oper-
ations.
® Since the last studies, refinery process unit capacities have
increased and refining technology, particularly in the
development of superior catalysts for catalytic cracking and
reforming, has continued to Improve.
• Potential crude supply restrictions to domestic refineries,
as illustrated by the recent Arab oil embargo indicate the
necessity of maintaining the refinery flexibility to vary
output product mix to meet seasonal demands, e.g., gasoline
and fuel oils.
1-1
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The Intent of this study was to evaluate the effect of lead phase-down
and lead-free gasoline scenarios on (1) crude oil requirements to meet
projected petroleum product demands (e.g., gasoline, jet fuel, petro-
chemical feedstocks, (2) associated net energy consumption for
refining, (3) capital investment (or strain on construction industry)
and gasoline costs, and (4) flexibility of the refining Industry to adjust
the product mix, particularly to seasonal variations, of gasoline and
fuel oil demands. To achieve this, three scenarios were evaluated for
each year considered:
• Scenario A — No Lead Regulations (minimal presence of lead-
free gasoline, 3ce/gal lead maximum in regular
and premium grades, and distribution of regular
and premium in the gasoline pool assuming no
additional automotive emission controls).
• Scenario B — Significant Lead-Free Gasoline Marketing, but with
No Lead Phase-Down (inctease in lead-free pool,
with increased lead-free percentage being propor-
tionally subtracted from premium and regular
grades; 3cc/gal lead maximum in regular and premium
grades).
• Scenario C — Lead-Free Gasoline with Promulgated Phase-Down
(same gasoline distribution as Scenario B but
with lead phase-down as promulgated in the
December 6, 1973 Federal Register).
The scope of this study was to consider the impact of the lead regulations
upon the manufacture of petroleum products. Additional impacts
involved in distributing and marketing lead-free gasolines have been
analyzed in previous studies.
The Federal Energy Office (FEO) issued forecasts in mid-December of
United States 1974 petroleum product demands in an unconstrained environ-
ment. Several possible supply scenarios were postulated and resultant
product shortages defined. We have used these estimates of 1974
petroleum product demands as the basic source of our model inputs with
only minor adjustments made to reflect more recent data in certain
instances.
The results of this overview study indicate that:
o Most large, modern, efficient refineries (which represent the
major source of supply to the U.S. marketplace), will suffer
little penalty from manufacturing lead-free gasoline and the
lead phase-down. A key premise is that moderate-octane
gasoline (refinery target of 92/8'+ RON/MON gasoline to allow
more than ample margin to ensure minimum octane levels of
91/83 RON/MON) will provide satisfactory performance in post-
197^ automobiles. (It is recognized that an overview study of
1-2
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this scope does not address itself to analysis of the specific
potential problems of some small or atypical refiners. However,
it should be noted that the promulgated lead phase-down schedule
does not require compliance by small refiners for the first two
years).
o Through 1976 there is essentially no crude oil penalty for
either B vs. A orC vs. B.
o The average crude oil penalty for 1977 through 1980 is 30,000 -
i+U5000 "barrels per calendar day (B/CD) (.2-.3% of A) for B vs. A
and approximately 28,000 B/CD for C vs. B (.1% of A).
o Through 1976 there is essentially no net energy input penalty
for either B vs. A or C vs. B.
o The average net energy input penalty (fuel oil equivalent barrels)
for 1977-1980 is about 10,000-20,000 B/CD (.1% of A) for B vs. A
and 20,000-30,000 B/CD (.1-.2# of A) for C vs. B.
o -Through 1976 there is essentially no capital investment penalty
for either B vs. A or C vs. B.
o The average yearly capital investment penalty for 1977 through
1980 is 150 million dollars (197^- dollars) for B vs. A and
220 million dollars for C vs. B. These incremental capital
investment figures are extremely sensitive to the process routes
selected. Phase II of this study will examine capital investment
in more detail, in order to provide further information on this
point.
o The incremental process unit construction due to the lead regu-
lations is insignificant compared to the construction necessary
to meet the growth of overall petroleum product demand.
o Through 1976 there is essentially no net economic penalty
(cents per gallon of gasoline) for either Scenario B vs. A or
C vs . B.
o For 1977 through 1980, the average net economic penalty is less
than .1 cents/gallon of lead-free gasoline for B vs. A and less
than .1 cents/gallon of total gasoline for C vs. B.
o There is essentially no net energy input penalty and no loss of
flexibility of product yields for either Scenario B vs. A or
C vs. B for current refinery capacity limitations.
1-3
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TABLE 1-1
R1PIIERX IMPACT OP EPA LEAD REGULATIONS
Average Yearly Penalty
197)i--1976 1977-1980
A Crude [MB/D]
Lead-free 0 30—1+1+
Lead Phase-down _j0 28
Total 0 58-72
A let Energy Input [FOE MB/D]
Lead-free 2 10-20
Lead Phase-down __2 20-30
Total 1* 30-50
A Capital Investment {$10^]
Lead-free 0 ,15
Lead P'hase-down 0 .22
Total 0 • .37
A Gasoline Cost [^/gal]
Lead-free1 (.02) ,02
Lead Phase-down'3 0 ,03
Combined^ (.Ol) .0^
1. Apportionated over lead-free gasoline production only.
2, Apportionated over total gasoline production.
1-1+
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II INTRODUCTION
The intent of the study was to evaluate the effect of various
lead phase-down and lead-free gasoline scenarios on (1) increased
crude oil requirements to meet projected, unrestrained petroleum product
demands (e.g., gasoline, jet fuel, petrochemical feedstocks, etc,)
(2) associated net energy consumption in refining,(3) capital investment
(or strain on construction industry) and increased gasoline costs, and
(4) flexibility of the refining industry to adjust the product mix,
particularly seasonal variations of gasoline and fuel oil demands,
To achieve this, three scenarios were evaluated for each year
considered:
•Scenario A — No Lead Regulations (minimal presence of lead-free
gasoline, 3cc/gal lead maximum in regular and pre-
mium grades, and distribution of regular and pre-
mium in the gasoline pool assuming no additional
automotive emission controls)» The specific grade
distribution is shown in Table II-l.
^Scenario B — Significant Lead-Free Gasoline Marketing (availability
required by EPA regulation promulgated in the
January 10, 1973 Federal Register), but with No
Lead Phase-Down (increase in lead-free pool, with
increased lead-free percentage being proportionally
subtracted from premium and regular grades; 3cc/gal
lead maximum in regular and premium grades), The
specific grade distribution is shown in Table II-l.
• Scenario C — 'Lead-Free Gasoline with Promulgated Phase-Down
(same gasoline grade distribution as Scenario B
but with lead phase-down as promulgated in the
December 6, 1973 Federal Register).
II-l
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TABLE II-l
Gasoline Grade "Requirements by Percent
No Lead Regulations
1974
1975
1976
1977
1978
1979
1980
Grade Distribution %
Premium
(100 RON)
40
38
39
40
41
42
43
Regular
(94 RON)
58
60
59
58
57
56
55
Lead-Free
(92 RON)
2
2
2
2
2
2
2
B. Lead-free
with
No Lead
Phase-
-down
Percent of Pool
Premium
37
34
28
22
19
15
11
Regular'
56
51
42
34
28
22
17
Lead-free
7
15
30
44
53
63
72
C. Lead-free
With
£
Lead Phase-down
Promulgated lead
phase-down, pool
average, grams/gal.
1.7
1.4
1.0
0.8
0.5
0.5
Allowable grams of
lead per gallon
of leaded gasoling
-2.2b
1.99
1.97
1.74
1.65
1.27
1.66
a. Same distribution
pattern
used
as in
Lead-free
(Case
B)
b. Current national average
II-2
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The impact of phase down of lead in gasoline was evaluated during
the interval 1974-1980 by consideration of the following cases, for each
Scenario,
•Case 1 — Simulation of U.S. Refining, industry by a single com-
posite crude slate, using best estimates of product
growth and annual average distribution for each year,
1974-1980 Inclusive.
•Case 2 —-A parametric study, varying only the clear octane
of the lead-free grade from 92/84, R0N/M0N, (Case 1)
to 93/85 R0N/M0N (Case 2 ). Case 2 . therefore evalu-
ates variations in the projected difference between
the current pool octane and the pool octane required
with lead phase-down.
•Case 3 — A parametric study, varying only the rate of growth
of gasoline demand from 4%/year (Case 1) to 7%/year
(Case 3 ). Case 3 thus evaluates uncertainties in
the gasoline growth"projection.
' «Case 4 — A parametric study, varying only the rate of intro-
duction of lead-free gasoline from Scenarios B & C in
Case 1.. Here, the amount of lead-free gasoline in the
total pool was reduced for Scenarios B and C with the
amount reduced distributed proportionally between the
premium and regular grades. This case evaluates un-
certainties in projections of market penetration of
lead-free gasoline. The gasoline distributions used
are shown below:
GRADE
DISTRIBUTION %
Case
1
Case
4
1976
1979
1976
1979
Premium
28
15
35
23
Regular
42
22
45
31
Lead-Free
30
63
20
46
•Case 5 — Restricted Capacity Evaluations - a parametric study,
similar to Case 1 except the capacity of each refining
unit was restricted to the percent of average U.S. crude
capacity as reported in the April 2, 1973 Oil and Gas
Journal. Hence, whereas Case 1 can be considered to
be new grass roots refineries from 1974 through 1976,
Case 5 represents existing average U.S. capacity
limitations. As a consequence, Case 5 was evaluated
only for 1974, 1975, and 19 76, the time period before
significant new capacity could be installed.
II-3
-------
*Case 6 —¦ Refinery Flexibility Studies - The unit capacities
were again fixed as in Case 5, and the ability of
the industry to swing from maximum gasoline (9.5 RVP
on gasoline based on 1973 Summer data of B.O.M.) to
maximum distillate (12 RVP on gasolines based on
1972 winter data of B.O.M,) was evaluated. LPG pro-
duction was restricted to 2.6-2.8% .yield on crude in
the summer (1973 B.O.M. data) and 2.8% minimum in the
winter. The ratio of distillate to residual fuel
was fixed at 2.58 for 1974 in accordance with his-
torical B.O.M. data and successively reduced to 2.19
in 1976 reflecting a more rapid growth in domestic
residual fuel production.
• Case 7 — A parametric study, varying (reducing) only the per-
centage of premium gasoline in the total pool (1979) and
increasing regular accordingly to examine uncertain-
ties in projecting future gasoline grade distribution.
The pool distribution used was:
Scenario A Scenarios B and C
Premium 30% 12%
Regular 68% 25%
Lead Free 2% 63%
II-4
-------
Ill MODEL RESULTS
A. Base Cases
Case 1 - Actual Refinery
The purpose of Case 1 was to examine the effect of
producing lead-free and reduced lead content motor gasolines
each year from 1974 to 1980 in an unrestricted refining
environment. For this series of runs we specified product
demands, specifications, and cost of raw materials. The
refining processing sequence was then allowed to optimize.
We call this series of runs our "actual" refinery in that
we have composited many of our parallel, blocked out
processing options allowed in our more "complex" refinery,
which is discussed, next in this section. We selected optimum
feed blends to some of the downstream processing operations
such as hydrocracking, coking and alkylation to more closely
simulate the actual flexibility available in a typical
refinery.
With the greatly increased costs of crude oil and the
limited supply and price competition for volatiles and natural
gas, the refining processing sequence selected considerably
more hydrocracking than is practiced today. This process
has a large volume gain even while producing substantial
volumes of middle distillates as co-products. While the
competitive catalytic cracking process also exhibits a volume
gain, it is not the same magnitude as for hydrocracking.
Also, catalytic cracking inherently requires that some of
the hydrocarbon feedstock be converted and consumed as
catalyst coke. As shown in Section III C, changing process
sequences appears to have minimal impact on either crude
penalty or energy penalty.
The optimum clear gasoline pool octane level for 197^-
was calculated to be 89.^/81.2 (RON/MON) which is not much
different from the anticipated average today, although many
variations exist in this projection.
In most years the capital expenditures required for
the reduction of lead content, were actually lower than for
the base scenarios. The primary reason for this is that,
for this case, it is most attractive to increase clear
octane levels via the catalytic cracking/alkylation process-
ing route (including increased conversion on the catalytic
cracker to produce higher octane gasolines) while reducing
hydrocracking/catalytic reforming. Although this results
in a less efficient raw material usage (because of the loss
in hydrocracking yield gain) it does require less overall
capital.
III-l
-------
As seen in the summary tables, the crude oil, energy,
operating cost, and capital cost penalties for the lead
regulations are relatively insignificant, and in some
situations there appears to be no penalty at all. The max-
imum crude penalty due to lead phase- down (C-B) is 62,000 B/CD
the maximum economic penalty is 4
-------
B, Parametric Studies
Case 2 - Actual Refinery
The purpose of this case was to examine the effects
of producing a lead-free grade of 93/85 RON/MON instead of
the 92/84 produced in Case 1 (and all other subsequent
cases). As expected the higher octane product required
a greater energy consumption and increased operating costs
resulting in a greater economic penalty than Case 1. The
maximum crude penalty (C-B) is 86,000 B/D; the maximum net energy
input penalty (C-B) is 95#000 B/D and the maximum economic
penalty is 5.2^/tfbl. As for Case 1, it should be noted
that these values are maximums and thus tend to overstate
some of the impacts. For example, although the maximum
crude oil penalty is 86,000 B/D for C-B, the average
penalty is only 6,000 B/D for 1974 through 1976 and is less
than 42,000 B/D for 1977 through 1980. A1 so it is significant
to note that once again the most attractive way to Increase
clear octane numbers for the pool is via catalytic cracking/
alkylatlon replacing hydrocracking/catalytic reforming.
For Case 1 the economic effect was most pronounced in
comparing scenario C versus B. In Case 2 the major delta
increase in catalytic cracking/alkylatlon occurs in comparing
scenario B versus A, and as a result there is a capital
investment penalty in 1980 associated with lead phase-down
(C versus B).
One must: caution that these results are only valid
comparing 92/84 product to 93/85 and should not be extrapolated
to higher octanes. Above the octane levels studied, one
would expect other capital intensive processing such as light
straight-run gasoline isomerization to be selected which would
cause a more rapid increase in overall capital requirements.
It should be noted that the primary purpose of this
case is to determine the sens it ivity of the model to
specific octane levels. The evaluation of this case is not
meant to suggest that 93/85 R0N/M0N will be necessary for
post-1974 vehicles. Rather, all post-1974 model year
vehicles will be satisfied by 91/83 RON/MON through the
vehicle life (i.e., including effect of increased octane
requirement with mileage). This conclusion is based on
recent communications with the automobile manufacturers in
addition to their numerous public statements.
Case 3 - Actual Refinery
In Case 3 we assumed that the overall refinery gasoline
production would increase 7% a year rather than the 4% average
annual growth which was used in all other cases.
III-3
-------
Since the other cases assuming a 4% gasoline growth
(with distillates and residual fuel increasing faster) re-
sult in an average decline in gasoline yield of about 4% over
the time period studied, this case countered that trend and
maintained essentially constant gasoline yield. In the later
years (such as 1979 and 1980) there are increased energy and
economic penalties with the lead phase-down. As stated
previously, it is attractive for certain instances to Increase
gasoline (or distillate) yields via hydrocracking because of
the related large associated volume gain. However, as the
need for high clear octane numbers are required, the intro-
duction of high severity catalytic cracking and alkylation
becomes more attractive. The "A" Scenarios desire a high
percentage of hydrocracking to provide the higher gasoline
growth rates and these percentages are in general about the
same order of magnitude as Case 1. However, in Case 3
Scenarios B and C, it is.necessary to maintain this high
level of hydrocracking versus Case 1 to manufacture the
required volume of gasoline complemented by increased reform-
ing severity to meet octane requirements. Thus there is the
need to process more raw materials to replace the gasoline
yield loss due to increasing reformer severity.
The major "penalty" associated with Case 3 is thus
the total crude run, which in 1980 has risen to 21,382,000
B/D (Scenario C) versus 19,642,000 B/D for Case 1. In general,
the maximum economic, crude oil, and energy penalties (C-B)
are greater for Case 3 than any other case: 11.1/Bbl.,
127,000 B/D crude oil and 155,000 B/D net energy input. As
for the other cases, these maximum values tend to overstate
the impact. For example, although the maximum crude oil
penalty is 127,000 B/D for C-B, the average is 6000 B/D for 197^
through 1976 and 28,000 B/D for 1977 through 1980. Further-
more it should be restated that we do not consider Case 3
to be likely. However, Phase II should include a parametric
case with a slightly greater gasoline growth rate than the
base (4%) but still less than the 71 of Case 3.
Case 4 - Actual Refinery
Case 4 runs were to study if a lower market penetra-
tion of lead-free gasoline (B versus A) would result in
increased penalties for lead phase-down (C versus B). Only
two years were studied (1976 and 1979) and the penalties for
B versus A were reduced and C versus B increased. However,
the deviations from Case 1 were not considered of sufficient
magnitude to alter the overall conclusions of this analysis.
The differences are summarized below for 1979.
III-4
-------
197p Penalty
Case 1 (Actual) Case k (Actual)
B-A C-B
A Crude MB/CD k2 ' 35
A let Energy Input,
MB/CD 3^ 75
A Total Gasoline
Cost tf/ Bbl. l.k i+. 0
B~A
C-B
10
151
10
111
(0.5)
8.1
It should again be noted that these are maximum values. We
looked only at 1976 and 1979 and thus can not present average
values for the time period. However, it is reasonable to think
that the average may be considerably less than the maximum,
in the same manner as the other cases. Furthermore it should
be noted that recent EPA communications with the automobile
industry still confirm earlier conclusions that lead tolerant
vehicles that can meet the 1975 emission standards while
maintaining fuel economy equivalent to catalyst-equipped
vehicles will not be available in the near future. Thus,
although Case 4 has value as a sensitivity analysis, the
probability of Case 4 occurring is very low.
Case 5 - Restricted Capacity Refinery
The purpose of Case 5 runs was to study the impact of
the lead regulations during the time period when refinery
operations would be essentially restricted to present pro-
cessing capability. For this series of runs we established
the percent of crude capacity for the major downstream pro-
cessing units based on the 1973 refining data in the April 2,
1973 Oil and Gas Journal. These ratios were held constant
throughout the 1974 to 1976 period, which was considered the
time period during which no major deviation from current pro-
cessing flexibility could be achieved.
The major difference in the processing sequences cho-
sen in this case was the large reduction in hydrocracking
capacity with attendent increases in catalytic cracker feed
rate, conversion, and alky.lation production. It is signi-
ficant to note that by choosing high conversion catalytic
cracking (which produces higher octane gasoline) the optimum
refinery clear octane pool increased from 89,4 to 90.5.(case 1)
The optimum catalytic reforming severity increased from 91
to 92 clear research octane number at the same time. Thus
there was a substantial decrease in the optimum gasoline
lead content in these runs,
III-5
-------
We feel there is a definite trend towards a reduction
in optimum lead content in refinery gasoline pools due to the
following reasons: (1) higher catalytic cracked gasoline
octane numbers resulting from higher conversions,zeolite ca-
talyst operation and hydrogenation of catalytic cracker feed,
(2) improvements in reformer technology due to better cata-
lyst stability which allows lower operating pressures and
better yield/octane relationships, (3) ' a change in re-
forming economics due to increased value of by-products such
as hydrogen, fuel gas and C3/C4 concurrent with the curtailed
supply of natural gas.
There are essentially no penalties for either of the
lead regulations for Case 5.
Case 6 _ Reatricted Capacity Refinery
The purpose of Case 6 was to examine the impact of
lead regulations on the ability of refineries to maintain a
flexibility in changing product mixes due to seasonal swings
'in demands and specifications. This was the only case in
which we allowed variations in prime product demands and sea-
sonal specifications. Although we allowed overall gasoline
volume to vary, we maintained the same ratios between premium,
regular, and lead-free gasoline as for the other cases between
scenarios A, B, and C. We also maintained a constant dis-
tillate to low sulfur residual fuel oil ratio for all scenarios.
For summer operation we reduced the maximum gasoline RVP spe-
cification to 9.5 and increased the composite gasoline pro-
duct price 3$/gal. above the equilibrium values calculated
in Case 5. Distillate and fuel oil product netbacks were
used equivalent to those calculated in Case 5. We had ori-
ginally planned to reduce LPG production for summer operation
due to the historical seasonal decrease in demand for this
product. However, in the summer months of 1973 the average
refinery production of LPG actually increased to the upper
range of the historical average annual demands (due to natu-
ral gas supply curtailment). We would expect this situation
to continue so the summer LPg product demand was left at the
2.6-2.8 percent yield used for the annual average demand in
other cases.
Despite the reduced vapor pressure specification it
was possible to increase gasoline production above Case 5
results by increasing catalytic cracker intake (and sometimes
conversion). However the small gains realized indicated that
our case 5 refinery runs were essentially at maximum gasoline
production.
III-6
-------
For the winter operation we increased the allowable
maximum RVP to 12 and required a minimum LPG production at
the upper range of summer operation (2.8%). We increased
distillate and fuel oil refinery netbacks 3^/gal. above the
equilibrium values calculated in Case 5 and reduced gaso-
line prices accordingly.
In order to achieve the required LPG production (and
at the same time maintain maximum production of distillates/
residual fuel oil) it was necessary to significantly increase
the reforming severity to approximately 97 to 98 clear RON.
Then gasoline lead additions declined to an average of
1.0 grams per gallon or less. We feel that the refinery
LPG supply, demand, price relationships should be investi-
gated in more detail before firm conclusions are drawn from
this analysis but we believe it is directionally correct.
It is interesting to note that the refinery achieved about
a 12-13 percentage crude swing between maximum gasoline and
fuel products production. In no cases did the proposed lead-
free and reduced lead regulations appear to inhibit flexibi-
lity.
The energy penalty for this case is zero and the etude
penalty is also zero. Economic penalties were not calculated.
Case 7 - Actual Refinery
This case was only run for one year (1979) to test
the sensitivity of a lower percent premium versus regular
in the leaded gasoline grades. In general, this case in-
creased the cost of producing lead-free gasoline (because the
optimum clear octane pool in Case A is lower) without
significantly changing the energy impact. However, the econ-
omic summary shows that the cost penalty for the phase-down
is smaller for Case 7 than for Case 1. The comparison is
summarized below.
1979 Penalty
Case 1 Case 7
B-A C-B B-A C-B
A Crude I^B/CD)
42
35
26
75
A Total Gasoline
2.2
4.0
6.7
2.9
Cost (/l31il)
^5
A Net Energy Input
3b
75
26
(MB/CD)
III- 7
-------
Description of Summary Tables
Table III-l contains a summary of the crude intake requirements for
all cases. The total refinery crude intake for Scenario A is shown as
the base total crude. The A crude elements are derived from the changes
in total crude intake for B-A and C-B, respectively. These A crude
changes are then converted to a percent of total crude.
Table III-2 contains a summary of the energy balances for all
cases. All elements on this table are expressed in units of F.O.E.
liquid barrels. The base energy input consists of total
hydrocarbon raw materials plus purchased electric power, adjusted for
the energy content changes in by-product out-turn.
Table III-3 contains a summary of the economics for all cases.
The format for this table is somewhat different in that all column
elements are presented as A B-A or A C-B9 respectively. The total cost
values represent a composite of changes in cost of raw materials, by-
product credits, refinery operating expenses and capital charge. The
penalties in c/barrel are allocated to only the lead-free volumes for
the B-A cases, but are distributed over the entire gasoline pool for
C-B (lead phase-down).
Ill- 8
-------
TABLE III-1 SUMM&Sy - CRUDE INTAKE REQUIREMENTS MB/CD
Case
Base Total Crude
1 A Crude
Actual A Crude, % of A>B
1974
A B
13,532
0
0
1975
ABC
14,489
0 0
0 0
1976
ABC
15,362
0 14
0 .09
1977
ABC
16,303
16 45
.10 .28
1978
ABC
17,136
13 62
-08 .36
1979
ABC
18,245
42 35
.23 .19
1980
ABC
19,559
103 (20) •
.53 (.10)
Base
1 A Crude
Complex A Crude, % of A,B
13,493
0
0
14,460
0 0
0 0
15,375
(14) (29)
(.09) (.19)
16,303
20 (3)
.12 (.02)
17,134
31 105
.18 .61
18,248
73 (23)
.40 (.13)
19,565
48 9
.24 .04
Base
2 A Crude
Actual A Crude, % of A,B
13,533
CD
(.01)
14,490
CD 6
(.01) .04
. 15,362
15 14
.10 .09
16,303
48 44
.29 .27
17,136
67 18
.39 .10
18,245
67 86
.37 .47 .
19,559
117 18
.60 .09
Base
2 A Crude
Complex A Crude, % of A,B
15,378
39 38
.25 .25
18,248
128 (35)
.70 (.19)
Base
3 A Crude
Actual A Crude, % of A,>B
13,532
0
0
14,696
0 1
0 .01
15,847
0 19
0 .12
17,064
12 58
.07 .34
18,347
46 (109)
.25 (.59)
19,709
(41) 127
(.21) .65
21,247
101 34
.48 .16
Base
3 A Crude
Complex A Crude, % of A,B
15,907
(29) 28
(.18) .18
19,627
55 76
.28 .39
-
Base
4 A Crude
Actual A Crude, % of A,B
15,362
0 23
0 .15
18,245 '
10 151
t .05 .83
Base
4 A Crude
Complex A Crude, % of A»B
13,375
(38) 40
(.25) .26
18,248
3 100
.02 .55
Base
5 A Crude
Actual A Crude, % of A,B
13,517
0
0
14,496
6 0
.04 0
15,396
8 0
.05 0
6 Base
Actual A Crude
jummer & A Crude, % of A,B
Winter
14,005
0
0
14,706
0 0
0 0
15,460
0 0
0 0
Base
.7 A Crude
Actual A Crude, % of A,B
18,245
26 75
.14 .41
III-9
-------
TABLE III-2
SDMMABI ENERGY BALANCES
Case Energy Impact
MB/CD (6.3 MM BrU FOE)
1974
A B
12,977
0
0
1975
ABC
13,771
0 0
0 0
1976
ABC
14,483
0 12
0 .08
1977
ABC
15,246
13 27
.09 .18
1978
ABC
15,917
12 34
.08 .21
1979
ABC
16,823
34 75
.20 .45
1980
A. JL JL
17,806
69 44
.39 .25
1 Base Energy Input
Actual A Energy Input
A Energy Input, % of Base
1 Base Energy Input
Complex A Energy Input
A Energy Input, % of Base
13s051
3
.02
13,842
0 0
0 0
14,554
7 3
.05 .02
15,344
(34) <48)
(.22) (.31)
16,035
5 8
.03 .05
16,939
27 17
.16 .10
17,924 47 6
.26 .03
Base Energy Input
2 A Energy Input
Actual A Energy Input, % of Base
12,978
(1)
(.01)
13,772
(1) 5
(.01) .04
14,484
13 11
.09 .08
15,245
36 26
.24 .17
15,917
38 14
.24 .09
16,823
77 95
.46 .56
17,806 40 20
.22 .11
Base Energy Input
2 A Energy Input
Complex A Energy Input, I of Base
14,585
(27) 3
(.19) .02
16,941
27 46
.16 .27
Base Energy Input
3 A Energy Input
Actual A Energy Input, t of Base
12,976
0
0
13,956
0 1
0 .01
14,918
0 17
0 .11
15,928
11 32
.07 .20
17,009
28 (98)
.16 (.58)
18,139
(53) 112
(.29) .62
19,324 72 155
.37 .80
Base Energy Input
3 A Energy Input
Complex A Energy Input, % of Base
14,968
11 13
.07 .09
18,188
24 74
.13 .41
Base Energy Input
4 A Energy Input
Actual A Energy Input, % of Ease
14,483
0 18
0 .12
16,821
10 111
.06 .66
Base Energy Input
4 A Energy Input
Complex A Energy Input, % o£ Base
14,555
14 6
.10 .04
16,939
9 41
.05 .24
Base Energy Input
5 A Energy Input
Actual A Energy Input, Z of Base
13,104
0
0
13,890
6 0
,04 0
14,646
7 0
.05 0
Base Energy Input
7 A Energy Input
Actual i Energy Input, % of Base
16,823
26 45
.15 .27
III-10
-------
TABLE III-3 SUMMARY - ECONOMICS
Case
1974
B—A
1975
B-A C-B
1976
B-A C-B
1977
B-A C-B
1978
B—A C—B
1979
B-A C-B
1980
B-A C-B
1 Total Cost $MM/Day
Actual Gasoline Volume MMB/CD*
Penalty, c/Bbl.
(.03)
7.0
(0.4)
.01 0
1.1 7.3
.9 0
(.05) .02
2.3 7.6
(2.2) .3
(.06) .09
3.5 7.9
(1.7) 1.1
.06 .14
4.3 8.2
1.4 1.7
.12 .34
5.4 8.5
2.2 4.0
.33 .28
6.4 8.9
5.2 3.1
Total Cost $MM/Day
1 Gasoline Volume MMB/CD
Complex Penalty, c/Bbl.
(.08)
7.0
(1.1)
(.01) 0
1.1 7.3
(.9) 0
(.02) 0
2.3 7.6
(.9) 0
(.04) .08
3.5 7.9
(1.1) 1.0
.05 .13
4.3 8.2
1.2 1.6
.17 .33
5.4 8.5
3.1 3.9
.43 .24
6.4 8.9
6.7 2.7
Total Cost $MM/Day
2 Gasoline Volume MMB/CD
Actual Penalty, c/Bbl.
(.01)
7.0
(.1)
.07 .02
1.1 7.3
6.4 .3
.13 .06
2.3 7.6
5.6 .8
.29 .11
3.5 7.9
8.3 1.4
.37 .26
4.3 8.2
8.6 3.2
.66 .44
5.4 8.5
12.2 5.2
1.11 • .35
6.4 8.9
17.3 3.9
Total Cost $MM/Day
2 Gasoline Volume MMB/CD
Complex Penalty, c/Bbl.
.10 .08
2.3 7.6
4.3 1.1
.77 .51
5.4 8.5
14.3 6.0
Total Cost $MM/Day
3 Gasoline Volume MMB/CD
Actual Penalty,
-------
C. Impact of Lead Phase-Down
The several cases discussed in Sections III A and III B were
designed to define the impact of lead phase-down regulations on refinery
crude oil consumption, refining energy consumption, refinery economics,
and refinery flexibility for maximizing either fuel oil or gasoline
production. These cases not only included the base case for which the
best estimates of gasoline growth, etc., were specified, but also
various parametric studies wherein several key assumptions were varied
to determine the effects of possible errors in these assumptions.
Finally, two types of refining simulation were evaluated. The "actual"
refinery represents a series of units typifying a single 100,000 B/D
refinery, i.e. one FCC Unit, one hydrocracker, etc., each feeding a
common stream. The "complex" refinery, by contrast, comprises a
plurality of FCC Units (one feeding sour gas oil and one feeding sweet
gas oil), a plurality of coking units, etc. Hence, the complex refinery
represents a different simulation of the U.S. refining industry, some
refineries of which feed sour gas oil to the FCC Unit, some feeding
sweet gas oil, etc. The purpose of the present subsection is to con-
sider all of these effects in order to determine the best projection
for the entire U.S. refining industry.
a. Refining Industry Crude Oil Consumption
Table III-l summarizes the crude oil penalties in the
entire refining industry due to lead phase-down, as abstracted
from Tables V~1 through ¥-11 and further summarized in Tables
V-12 through V-22. The Base Total Crude requirements of Table
III-l are the total imported and domestic crude requirements for
Scenario A meeting projected product demands for 1974 through
1980. The other entries represent incremental crude oil require-
ments due to lead-free gasoline and lead phase-down for Scenarios
B and C, respectively.
The trends shown in Table III-l are directionally as would
be expected; for example, increasing the octane of the lead-free
gasoline or increasing the rate of growth of gasoline demand
increase -the crude oil penalty. However, the lack of agreement
of the "complex" and the "actual" refinery and the lack of a
consistent trend with the parametric studies make relative
comparisons difficult. For example, selected entries from Table
III-l are as follows;
1978 C-B 1979 C-B
Case 1, Actual 62 35
Case 1, Complex 105 (23)
Case 2,' Actual 18 86
Case 3, Actual (109) 12 7
111-12
-------
Comparing each entry to Case 1, Actual, it is apparent that there
is no consistent trend between these studies. This probably reflects
a certain inadequacy in the refinery simulation; even though the
crude oil penalties are small as a percent of Base Total Crude
(see Table III-l), they are large enough to be of interest from
the point of view of energy policy making. It is felt that the
reasons for this variation can be corrected in subsequent studies.
It is apparent from these entries- of Table T.II-1, however,
that the maximum crude oil penalty in any given year is 151,000
B/CD which would be incurred under Case 4, However, a more
likely largest penalty is about 105,000 B/CD, reached in Case 1
in 1978. A more appropriate measure of crude penalty is obtained
by averaging the penalties over the years 1977-1980, for this
reduces the above-discussed variability. These averages, tabulated
below, should be recognized to exclude several years of zero
penalty, during 1974-1976 when the market penetration of lead-
free gasoline is small.
Case 1, Actual
Case 1, Complex
Case 2, Actual
Case 3, Actual
Average Crude Oil Penalty, 1977-1980
Scenario B-A Scenario C-B
44,000 B/CD 31,000 B/CD
43,000 B/CD 22,000 B/CD
75,000 B/CD 42,000 B/CD
30,000 B/CD 28,000 B/CD
The agreement between the "actual" and "complex" refinery
simulations is now quite good. Specifically, the penalty for
Scenario B relative to Scenario A is about 50,000 B/CD and for
Scenario C relative to Scenario B is about 30,000 B/CD. Based
upon the results of Case 1, the "complex" versus "actual" refinery
simulations are equivalent, so no further distinction between these
simulations is necessary. Raising the lead-free gasoline octane
to 93/85 RON/M0N (Case 2) will approximately double the crude oil
penalty relative to Case 1. Varying the rate of growth of gasoline
(Case 3) does not cause appreciable changes in crude oil penalty
relative to Case 1.
Case 4 (lower rate of introduction of lead-free gasoline)
and Case 7 (lower percentage premium in the total pool) of
Table T.II-1 could not be averaged in this fashion, because the
simulation was run only in 1979. By comparing the penalty of
Case 4 to that of Case 3, Actual, in 1979, it is apparent that
the average crude penalty could be as low as about 30,000 B/CD
for Case 4. Also, the average crude penalty will be less than
150,000 B/CD. However it would not be expected that the lead-
free gasoline percent of the pool would be as low as assumed for
111-13
-------
Case 4 in the light of announced automobile and petroleum Industry
plans. Hence, it is not important to define the Case 4 penalty
more precisely than 30-150 MB/CD. Case 7 penalties appear consis-
tent with those of Case 1, and can be taken to be equal to those
indicated above.
In examining the entries in Table III-l for the years
1974-1976, it can be seen that the average penalties are in the
range of zero to 5,000 B/CD. Hence, the average crude penalties
for all cases may be summarized as:
Case 1
Case 2
Case 3
Case 4
Case 5
Case 6
Case 7
Average Crude Penalty
1974-1976
Scenario B-A
0
5 MB/CD
0
(10 MB/CD)
5 MB/CD
0
Scenario C-B
5 MB/CD
5 MB/CD
5 MB/CD
10 MB/CD
0
0
1977-1980
Scenario B-A
44 MB/CD
75 MB/CD
30 MB/CD
10-50 MB/CD
Scenario C-B
27 MB/CD
1+2 MB/CD
28 MB/CD
30-150 MB/CD
25-50/MB/CD 30-75 MB/CD
In considering these penalties, it should be recognized
that it is difficult to simulate the refining industry within a
precision of 1% of crude run (170 MB/CD), and all of these
penalties are much smaller. However, it may be generally con-
cluded from this analysis that the crude oil penaltv in 1974-
.1976 will be essentially zero, due to the low market penetration
of lead-free gasoline. For the years 1977-1980 on an average,
the penalty will be 30 to 44 MB/CD due to the introduction of
lead-free gasoline (but increasing with higher lead-free gasoline
octane number), -with an additional penalty of approximately 28
MB/CD attributable to the lead phase-down regulation.
b. Refining Industry Energy Consumption (FEO Basis)
Refinery energy consumption for the cases considered
herein is tabulated in Tables V-33 through ¥-43. The Total Energy
Consumed identified in Table V-33, for example, is the summation
of purchased electrical power, refinery fuel consumed, and catalytic
cracking coke consumed. Also tabulated is ATEC,'the incremental
changes of total energy consumed for Scenario B relative to
Scenario A and for Scenario C relative to Scenario B. These
111-14
-------
increments represent the increased refinery energy consumption
for introducing lead-free gasoline (Scenario B) and the further
incremental energy consumption attributable to lead phase-down
regulations (Scenario C).
A preliminary survey of Tables V-33 through V-43 indicates
that, for all cases considered, the energy penalty is extremely
small, particularly considering the limits of accuracy of
projection. For example, in Table V-33, Case 1, Scenario B,
1980 (the largest entry in this case) has an indicated incremental
energy penalty of 34,000 B/CD, above a total base energy consump-
tion of 1,739,000 B/CD, or less than 2%. Furthermore, the
total refinery intake for this case is about 18,000,000 B/CD,
thus representing approximately 0.2% energy loss on total intake.
In addition, it should be noted that this represents a maximum
penalty for the single year of 1980. If the energy penalty is
averaged over the years 1974.through 1980 for Tables V-33, V-34,
V-35, and V-40 (for which entries are available for every year),
an estimate of the energy penalty through the remainder of the
decade is obtained:
Average Energy Consumption Penalty
(FOE Basis), 197^-1980
Case 1, Actual
Case 1, Complex
Case 2, Actual
Case 3, Actual
Scenario B
9,000 B/CD
10,000 B/CD
16,000 B/CD
10,000 B/CD
Scenario C
10,000 B/CD
15,000 B/CD
12,000 B/CD
15,000 B/CD
Furthermore, by comparing the energy penalties for the other cases
of Tables V-33 through V-43 to those for which averages are
reported above, it would appear that an approximate value of
10,000 to 20,000 B/CD would represent the average energy penalty
for all cases considered.
The primary conclusion from such an analysis is quite
clear: penalties from increased refinery energy consumption due
to lead phase-down are negligible. Specifically, the present
study has examined two widely different simulations of the
refining industry (actual vs. complex) and seven different cases
which vary lead-free pool octane, rate of growth of gasoline
demand, 'etc. In no case does the energy penalty exceed 60,000
B/CD, and it is highly likely that the average penalty over the
years 1974-1980 is from 10,000 to 20,000 B/CD. In the perspective
of total refinery intake, this energy penalty is no more significant
than refinery leakage and losses. It is perhaps 10% of the
savings achieved by lowering comfort levels in buildings by 2° F,
and is less than 10% of offshore California oil production. In
111-15
-------
short, increased refining industry energy consumption is not an
area of concern in making energy policy decisions regarding
lead phase-down regulations.
c. Total Refinery Energy Utilization
From an examination of Tables V-l through V-ll, it is
apparent that the crude penalties discussed earlier are misleading
because the production of lead-free gasoline also produces signifi-
cant quantities of increasingly valuable LPG as a natural by-
product of such refinery operation (see Section VI C for additional
discussion of the reasons for this). Hence, incremental crude
is consumed to produce a product which may be produced anyway
under Scenario A if LPG market pressures accelerate because of
diminishing natural gas supplies (see Section IV A for LPG market
assumptions). However, full credit cannot be taken for this
incremental LPG production because increased refinery energy was
required to produce it. Hence, in Table III-2, the base energy
input to the refinery was taken to be the total raw material
intake plus purchased power, thus representing the total energy
available when placed on an F.O.E. basis. This figure was then
adjusted by subtracting the LPG production of the refinery, on
an F.O.E. basis, which was the only remaining plot limit energy
variant from case to case within the Scenarios. The difference
in this energy input is also reported in Table III-2 for Scenario
B relative to Scenario A and for Scenario C relative to Scenario
B.
By comparing Table III-l and Table III-2, it is apparent
that much of the crude penalty is regained for many entries by
taking credit for LPG production. Because of variable levels of
butane purchases, however, some entries are higher than those of
Table III-l. The basic data from which Table III-2 was
abstracted is contained in Tables V-33 through V-43.
With the exception of Case 3C, 1980, the net energy
penalties shown in Table III-2 are generally well below 100,000 B/CD
(F.O.E. basis). Case 3C, 1980, is higher due to high butane
purchases with rapid gasoline growth (see Table V-3), markedly
increasing total refinery intake. From the point of view of
energy penalties, this case is artificially high, because butane
pricing made it desirable to buy butanes rather than produce them
within the refinery. It is likely that butanes could have been
produced at a much lower energy penalty than was incurred by out-
side purchases»
When the 1977 through 1980 net energy input penalties are
averaged in the same fashion as discussed under crude penalties,
the following summary statistics are obtained:
111-16
-------
Average Net Energy Input Penalty, 1977-1980
Scenario B-A Scenario C-B
Case 1, Actual 32 45
Case 1, Complex 11 . (4)
Case 2, Actual 48 39
Case 3, Actual 15 50
It is apparent that the entries in this table are more variable
than those of the average crude oil penalty. In general, the
lower range of numbers in this table are most likely to be
accurate measures of the energy penalty. Specifically, refer-
ence to Tables V-33, ¥-34 and V-35 indicate that little butanes
are purchased for the "actual" refinery, which differs from
normal refinery practice. However, in the "complex" refinery of
Table V-40, considerable butanes are purchased. Hence as the
refinery pool octane is increased from Scenarios A to B to C,
butanes are produced at increasing levels in the refinery which
should then back out purchased butanes. The net result, as
abstracted from Tables V-33 and V-40 for Case 1 becomes:
Actual Refinery, MB/CD Complex Refinery, MB/CD
1978 1978
Scenario B-A
C-B
B-A .
C-B
A Crude
12
55
28
93
A Purchased
Butanes
0
0
(23)
(92)
Net Intake
12
55
5
1
Since the "actual" refinery purchased no butanes, none could be
backed out. This leads to a large net intake for the actual
refinery, which translates into a net energy input penalty for
the actual refinery which does not have the proper credit for
backed out purchased butanes. Hence, all average net energy
input penalties for the actual refinery tabulated above are
expected to be excessively large, by probably 20 MB/CD.
Arguments based only on zero purchased butanes are
oversimplified. Other distortions of average net,energy input
penalty are due to upper limits on purchased butanes, allowable
ranges of LPG production, and other differences in "complex" and
"actual" refinery models discussed earlier. Although minor
refinements in the simulation will be included in Phase II of
111-17
-------
this study, it is highly likely that the net energy input penalty
for 92/84 RON/MON will be 10-20,000 B/CD for Scenario B relative
to A and 20-30,000 B/CD for Scenario C relative to B. For 93/85
RON/MON unleaded gasoline, Scenario B-A incurs a 20-30,000 B/CD
net energy input penalty and Scenario C-B also incurs a 20-30,000
B/CD penalty.
d. Refining Industry Cost and Construction
As stated previously, one of the objectives of this study
was to determine the effects of the various scenarios and cases on
capital investment, economic penalty (gasoline price) and the
construction industry. These results are described in some detail
in Section VI B. In general the results show:
e The new capital investment required by 1980 is about 8
billion dollars (1974 dollars) for all cases except Case
3 (7% gasoline growth) in which case it is 11.75 billion
dollars.
e The difference in capital investment between A, B and C
scenarios is small relative to the total new investment.
This actual investment delta is very sensitive to
parameter variation, and warrants further study in Phase
II. However, the conclusion that the delta is small is
not sensitive to parameter variation.
® The different lead regulation scenarios, B and C, have
essentially the same new construction requirements and
differences between them.are far outweighed by the
construction requirement for new refining capacity.
• The economic penalty is small for all cases and scenarios,
but it is also reasonably sensitive to octane number and
gasoline growth. The penalty for Case 1 has a maximum of
4.0^/Bbl (C-B). If the gasoline growth rate increases
from 4% (Case 1) to 7% (Case 3), the maximum penalty
becomes 5.7^/Bbl (C-B). If on the other hand the octane
number increases from 92/84 to 93/85 RON/MON the
maximum penalty (C-B) becomes 5.2c/Bbl. Similarly, the
high octane case also has a relatively larger economic
penalty for B-A of 12.5c/Bbl.
e. Refinery Flexibility
Studies of refinery flexibility were made by fixing
individual unit capacities at the U.S. average levels (see Section
IV A) during the years 1974-1976. Then, gasoline specifications
were set at either summer or winter levels, and the refinery model
was run at adjusted gasoline and fuel oil prices to maximize gasoline
111-18
-------
in the summer and fuel oil in the winter (see Case 6, Section III B) .
Maximum purchased isobutane availability and normal butane availa-
bility were set at 112 MB/CD, 110 MB/CD, and 108 MB/CD for 1974,
1975, and 1976, respectively. Allowable ranges of LPG production
in the summer were 364 to 392 MB/CD, 382 to 412 MB/CD, and 402
to 433 MB/CD for 1974, 1975 and 1976, respectively. For the
winter, a minimum allowable production level was set at 392 MB/CD,
412 MB/CD and 433 MB/CD for 1974, 1975 and 1976 respectively. All
other products, such as petrochemical feedstocks and various jet
fuels, were held fixed at levels identified in Section IV A.
Assessments of flexibility for producing either fuel oil
or gasoline may be made by comparing the several scenarios within
a given year in Tables V-6, V-17 and V-38.
The primary conclusions of the study are obtained by
comparing, in Table V-6, the Subtotal Gasoline entries between
the scenarios for each year and the Distillate plus fuel oil
entries between the scenarios. It is apparent that no,loss in
flexibility to maximize either gasoline or fuel oil can be associated
with either lead-free gasoline introduction (Scenario B) or with
lead phase-down (Scenario C). The slight increase in gasoline
production with lead phase-down is discussed in Section VI C.
Because of product pricing assumptions, the LPG production in the
summer and winter were at the minimum allowable levels. In the
summer, the purchased butanes were diminished with lead phase-
down, due to the increased refinery butane production associated
with higher gasoline pool octane (shown on Table V-17). Additional
implications of this high pool octane are contained in Section
VI. C.
Because the refining unit capacities (on percent of
crude) were fixed, no difference in capital charges for the
several scenarios with a given year are observed. Differences in
operating costs are attributable to lead savings between Scenarios
B and C and to higher pool octanes between Scenarios B and A.
Total energy consumption (refinery fuel, purchased electrical
power, and catalytic cracking coke) is shown in Table V-38. Incre-
mental energy consumption between Scenarios B and A are negligibly
small (less than 2,000 B/CD) in these flexibility studies. Energy
consumptions for Scenarios C versus B are also very small, reaching
a maximum of 22,000 B/CD only in the summer of 1976.
f. Petrochemical Feedstocks and Other Products
Numerous other refinery products are of importance in the
U.S. refining industry simulation, notably petrochemical feedstocks
but also naphtha jet and various specialty products. These were
fixed at projected market demands, and were met for all scenarios
111-19
-------
and all cases evaluated In this study. Thus, they were effec-
tively given a priority allocation among refinery products. The
specific product rates for other refinery products are reported
in Table I.V-1 and are discussed in the accompanying text. In
comparing the entries of Table IV-1 to Tables V-l through V-43,
however, it is important to note that the product streams are
split slightly differently in these two sets of tables. As
described in the text accompanying Table IV-1, these two entries
are consistent and may be readily translated from one to the
other. These distinctions were made to allow different inter-
ested parties to interpret the results on either basis, since these
product outturns are constant for all cases.
111-20
-------
I? Model Considerations
INPUT DATA
Crude Supply and Product Demands
The refinery raw material and product slates assumed for each
year in Case 1, Scenario A are shown in Table IV-1. For other
cases, the crude and product slates will vary (e.g. 7%
growth in gasoline In Case 3). In all the studies, the
domestic crudes and the imported sweet crude were fixed.
Imported sour crude and purchased iso and normal butanes
(with specified maximum volumes) were varied as required
to meet product demands and specifications. All product
demands were fixed in accordance with Table IV-1 (with
adjustments for the various cases), except the total LPG and
the low sulfur fuel oil produced were allowed to vary within
ranges, since their markets are primarily supplied by sources
other than domestic refining. However, no appreciable varia-
tion was observed in the low sulfur fuel oil production in
actual computer runs,
The domestic crude production estimated by the F.E.O. was
8974 MB/CD; however, historical levels from B.O.M. data are
9491 MB/CD (1972) and 9235 MB/CD (1973). Hence, to reflect
additional incentives to domestic exploration, a domestic
crude production of about 9250 MB/CD was used for years
1974-1980. Imported crude then made -up the difference be-
tween the total, crude requirements and domestic production,
with primary growth taking place in imported sour crude
(imported sweet crude level increased from 1680 MB/CD in
1974 to 2100 MB/CD in 1980). Total crude requirements were
determined from total product demand projections, discussed
below. Natural gasoline available to the refinery was
estimated to be 490 MB/CD in 1974. This was based on 1972
B.O.M. data of 450 MB/CD, which was increased slightly for
1974 to reflect increased production incentives. The avail-
able natural gasoline was gradually reduced to 382 MB/CD in
1980 to reflect its expected diminishing production . Pur-
chased natural gas for refinery fuel, based on 1972 B.O.M.
figures, was 478 MB/CD; this was increased to 490 MB/CD in
1974 and then reduced each year reaching zero in 1980. Total
purchased butanes were restricted to a maximum of 224 MB/CD
in 1974, and reduced to 190 MB/CD in 1980. These are consis-
tent with 1972 B.O.M. levels of 233 MB/CD and 1973 levels of
212 MB/CD. Note in Table IV-1, however, that Case 1 Sce-
nario A, did not require any external butane purchases.
IV-1
-------
TABLE IV-1
INPUT/OUTPUT SUMMARY - MB/CD
CASE 1: ACTUAL REFINERY - UNRESTRICTED CASES (SCENARIO A)
1.974
F.E.O.
ADL
Net
ADL
Estimates
Market
Import
Refinery
Est.
Est.
Product ion
1974
1975
1976
1977
1978
1979
1980
Basis For Estimates
Based on OGJ
Crude
Production
8,974
9,243
9,265
9,276
9,274
9,257
9,222
9,168
Held approximately fixed
Imports
4,289
5,224
6,086
7,029
7 ,879
9 s 023
10,391
Increased to balance crude oil requi
Total
13,532
14,489
15,362
16,303
17,136
18,245
19,559
Based
on total product estimate
Natural Gasoline
490
471
448
423
411
398
382
Purch. Refinery Fuel
490
441
387
325
257
181
0
Purch. Butanes
0
0
0
0
0
0
0
Purch.
as required up to 224 (1974)
to 190 (1980)
Total Gasoline Production
7,123
130
6,993
6,988
7,265
7,576
7,875
8,176
8,499
8,862
4%/yr.
growth from 1974 estimates
^Premium
2,801
2,765
2,953
3,140
3,360
3,580
3,801
*Regular
4,047
4,353
4,468
4,572
4,645
4,756
4,889
*Lead Free
140
147
155
163
171
163
172
Distillate to Fuel
3,283
400
2,883
2,887
3,059
3,246
3,430
3,647
3,864
4,100
6%/yr.
growth from 1974 estimates
Residual Fuel
3,186
1,950
ls236
1,260
1,588
1,794
2,050
2,159
2,478
2,846
15%/yr.
growth from 1974 estimates
to supplement U.S. natural gas
Keroje t
1,03d
170
868
768
782
797
827
843
858
874
2%/yr growth
Naphjet
381
24
357
250
250
250
250
250
250
250
Total Petrochem Feed
409
6
403
403
425
449
473
500
529
559
6%/yr.
growth
Distillate
180
191
202
214
227
241
255
BTX
140
147
155
163
171
181
191
LPG
83
88
93
99
104
110
117
*LPG - LPG to petrochera
281-312
281
294
309
324
342
360
380
5%/yr.
, growth on total LPG produced
Other Products
1,222
1,248
1,255
1,267
' 1,290
1,314
1,301
Special Naphthas
102
100
97
94
107
103
98
0 growth
Kerosene
210
221
216
212
223
217
210
0 growth
Lube Base Stocks
210
221
216
228
223
235
229
2%/yx.
. growth
Asphalt and Road Oil
490
500
510
521
531
542
554
2%/yr.
. growth
Coke
210
206
216
212
206
217
210
lX/yr.
. growth
Total Products
14,059
14,911
15,676
16,496
17,207
18,152
19,172
Summation of individual products
* Varies significantly from Scenario A to 3 to C
TV-2
-------
Total gasoline market demand In 1974 was estimated to be 7123
MB/CD. Based on Oil and Gas Journal Data, estimated 1974 Imports
(without embargo) were 130 MB/CD, requiring refining production of
about 7000 MB/CD, For Case 1, a growth rate of 4%/year in total gaso-
line was assumed. Case 3 is a parametric study in which this growth
rate is increased to 7%/year. Long term historical data on gasoline
growth indicate a 4% average annual increase, although recent data
(post 1970) after emission controls has been about 6%. We expect that
the effects of more efficient emission controls, gasoline pricing, and
consumer energy awareness will result in post-1974 growth rates of 4%/
year or less. As will be discussed later, energy penalties associated
with lead-free gasoline become more pronounced as the gasoline growth
rates are increased. Demand for individual gasoline grades is set by
combining the gasoline grade distribution shown on Table II-l with the
total gasoline production of Table IV-1.
Distillate used as fuel (in contrast to petrochemical feedstock)
is determined from the FEO 1974 market demand of 3283 MB/CD, and imports
of 400 MB/CD as reported by the Oil and Gas Journal. Growth of distil-
late is assumed to be 6%/year for all cases and all scenarios,, re-
flecting increased use of distillates in markets suffering natural gas
supply limitations. Maximum sulfur level of distillates products is
0.21 wt.
Residual fuel demand estimated by the FEO is 3186 MB/CD, and our
1974 import estimates based on Oil and Gas Journal 1973 data are 1950
MB/CD, resulting in required refinery production requirements of about
1250 MB/CD. The domestic residual fuel production for all cases and
all scenarios is projected to grow , at a level of 15%/year, reflecting
a larger market share at the expense of natural gas and reduced con-
version operations in U.S. refining. About 90% of the residual fuel
under this category is low-sulfur fuel oil, meeting a .5% sulfur
limitation.
Kerosene jet fuel demand in 1974 is estimated by FEO to be 1038
MB/CD, with imports of 170 MB/CD. This leads to a production require-
ment of 868 MB/CD for 1974. However, B.O.M. figures for 1972 are 680
MB/CD and for 1973 are 720 MB/CD. Hence, the FEO 1974 estimate of 868
MB/CD represents a 20% increase over 1973, which is not typical of in-
dustry estimates of 1974 consumption levels, even before jet fuel pri-
ority allocations. Hence, an estimate of 768 MB/CD was used for 1974,
representing a more reasonable 7% increase over 1973 production. Kero-
jet growth rate for the remaining years was estimated to be 2I/year,
which is lower than the recent historical growth rate of 5-6% and more
in line with airline traffic growth projections combined with more ef-
ficient fuel usage per passenger-mile.
The naphtha jet demand projections by the FEO in 1974 was 381
MB/CD, with 24 MB/CD of imports (Oil and Gas Journal), resulting in 357
MB/CD of refinery production estimated. By similar reasoning to kerojet
IV-3
-------
and because of domestic competition for petrochemical naphtha, our re-
finery output projection was set at 250 MB/CD, with any possible growth
in this market expected to be supplied by lower-grade imported naphtha.
We assumed a peace-time economy. 1973 domestic production was 180 MB/CD.
Total petrochemical feedstock demands in 1974 projected by the
FEO are 409 MB/CD, with import estimates of 6 MB/CD. Hence, the esti-
mated 1974 refinery production level is estimated to be 403 MB/CD.
Data for 1972 distillate to petrochemical feedstock from the B.O.M, was
143 MB/CD, whereas 1973 B.O.H. data show 171 MB/CD. Hence, 1974 esti-
mates of distillate to petrochemical feedstocks were taken to be 180
MB/CD. Internal estimates by ADL of BTX production, meeting all ben-
zene , toluene, and xylene demands are 111 MB/CD in 1972 and 130 MB/CD
in 1973. Thus, the 1974 estimate was taken to be 140 MB/CD. Also 1972
B.O.M. data shows 100 MB/CD of LPG for chemical use. Reflecting upon
increased demand of LPG for fuels, the difference between 403 MB/CD of
total petrochemical feedstock, and the 1974 estimates of BTX and petro-
chemical distillate production (totaling 320 MB/CD) would provide a
reasonable estimate of 83 MB/CD for LPG as a petrochemical feedstock
for 1974.
'Bureau of Mines data for winter of 1972 show about 2.6% of crude
run for LPG production. For the summer of 1973, LPG yield to crude was
2.8%, reflecting the high demand and price for LPG last summer. Hence,
the refinery was required to produce between 2.6 and 2.8% of LPG on an
annual basis (Case 6 required 2.8% minimum for winter operation). On
an annual basis, this corresponds to 364 to 395 MB/CD in 1974. In
Table IV-1 this range is reported as net refinery LPG production after
subtracting LPG allocated to petrochemical (83 MB/CD), or as 281 to 312
MB/CD. All petrochemical feedstocks are subjected to a projected growth
rate of 6%/year. Although the recent historical growth rate has' been
8%/year, most recent reports indicate this historic growth rate will
slow down (e.g. Chemical and Engineering News, March, 1974).
Other products from the refinery are also shown, and the 1974 re-
finery production estimates are based on B.O.M. data:
1972
1973
Special Naphthas.
"88"
9o-
Kerosene
216
217
Lube Base Stocks
195
204
Asphalt and Road Oil
446
480
Coke
183
185
Assumed growth patterns are shown on Table IV-1. The refinery simulation
used in this study does not attempt to meet any product specifications
on these specialty products, other than'normal boiling range targets.
IV-4
-------
The apparent discontinuities in the year to year product demands for
the specialty products is due to rounding of total U.S. production to a
modular 100 MB/CD composite refinery. The important point is that .pro-
duction levels within any given year are maintained absolutely constant
between scenarios A,B,C which is the purpose of this study.
Crude and Product Price Assumptions
The key element in these assumptions is our price projections for
delivered Arabian light crude oil. We feel that the U.S. Project
Independence will not be achieved over the next decade and that in fact
we (and the rest of the world) will largely depend on this particular
crude as the marginal supply source. We believe it is unrealistic to
insulate U.S. energy supply and associated economics from the rest of
the free world. Many other energy studies have used Arabian light
crude as the primary reference for setting world price parity levels
due to its large reserves, present high production volume and poten-
tial for increase in supply.
We used the following methodology to predict Arabian light crude
price. We assumed two potential scenarios might exist, each with a 50%
probability of occurrence. First is that the present price structure
will hold for 1974 escalated 4% per year, thereafter.. Second, we as-
sumed a drop in FOB price to $5.00 a barrel but that this price would
then escalate 6% per year. This resulted in a delivered Arabian light
crude price of $7.90 a barrel for 1974 which increases to $10.05 a bar-
rel in 1980. Most other raw material and product prices were estimated
based on these crude values.
In previous studies we have done extensive analyses of offshore
refining and transshipment of Arabian light crude oil for low sulfur
(.5%) residual fuel oil delivery to the U.S. market. Since this is the
most important and marginal source of supply for this product, we feel
it will set the competitive market price. These values range from $8.90
a barrel in 1974 to $11.65 a barrel in 1980. LPG refinery netback was
calculated to be on a heating value parity with the price level for low
sulfur residual fuel, adjusted for a"form value" premium. Estimated LPG
refinery netbacks varied from $6.11 per barrel in 1974 to $7.84 a barrel
in 1980. The purchase prices for iso and normal butane were assumed to
be consistent with LPG price (since in many cases they are interchange-
able) and we assumed refinery purchase prices to be 10
-------
Composite Refinery Structure
As described above, the crude slate for all runs was fixed in
source, with the imported sour being varied in quantity as required to
meet product demands. The following crudes were taken to represent the
re f ine ry inp ut:
Domestic Sweet — Louisiana
Domestic Sour — West Texas
Imported Sweet — Nigerian Medium
Imported Sour — Arabian Light
The quantity of domestic crude is shown in Table IV-1, and the ratio of
domestic sweet to domestic sour was fixed at 2/1.
This crude mix is felt to be. representative of future average U.S.
crude slates, and will probably represent PAD I and PAD III district
slates if additional low sulfur domestic crude is transported to the
East Coast for low sulfur fuel oil stocks. No attempt was made to in-
clude Alaskan crudes since they will not become a significant' market
factor until the end of the decade.
The refinery simulated had all of the major refinery units typically
present in large U.S. refineries. In some cases, the size of each unit
was selected to be optimum for the particular product slate under evalu-
ation (called unrestricted capacity cases). Since this selection of
unit capacities frequently deviated from the average U.S. unit capaci-
ties, other cases were run in which capacities were restricted to ave-
rage values listed in the Oil and Gas Journal (called restricted capa-
city cases). On the basis of 100 MB/CD of atmosphic distillation,
these capacities were restricted to a. maximum of:
Comparison of these numbers, when scaled up to total U.S. crude run, to
the refinery unit feed rates tabulated under Basic Data will indicate
the unit size in the simulation relative to the average U.S. unit size.
For the restricted capacity cases, hydrocracking and alkylation were
always limiting.
Catalytic Cracker
Catalytic Reformer
Alkylation
(Basis product)
Hydrocracking
32.2 MB/CD
26.6 MB/CD
5.8 MB/CD
6.2 MB/CD
IV-6
-------
MODEL VALIDATION AND CALIBRATION
There are two components to be considered In the validation of a
refinery model. First, there is the validation of the proper function-
ing of the Linear Program, the associated input/output pricing structure
(e.g. Arabian Light crude prices through 1980, LPG pricing through 1980,
etc.), and the associated product distribution through 1980. The func-
tioning of the L.P. and the pricing structure have been validated
through the large number of studies conducted by ADL for various
clients, described in part under "Crude and Product Price Assumptions".
Although projections or predictions of the future are always suspect,
the most reliable guide is knowledge and insight of the views of a wide
spectrum of clients concerned with energy supply and economics. Al-
though time constraints did not permit parametric studies of product
pricing assumptions, such studies could be used to further determine
the impact of such assumptions on the conclusions of the study. Ex-
tensive studies of the effect of various assumptions of product distri-
butions were made during the study (e.g. changes of rate of growth of
gasoline demand, gasoline grade distribution, etc.). Since the conclu-
sions of the study were not seriously affected by such assumptions, it
may be concluded that the model was quite satisfactorily validated in
this dimension.
Second, there is a necessity for validation of the structure and
behavior of basic refinery units. The basic yields, costs, and rela-
tionship to other units werechecked independently by consultants for
every unit in the refinery. In addition, parametric studies were con-
ducted by varying the allowable complexity of the refinery, (Actual vs.
Complex refinery). Also, parametric studies were conducted by compar-
ing unit sizes of processing units for a completely optimal configura-
tion versus sizes dictated by average capacities for the U.S. as re-
ported in the Oil and Gas Journal. Again, the penalties for low lead
gasoline in Case 5 versus Case 1, for example, are not significantly
different. However the capital investment is very sensitive to
parameter variation. This sensitivity will be further studied and
defined in Phase II.
It is desirable that additional parametric studies be conducted
to study the effects of further variation in unit capacity limitations,
petrochemical feedstock demand assumptions, pricing structure assump-
tions, crude slate assumptions, etc., particularly on capital invest-
ment.
Model calibration, in contrast to model validation, is necessary
to ensure that the model faithfully represents the U.S. refining in-
dustry in 1974. Obviously, many of the above-discussed validation
studies are important in that they indicate which types of calibration
IV-7
-------
errors are insignificant in their effect on the conclusions of the study.
In addition, it is important to determine if the catalytic cracker con-
version, the catalytic reformer severity, the gasoline pool octanes,
etc.. adequately represent the U.S. refinery performance. Since many
of these variables do not vary outside acceptable ranges within
Scenarios A» B, and C, it is unlikely that major effects on the conclu-
sions of the study will be found by improving this calibration (it may be
desirable to check this, however). One major concern in calibration is
the pool octane in 19 74, Scenario A, which is somewhat higher than other
estimates. However, it should be noted there is no completely satis-
factory method to measure the average clear pool octanes in the U.S.
today, and in fact the level can be adjusted merely by changing
reformer severity. The effect of error in this calibration should be
no greater than shown by Case 2 versus Case 1 (e.g. an additional
50,000 BPD of crude penalty).
However, in this regard, it is important to note that appropriate
model calibration does not mean that the 1974 model performance should
necessarily duplicate historical refining data, as implied for example
by Ethyl Corporation. First, Bureau of Mines data has shown fairly
significant change in such variables as gasoline EVP, lead level, etc.
during the last year, and some of these trends will likely continue into
1974. Second, significant changes in product values have taken place in
the last 6 months (e.g. fuel oil and LPG prices), and these price
changes will probably continue. This will have a pronounced effect on
the operation of the highly flexible and resourceful refining industry.
For example, enhanced market demand for LPG as a natural gas replace-
ment has led to high LPG pricing and high LPG production, particularly
in the summer of 1973. Increased LPG production as a percent of crude
will most likely come from higher severity reformer operation, high FCC
unit severity, and higher hydrocraclcing severity (or feed rates) . With
an economic incentive to produce LPG, it would therefore be highly
simplistic to assume the clear pool octane of gasoline will not increase
above 1972 levels in 1974. Specifically, high LPG production will
likely imply increased high clear octane reformate, high clear octane
alkylate from FCC olefins, and high reformer feed and yields from hydro-
cracker naphtha. To better quantify these effects, parametric studies
of LPG production need to be conducted to arrive at the proper refinery
calibration.
IV-8
-------
V. DETAILED DATA
This section contains detailed LP results of all the runs performed in
this study. There are four categories of tables. The first eleven
(V - 1 to V - 11) contain Basic Data for each run; the next eleven
(V - 12 to V - 22) are entitled Reduced Data;th'en the next ten tables
(V - 23 to V - 32) contain an Economic Summary; and, finally, the last
eleven tables (V - 33 to V - 43) contain Energy Balances. The last ten
pages of this section contain simplified refinery flow diagrams (Figs.
V - 1 to V - 10) for selected key cases.
The format used on the Basic Data tables is relatively straight forward
and is somewhat similar to that used in Table II-l (as discussed in the
Introduction Section). The material balance data presented as MB/CD
total U.S. were obtained by multiplying the LP results from the modular
composite refinery developed for each year by our estimate of total U.S.
product out-turn. This results in some minor discontinuity between
years for by-products production due to this rounding procedure. How-
ever, product out-turns were maintained absolutely constant within each
year between scenarios A, B, and C (except as noted for LPG and low-sul-
fur residual fuel oil) and this is the effect we were trying to measure
in this study.
Beneath the Total Product sums in the Basic Data tables, additional in-
formation is tabulated for each run. This includes refinery fuel con-
sumption (in fuel oil equivalent barrels of 6.3 M MBTU), purchased
electric power (refineries were not allowed to generate power), ave-
rage lead levels in premium and regular gasoline, and calculated opti*-
mum intakes to key refinery processing units. The operating cost pre-
sented includes purchased supplies, utilities, and operating/maintenance
labor. It does not include the cost of purchased or self-generated re-
finery fuel. The capital charge is derived by a 20% per year gross
margin of total invested capital to provide funds for depreciation, in-
come tax, and return on investment.
The format for the Reduced Data tables (V - 12. to V - 23 ) is readily
discernible. Near the bottom of the page, purchased electric power is
converted to a fuel oil equivalent as is catalyst coke consumed at
the catalytic cracking unit. These are then added to the total refinery
fuel consumption to create the total energy consumption in FOE bar-
rels .
On Table V - . 12. we have tabulated additional information at the bottom
of the table to assist in run interpretation. This includes the average
catalytic cracker conversion level for each case, the catalytic reformer
severity plus the gasoline pool clear research and motor octane numbers
for several key years. We have also tabulated at the bottom of this
table, our estimate of petrochemical supply distribution for each year.
V-l
-------
The Economic Summary tables adopt a somewhat different format. Here we
present delta scenario changes within any given year. Specifically
Scenario B minus Scenario A and Scenario C minus Scenario B, There are
essentially four elements involved in computing the overall economic
penalties. These include; Changes in raw material supply costs; Operat-
ing costs; Capital charge; and By-product revenue. The differential
elements for each case are tabulated on the economic .summary tables
and composited into a total cost. When this is divided by the volume
of the total gasoline pool, the penalty is expressed in cents /barrel.
Of course, one could arbitrarily reassign this penalty over selected
portions of the pool. At the bottom of this table is a tabulated in-
vestment summary for each case. Here the Case A-Total Cumulative Plant
Investments- are tabulated in constant 1974 dollars. The differential
in total plant investments for Scenario B and C are than shown under
the appropriate Delta columns.
The Energy-Balances (Table V - 33 to V - 43) adjust the basic material
balance barrel differentials to reflect the differential energy penal-
ties from comparing straight volume changes in intakes/production of
volatiles with high sulfur crude oil and low sulfur residual fuel oil
which all have different heating values. All intakes and energy out-
turn products (LPG, distillate, and residual fuel oil) were converted
to FOE barrels in this comparison. Near the bottom of the table,
the'delta TEC rows represent changes in the total energy consumed
between scenarios B - A and C - B respectively. At the very bottom of
.the table, the total energy input is determined by adding the total
changes in raw material in (Delta TBMI) purchase power (delta pP) and
LPG production.
V-2
-------
TABLE V-l
REFINERY- MATERIAL BALANCES MB/CD
CASE 1: ACTUAL REFINERY - DERESTRICTED CASES
PSlC DATA
1974
,
1975
1976
1977
1978
1979
1980
A
B
A
1
C
A
B
C
A
B
C
A
B
C
A
1*
£
A
B
£
Domestic Sweet Crude
6,162
6,162
6,177
6,177
6,177
8,184
6,184
6,184
6,183
6 3183
6,183
6,171
6,171
6,171
6,148
6,148
6,148
6,112
6,112
6,112
Domestic Sour Crude
3,081
3,081
3,088
3,088
3,088
3,092
3,092
3 >092
3,091
3 ?091
3,091
3,086
3,086
3,086
3,074
3,074
3,074
3,056
3 j056
3,056
Imported Sweet Crude
1,681
1,681
1,735
1,735
1,735
1,793
1,793
1,793
1,855
1,855
1,855
1,920
1,920
1,920
1,989
1,989
1,989
2,101
2,101
2,101
Imported Sour Crude
2,608
2,608
3,489
3,489
3,489
4,293
4,293
4,307
5,174
5,190
5,235
5,959
5,972
6,034
7,034
7,076
7,111
8,290
8,393
8,373
SUBTOTAL CRUDE
13,532
13,532
14,489
14,489.
14,489
15,362
15,362
15,376
16,303
16,319
16,364
17,136
17,149
17,211
18,245
18,287
18,322
19,559
19,662
19,642
Natural Gasoline
490
490
471
471
471
448
448
448
423
423
423
411
411
411
398
398
398
382
382
382
Purch. Refinery Fuel
490
490
441
441
441
387
387
387
325
325
325
257
257
257
181
. 181
181
-
-
-
Isobutane
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
98
-
-
95
Normal Butane
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
TOTAL INPUT
14,512
14,512
15,401
15,401
15,401
16,197
16,197
16,211
17,051
17,067
17,112
17,804
17,817
17,879
18,824
18,866
18,999
19,941
20,044
20,119
Premium Gasoline
2.
,801
2.
,590
2,
,765
2.
,471
2.
,471
2.
,953
2,118
2.
,118
3.
,140
1.
,725
1
,725
3.
,360
1.
,560
1.
,560
3;
,580
1;
,284
1:
,284
3.
,801
974
974
Regular Gasoline
4;
,047
3:
,908
4,
,353
3;
,706
3;
,706
4.
,468
3,185
3,
,185
4.
,572
2.
,685
2.
,685
4.
,645
2.
,297
2.
,297
4.
,756
1.
,863
1.
,863
4;
,889
1:
,509
1.
,509
Lead Free Gasoline
140
490
147
1.
,088
1;
,088
155
2,273
2
,273
163
3.
,465
3
,465
171
4.
,319
4.
,319
163
5.
,352
5;
,352
172
6.
,379
6.
,379
SUBTOTAL GASOLINE
6,
,988
6;
,988
7;
,265
7.
,265
7.
,265
7,
f 576
7,576
7.
,576
7:
,875
7.
,875
7.
,875
8.
,176
8.
,176
8;
,176
8.
,499
8;
,499
8;
,499
8.
,862
8.
,862
8 =
,862
BTX
140
140
147
147
147
155
155
155
163
163
163
171
171
171
181
181
iai
191
191
191
Naphtha
252
252
250
250
25Q
247
247
247
244
244
244
257
257
257
253
253
253
248
248
248
Kero Jet
868
868
882
882
882
897
897
£97
927
927
927
943
943
943
958
958
958
974
974
974
Kerosene
210
.210
221
221
221
216
216
216
212
212
212
223
223
223
217
217
217
210
210
210
Distillates
3;
,067
3,
,067
3,
,250
3
,250
3,
,250
3;
,448
3,448
3:
,448
3;
,644
3.
, 644
3,
,644
3,
,874
3,
,874
3.
,874
4.
,105
4;
,105
4,
,105
4
,355
4.
,355
4;
,355
High Sulfur Fuel
140
140
147
147
147
155
155
155
163
163
163
171
1/1
171
181
181
181
191
191
191
Lube Base Stocks
210
210
221
221
221
216
216
216
228
228
228
223
223
223
235
235
235
229
229
229
Asphalt
490
490
500
500
500
510
510
510
521
521
521
531
531
531
542
542
542
554
554
554
Coke
210
210
206
206
206
216
216
216
212
212
212
206
206
206
217
217
217
210
210
210
SUBTOTAL FIXED
12.
,575
12.
,575
13;
,089
13.
,089
13;
,089
13.
, 636
13,636
13;
,636
14;
,189
14;
,189
14.
,189
14.
,775
14:
,775
14,
,775
15;
,388
15.
,388
15;
,388
16,
,024
16.
,024
16:
,024
LPG
364
364
382
382
382
402
402
402
423
423
445
446
446
480
470
476
506
497
535
535
Low Sulfur Fuel
1.
,120
1
,120
1,
,441
1;
,441
1.
,441
1.
,639
1,639
1
,639
1
,887
1.
,887
1
,887
1.
,988
1
,988
I.
,988
2;
,297
2.
,297
2,
,297
2
,655
2.
,655
2;
,655
TOTAL PRODUCTS
14;
,059
14.
,059
14.
,912
14:
,912
14,
,912
15;
,677
15,677
15
,677
16.
,499
16.
,499
16
,521
17.
,209
17:
,209
17;
,243
18;
,155
18
,161
18.
„ 191
19
,176
19;
,214
19 ;
,214
Refinery Fuel Used
1,050
1,050
1,118
1,118
1,118
1,187
1,187
1,189
1,261
1,261
1,269
1,329
1,332
1,341
1,407
1,423
1,441
1,499
1,530
1,537
Purch. power - Mil KWH
63
63
67
67
67
71
71
71
75
75
75
80
80
80
83
84
82
88
89
88
Lead Level - premium
2.33
2.47
2.13
2.55
2.55
2.12
3.00
2.27
2.13
3.00
1-76
2.17
3.00
1.69
2.19
3.00
1.40
2,20
3.00
1.51
- Regular
1.46
1.43
1.44
1.61
1.61
1.48
1.88
1.82
1.52
2.24
1.80
1.56
2.69
1.70
1.67
3.00
1.32
1.84
3.00
1.96
- Pool (leaded)
1,82
1.84
1,71
" 1.99
1.99
1.73
2.33
2.00
1.77
2.54
1.78
1.82
2.82
1.70
1.89
3.00
1.35
2.00
3.00
1.78
- Bool (Total)
1.78
1.72
1.67
1.69
1.69
1.70
1.63
1.40
1.73
1.42
1.00
1.78
1.33
0.80
1.86
1.11
0.50
1.96
0.84
0.50
Intake - Cat Reform
3,732
3,732
3,871
3,871
3,871
4,029
4,029
4,000
4,216
4,160
4,105
4,390
4,364
4,275
4,617
4,609
4,400
4,861
4,811
4,700
Cat Crack
2,672
2,671
2,836
2,836
2,836
3,012
3,015
3,123
3,134
3,282
3,405
3,279
3,428
3,668
3,374
3,432
3,644
3,476
3,564
3,722
Hydro Crk
1,695
1,696
1,846
1,846
1,846
1,996
1,994
1,916
2,213
2,094
1,988
2,343
2,295
2,139
2,349
2,318
1,984
2,340
2,227
2,061
Coking
578
578
568
568
568
597
597
597
582
582
582
567
567
567
599
599
599-
579
579
579
Alky (Prod.)
646
646
681
681
681
724
724
748
750
784
843
782
816
893
807
872
1,038
831
" 961
1,050
R2 (MMSGFD)
1,604
1,605
1,846
1,847
1,847
2,093
2,092
1,982
2,431
2,263
2,061
2,671
2,547
2,285
2,756
2,568
2,025
2,850
2,473
2,200
Desulf (Naphtha)
3,357
3,357
3,606
3,606
3,606
3,847
3,845
3,856
4,090
4,103
4,124
4,291
4,301
4,328
4,606
4,624
4,660
4,960
5,004
5,012
(Gas Oil)
644
644
438
438
438
271
272
301
88
119
122
55
27
-
255
298
387
466
560
594
(VGQ)
373
371
527
527
527
682
683
793
796
947
1,072
970
1,075
1,317
1,193
1,136
1,289
1,534
1,474
1,547
Operating Cost $MK
7.10
7.07
7.80
7,81
7,81
8.64
8.59
8,49
9.54
9.37
9.19
10.46
10.26
10,04
11.50
11.17
10.84
12.71
12.20
12.02
Capital Charge $MH
10.49
10.49
11.92
11.92
11.92
13.47
13.47
13.47
15.16
15.13
15.15
16.84
16.90
16.94
18.72
18.81
18.62
20.84
20.94
20.85
Gasoline Grade Distribution - %:
- Premium
40
37
38
34
34
39
28
28
40
22
22
41
19
19
42
15
15
43
11
11
- Regular
58
56
60
51
51
59
42
42
58
34
34
57
28
28
56
22
22
55
17
17
- Lead Free
2
7
2
15
15
2
30
30
2
44
44
2
53
53
2
63
63
2
72
72
-------
TABLE V-2
REFINERY MATERIAL BALANCES MB/CD
CASS 2; ACTUAL REFINERY - 93/85 ROE/MDN LEAD 1
BASIC DATA
Domestic Sweet Crude
Domestic Sour Crude
Imported Sweet Crude
Imported Sour Crude
SUBTOTAL CRUDE
Natural Gasoline
Purch. Refinery Fuel
Isobutane
Normal Butane
TOTAL INPUT
1974
1975
1976
1977
A
B
A
-1
C
A
B
£
A
1
£
6,162
6,162
* 6,177
6,177
6,177
6,184
6,184
6,184
6,183
5,183
6,183
3,081
3,081
3,088
3,088
3,088
3,092
3,092
3,092
3,091
3,091
3,091
1,681
1,681
1,735
1,735
1,735
1,793
1,793
1,793
1,855
1,355
1,855
2,609
' 2,608
3,490
3,489
3,495
4,293
4,308
4,322
5,174
5,222
5,266
13,533
13,532
14,490
14,489
14,495
15,362
15,377
15,391
16,303
16,351
16,395
490
490
471
471
471
448
448
448
423
423
423
490
490
441
441
441
387
387
387
325
325
325
14,513
14,512
15,402
15,401
15,407
16,197
16,212
16,226
17,051
17,099
17,143
Premium Gasoline
2,801
2,591
2,765
2,471
2,471
2,953
2,118
2,118
3,140
1,725
1,725
Regular Gasoline
4,047
3,907
4,353
3,706
3,706
4,468
3,135
3,185
4,572
2,685
2,685
Lead Free Gasoline
140
490
147
1,088
1,088
155
2,273
2,273
163
3,465
3,465
SUBTOTAL GASOLINE
6,988
6,988
7,265
7,265
7,265
7,576
7,576
7,576
7,875
7,875
7,875
BTX
140
140
147
147
147
155
1-55
155
163
163
163
Naphtha
252
252
250
250
250
247
247
247
244
244
244
Xero Jet
868
868
882
882
882
897
897
897
927
927
927
Kerosene
210
210
221
221
221
216
216
216
212
212
212
Distillates
3,067
3,06/
3,250
3,250
3,250
3,448
3,448
3,448
3,644
3,644
3,644
High Sulfur Fuel
140
140
147
147
147
155
155
155
163
163
163
Lube Base Stocks
210
210
221
221
221
216
216
216
228
228
228
Asphalt
490
490
500
500
500
510
510
510
521
521
521
Coke
210
210
206
206
206
216
216
216
212
212
212
SUBTOTAL FIXED
12,575
12,575
13,089
13,089
13,089
13,636
13,636
13,636
14,189
14,189
14,189
LPG
364
364
382
382
382
402
402
402
423
434
456
Low Sulfur Fuel
1,120
1,120
1,441
1,441
1,441
1,639
1,639
1,639
1,887
1,887
1,887
TOTAL PRODUCTS
14,059 :
14,059
14,912
14,912
14,912
15,677
15,677
15,67?
16,499
16,510
16,532
Refinery Fuel Used
1,050
1,050
1,118
1,118
1,119
1,187
1,189
1,189
1,261
1,264
1,284
Purch. Power - Mil KWH
63
63
67
67
67
71
71
70
75
75
75
Lead Level - premium
2.33
2.58
2.13
2,88
2.59
2.16
3.00
£.58
2.18
3.00
1.62
- Regular
1.45
1.45
1.44
1.62
1.61
1.48
1.84
1.61
1.53
2.26
1.89
- Pool (Leaded)
1.81
1.90
1.71
2.12
2.00
1.75
2.30
2.00
1.79
2.55
1.78
- Pool (Totals
1* 77
1.77
1.6 7
1.81
1.70
1.71
1.61
1.40
1.76
1.43
1.00
Intake - Cat Reform
3,730
3,732
3,868
3,871
3,861
4,029
3,998
3,969
4,216
4,113
4,094
Cat Crack
2,681
2,671
2,846
2,836
2,877
3,012
3,132
3,241
3,134
3,446
3,360
Hydro Crk
1,688
1,696
1,838
1,846
1,816
1,996
1,909
1,829
2,213
1,972
2,009
Coking
578
578
568
568
568
597
597
597
582
582
582
Alky (Prod.)
647
647
684
681
691
724
751
776
750
828
887
H2 (MMSCFD)
1,592
1,605
1,832
1,847
1,813
2,093
1,973
1,849
2,431
2,060
2,024
Desulf (Naphtha)
3,358
3,357
3,606
3,606
3,609
3,845
3,856
' 3,865
4,090
4,121
4,134
(Gas Oil)
647
644
441
438
452
271
305
334
88
156
73
(VGC)
382
371
537
527
569
682
802
912
796
1,113
1,027
Operating Cost $MM
7.10
7.10
7.80
7.88
7.83
8.65
8.-63
8.54
9.56
9.46
9.29
Capital Charge $MM
10.49
10.49
11.92
11.92
11.93
13.47
13.47
13.48
15.16
15.15
15.19
Gasoline Grade" Distribution -
%:
- Premium
40
37
38
34
34
39
28
28
40
22
22
- Regular
58
56
60
51
51
59
42
42
58
34
34
- Lead Free
2
7
2
15
15
2
•30
30
2
44
44
V-4
OCTANE
1978
1979
1980
A
/ 1
C
A
1
£
A
. 1
£
171
6,171
6,171
6,148
6,148
6,148
6,112
6,112
6,112
,086
3,086
3,086
3,074
3,074
3,074
3,056
3,056
3,056
920
1,920
1,920
1,989
1,989
1,989
2,101
2,101
2,101
959
6,026
6,044
7,034
7,101
7,187
8,290
8,407
8,425
.136
17,203
17,221
18,245
18,312
18,398
19,559
19,676
19,694
411
411
411
398
398
398
382
382
382
257
257
257
181
181
181
-
-
-
-
-
55
-
60
93
-
95
95
,804
17,871
17,944
18,824
18,951
19,070
19,941
20,153
20,171
,360
1,560
1,560
3,580
1,284
1,284
3,801
974
974
,645
2,297
2,297
4,756
1,863
1,863
4,889
1,509
1,509
171
4,319
4,319
163
5,352
5,352
172
6,379
6,379
176
8,176
8,176
8,499
8,499
8,499
8,862
8,862
8,862
171
171
171
181
181
181-
191
191
191
257
257
257
253
253
253
248
248
248
943
943
943
958
958
958
974
974
974
223
223
223
217
217
217
210
210
210
,874
3,874
3,874
4,105
4,105
4,105
4,355
4,355
4,355
171
171
171
181
181
181
191
191
191
223
223
223
235
235
235
229
229
229
531
531
531
542
542
542
554
554
554
206
206
206
217
217
217
210
210
210
,775
14,775
14,775
15,388
15,388
15,388
16,024
16,024
16,024
446
478
480
470
506
506
497
535
535
988
1,988
1,988
2,297
2,297
2,297
2,655
2,655
2,655
,209
17,241
17,243
18,155
18,191
18,191
19,176
19,214
19,214
,329
1,337
1,347
1,407
1,429
1,459
1,499
1,539
1,555
80
79
79
83
83
81
88
86
88
2.21
3.00
1.55
2.22
3.00
1.42
2.24
3.00
1.41
1.56
2.72
1.80
1.67
3.00
1.30
1.85
3.00
2.02
1.83
2,83
1.70
1.91
3.00
1.35
2.02
3.00
1.78
1.79
1.34
0.80
1.87
1.11
0.50
1.98
0.84
0.50.,
4,390
4,275
4,140
4,617
4,468
4,237
4,861
'4,559
4,616
3,279
3,662
3,881
3,374
3,747
3,768
3,476
3,921
3,873
2,343
2,143
1,928
2,349
2,094
1,709
2,340
1,834
1,954
567
567
567
599
599
599
579
579
579
782
885
991
807
971
1,174
831
1,131
1,131
2,671
2,307
1,976
2,756
2,222
1,608
2,850
1,908
2,024
4,291
4,327
4,345
4,606
4,647
4,698
4,960
5,034
5,033
55
-
-
255
273
476
466
596
575
970
1,310
1,532
1,193
1,418
1,416
1,534
1,793
1,667
10.48
10.38
10.13
11.52
11.30
10.94
12.72
12.30
12.22
16.84
16.92
16.87
18.72
18.78
18.50
20.84
20.74
20.99
41
19
19
42
15
15
43
11
11
57
28
28
56
22
22
55
17
17
2
53
53
2
63
63
2
72
72
-------
TABLE V-3
REFINERY MATERIAL BALANCES MS /CD
CASE 3: ACTUAL REFINERY - 7% GROWTH GASOLINE DEMAND
BASIC DATA
Domestic Sweet Crude
Domestic Sour Crude
Imported Sweet Crude
Imported Sour Crude
SUBTOTAL CRUDE
Natural Gasoline
Purch. Refinery Fuel
Isobutane
Normal Butane
1974
1975
1976
1977
1978
A B
A
B
£ ¦
A
1
£
A
B
C
A
B
£
6,162 6,162
6,177
6,177
6 , 177
6,184
6,184
6,184
6,183
6,183
6,183
6,171
6,171
6,171
3,081 3,081
3,088
3,088
3,088
3,092
3,092
3,092
3,091
3,091
3,091
3,086
3,086
3,08b
1,681 1,681
1,735
1,735
1,735
1,793
1,793
1,793
1,855
1,855
1,855
1,920
1,920
1,920
2,608 2,608
3,696
3,696
3,697
4,778
4,778
4,797
5,935
5,947
6,005
7,170
7,216
7,107
13,532 13,532
14,696
14,696
14,697
15,847
15,847
15,866
17,064
17,076
17-* 134
18,347
14,393
18,284
490 490
471
471
471
448
448
448
423
423
423
411
411
411
490 490
441
441
441
387
387
387
325
325
325
257
257
257
TOTAL IHFUT
14
,512
14
,512
15.
00
o
15;
,608
15.
,609
16
,682
16
,682
16.
,701
17
,812
17
,824
17,
,882
19
,015
13;
,051
18.
,952
Premium Gasoline
2.
, 801
2.
,590
2
,838
2-
,544
2.
,544
3.
,123
2
,242
2
,242
3
,417
L
,871
1:
,871
3
,771
1.
,748
1.
, 748
Regular Gasoline
4.
,047
3.
,908
4
,471
3.
,794
3.
,794
4.
,731
3.
,370
3
,370
4
,979
2.
,929
2.
,929
5;
,194
2.
,572
2
,572
Lead Eree Gasoline
140
490
147
1,
,118
1.
.118
170
2.
,412
2.
,412
179
3
,775
3'
,775
189
4.
,834
4
,834
SUBTOTAL GASOLINE
6:
,988
6;
,988
7.
,456
7.
,456
7.
,456
8;
,024
8:
,024
8
,024
8
,575
8.
,575
8
,575
9,
,154
9,
,154
a
,154
BTX
140
140
147
147
147
155
155
155
163
163
163
171
171
171
Naphtha
252
252
250
250
250
24?
247
247
244
244
244
257
257
257
Kero Jet
868
868
882
882
882
897
897
897
927
927
927
943
943
943
Kerosene
210
210
221
221
221
216
216
216
212
212
212
223
223
223
Distillates
3.
,067
3.
,067
3
,250
3:
,250
3.
,250
3
,448
3.
,448
3.
,448
3.
,644
3,
,644
3;
,644
3.
,874
3.
,874
3.
,874
High Sulfur Fuel
140
140
147
147
147
155
155
155
163
163
163
171
171
171
Lube Base Stocks
210
210
221
221
221
216
216
216
228
228
228
223
223
223
Asphalt
490
490
500
500
500
510
510
510
521
521
521
531
531
531
Coke
210
210
206
206
206
216
216
216
212
212
212
206
206
206
SUBTOTAL FIXED
12,
• 575
12.
,575
13.
,280
13.
,280
13.
,280
14.
,084
14,
,084
14,
,084
14.
,789
14.
,789
14,
,789
15.
,753
15.
,753
15.
,753
LPG
364
364
382
382
382
402
402
402
423
423
456
464
480
480
Low Sulfur Fuel
1.
,120
1.
,120
1.
,441
1.
,441
I.
,441
1.
,639
1.
,639
I.
,639
1:
,887
1.
,887
1.
,887
2:
,160
2.
,160
1:
,988
TOTAL PRODUCTS
14s
,059
14:
,059
15,
,103
15-
,103
15;
,103
16.
,125
16,
,125
16,
,125
17.
,099
17:
,099
U;
,132
18;
,377
18;
,393
18.
,221
Refinery Fuel Used
1,
,050
1,
,050
1:
,141
1 ;
, 141
1,
,141
1,
,242
1.
,242
1:
,242
1.
,344
1:
,344
1:
,365
I,
,474
1:
,471
1:
,488
Purch. Power - Mil KWH
63
63
68
63
68
74
74
74
80
80
80
91
89
88
Lead Level - Premium
2.33
2.47
2.11
2.53
2.46
2.06
2.95
2.19
2.03
3.00
1.44
2.12
3.00
1.34
- Regular
- 1.46
1.43
1.44
1.61
1.60
1.4 7
1.86
1.69
1.50
2.22
1.77
1.61
2.77
1.63
- Pool (Leaded)
1.82
1.84
1.70
1.98
1.95
1.70
2.30
1.89
1.72
2.52
1.64
1.82
2.86
1.51
- Pool (Total)
1.78
1.72
1.67
1.68
1.65
1.67
1-61
1.32
1.68
1.41
0.92
1.79
1.35
0.71
.Intake - Cat Reform
3,732
3,732
3,943
3,943
3,940
4,198
4,198
4,157
4,445
4,419
4,378
4,975
4,846
4,630
Cat Crack
2,672
2,671
2,956
2,955
2,965
3,295
3,295
3,443
3,633
3,726
3,674
3,468
3,806
3,962
Hydro Crk
1,695
1,696
1,844
1,844
1,837
1,993
1,993
1,885
2,156
2,087
2,096
2,880
2,597
2,348
Coking
578
578
568
568
568
597
597
597
582
582
582
567
567
567
Alky (Prod.)
646
646
709
709
710
787
787
821
864
885
962
826
902
1,077
U2 (MMSCFD)
1,604
1,605
1,882
1,884
1,877
2,180
2,180
2.019
2,504
2,395
2,302
3,530
3,128
2,690
Desulf (Naphtha)
3,357
3,357
3.661
3,661
3,661
3,973
3,973
3,986
4,292
4,300
4,321
4,579
4,609
4,601
(Gas Oil)
644
644
494
494
497
399
399
441
290
314
226
31
103
46
(VGO)
373
371
649
649
657
966
966
1,118
'1,303
1,396
1,342
1,113
1,478
1,611
Operating Cost $MM
7.10
7.07
7.96
7.97
7.96
9.03-
8.99
8.85
10.17-
10.01
9.80
11.62
11.36
10.97
Capital Charge $MM
10-49
10.49
12,16-
12.16
12.16
14.05:
14.05
14.05
16.09
16.09
16.14
18.70
18.64
18.43
Gasoline Grade Distribution -
%%
- Premium
40
37
38
34
34
39
- 2a ¦
28
40
22
22
41
19
19
- Regular
58
56
60
51
51
59
'42
42
58
34
34
57
28
28
- Lead Free
2
7
2
15
15
2
30
30
• 2
44
44
2
53
53
V-5
1979
1980
A
B
£
A
B
C
6,148
6,148
6,148
6 .112
6,112
6,112
3,074
3,074
3,074
3,056
3,056
3,056
1,989
1,989
1,989
2,101
2,101
2,101
8,498
8,457
8,584
9,978
10,079
10,113
19,709
L9,66d
19,795
21,247
21,348
21,382
338
398
398
382
382
382
181
181
181
-
-
-
-
-
-
-
-
95
-
-
-
-
-
95
20,288
20,247
20,374
21,629
21,730
21,954
4,123
1,483
1,483
4,507
1,146
1,146
5,479
2,134
2,134
5,787
1,795
1,795
181
6,166
0,16b
210
7,563
7,563
9,783
9,783
9,783
10,504
10,504
10,504
181
181
181
191
191
191
253
253
253
248
248
248
958
958
953
974
974
974
217
217
217
210
210
210
4,105
4,105
4,105
4,355
4,355
4,355
131
181
131
191
191
191
235
235
235
229
229
229
542
542
542
554
554
554
217
217
217
210
210
210
16,6 72
16,672
16,672
17,666
17,666
17,666
473
506
506 •
497
535
535
2,392
2,297
2,297
2,655
2,655
2,655
19,537
19,475
19,475
20,818
20,856
20,856
1,582
1,604
1,649
- 1,717
1,761
1*795
94
96
95
101
104
102
2.04
3.00
l.ld
2.04
3.00
1.40
1.72
3.00
1.17
1.81
3.00
1.58
1.86
3.00
1.17
1.91
3.00
1.51
1.82
1.11
0.43
1.87
0.84
0.42
5,038
5,110
4,958
5,338
5,437
5,306
4,199
4,092
3,808
4,653
4,423
4,169
2,606
2,720
2,443
2,632
2,743
2,521
599
599
599
579
579
579
996
1,042
1,244
1,098
1,192
1,358
3,394
3,351
2,772
3,686
3,514
3,058
4,971
4,962
5,023
5,378
5,413
5,443
-
49
373
246
414
686
2,123
1,854
1,495 '
2,842
2,368
2,002
,12.99
12.63
12.20'
. 14.64
14.12
13.78
21.00 .
21.12
20.88 .
23.84
24.06
23.73
42
15
15
43
11
11
56
22
22
55
17
17
2
63
63
2
72
72
-------
TABLE V-4 REFINERY MATERIAL BALANCES MB/CD
CASE 4; ACTUAL REFINERY - REDUCED LEAD FREE DEMANDS
ASIC DATA
1976
1979
A
B_
C
A
1
C
Domestic Sweet Crude
6,184
6,184
6,184
6,148
6,148
6,148
Domestic Sour Crude
3,092
3,092
3,092
3,074
3,074
3,074
Imported Sweet Crude
1,793
1,793
1,793
1,989
1,989
1,989
Imported Sour Crude
4,293
4,293
4,316
7,034
7,044
7,195
SUBTOTAL CRUDE
15,362
15,362
15,385
18,245
18,255
18,406
Natural Gasoline
448
448
448
398
398
398
Purch. Refinery Fuel
387
387
387
181
181
181
Isobutane
_
-
-
_
-
-
Normal Butane
_
-
-
_
-
-
TOTAL INPUT
16,197
16,197
16,220
18,824
18,834
18,985
Premium Gasoline
2,953
2,659
2,659
3,580
1,953
1,953
Regular Gasoline
4,468
3,402
3,402
4,756
2,640
2,640
Lead Free Gasoline
155
1,515
1,515
163
3,906
3,906
SUBTOTAL GASOLINE
7,576
7,576
7,576
8,499
8,499
8,499
BTX
155
155
155
181
181
181
Naphtha
247
247
247
253
253
253
Kero Jet
897
897
897
958
958
958
Kerosene
216
216
216
217
217
217
Distillates
3,448
3,448
3,448
4,105
4,105
4,105
High Sulfur Fuel
155
155
155
181
181
181
Lube Base Stocks
216
216
216
235
235
235
Asphalt
510
510
510
542
542
542
Coke
216
216
216
217
217
217
SUBTOTAL, FIXED
13,636
13,636
13,636
15,388
15,388
15,388
LPG '
402
402
402
470
470
506
Low Sulfur Fuel
1,639
1,639
1,639
2,297
2,297
2,297
TOTAL PRODUCTS
15,677
15,677
15,677
18,155
18,155
18,191
Refinery Fuel Used
1,187
1,187
1,189
1,407
1,409
1,456
Purchase Power - Mil KWH 71
71
70
83
84
83
Lead Level - Premium
2.12
2.79
1.77
2.19
3.00
.74
- Regular
1.48
1.81
1.73
1.67
2.60
1.06
-Pool (Leaded)
1.73
2.24
1,75
1.89
2,77
0.92
-Pool (Total)
1.70
1.79
1.40
1.86
1.50
0.50
Intake - Cat Reform
4,029
4,029
3,981
4,617
4,595
4,467
Cat Crack
3,012
3,012
3,193
3,374
3,481
3,409
Hydro Crk
1,996
1,996
1,865
2,349
2,311
2,061
Coking
597
597
597 •
599
599
599
Alky (Prod.)
724
724
765
807
830
1,038
H2 (MMSCFD)
2,093
2,093
1,917
2,756
2,664
2,092
Desulf (Naphtha)
3,845
3,845
3,861
4,606
4,611
4,678
(Gas Oil)
271
271
322
255
237
474
(VGO)
682
682
864
1,193
1,271
870
Operating Cost $MM
8.64
8.70'
8.52
11.50
11.32
10.89
Capital Charge $MM
13.47
13.47
13.48
18.72
18.76
18.69
Gasoline Grade Distribution -
%:
-Premium
39
35
35
42
23
23
-Regular
59
45
45
56
31
31
-Lead Free
2
20
20
2
46
46
V-6
-------
TABLE V-5 REFINERY MATERIAL BALANCES MB/CD
CASE 5: ACTUAL REFINERY - RESTRICTED REFINING CAPACITY
\
5ASIC DATA
1974
1975
1976
A
B
A
B_
C.
A
B
C
Domestic Sweet Crude
6,162
6,162
6,177
6,177
6,177
6,184
6,184
6,184
Domestic Sour Crude
3,081
3,081
3,088
3,088
3,088
3,092
3,092
3,092
Imported Sweet Crude
1,681
1,681
1,735
1,735
1,735
1,793
1,793
1,793
Imported Sour Crude
2,593
2,593
3,496
3,502
3,502
4,327
4,335
4,335
SUBTOTAL CRUDE
13,517
13,517
14,496
14,502
14,502
15,396
15,404
15,404
Natural Gasoline
490
490
471
471
471
448
448
448
Purch. Refinery Fuel
490
490
441
441
441
387
387
387
Isobutaae
112
112
110
110
110
108
108
108
Normal Butane
112
112
110
110
110
108
108
108
TOTAL INPUT
14,721
14,721
15,628
15,634
15,634
16,447
16,455
16,455
BTX
140
140
147
147
147
155
155
155
Naphtha
252
252
250
250
250
247
247
247
Kero Jet
868
868
882
882
882
897
897
897
Kerosene
210
210
221
221
221
216
216
216
High Sulfur Fuel
140
140
147
147
147
155
155
155
Lube Base Stocks
210
210
. 221
221
221
216
216
216
Asphalt
490
490
X 500
500
500
510
510
510
Coke
210
210
206
206
206
216
216
216
SUBTOTAL FIXED
2,520
2,520
2,574
2,574
2,574
2,612
2,612
2,612
Premium Gasoline
2,801
2,590
2,765
2,471
2,471
2,953
2,118
2,118
Regular Gasoline
4,047
3,908
4,353
3,706
3,706
4,468
3,185
3,185
Lead Free Gasoline
14.0
490
147
1,088
1,088
155
2,273
2,273
SUBTOTAL GASOLINE
6,988
6,988
7,265
7,265
7,265
7,576
7,576
7,576
Distillates
3,067
3,067
3,250
3,250
3,250
3,448
3,448
3,448
Low Sulfur Fuel
1,120
1,120
1,441
1,441
1,441
1,6.39
1,639
1,639
LPS
364
364
382
382
382
402
402
402
TOTAL PRODUCTS
14,059
14,059
14,912
14,912
14,912
15,677
15,677
15,677
Refinery fuel Used
1,055
1,055
1,116
1,125 '
1,125
1,189
1,200
1,200
Purch, Power - Mil KWH
56
56
59
59
59
63
63
63
Lead Level - Premium
1.26
1.34
1.28
1.52
1.52
1.27
1.81
1.81
- Regular
1,37
1.32
1.23
1.39
1.39.
1.24
1,79
1.79
-Podl (Leaded)
1.33
1.33
1.45
1.44
1.4-4
1,25
1.80
1.80
-Pool (Total)
1.30
1.23
1.22
1.23
1.23
1.23
1.26
1.26
Intake - Cat Reform
3,252
3,251
3,362
3,393
3,393
3,482
3,530
3,530
Cat Crack
3,290
3,291
3,443
3,388
3,388
3,664
3,565
3,565
Hydro Crack
875:
875
928
925
925
983
980
980
Coking
578
578
568
568
568
597
597
597
Alky (Prod.)
812
812
853
853
853
897
897
897
h2 (MMSCFD)
535
531
650
627
627
772
741
741
Desulf (Naphtha)
3,427
3,427
3,665
3,546
3,546
3,916
3,953
3,953
(Gas Oil)
823
822
771
825
825
669
770
770
(VG0)
997
999
1,140
1,087
1,087
1,339
1,240
1,240
Operating Cost $MM
6,74
6.70
7.40
7.39
7.39
8.19
8.19
8.19
Capital Charge $MM
10.01
10.01
11.35
11.32
11.32
12.80
12.75
12.75
Gasoline Grade Distribution -
%:
-Premium
40
37
38
34
34
39
28
28
-Regular
58
56
60
51
51
59
42
42
-Lead Free
2
7
2
15
15
2
30
30
V-7
-------
TABLE V-6
REFINERY MATERIAL BALAKCES MB/CD
CASE 6: ACTUAL SEFIKERX - RESTRICTED CAPACITIES, FLEXIBILITY STUDIES
BASIC DATA.
1974
Domestic Sweet Crude 6,162
Domestic Sour Crude 3,081
Imported Sweet Crude 1,681
Imported Sour Crude 3,081
SUBTOTAL CRUDE 14,005
Natural Gasoline 490
Purch, Refinery Fuel 490
Isotmcane 112
Normal Butane 44
TOTAL INPUT 15,141
BTX 140
Naphtha 252
Kero Jet 868
Kerosene 210
High Sulfur Fuel 140
Lube Base Stocks 210
Asphalt 490
Coke 210
SUBTOTAL FIXED 2,520
Premium Gasoline 2,832
Regular Gasoline 4,106
Lead Free Gasoline 141
SUBTOTAL GASOLINE 7,079
Distillates 3,227
Low Sulfur Fuel 1,249
LPG 364
TOTAL PRODUCTS 14,435
B
6,162
3,081
1,681
3,081
14,005
490
490
112
45
15,142
140
252
868
210
140
210
490
210
2,520
2,830
3,751
496
7,077
3,230
1,249
364
14,440
SUMMER (9.5 RTO
1975
ABC
Lead Level - Premium
- Regular
- Pool (Leaded)
- Pool (Total)
6,177
3,088
1,735
3,706
14,706
471
441
' 56
76
15,750
147
250
882
221
147
221
500
206
2,574
2,819
4,452
149
7,420
3,255
1,369
382
15,000
6,177
3,088
1,735
3,706
14,706
471
441
110
73
15,801
147
250
882
221
147
221
500
206
2,574
2,805
3,469
1,107
7,381
3,318
1,396
382
15,051
Refinery Fuel Used 1,092 1,092
Purch, Power - Mil KWH 57 58
1,157 1,149
60 60
6,177
3,088
1,735
3,706
14,706
471
441
110
72
15,800
147
250
882
221
147
221
500
206
2,574
2,802
3,465
1,106
7,373
3,324
1,397
382
15,050
1,149
60
1.40 1.57
1.55 1.59
1.49 1.58
1.46 1.47
1.29 1.82 1.80
1.70 2.28 2.16
1.54 2.07 2:06"
1.51 1.76 1.70
1976
ABC
6,184 6,184 6,184
3,092 3,092 3,092
1,793 1,793 1,793
4,391 4,391 4,391
15,460 15,460 15,460
448 448 448
387 387 387
108 108 93
65 86 3
16,468 16,489 16,391
155
247
897
216
155
216
510
216
2,612
2,992
4,526
153
7,671
3,496
1,593
402
15,774
1,212
63
1.-2-9
1.84
1.62
1.59
155
247
897
216
155
216
510
216
2,612
2,342
3,033
2,304
7,679
3,434
1,565
402
15,692
155
247
897
216
155
216
510
216
2,612
2,364
3,061
2,325
7,750
3,312
1,509
402
15,585
1,212 1.
63
234
64
2.22 2.19
_2.74 1.85
2.51 2.00
1.76 1.40
Intake - Cat Reform
3,167
3,181
3,222
3,250
3,272
3,316
3,381
3,527
Cat Crack
3,650
3,651
3,796
3,819
3,822
4,040
4,035
3,981
Hydro Crk
894
894
941
952
952
994
1,007
1,002
Coking
578
578
568
568
568
597
597
597
Alky (Prod.)
812
812
853
853
853
897
897
897
H2 (MMSCFB)
664
655
800
791
777
931
900
799
Besulf (Naphtha)
3,559
3,559
3,750
3,750
3,750
3,969
3,969
3,969
(Gas Oil)
459
459
415
390.
388
289.
295
349
(VG0)
1,361
1,361
1,497
1,522
1,524
1,721
1,715
1,661
Operating Cost $MM
.03
.14
(-04)
.12
(.15)
Gasoline Grade Distribution -
%:
- Premium
'¦ 40
40
38
38
38
39
30
31
- Regular
58
53
60
47
47
59
40
39
- Lead Free
1 2
7
2
15
15
2
30
30
1974
1975
1976
A
B
A
B
C
A
B
C
6,162
6,162
6,177
6,177
6,177
6,184
6,184
6,184
3,081
3,081
3,088
3,088
3,088
3,092
3,092
3,092
1,681
-1,681
1,735
1,735
1,735
1,793
1,793
1,793
3,081
3,081
3,706
3,706
3,706
4,391
4,391
4,391
14,005
14,005 •
14,706
14,706
14,706
15,460
15,460
15,460
490
490
471
471
471
44S
44S
448
490
490
441
441
441
387
387
387
112
112
110
110
110
108
108
108
112
112
110
110
110
108
108
108
15,209
15,209
15,838
15,838
15,838
16,511
16,511
16,511
140
140
147
147
147
155
155
155
252
252
250
250
250
247
247
247
868
868
882
882
882
897
897
897
210
210
221
221
221
216
216
216
140
140
147
147
147
155
155
155
210
210
221
221
221
216
216
216
490
490
500
500
500
510
510
510
210
210
206
206
206
216
216
216
2,520
2,520
2,574
2,574
2,574
2,612
2,612
2,612
2,143
2,139
2,218
2,218
2,218
2,327
1,820
1,820
3,106
2,833
3,502
2,743
2,743
3,520
2,356
2,356
106
374
116
875
875
119
1,789
1,789
5,355
5,346
5,836
5,836
5,836
5,966
5,965
5,965
4,574
4,584
4,497
4,497
4,497
4,696
4,696
4,696
1,770
1,774
1,891
1,891
1,891
2,140
2,140
2,140
392
392
412
412
412
433
433
433
14,611
14,616
15,210
15,210
15,210
15,847
15;846
15,846
926
923
982
984
984
1,028
1,028
1,028
51
51
. 55
55
55
57
57
57
.49
.53
.58
.64
.64
.59
.82
.82
1.19
1.16
1.15
1.49
1.49
1.27
1.45
1.45
0.90
0.89
0.93 "
1.11
1.11
1.00
1.18
1.18
0.89
0.83
0.91
0.94
0.94
0.98
0.82
0.82
2,987
2,977
3,310
3,319
3,319
3,430
3,480
3,460
1,972
1,971
2,050
2,052
2,052
1,991
1,993
1,993
915.
915 -
937
938
938
986
986
986
578
578
568
568
568
597
597
597
458
427
472
481
481
478
487
487
440
444
515
504
504
589
580
•580
3,539
3,552
3,727
3,727
3,727
3,941
3,943
3,943
627
616
950
950
950
960
960
960
863
866
962
963
963
1,050
1,050
1,050
(-02)
.03
-
(.07)
-
40
40
38
38
38
39
31
31
58
53
60
47
47
59
39
39
2
7
2
15
15
2
30
30
-------
TABLE v-7 REFINERY MATERIAL BALANCES MB/CD
CASE 7: ACTUAL REFINERY - REDUCED PREMIUM DEMAND
BASIC DATA
A
Domestic Sweet Crude 6,148
Domestic Sour Crude 3,074
Imported Sweet Crude 1,989
Imported Sour Crude 7,034
SUBTOTAL CRUDE 18,245
Natural Gasoline 398
Purch. Refinery Fuel 181
Isobutane -
Normal butane
TOTAL INPUT 18,824
Premium Gasoline 2,550
Regular Gasoline 5,787
Lead Free Gasoline 163
SUBTOTAL GASOLINE 8,500
BTX 181
Naphtha 253
Kerojet 958
Kerosene 217
Distillates 4,105
High Sulfur Fuel 181
Lube Base Stocks 235
Asphalt 542
Coke 217
SUBTOTAL, FIXED 15,389
LPG 470
Low Sulfur Fuel 2,297
TOTAL PRODUCTS 18,156
Refinery Fuel Used 1,407
Purch. Power - Mil KWH 83
Lead Level - Premium 1.41
Regular 1.34
-P£>ol. (Le&d6d) 1.36
-Pool (Total) 1.34
Intake - Cat Reform 4,617
Cat Crack 3,374
Hydro Crk 2,349
Coking 599
Alky (Prod.) 807
H2 (MMSCFD) 2,756
Desulf (Naph) 4,606
(Gas Oil) 255
(VGO) 1,193
Operating Cost $MM 11.13
Capital Charge $MM 18.72
Gasoline Grade Distribution - °L\
- Premium 30
- Regular 68
- Lead Free 2
1979
B
C
6,148
6,148
3,074
3,074
1,989
1,989
7,060
7,135
18,271
18,346
398
398
181
181
18,850
18,925
1,013
1,013
2,134
2,134
5,353
5,353
8,500
8,500
181
181
253
253
958
958
217
217
4,105
4,105
181
181
235
235
542
542
217
217
15,389
15,389
470
506
2,297
2,297
18,156
18,192
1,423
1,439
85
85
3.00
1.45
3.00
1.30
3.00
1.35
1.11
0.50
4,665
4,599
3,313
3,452
2,409
2,282
599
599
841
926
2,691.
2,421
4,615
4,647
315
342
1,002
1,096
11.14
10.89
18.82
18.87
12
12
25.
25
63
63
V-9
-------
TABLE V-8
REFINERY MATERIAL BALANCES MB/CD
CASE 1: COMPLEX REFINERY - UNRESTRICTED CASES
1974
1975
1976
1977
1978
1979
1980
A
B
A
B
C
A
B
C
A
B
^ C
A
B
C
A
B
C
A
B
C
Domestic Sweet Crude
6,162
6,162
6,177
6,177
6,177
6,184
6,184
6,134
6,183
6,183
6,183
6,171
6 ,171
6,171
6,148
6,14b
b, 148
6,112
6,112
6,112
Domestic Sour Crude
3,081
3,081
3,088
3,088
3,088
3,092
3,092
3,092
3,091
3,091
3,091
3,086
3,08b
3,086
3,074
3,074
3,074
3,05b
3,056
3,056
Imported Sweet Crude
1,681
1,681
1,735
1,735
1,735
1,793
1,793
1,793
1,855
1,855
1,855
1,920
1,920
1,920
1,989
1,989
1,989
2,101
2,101
2,101
Imported Sour Crude
2,569
2,569
3,460
3,460
3,460
4,306
4,292
4,321
5,174
5,194
5,291
5,957
5,988
6,093
7,037
7,110
7,087
8,296
8,344
8,353
SUBTOTAL CRUDE
13,493
13,493
14,460
14,460
14,460
15,375
15,361
15,390
16,303
16,323
16,320
17,134
17,165
17,270
18,248
18,321
18,298
19,565
19,613
19,622
Natural Gasoline
490
490
471
471
471
448
448
448
423
423
423
411
411
411
398
3 98
398
382
382
382
purch. Refinery Fuel
490
490
441
441
441
387
387
387
325
325
325
25 7
257
257
181
lol
181
-
-
-
Isobutane
112
112
110
110
110
94
52
29
106
85
14
103
78
29
99
99
99
95
95
95
Normal Butane
61
66
47
47
47
7
78
66
58
-
-
96
88
-
91
35
99
95
95
95
TOTAL INPUT
14,646
14,651
15,530
15,530
15,530
16,312
16,327
16,321
17,215
17,156
17,182
18,001
17,999
17,967
19,01/
19,034
19,075
20,136
20,184
20,193
premium Gasoline
2,801
2,590
2,765
2,471
2,471
2,953
2,118
2,118
3,140
1,725
1,725
3,360
l,5b0
1,560
3,580
1,284
1,284
3,801
974
974
Regular Gasoline
4,047
3,908
4,353
3,706
3,706
4,468
3,185
3,185
4,572
2,685
2,685
4,645
2,297
2,297
4,756
1, 8b3
1,863
4,889
1,509
1,509
Lead Free Gasoline
140
490
147
1,088
1,088
155
2,273
2,273
163
3,465
3,465
171
4,319
4,319
lb3
5,352
5,352
172
6,379
6,379
SUBTOTAL GASOLINE
6,988
6,988
7,265
7,265
7,265
7,576
7,576
7,576
7,875
7,875
7,875
8,176
8,176
8,176
8,499
8,499
8,499
8,862
3,862
8,862
BTX
140
140
147
147
147
155
155
155
163
163
163
171
171
171
181
lol
181
191
191
191
Naphtha
252
252
250
250
250
247
247
247
244
244
244
257
257
257
253
253
253
248
248
248
Kero Jet
S68
868
882
882
882
897
897
897
927
927
927
943
943
943
958
958
958
9 74
974
974
Kerosene
210
210
221
221
221
216
216
216
212
212
212
223
223
223
217
217
217
210
210
210
Distillates
3,067
3,067
3,250
3,250
3,250
3,448
3,448
3,448
3,644
3,644
3,644
3,874
3,874
3-, 874
4,105
4,105
4,103
4,355
4,355
4,355
High Sulfur Fuel
140
140
147
147
147
155
155
155
lb3
163
163
171
171
171
181
181
181
191
191
191
Lube Base Stocks
210
210
221
221
221
216
216
216
228
228
223
223
223
223
235
235
235
229
229
229
Asphalt
490
490
500
500
500
510
510
510
521
521
521
531
531
531
542
542
542
554
554
554
Coke
210
210
206
206
206
216
216
216
212
212
212
20b
20b
206
217
2>17
217
210
210
210
SUBTOTAL FIXED
12,575
12,575
13,089
13,089
13,089
13,636
13,636
13,636
14,189
14,189
14,139
14,775
14,775
14,775
15,388
I 5,38o
15.388
16,024
16,024
16,024
LPG
364
364
382
382
382
402
402
402
423
423
423
446
44o
44 b
470
4/0
489
497
497
505
Low Sulfur Fuel
1,120
1,120
1,441
1,441
1,441
1,639
1,639
1,639
1,887
1,360
1,387
1,988
1,988
1,988
2,297
2.29/
2 , 2 L> 7
2,b55
2,655
2,b55
TOTAL PRODUCTS
14,059
14,059
14,912
14,912
14,912
15,677
15,677
15,677
16,499
lb,472
16,499
17,209
17,209
17,209
18,155
18,155
18,1/4
19,17b
19,176
19,184
Refinery Fuel Used
1,029
1,029
1,096
1,096
1,096
l,lb6
1,163
1,166
1,227
1,235
1,248
1,289
l,2 9o
1,315
1.36 7
1, 3b0
I ,4o 'i
1 ,461
1 ,482
1,509
Purch. Power - Mil KWH
58
58
62
62
62
66
65
ob
68
69
70
71
71
74
75
75
78
79
ol
83
Lead Level - Premium
1.83
1.77
2.03
2.40
2.40
2.12
2.93
2.49
2.03
3.00
1.71
1.83
3.00
1.52
2.05
3.00
1 .34
2.0/
3.00
1.42
- Regular
1.40
1.37
1.41
1.57
1.57
1.47
1.86
1.67
1.51
2.43
1.84
1.53
2.98
1.81
1 .b2
3.00
1.3b
1 -79
3.00
2.02
- Pool (Leaded
1.58
1.53
1.92
1.90
1.90
1.73
2.29
2.00
1.72
2.65
1.79
1.66
2.99
1.69
1.80
3.00
1.35
1.91
3.00
1.78
- Pool (Total)
1.54
1.42
1.62
1.62
1.62
1.69
1.60
1.40
1.69
1.49
1.00
1.62
1.41
0.80
1.77
1.11
0.50
1.88
0.84
0.50
Intake - Cat Reform
3,510
3,500
3,678
3,678
3,678
3,944
3,901
3,909
4,028
4,124
4,137
4,133
4,143
4,2 SO
4, 3o9
4, .10 7
4,418
4,588
4,553
4,597
Cat Crack
3,133
3,161
3,196
3,19o
3,196
3,199
3,272
3,309
3,50b
3,371
3, 4b4
3,7 o
3,812
3,754
3,814
4.110
4, lJi
3,90b
4,33/
4,425
Hydro Crk
1,127
1,105
1,216
1,216
1,216
l,3o4
1,302
1,306
1,240
1,331
1,37b
1,181
1.190
1,36b
1,224
1 , 1.0/
1 .2/8
1,220
1,129
1,192
Coking
578
578
568
568
568
597
597
597
582
582
582
5b7
567
56 7
599
599
5 99
579
579
579
Alky (Prod.)
758
765
772
772
772
775
792
801
848
815
333
915
922
910
cj-yq
1 .000
1.013
961
1,058
1,079
H2 (MMSCFD)
763
734
941
941
941
1,169
1,093
1,058
1,077
1,224
1,152
1,135
1,092
1.20/
1 .38 7
1 , 114
1 ,21 3
1 ,652
1,308
1,373
Desulf (Naphtha)
3,384
3,385
3,641
3,641
3,641
3,892
3,892
3,901
4,150
4,149
4,180
4. 3b 1
4,371
4,393
4. fib 7
4.700
4 ,u89
5.015
5,044
5,044
(Gas Oil)
860
864
900
900
900
1,022
1,010
99b
1,142
1,149
1,123
1,205
1,205
L,20^
L .25 i
I ,255
i ,22 1
1 .2o2
1,285
L ,232
(VGO)
839
867
891
891
891
870
943
980
1,173
1 ,036
1,131
1,539
J , 544
1 ,404
L ,911
2.05b
1 . oo3
2,422
2,523
2,466
Operating Cost $MM
6.84
6.77
7.59
7.58
7.58
8.42
8.35
8.28
9.20
9.13
8.96
10.01
9.93
9.77
11.07
10.82
10.71
12.28
11.94
11.92
Capital Charge $MM
11.31
11.30
12.83
12.83
12.83
14.51
14.47
14.53
16.13
16 .2b
16.43
17.86
17.94
1 b . 2 o
19.95
20.1 {5
20.41
22.33
22.62
22.85
Gasoline Grade Distribution -
%:
- Premium
40
37
38
34
34
39
28
28
40
22
22
41
19
19
42
15
15
43
11
11
- Regular
58
56
60
51
51
59
42
42
58
34
34
57
2S
28
56
22
22
55
17
17
- Lead Free
2
7
2
15
15
2
30
30
2
44
44
2
53
53
2
63
63
2
72
72
V-10
-------
TABLE V-9 REFINERY MATERIAL BALANCES MB/CD
CASE 2: COMPLEX EEFINER? 93/85 RON/MQN LEAD FREE OCTANE
ASIC DATA
1976
1979
A
B
C
A
C
Domestic Sweet Crude
6,184
6,184
6,184
6,148
6,148
6,148
Domestic Sour Crude
3,092
3,092
3,092
3,074
3,074
3,074
Imported Sweet Crude
1,793
1,793
1,793
1,989
1,989
1,989
Imported Sour Crude
4,309
4,348
4,386
7,037
7,165
7,130
SUBTOTAL CRUDE
15,378
15,417
15,455
18,248
18,376
18,341
Natural Gasoline
448
448
448
398
398
398
Purch. Refinery Fuel
387
387
387
181
181
181
Isobutane
92
49
_
99
56
99
Normal Butane
6
-
1
93
-
99
TOTAL INPUT
16,311
16,301
16,291
19,019
19,011
19,118
Premium Gasoline
2,953
2,118
2,118
3,580
1,284
1,284
Regular Gasoline
4,468
3,185
3,185
4,756
1,863
1,863
Lead Free Gasoline
155
2,273
2,273
163
5,352
5,352
SUBTOTAL GASOLINE
7,576
7,576
7,576
8,499
8,499
8,499
BIX
155
155
155
181
181
181
Naphtha
247
247
247
253
253
253
Kero Jet
897
897
897
958
958
958
Kerosene
216
216
216
217
217
217
Distillates
3,448
3,448
3,448
4,105
4,105
4,105
High Sulfur Fuel
155
155
155
181
181
181
Lube Base Stocks
216
216
216
235
235
235
Asphalt
510
510
510
542
542
542
Coke
216
216
216
217
217
217
SUBTOTAL FIXED
13,636
13,636
13,636
15,388
15,388
15,388
LPG
402
402
402 .
470
470
506
Low Sulfur Fuel
1,639
1,639
1,639
2,297
2,297
2,297
TOTAL PRODUCTS
15,677
15,677
15,677
18,155
18,155
18,191
Refinery Fuel Used
1,166
1,170
1,177
1,367
1,416
1,432
Purch. Power - Mil KWH
66
67
67
75
78
80
Lead Level - Premium
- Regular
- Pool (Leaded)
- Pool (Total)
Intake - Cat Reform
Cat Crack
Hydro Crk
Coking
Alky (Prod.)
02 (MMSCFD)
Deeulf (Naphtha)
(Gas Oil)
(VGO)
Operating Coat $MM
Capital Charge $MM
2.12
3.00
2.64
1.47
1.84
1.57
1.73
2,30
2.00
1.69
1.61
1.40
3,947
3,972
3,997
3,200
3,217
3,231
1,365
1,395
1,422.
597
597
597
775
779
782
1,167
1,175
1,163
3,893
3,902
3,915
1,020
1,008
997
872
887
903
8.43
8.45
8.39
14.52
14.60
14.68
2,05
3.00
1.35
1.62
3.00
1.35
1.80
3.00
1.35
1.77
1.11
0.50
4,362
4,457
4,465
3,830
4,031
4,163
1,212
1,322
1,336
599
599
599
935
978
1,040
1,367
1,353
1,260
4,669
4,703
4,700
1,253
1,210
1,208
1,922
1,863
1,816
11.07
11.10
10.94
19.94
20.48
20.68
Gasoline Grade Distribution - %:
- Premium
39
28
28
42
15
• 15
- Regular
59
42
42
56
22
22
- Lead Free
2
30
30
2
63
63
V-ll
-------
TABLE V-10 REFINERY MATERIAL BALANCES MB/CD
CASE 3: COMPLEX REFINERY 7% GROWTH GASOLINE DEMAND
ASIC DATA
1976
1979
A
B
C
A
B
C
Domestic Sweet Crude
6,184
6,184
6,184
6,148
6,148
6,148
Domestic Sour Crude
3,092
3,092
3,092
3,074
3,074
3,074
Imported Sweet Crude
1,793
1,793
1,793
1,989
1,989
1,989
Imported Sour Crude
4,838
4,.809
4,837
8,416
8,471
8,547
SUBTOTAL CRUDE
15,907
15,878
15,906
.19,627
19,682
19,758
Natural Gasoline
448
448
448
398
398
398
Purch. Refinery Fuel
387
387
387
181
181
181
Isobutane
-
56
14
99
88
99
Normal Butane
-
2
25
99
99
99
TOTAL INPUT
16,742
16,771
16,780
20,404
20,448
20,535
Premium Gasoline
3,123
2,242
2,242
4,123
1,483
1,483
Regular Gasoline
4,731
3,370
3,370
5,479
2,134
2,134
Lead Free Gasoline
170
2,412
2,412
181
6,166
6,166
SUBTOTAL GASOLINE
8,024
8,024
8,024
9,783
9,783
9,783
BTX
155
155
155
181
181
181
Naphtha
247
247
247
253
253
253
Kero Jet
897
897
897
958
958
958
Kerosene
216
216
216
217
217
217
Distillates
3,448
3,448
3,448
4,105
4,105
4,105
High Sulfur Fuel
155
155
155
181
181
181
Lube Base Stocks
216
216
216
235
235
235
Asphalt
510
510
510
542
542
542
Coke
216
216
216
217
217
217
SUBTOTAL FIXED
14,084
14,084
14,084
16,672
16,672
16,672
LPG
402
402
402
470
505
506
Low Sulfur Fuel
1,639
1,639
1,639
2,301
2,297
2,297
TOTAL PRODUCTS
16,125
16,125
16,125
19,443
19,474
19,475
Refinery Fuel Used
1,229
1,225
1,226
1,539
1,584
1,604
Purch. Power - Mil KWH
71
70
70
86
88
88
Lead Level - Premium
2.20
3.00
2.34
1.98
3.00
1.17
- Regular
1.48
1.86
1.59
1.65
3.00
1.18
- Pool (Leaded)
1.77
2.32
1.89
1.79
3.00
1,18
- Pool (Total)
1.73
1.62
1.32
1.76
1.11
0.43
Intake - Cat Reform
4,232
4,142
4,108
4,768
4,937
4,767
Cat Crack
3,242
3,389
3,519
4,617
4,228
4,512
Hydro Crk
1,685
1,560
1,501
1,526
1,747
1,463
Coking
597
597
597
599
599
599
Alky (Prod.)
785
821
852
. 1,125
1,143
1,302
H2 (MMSCFD)
1,636
1,480
1,357
2,107
2,246
1,770
Desulf (Naphtha)
4,014
4,015
4,023
5,007
5,016
5,058
(Gas Oil)
915
895
864
1,011
1,264
1,360
(VGO)
1,789
1,062
1,194
2,600
2,051
2,257
Operating Cost $MM
8.92
8.82
8.69
12.52
12.25
11.99
Capital Charge $MM
15.34
15.26
15.29
22.31
22,60
22.66
Gasoline Grade Distribution -
%:
-Premium
39
28
28
42
15
15
-Regular
59
42
42
56
22
22
-Lead Free
2
30
30
2
63
63
V-12
-------
TABLE V-ll
REFINERY MATERIAL BALANCES MB/CD
CASE 4: COMPLEX REFINERY
REDUCED
LEAD Fill DEMANDS
BASIC DATA
1976
1979
A
B
C
A
B
c
Domestic Sweet Crude
6,184
6,184
6,184
6,148
6,148
6,148
Domestic Sour Crude
3,092
3,092
3,092
3,074
3,074
3,074
Imported Sweet Crude
1,793
1,793
1,793
1,989
1,989
1,989
Imported Sour Crude
4,306
4,268
4,308
7,037
7,040
7,140
SUBTOTAL CRUDE
15,375
15,337
15,377
18,248
18,251
18,351
Hatural Gasoline
448
448
448
398
398
398
Pureh. Refinery Fuel
387
387
387
181
181
181
Isobutaae
94
108
108
99
99
44
Normal Butane
7
69
25
91
99
99
TOTAL INPUT
16,312
16,349
16,345
19,017
19,028
19,073
Premium Gasoline
2,953
2,659
2,659
3,580
1,953
1,953
Regular Gasoline
4,468
3,402
3,402
4,756
2,640
2,640
Lead Free Gasoline
155
1,515
1,515
163
3,906
3,906
SUBTOTAL GASOLINE
7,576
7,576
7,576
8,499
8,499
8,499
BTX
155
155
155
181
181
181
Naphtha
247
247
247
253
253
253
Kero Jet
897
897
897
958
958
958
Kerosene
216
216
216
217
217
217
Distillates
3,448
3,448
3,448
4,105
4,105
4,105
High Sulfur Fuel
155
155
155
181
181
181
Lube Base Stocks
216
216
216
235
235
235
Asphalt
510
510
510
542
542
542
Coke
216
216
216
217
217
217
SUBTOTAL FIXED
13,636
13,636
13,636
15,388
15,388
15,388
LPG
402
402
402
470
470
503
Low Sulfur Fuel
1,639
1,639
1,639
2,297
2,297
2,297
TOTAL PRODUCTS
15,677
15,677
15,677
18,155
18,155
18,188
Refinery Fuel Used
1,166
1,158
1,164
1,367
1,371
1,412
Purch, Power - Mil KWH
66
64
65
75
75
80
Lead Level - Premium
2.12
2.61
1.87
2.05
3.00
.64
- Regular
1.47
1.78
1.66
1.62
2.89
1.13
- Pool (Leaded)
1.73
2.14
1.75
1.80
2.94
0.92
- Pool (Total)
1.69
1.72
1.40
1.77
1.59
0.50
Intake - Cat Reform
3,944
3,827
3,839
4,369
4,344
4,488
Cat Crack
3,199
3,394
3,443
3,814
3,873
4,103
Hydro Crk
1,364
1,197
1,206
1,224
1,183
1,372
Coking
597
597
597
599
599
599
Alky (Prod.)
775
823
833
929
944
993
li2 CMMSCFD)
1,169
962
965
1,387
1,318
1,336
Desulf (Naphtha)
3,892
3,890
3,902
4,667
4,673'
4,698
(Gas Oil)
1,022
991
972
1,253
1,255
1,219
(VGO)
870
1,067
1,118
1,911
1,953
1,788
Operating Cost $MM
8.42
8.40
8.29
11.07
10.96
10.82
Capital Charge $MM
14,51
14.40
14.49
19.95
19.96
20.61
Gasoline Grade Distribution - %
.
- Premium
39
35
35
42
23
23
- Regular
59
45
45
56
31
31
- Lead Free
2
20
20
2
46
46
V-13
-------
TABLE V-12
RSFIKERY MATERIAL BALAKCES MB/CD
CASE 1: ACTUAL REFINERY - UNRESTRICTED CASES
REDUCED DATA
1974
1975
1976
1977
1978
1979
1980
A
B
A
B
C
A
B
C
A
B
£
A
B
C
A
1
c
A
B
£
Total Crude Intake
13,532
13a 532
14,489
14,489
14,489
15,362
15,362
15,376
16,303
16,319
16,364
17,136
17,149
17,211
18,245
18,287
18,322
19,559
19,662
19,642
\Crude A vs. B/B vs. C
-
-
-
_
14
16
45
13
62
42
35
103
(20)
AC rude 7,
-
-
-
0.09
0.10
0.28
0.08
0.36
0.23
0.19
0.53
(0.10)
Total intake
14,512
14,512
15,401
15,401
15,401
16,197
16,197
16,211
17,051
17,067
17,112
17,804
17,817
17,879
18,824
18,866
18,999
19,941
20,044
20,119
A Intake A vs. B/B vs. C
-
-
-
-
14
16
45
13
62
42
133
103
75
A Intake 7*
-
-
-
-
0.09
0.09
0.26
0.07
0.35
0-22
0.70
0.52
0.37
Gasoline Production
6,988
6,988
7,265
7,265
7,265
7,576
7,576
7,576
7,875
7,875
7,875
8,176
8,176
8,176
8,499
8,499
8,499
8,862
8,862
8,862
% Crude Intake
51.64
51.64
50.14
50.14
50.14
49.32
49.32
49.27
48.30
48.26
48.12
47.71
47.68
47.50
46.58
46.48
46.39
45.31
45.07
45.12
% Total Intake
48.15
48.15
47.17
47.17
47.17
4&.77
46.77
46.73
46.18
46.14
46.02
45.92
45.89
45.73
45.15
45.05
44.73
44.44
44.21
44.05
Distillates - % Crude
22.56
22.66
22.43
22.43
22,43
22.44
22.44
22.42
22.35
22.33
22.27
22.61
22.59
22.51
22.50
22.45
22.40
22.27
22.15
22.17
Low Sulfur Fuel - % Crude
8.28
8.23
9.95
9.95
9.95
10.67
10.6?
10.66
11.57
11.56
11.53
11.60
11.59
11.55
12.59
12.56
12.54
13.57
13.50
13.52
Dist. + LoSF - % Crude
30.94
30.94
32.38
32.38
32.38
33.11
33.11
33.08
33.92
33.89
33.80
34.21
34.18
34.06
35.09
35.01
34.94
35.84
35.65
35.69
LPG - % Crude
2.69
2.69
2.64
2.64
2.64
2.62
2.62
2.61
2.59
2.59
2.72
2.60
2.60
2.79
2.58
2.60
2.76
2.54
2.72
2.72
Total product Outturn
14,059
14,059
14,912
14,912
14,912
15,677
15,677
15,677
16,499
16,499
16,521
17,209
17,209
17,243
18,155
18,161
lb,191
19,176
19,214
19,214
A Outturn A vs. B/B vs. C
-
-
-
-
-
-
22
-
34
6
30
33
A Outturn 7e
-
-
-
_
-
-
0.13
-
0.20
0.03
0.17
0.20
Intake - Outturn
453
453
489
489
489
520
520
534
552
568
591
595
608
63b
669
705
808
765
830
905
A A vs. B/B vs. C
-
-
-
-
14
16
23
13
28
36
103
65
75
A% Crude
-
-
_
-
0.09
0.10
0.14
0.08
0.16
0,. 20
0.56
0.33
0.38
Total Refinery Fuel
1,050
1,050
1,118
1,118
1,118
1,187
1,187
1,189
1,261
1,261
1,269
1,329
1,332
1,341
1,407
1,423
1,441
1,499
1 ,-530
1,537
% Crude Intake
7.76
7.76
7.72
7.72
7.72
7.73
7.73
7.73
7.73
7.73
7.75
7.76
7.77
7.79
7.71
7.78
7.86
7.66
7.78
7.83
Purchased power - F.O.E.
100
100
106
106
106
113
113
113
119
119
119
127
127
127
132
133
130
140
141
140
Cat Crack Coke F.O.E.
77
77
81
81
81
86
86
90
90
94
98
94
98
105
97
98
105
100
102
107
Energy Consumed
1,22?
1,227
1,305
lj305
1,305
1,386
1,386
1,392
1,470
1,474
1,486
1,550
1,557
1,573
1,636
1,654
1,676
1,739
1,773
1,784
% Crude Intake
' 9.07
9.0?
9.01
9.01
9.01
9.02
9.02
9.05
9.02
9.03
9.08
9.05
9.08
9.14
8.97
9.04
9.15
8.89
9.02
9.08
Cat Crk Corn? - XV
65
65
65
65
65
65
65
65
65
65
67
65
65
66
65
68
76
65
72
75
Reformer R-0
91
91
91
93
92
95
97
Gaso Pool R-0
89.4
89.6
89.6
90.0
89.5
90.7
91.8
Gaso Pool M-0
81.2
81.2
81.2
81.4
81.0
81.8
82.6
Distillate to Fetchem
180
180
191
191
191
202
202
202
214
214
214
227
227
227
241
241
241
255
255
255
BTX
140
140
147
147
147
155
155
155
163
163
163
171
171
171
181
181
181
191
191
191
LPG to petchem
83
83
87
87
87
92
92
92
96
96
96
102
102
102
107
107
107
113
113
113
TOTAL PETCHSM
403
403
425
425
425
449
449
449
473
473
473
500
500
500
529
529
529
559
559
559
¥-14
-------
TABLE v-13
REFINERY MATERIAL BALANCES MB/CD
CASE 2: ACTUAL REFINERY - 93/85 RON/MON LEAD FREE OCTAKE
REDUCED DATA
L974
1975
1976
1977
1978
1979
1980
A
1
A
B
C
A
B
C
A
B
£
A
B
C
A
B
C
A
B
G
Total Crude Intake
13,533
13,532
14,490
14,489
14,495
15,362
15,377
15,391
16,303
16,351
16,395
17,136
17,203
17,221
18,245
18,312
18,398
19,559
19,676
19,694
A Crude A vs. B/B vs. C
(1)
(1)
6
15
14
48
44
67
18
67
86
117
18
£ Crude %
(0.01)
(0.01)
0.04
0.10
0.09
0.29
0.27
0.39
0.10
0.37
0.47
0.60
0,09
Total Intake
14,513
14,512
15,402
15,401
15,407
16,197
16,212
16,226
17,051
17,099
17,143
17,804
17,871
17,944
18,824
18,951
19,070
19,941
20,153
20,171
h Intake A vs. B/B vs. C
(1)
(1>
6
15
14
48
44
67
73
127
119
212
18
LIntake %
(0.01)
(0.01)
0.04
0.09
0.09
0.28
0.26
0.38
0.41
0.67
0.63
1.06
0.09
Gasoline Production
6,98 8
6,988
? ,265
7,265
7,265
7 j 576
7,576
7,576
7,875
7,875
7,875
8,176
8 ,176
8,176
8,499
8,499
8,499
8,862
8,862
8,862
% Crude Intake
51.64
51.64
50.14
50.14
50.12
49.32
49.27
49.22
48.30
48.16
48.03
47.71
47.53
47.48
46.58
46.41
46.20
45.31
45 .04
45.00
% Total Intake
48.15
48.15
47.17
47.17
47.15
46.77
46.73
46.69
46.18
46.06
45.94
45.92
45.75
45 .56
45.15
44.85
44.57
44.44
43.97
43.93
Distillates - % Crude
22.66
22.66
22.43
22.43
22.42
22.44
22.42
22.40
22.35
22.29
22.23
22.61
22.52
22.50
22.50
22.42
22.31
22.27
22.13
22.11
Low Sulfur Fuel - % Crude
8.28
8.28
9.94
9.95
9.94
10.67
10,66
10,65
11.57
11.54
11.51
11.60
11.56
11.54
12.59
12.54
12.49
13.57
13.49
13.48
Dist. + LoSF % Crude
30,94
30,94
32.37
32.38
32.36
33.11
33.08
33.05
33.92
33.83
33.74
34.21
34.08
34.04
35.09
34.96
34.80
35.84
35.62
35.59
LPG - % Crude
2.69
2.69
2.64
2.64
2.64
2.62
2.61
2.61
2,59
2.65
2.78
2.60
2.78
2.78
2.58
2.76
2.75
2.54
2.72
2.72
Total Product Outturn
14,059
14,059
14,912
14,912
14,912
15,677
15,677
15,677
16,499
16,510
16,532
17,209
17,241
17,243
18,135
18,191
18,191
19,176
19,214
19,214
A Outturn A vs. B/B vs. C
-
-
-
-
-
11
22
32
2
36
-
38
-
& Outturn %
-
-
-
-
-
0.07
0.13
0.19
0.01
0.20
-
0.20
-
Intake - Outturn
454
453
490
489
495
520
535
549
552
589
611
595
630
701
669
760
879
765
939
957
A A vs. B/B vs. C
(1)
(1)
6
15
14
37
22
35
71
91
119
174
18
A % Crude
(0.01)
(0.01)
0.04
0.10
0.09
0.23
0.13
0.20
0.41
0.50
0.65
0.89
0.09
Total Refinery Fuel
. 1,050
1,050
1,118
1,118
1,119
1,187
1,189
1,189
1,261
1,264
1,284
1,329
1,337
1,347
1,407
1,429
1,459
1,499
i;539
1,555
% Crude Intake
7.76
7.76
7.72
7.72
7.72
7.73
7.73
7.73
7.73
7.73
7.83
7.76
7.77
7.82
7.71
7.80
7.93
7.66
7.82
7.90
Purchased Power F.O.E.
100
100
106
106
106
113
113
111
119
119
119
127
125
125
132
132
129
140
136
140
Cat. Crack Coke - F.O.E.
77
77
82
81
83
86
90
93
90
99
96
94
105
111
97
107
108
100
112
111
Energy Consumed
1,227
1,227
1,306
1,305
1,308
1,386
1,392
1,393
1,470
1,482
1,499
1,550
1,567
1,583
1,636
1,668
1,696
1,739
1,787
1,806
% Crude Intake
9.07
9.07
9.01
9.01
9.02
9.02
9.05
9.05
9.02
9.06
9.14
9.05
9.11
9.19
8.97
9.11
9.22
8.89
9.08
9.17
V-15
-------
TABLE ¥-14
REFINERY MTEKIAL BALANCES MB/CD
CASE 3: ACTUAL REFINERY - 7% GROWTH GASOLINE DEMAND
REDUCED DATA
1974
1975
1976
1977
1978
1979
1980
A
B
A
B
C
A
1
C
A
B
C
A
B
C
A
1
C
A
B
c
Total Crude Intake
13,
532
13,532
'14,696
14,696
14,
697
15,
847
15,847
15,
866
17,064
17,076
17,134
18,347
18,393
18,284
19,709
19,668
19,795
21,
247
21,348
21,
382
A Crude A vs. B/B vs. C
-
-
1
-
19
12
58
46
(109)
(41)
127
101
34
A Crude %
-
-
0
.01
-
0
.12
0.07
0.34
0.25
(0.59)
(0.21)
0.65
0.48
0
. 16
Total Intake
14,
512
14,512
15,608
15,608
15,
609
16,
682
16 ,682
16,
701
17,812
17,824
17,882
19,015
19,061
18,952
20,288
20,247
20,374
21,
629
21,730
21.
954
A Intake A vs. B/B vs. C
-
-
1
-
19
12
58
46
(109)
(41)
127
101
224
A Intake %
-
-
0
.01
-
0
.11
0.07
0.33
0.24
(0.57)
(0.20)
0.63
0.47
1
.03
Gasoline Production
6,
988
6,988
7,456
7,456
7,
456
8,
024
8,024
8,024
8,575
8,575
8,575
9,154
9,154
9,154
9,783
9,783
9,783
10,
504
10,504
10,
504
% Crude Intake
51
.64
51.64
50.73
50.73
50
.73
50
.63
50.63
50
.57
50.25
50.22
50.05
49.89
49.77
50.07
49.64
49.74
49.42
49
.44
49.20
49
.13
% Total Intake
48
.15
48.15
47.77
47.77
47
.77
48
.10
48.10
48
.05
48.14
48.11
47.95
48.14
48.02
48.30
48.22
48.32
48.02
48
.56
48.34
47
.85
Distillates - % Crude
22
.66
22.66
22.11
22.11
22
.11
21
.76
21.76
21
.73
21.35
21.34
21.27
21.12
21.06
21.19
20.83
20.87
20.74
20
.50
20.40
20
.37
Low Sulfur Fuel - % Crude
8
.28
8.28
9.81
9.81
9
.80
10
.34
10.34
10
.33
11.06
11.05
11.01
11.77
11.74
10.87
12.14
11.68
11.60
12
.96
12.44
12
.42
Dist. -rLoSF - % Crude
30
.94
30.94
31.92
31.92
31
.91
32
.10
32.10
32
.06
32.41
32.39
32.28
32.89
32.80
32.06
32.97
32.55
32.34
33
.46
32.84
32
.79
L?G - % Crude
2
.69
2.69
2.60
2.60
2
.60
2
.54
2.54
2
.53
2.48
2.48
2.66
2.53
2.61
2.63
2.40
2.57
2.56
2
.34
2.51
2
.50
Total Product Outturn
14 T
059
14,059
15,103
15,103
15,
103
16,
125
16,125
16,
125
17,099
17,099
17,132
18,377
18,393
18,221
19,537
19,475
19,475
20,
818
20,856
20,
856
A Outturn A vs. B/B vs. C
-
-
-
-
-
-
33
16
(172)
(62)
-
38
-
A Outturn 7„
-
-
-
-
-
-
0.19
0.09
(0.94)
(0.32)
-
0.18
-
Intake - Outturn
453
453
505
505
506
557
557
576
713
725
750
638
668
731
751
772
899
811
874
1,
098
A A vs. B/B vs. C
-
-
1
19
12
25
30
63
21
127
63
224
Crude
-
-
0
.01
-
0
.12
0.07
0.15
0.16
0.34
0.11
0.65
.0.30
1
.05
Total Refinery Fuel
1,
050
1,050
1,141
1,141
1,
141
1,
242
1,242
1,
242
1,344
1,344
1) 365
1,474
1,471
1,438
1,582
1,604
1,649
1,
717
1,761
1,
795
% Crude Intake
7
.76
7.76
7,76
7.76
7
.76
7
.84
7.84
7
.83
7.88
7.87
7.97
8.03
8.00
8.14
8.03
8.16
8.33
8
.08
8.25
8
.39
Purchased Power - F.O.E.
100
100
108
108
108
117
117
117
127
127
127
144
141
140
149
152
151
160
165
162
Cat Crk. Coke - F.O.E.
77
77
85
85
85
95
95
99
104
107
105
99
109
114
120
117
109
133
127
120
Energy Consumed
1,
227
1,227
ls334
1,334
1,
334
1,
454
1,454
1,
458
1,575
1,578
1,597
1,717
1,721
1,742
1,851
1,873
1,909
2
010
2,053
2,
077
% Crude Intake
9
.07
9.07
9.08
9.08
9
.08
9
.18
9.18
9
.19
9.23
9.24
9.32
9.36
9.36
9.53
9.39
9.52
9.64
S
.46
9.62
S
.71
F-I6
i
-------
TABLE V-15 REFINERY MATERIAL BALANCES MB/CD
CASE 4: ACTUAL REFINERY - REDUCED LEAD FREE DEMANDS
REDUCED DATA
Total Crude Intake
A Crude A vs. B/B vs. C
A Crude %
Total Intake
A Intake A vs. B/B vs. C
A Intake %
Gasoline Production
% Crude Intake
Z Total Intake
Distillates - % Crude
Low Sulfur Fuel - % Crude
Dist. + LoSF - % Crude
LPG - % Crude
Total Product Outturn
A Outturn A vs. B/B vs. C
A Outturn %
Intake - Outturn
A A va. B/B vs. C
A I Crude
Total Refinery Fuel
% Crude Intake
Purchased Power - F.O.E.
Cat Crk Coke - F.O.E.
Energy Consumed
% Crude Intake
A
1976
E
C
A
1979
B
C
15,362
16,197
15,362
16,197
15,385
23
0.15
16,220
23
0.14
18,245
18,824
18,255
10
0.05
18,834
10
0.05
18,406
151
0.83
18,985
151
0.80
7,576
49.32
46.77
7,576
49.32
46.77
7,576
49.24
46.71
8,499
46.58
45.15
8,499
46.56
45.13
8,499
46.18
44.77
22.44
10.67
33.11
22.44
10.67
33.11
22.41
10.65
33.06
• 22.50
12.59
35.09
22.49
12.58
35.07
22.30
12.48
34.78
2.62
2.62
2,61
2.58
2.57
2.75
15,677
15,677
15,677
18,155
18,155
18,191
36
0.20
520
520
¦ 543
23
0.15
669
679
10
0.05
794
115
0.63
1,187
7.73
1,187
7.73
1,189
7.73
1,407
7.71
1,409
7.72
1,456
7.91
113
86
113
86
111
92
132
97
133
100
132
98
1,386
9.02
1,386
9.02
1,392
9.05
1,636
8.97
1,642
8.99
1,686
9.16
V-17
-------
TABLE V-16 REFINERY MATERIAL BALANCES MB/CD
CASE 5: ACTUAL REFINERY - RESTRICTED REFINING CAPACITY
REDUCED DATA
1974
1975
1976
A
3
A
B
C
A
B
C
Total Crude Intake
13,517
13,517
14,496
14,502
14,502
15,396
15,404
15,404
ACrude A vs. B/B vs. C
_
6
-
8
_
ACrude %
-
0.Q4
-
0.05
-
Total Intake
14,721
14,721
15,628
15,634
15,634
16,447
16,455
16,455
AIntake A vs.B/B vs. C
-
6
-
8
_
A In take %
-
0.04
-
0.05
-
Gasoline Production
6,988
6,988
7,265
7,265
7,265
7,576
7,576
7,576
% Crude Intake
51.70
51.70.
50.12
50.10
50.10
49,21
49,18
49.18
% Total Intake
47.47
47.47
46.49
50,10
50.10
46.06
46,04
46.04
Distillates - % Crude
22.69
22,69
22,42
22.41
22.41
22,40
22.38
22.38
Low Sulfur Fuel - 7, Crude
8,29
8,29
9.94
9.94
9,94
10.65
10,64
10.64
Dlst. + LoSF - % Crude
30,98
30.98
32.36
32.35
32,35
33,05
33.02
33,02
LPG - % Crude
2.69
2.69
2.64
2.63
2.63
2.61
2.61
2.61
Total Product Outturn
14,059
14,059
14,912
14,912
14,912
15,677
15,677
15,677
AOutturn A vs. B/B vs. C
-
-
-
-
-
AOutturn %
-
-
-
-
-
Intake - Outturn
662
662
716
722
722
780
778
778
AA va. B/B vs. C
-
6
-
(2)
_
A% Crude
-
0.04
-
(0.01)
-
Total Refinery Fuel
1,055
1,055
1,116
1,125
1,125
1,189
1,200
1,200
% Crude Intake
7.80
7.80
7.70
7.76
7.76
7.72
7.79
7.79
Purchased Power - F.O.E.
89
89
94
94
94
100
100
100
Cat Crack Coke - F.O.E,
94
94
98
97
97
105
102
102
Energy Consumed
1,238
1,238
1,308
1,316
1,316
1,394
1,402
1,402
% Crude Intake
9.16
9.16
9.02
9.07
9.07
9.05
9,10
9.10
Cat Crk Conv - %V
75
75
78
77
77
79
79
79
Reformer R-0
92
92
92
92
Gaso Pool R-0
90.5
90.6
90.5
90,!
Gaso Pool M-0
81.7
81.7
81.7
81.;
V-18
-------
TABLE V-17
SEFISE&Y MATERIAL BALANCES MB/CD
CASE 6; ACTUAL REFINERY - RESTRICTED CAPACITIES, FLEXIBILITY STUDIES
SUMMER (9.5 RV?)
1974
1975
A
B
A
B
C
Total Crude Intake
14,005
14,005
14,706
14,706
14,706
A Crude A vs. B/B vs. C
-
-
-
A Crude \
-
-
-
Total Intake
15,141
15,142
15,750
15,801
15,800
A Intake A vs. B/ B vs. C
1
51
(1)
A Intake %
0.01
0.32
(0.01)
Gasoline Production
7,079
7,077
7,420
7 s 381
7,373
% Crude Intake
50.55
50.53
50.46
50.19
50.14
% Total intake
46.75
46.74
47.11
46.71
46.66
Distillates - % Crude
23.04
23.06
22.13
22.56
22.60
Low Sulfur Fuel - % Crude
8,92
8.92
9.31
9.49
9 .50
Dist. -I- LoSF - % Crude
31.96
31.98
31.44
32.05
32.10
L?G - % Crude
2.60
2.60
2.60
2.60
2.60
Total Product Outturn
14,439
14,440
15,000
15,051
15,050
A Outturn A vs. B/B vs. C
1
51
CD
A Outturn %
0.01
0.34
(0.01)
Intake - Outturn
702
702
750
750
750
A A vs. B/B vs. C
-
-
-
A % Crude
-
-
-
Total Refinery Fuel
1,092
1,092
1,157
1,149
1,149
% Crude Intake
7.80
7.80
7.87
7.81
7.81
Purchased Power - F.O.I.
90
92
95
95
95
Cat Crk Coke - F.O.E.
105
105
109
110
110
Energy Consumed
1,287
1,289
1,361
1,3.54
1,354
% Crude Intake
9.19
9.20
9.25
9.21
9.21
Cat Crk Conv - 7aV
76
76
80
77
76
Reformer R-G
92
Gaso Pool R-0
90,4
Gaso Pool M-0
81.3
WINTER (12
RVP")
1976
1974
1975
1976
A
B
C
A
B
A
B
C
A
B
C
15,460
15,460
15,460
14,005
14,005
14,706
14,706
14,706
15,460
15,460
15,460
16,468
16,489
16,391
15,209
15,209
15,838
15,838
15,838
16,511
16,511
16,511
21
(98)
-
-
-
-
-
0.13
(0.59)
-
-
-
-
-
7,671
7,679
7,750
5,355
5,346
5,836
5,836
5,836
5,966
5,965
5,965
49.62
49.67
50.12
38.24
38.17
39.68
39.63
39.68
38.59
33.58
38.58
46.58
46 -57
47.28
35.21
35,15
36.85
36.85
36.85
36.13
36.13
36.13
22.61
22.21
21.42
32.66
32.73
30.58
30.58
30.58
30.38
30.38
30.38
10.30
10.12
9.76
12.64
12.67
12.86
12.86
12.86
13.84
13.84
13.84
32.91
32.33
31.18
45.30
45.40
43.44
43.44
43.44
44.22
44.22
44.22
2.60
2.60
2.60
2.80
2.80
2.80
2.80
2. SO
2.80
2.80
2.80
15,774
15,692
15,585
14,611
14,616
15,210
15,210
15,210
15,847
15,846
15,846
(82)
(107)
5
-
_
(1)
-
(0.52)
(0.68)
0.03
-
-
(0.01)
-
694
797
806
598
593
628
628
628
664
665
665
103
9
(5)
-
-
1
-
0.67
0.06
(0.04)
-
-
0.01
-
1 j 212
1,212
1,234
926
923
982
984
984
1,028
1,028
1,028
8.40
7.84
9,80
6.61
6.59
6.68
6.69
6.69
6.65
6.65
6.65
100
100
102
81
81
87
87
87
90
90
90
116
116
114
57
57
59
59
59
57
57
57
1,428
1,428
1,450
1,064
1,061
1,128
1,130
1,130
1,175
1,175
1,175
9.24
9.24
9.38
7,60
7.58
7.67
7.68
7.68
7.60
7.60
7.60
77
77
82
65
65
65
65
65
65
65
65
92
92
92
98
97
97
97
90.0
90.1
90.9
91.4
91.0
91,0
91,0
81,0
81.0
81.6
83.1
82.6
82.7
82.7
V-19
-------
TABLE V-18 REFINERY MATERIAL BALANCES MB/CD
CASE 7; ACTUAL REFINERY - REDUCED PREMIUM DEMAND
REDUCED DATA
1979
ABC
Total Crude Intake 18,245 18,271 18,346
ACrude A vs. B/B vs. C 26 75
A Crude % 0.14 0.4-1
Total Intake 18,824 18,850 18,925
AIntaka A vs. B/B vs. C 26 75
AIntake % 0.14 0.40
Gasoline Production 8,500 8,500 8,500
% Crude Intake 46.59 46,52 46.33
% Total Intake 45.16 45.09 44.91
Distillates - % Crude 22.50 "22.47 22.38
Low Sulfur Fuel - % Crude 12.59 12.57 12.52
Dist. + LoSF - % Crude 35.09 35.04 34.90
LPG - % Crude 2.58 2.57 2.76
Total Product Outturn 18,156 18,156 18,192
AOutturn A vs. B/B vs. C - 36
AOutturn 1 -0,20
Intake - Outturn 668 694 733
AA vs. B/B vs. C 26 39
n Crude 0.14 0.21
Tptal Refinery Fuel 1,407 1,423 1,439
% Crude Intake 7.71 7,79 7.84
Purchased Power - F.O.E. 132 135 135
Cat Crack Coke - F.O.E. 97 95 99
Energy Consumed 1,636 1,653 1,673
% Crude Intake 8.97 9.05 9.12
Cat Crk Conv - %V 65 68 72
V-20
-------
TABLE V-19
REFINERY MATERIAL BALANCES MB /CD
CASE 1: COMPLEX REFINERY - UNRESTRICTED CASES
SEDUCED DATA
1974
1975
1976
1977
1978
1979
1980
A
B
A
B
C
A
B
C
A
B
C
A
B
C
A
B
C
A
B
C
Total Crude Intake
13,493
13,493 '
14,460 14,460
14.460
15,375
15,361
15,390
16,303
16,323
16,320
17,134
17,165
17,270
18,248
18,321
18,298
19,565
19,613
19,622
Crude A vs. B/B vs. C
-
-
-
(14)
(29)
20
(3)
31
105
73
(23)
48
9
AGrade %
-
-
(0.09)
(0.19)
0.12
(0.02)
0.18
0.6t
.40
(0.13)
0.25
0.05
Total Intake
14,646
14,651
15,530
15,530
15,530
16,312
16,327
16,321
17,215
17,156
17,182
18,001
17,999
17,967
19,017
19,034
19,075
20,136
20,184
20,193
A. Intake A vs. B/B vs. C
5
-
-
15
(6)
(59)
26
(2)
(32)
17
41
48
9
LIntake %
0.03
-
-
0.09
(0.04)
(0.34)
0,15
(0.01)
(0.18)
0.09
0.22
0.24
0.04
Gasoline Production.
6,988
6,938
7,265
7,265
7,265
7,576
7,576
7,576
7,875
7,875
7,875
8,176
8,176
8,176
8,499
8,499
8,499
8,862
8,862
8,862
% Crude Intake
51.79
51.79
50.24
50.24
50.24
49.27
49.32
49.23
48.30
48.24
48.25
47.72
47.63
47.34
46.5"?
46. 3f>
46.45
45.30
45. IS
45.16
% Total I ntake
47.71
47.70
46.78
46.78
46.78
46.44
46.40
46.42
45.74
45.90
45.83
45.42
45.42
45.51
44.69
44.65
44.56
44.01
43.91
43.89
Distillates - % Crude
22.73
22.73
22.48
22.48
22.48
22.43
22.45
22.40
22.35
22.32
22.33
22.61
22.57
22.43
22.50
22.41
22.43
22.26
22.20
22.19
Low Sulfur Fuel - % Crude
8.30
8.30
9.97
9.97
9.97
10.66
10.67
10.65
11.57
11.39
11.56
11.60
11.58
11.51
12.59
12.54
12.55
13.57
13.54
13.53
Dist. + LoSF - % Crude
31,03
31.03
32.45
32.45
32.45
33.09
33.12
31.05
33.92
33.71
33.89
34.21
34.15
33.94
35.09
34.95
34.98
35,83
35.74
35.72
LPS - % Crude
2,70
2.70
2.64
2.64
2.64
2.61
2.62
2.61
2.59
2.59
2.59
2.60
2.60
2.58
2.58
2.57
2.67
2.54
2.53
2.57
Total Product Outturn
14,059
14,059
14,912
14,912
14,912
15,677
15,677
15,677
16,499
16,472
16,499
17S209
17,209
17,209
18,155
18,155
18,174
19,176
19,176
19,184
£ Outturn A -vs. B/B vs. C
-
-
-
-
-
(27)
27
-
-
-
19
-
8
A Outturn %
-
-
-
-
-
(0.16)
0.16
-
-
-
0.10
*
0.04
Intake - Outturn
587
592
618
618
618
635
650
644
716
684
683
792
790
758
862
879
901 .
960
1,008
1,009
A A vs. B/B vs. C
5
-
-
15
<6)
(32)
CD
(2)
(32)
(17)
22
48
1
Z\% Crude
0.04
-
-
0.10
(0.04)
(0.20)
(0.01)
(0.01)
(0.19)
(0.09)
0.12
. 0.25
0.01
Total Refinery Fuel
1,029
1,029
1,096
1,096
1,096
1,166
1,163
1,166
1,227
1,235
1,248
1,289
1,296
1.315
1,367
1,380
1,403
1,461
1,482
1,509
% Crude Intake
7.63
7.63
7.58
7.58
7.58
7.58
7.57
7.58
7.53
7.57
7.65
7.52
7.55
7.61
7.49
7.53
7.67
7.47
7,56
7.69
Purchased Power - F.O.E,
92
92
98
98
98
104
103
104
108
110
111
113
113
117
119
119
124
125
129
132
Cat Crack Coke - F.O.E.
90
91
92
92
92
92
94
95
100
97
99
108
109
108
109
118
120
112
124
127
Energy Consumed
1,211
1,212
1,286
1,286
1,286
1,362
1,360
1,365
1,435
1,442
1,458
1,510
1,518
1,540
1,595
1,617
1,647
1,698
1,735
1,768
% Crude Intake
8.98
8.98
8.89
8.89
8.89
8.86
8.85
8.87
8.80
8,83
8.93
8.81
8.84
8.92
S. 74
8.83
9.00
8.68
8.85
9.01
Cat Crk Conv -
65
65
65
65
65
65
65
65
65
65
65
65
65
65
65
65
65
65
65
65
Reformer R-0
92
91
91
94
92
95
98
7-21
-------
TABLE V-20 REFINERY MATERIAL BALANCES MB/CD
CASE 2: COMPLEX REFINERY - 93/85 RON/MON LEAD FREE OCTANE
REDUCED DATA
Total Crude Intake
ACrude A vs. B/B vs. C
ACrude %
Total Intake
AIntake A vs. B/B vs. C
AIntake %
Gasoline Production
% Crude Intake
% Total Intake
Distillates - % Crude
Low Sulfur Fuel - % Crude
Dist. + LoSF - % Crude
LPG - 1 Crude
Total Product Outturn
AOutturn A vs. B/B vs. C
, AOutturn %
Intake - Outturn
AA vs, B/B vs. C
A% Crude
Total Refinery Fuel
% Crude Intake
Purchased Power - F.O.E.
Cat Crack Coke - F.O.E.
Energy Consumed
% Crude Intake
1976
ABC
.1.5,378 15,417 15,455
39 38
0.25 0.25
16,311 16,301 16,291
(10) (10)
(0.06) (0.06)
7,576 7,576 7,576
49.27 49.14 49.02
46.45 46.48 • 46.50
22.42 22.36 22.31
10.66 10,63 10.60
33.08 32.99 32.91
2.61 2.61 2.60
15,677 15,677 15,677
634 624 614
(10) (10)
(0.06) (0.06)
1,166
1,170
1,177
7.58
7.59
7.62
105
106
106
92
92
93
1,363
1,368
1,376
8.86
8.87
8.90
1979
A
1
C
18,248
18,376
18,341
128
(35)
0.70
(0.19)
19,019
19,011
19,118
(8)
107
(0.04)
0.56
8,499
8,499
8,499
46.57
46.25
46.34
46.67
44.71
44.46
22.50
22.34
22.38
12.59
12.50
12.52
35.09
34.84
35.20
2,58
2.56
2.76
18,155
18,155
18,191
-
36
-
0.20
864
856
927
(8)
71
(0P04)
0.39
1,367
1 j 416
1,432
7.49
7.71
7.81
119
124
127
110
116
119
1,596
1,656
1,678
8.75
9.01
9.15
V-22
-------
TABLE V-21 REFINERY MATERIAL BALANCES MB/CD
CASE 3: COMPLEX REFINERY - 7% GROWTH GASOLINE DEMAND
REDUCED DATA
1976
1979
A
B
C
A
B
C
Total Crude Intake
15,907
15,878
15,906
19,627
19,682
19,758
ACrude A vs B/B vs. C
(29)
28
55
76
ACrude %
(0.18)
0.18
0.28
0.39
Total Intake
16,742
16,771
16,780
20,404
20,448
20,535
AIntake A vs. B/B vs. C
29
9
44
87
AIntake %
0.17
0.05
0.22
0.43
Gasoline Production
8,024
8,024
8,024
9,783
9,783
9,783
% Crude Intake
50.44
50.54
50.45
49.84
49.71
49,51
Z Total Intake
47.93
47.84
47.82
47.95
' 47.84
47.64
Distillates - X Crude
21.68
21.72
21.68
20.92
20.86
20.78
Low Sulfur Fuel - % Crude
10.30
10.32
10.30
11.72
11.67
11.63
Dist. + LoSF - % Crude
31.98
32.04
31.98
32.64
32.53
32.41
LPG - % Crude
2.53
2,53
2,53
2.39
2.57
2.56
Total Product Outturn
16,125
16,125
16,125
19,443
19,474
19,475
AOutturn A vs, B/B vs. C
_
-
31
1
AOutturn I
-
-
0.16
0.01
Intake - Outturn
617
646
655
961
974
1,060
AA vs. B/B vs. C
29
9
13
86
A% Crude
0.18
0.06
0.07
0.44
Total Refinery Fuel
1,229
1,225
1,226
1,539
1,584
1,604
% Crude Intake
7.73
7.72
7.71
7.84
8.05
8.12
Purchased Power - F.O.E.
113
111
111
136
140
140
Cat Crack Coke - F.O.E.
93
97
101
132
121
129
Energy Consumed
1,435
1,433
1,438
1,807
1,845
1,873
% Crude Intake
9.02
9.03
9.04
9.21
9.37
9.48
V-23
-------
TABLE V-22 REFINERY MATERIAL BALANCES MB/CD
CASE 4: COMPLEX REFINERY - REDUCED LEAD FREE DEMANDS
REDUCED DATA
Total Crude Intake
A Crude A vs. B/B vs. C
A Crude %
Total Intake
A Intake A vs, B/B vs. C
A Intake %
Gasoline Production
% Crude Intake
% Total Intake
Distillates - % Crude
Low Sulfur Fuel - % Crude
Dlst. + LoSF - % Crude
LPG - 1 Crude
Total Product Outturn
A Outturn A vs. B/B vs, C
A Outturn %
Intake - Outturn
A A vs. B/B vs. C
A % Crude
Total Refinery Fuel
% Crude Intake
Purchased Power - F.O.E.
Cat Crack Coke - F.O.E.
Energy Consumed
% Crude Intake
1976
1979
A
B
C
A
B
C
15,375
15,337
15,377
18,248
18,251
18,351
(38)
40
3
100
(0.25)
0.26
0.02
0.55
16,312
16,349
16,345
19,017
19,028
19,073
37
(4)
11
45
0.23
(0.02)
0.06
0.24
7,576
7,576
7,576
8,499
8,499
8,499
49.27
49.40
49.27
46.57
46.57
46.31
46.44
46.34
46.35
44.69
. 44.67
44.56
22.43
22.48
22.42
22.50
22.49
22.37
10.66
10.69
10.66
12.59
12.59
12.52
33.09
33.17
33.08
35.09
35.08
34.89
2.61
2.62
2.61
2.58
2.58
2.74
15,677
15,677
15,677
18,155
18,155
18,188
~
_
-
33
-
-
-
0.18
635
672
668
862
873
885
37
(4)
11
12
0.24
(0.03)
0.06
0.07
1,166
1,158
1,164
1,367
1,371
1,412
7.58
7.55
7.57
7.49
7.51
7.69
105
102
103
119
119
127
92
97
99
109
111
118
1,363
1,357
1,366
1,595
1,601
1,657
8.87
8.85
8.88
8.74
8.77
9.03
V-24
-------
TABLE ¥-23
Raw Materials Cost
4 Crude
A.Iso"butane
A Normal Butane
A Operating Cost
A Capital Cost 5? 20%
By-Product Value
ALPG
ALow Sulfur Fuel
Total Cost
Gaso Volume MMB/D
Penalty £/Bbl
(Billions of 1974 $)
Case A Total plant Invest.
&Total Plant Investment
Cumulative A plant Invest.
1974 " 1975
B-A B-A C-B
(0.03) 0.01
(0.03) 0.01
7.0 7.3 7.3
(0.4) 0.1
19.14 20.39
0 0 0
0 0 0
ECONOMIC SUMMARY $ MM/MY
CASE 1: ACTUAL REFINERY - UNRESTRICTED CASES
1976
B-A C-B
0.12
(0.05) (0.10)
(0.05) 0.02
7.6 7.6
(0.7) 0.3
21.63
0 0
0 0
1977
B-A C-B
0.14 0.40
(0.17) (0.18)
(0.03) 0.02
(0.15)
(0.06) 0.09
7.9 7.9
(0.8) 1.1
23.06
(0.05) 0.03
(0.05) 0.03
1978
B-A C-B
0.12 0.57
(0.20) (0.22)
0.14 0.04
(0.25)
0.06 0.14
8.2 8.2
0.7 1.7
24.28
0.08 0.07
0.03 0.10
1979
B-A C-B
0.41 0.34
0.75
(0.33) (0.33)
0.09 (0.19)
(0.05) (0.23)
0.12 0.34
8.5 8.5
1.4 4.0
25.62
0.13 (0.29)
0.16 (0.19)
1980
3-A" C-B
1.04 (0.20)
0.75
(0-51) (0.18)
0.10 (0.09)
(0.30)
0,33 0.28
8.9 8.9
3.7 3.1
27.00
0.13 (0.11)
0.29 (0.30)
V-25
-------
TABLE V-24
Saw Materials Cost:
ACrude
AIsobutane
hNormal Butane
<6 Operating Cost
& Capital Cost
-------
TABLE ?-25
CASE 3:
ECONOMIC SUMMARY $ MM'/DAY
ACTUAL REFINERY - 7% GROWTH GASOLINE DEMAND
1974
1975
1976
1977
1978
1979
.980
B-A
B-A
C-B
B-A
C-B
B-A
C-B
B-A
C-B
B-A
C-B
B-A
C-B
Raw Materials Cost
A Crude
A Isobutane
A Normal Butane
-
-
Q.01
-
0.16
0.11
0.52
0.43
(1-0)
(0.40)
1.23
1.02
0.34
0.75
0.75
A Operating Cost
ACapltal Cost @ 20%
(0.03)
0.01
(0,01)
(0.04)
(0.14)
(0.16)
(0.21)
0.05
(0.26)
(0.06)
(0-39)
(0.21)
(0.36)
0.12
(0.43)
(0.24)
(0.52)
0.22
(0.34)
(0.33)
By-product Value
ALPG
A Low Sulfur Fuel
-
_
-
-
-
(0.23)
(0.12)
1.83
(0.25)
1.1
(0.30)
_
Total Cost
(0.03)
0.01
-
(0.04)
0.02
(0.05)
0,13
(0.01)
0.23
0.21
0.56
0.42
1.17
Gaso Volume MMB/D
7.0
7.5
7.5
8.0
8.0
8.6
8.6
9.2
9.2
9.8
9.8
10.5
10.5
penalty c/Bbl
(0-4)
0.1
-
(0.5)
0.3
(0.6)
1.5
(0-1)
2.5
2.1
5.7
4.0
11.1
(Billions of 1974 $)
Case A Total Plant Invest.
A Total Plant Investment
CuaulativeAPlant Invest.
19.14
0
0
20.75
0
0
0
0
22.56
0
0
0
0
24.37
0
0
0.08
0.08
26.96
(0.08)
(0.08)
(0.31)
(0.23)
28.75
0.16
0.08
(0.33)
(0.56)
30.89
0.29
0.37
(0.44)
(1-.00)
V-27
-------
TABLE V-26 ECONOMIC SUMMARY $MM/DAY
CASE 4: ACTUAL REFINERY - REDUCED LEAD FREE DEMANDS
Raw Materials Cost
A Crude
A Iso Butane
A Norm Butane
A Operating Cost
A Capital Cost
By-Product Value
A LPG
A Low Sulfur Fuel Oil
Total Cost
Gaso Volume MMB/D
Penalty 0/BBL
(Billions of 1974 Dollars)
Case A Total Plant Invest.
A Total Plant Invest.
1976 1979
B - A C - B B - A C - B
.20 .10 1.46
.06 (.18) . (.18) (.43)
.01 .04 (.07)
(.27)
.06 .03 . (.04) .69
7.6 7.6 8.5 8.5
.8 .4 (.5) 8.1
21.63 25.62
0 .02 .06 (.10)
V-28
-------
TABLE V-27 ECONOMIC SUMMARY $MM/DAY
CASE 5: ACTUAL REFINERY RESTRICTED REFINING CAPACITY
Raw Materials Cost
1974 1975 1976
B-A B-AC-B B-AC-B
A Crude - ,05 - .07
A Iso Butane - - - -
A Norm Butane - - - -
A Operating Cost (.04) (.01) - -
A Capital Cost - (.03) - (-05)
By-Product Value
A LPG - -
A Low Sulfur Fuel Oil - - -
Total Cost (.04) .01 - .02
Gaso Volume MMB/D 7.0 7.3 7.3 7.6 7.6
Penalty
-------
TABLE V-28 ECONOMIC SUMMARY $MM/DAY
CASE 7: ACTUAL REFINERY - REDUCED PREMIUM DEMAND
Raw Materials Cost
A Crude
A Iso Butane
A Norm Butane
A Operating Cost
A Capital Cost
By-Product Value
A LPG
A Low Sulfur Fuel
1979
B - A C - B
0.25 0.72
.01 (.25)
.10 .05
(.27)
Total Cost
Gaso Volume MMB/D
Penalty c/BBL
.36 .25
8.5 8.5
4.2 2.9
Case A Total Plant Invest. 25.62
(Billions of 1974 Dollars)
A Total Plant Invest. .14 .07
V-30
-------
TABLE 7-29
Raw Materials Cost
A Crude
Alsobutane
ANorml Butane
A Operating Cost
A Capital Charge @ 20%
By-Prodtict Value
Alpg
ALow Sulfur Fuel Oil
Total Cost
Gaso Volume MMB/D
Penalty
-------
TABLE V-30 ECONOMIC SUMMARY $MM/DAY
CASE 2; COMPLEX REFINERY - 93/85 RON/MON LEAD FREE OCTANE
Raw Materials Cost
A Crude
A Iso Butane
A Norm Butane
A Operating Cost
A Capital Charge @ 20%
By-Product Values
ALPG
ALow Sulfur Fuel Oil
Total Cost
%
Gaso Volume MMB/D
Penalty C/BBL
Case A Total Plant Invest.
A Total Plant Invest.
(Billions of 1974 Dollars)
1976 1979
B - A -B-C B-A B-C
.33 .38 1.24 (.34)
(.29) (.33) (,33) .33
(.04) .01 (.71) .75
.02 (.06) .03 (.16)
.08 .08 .54 .20
(.27)
.10 .08 .77 .51
7.6 7.6 8.5 8.5
1.3 1.1 9.1 6.0
22.89 27.29
.55 .14 .75 .26
V-32
-------
TABLE V-31 ECONOMIC SUMMARY $MM/DAY
CASE 3: COMPLEX REFINERY 7% GROWTH GASOLINE DEMAND
1976 1979
C-B B-A C-B
Raw Materials Cost
A Crude (.25) .24 .53 .73
A Iso Butane .38 (.28) (.08) .08
A Norm Butane .01 .16
A Opertating Cost (.10) (.13) (.27) (.26)
A Capital Charge @ 20% (.08) .03 .29 .06
By-Product Values
A LPG - - (.26) (.01)
A Low Sulfur Fuel Oil - - .04
Total Cost o *02 .25 .60
Gaso Volume MMB/D 8.0 8.0 9.8 9.8
Penalty c/BBL (-5) .2 10.2 6.1
Case A Total Plant Inv. 24.64 30.54
A Total Plant Invest. (.13) .04 .39 .08
(Billions of 1974 Dollars)
V-33
-------
TABLE V-32 ECONOMIC SUMMARY $MM/DAY
CASE 4: COMPLEX REFINERY - REDUCED LEAD FREE DEMAND
1976 1979
B-A C-B B-A C-B
Raw Materials Cost
A Crude (. 32) .34 .03 .97
A Iso Butane .09 - - (.42)
A Norm Butane .42 (-30) -06
AOperating Cost (.02) (.11) («11) (-14)
ACapital Charge @ 20% (.11) .09 .01 .65
By-Product Values
A LPG ' - - - (.29)
A Low Sulfur Fuel Oil - -
Total Cost .06 .02 (.01) j; .77
Gaso Volume MMB/D 7.6 7.6 8.5 8.5
Penalty c/BBL .8 .3 («1) 9.1
Case A Total Plant Inv. 23.30 27.31
A Total Plant Invest. (.17) .14 ..01 .89
(Billions of 1974 Dollars)
V-34
-------
TABLE "»-33 ENERGY BALANCES MB/CD
(6.3 MMBtu F.O.E.)
CASE 1: ACTUAL REFIKEKY - tlKRESTKfGTED CASES
1974
1975
1976
1977
1978
1979
1980
A
B
A
B
£
A
B
c
A
B
C
A
B
C
A
B
£
A
B
£
Total Crude
12,028
12,028
12,879
12,879
12,879
13,655
13,655
13,667
14,492
14,505
14,545
15,232
15,244
15,299
16,218
16,255
16,286
17,386
17,477
17,460
A Crude
-
-
-
-
12
13
40
12
55
37
31
91
(17)
& Crude, % of A
-
-
-
-
0.09
0.09
0.28
0.08
0.36
0.23
0.19
0.52
(0.10)
Purcti. Refinery Fuel
490
490
441
441
441
387
387
387
325
325
325
257
257
257
181
181
181
_
_
„
Natural Gasoline
359
359
345
345
345
328
328
328
310
310
310
301
301
301
292
292
292
280
280
280
Isobutane
-
-
-
-
-
_
-
-
-
-
_
-
_
-
-
65
_
_
63
Normal Butane
-
-
-
-
-
-
-
-
-
-
-
-
-
-
_
,
-
-
_
-
Total Raw Material In
12,877
13,665
13,665
13,665
14,370
14,370
14,382
15,127
15,140
15,180
15,790
15,802
15,857
16,691
16,728
16,824
17,666
17,757
17,803
ATRMI
-
-
-
-
12
13
40
12
55
37
96
91
46
ATRMT, % of A
-
-
-
-
0.08
0.09
0.26
0.08
0.35
0.22
0.5S
0.52
0.26
Outputs
LPS
220
220
231
231
231
243
243
243
256
256
269
270
270
291
284
288
306
301
324
324
A IPG
-
-
-
-
-
-
13
-
21
4
18
23
-
A UPS, X of A
-
-
-
-
-
-
5.08
-
7.77
1.41
6.34
7.64
-
Distillates
2,836
2,836
3,005
3,005
3,005
3,183
3,188
3,183
3,369
3,369
3,369
3,582
3,582
3,582
3,795
3,795
3,795
4,027
4,027
4,027
Low Sulfur Fuel
1,067
1,067
1,372
1,372
1,372
1,561
1,561
1,561
1,797
1,797
1,797
1,893
1,893
1,893
2,188
2,188
2,188
2,529
2,529
2,529
Purch. Power (PP)
100
100
106
106
106
113
113
113
119
119
119
127
127
127
132
133
130
140
141
140
L Purch. Power
-
-
-
-
-
-
-
-
-
1
(3)
1
(1)
LPurclu Power, % of A
-
-
-
-
-
-
-
-
-
0.76
(2.27)
0.71
(0.71)
Refinery Fuel Consumed
1,050
1,050
1,118
1,118
1,118
1,187
1,187
1,189
1,261
1,261
1,269
1,329
1,332
1,341
1,40?
1,423
1,441
1,499
1,530
1,537
Cat Crack Coke
77
77
81
81
81
86
86
90
90
94
98
94
98
105
97
98
105
100
102
107
Total Energy Consumed
1,227
1,227
1,305
1,305
1,305
1,386
1,386
1,392
1,470
1,474
1,486
1,550
1,557
1,573
1,636
1,654
1,676
1,739
1,773
1,784
TEC, % of Crude
10.2
10.2
10.1
10.1
10.1
10.15
10.15
10.19
10.14
10-. 16
10.22
10.18
10.21
10.28
10.09
10.18
10.29
10.00
10.14
10.31
ATEC
_
-
_
-
6
4
12
7
16
18
22
34
11
ATEC, I of A
-
-
-
-
0.4
0.3
0.82
0.45
1.03
1.10
1.34
1.96
0.63
A Energy laput-ATRMI+APP-ALPG
0
0
0
0
12
13
27
12
34
34
75
69
45
"Base Energy Input=TBMI+P?
12,977
13,771
14,483
15,246
15,917
16,823
17,806
AEnergy Input, % of Base
0
0
0
0
0.083
0.085
'0.177
0.075
0.214
0-202
0.446
0.388
0.253
¥-35
-------
TABLE V-34
ENERGY BALANCES MB/CD
(6.3 MM Btu F.O.I,)
CASE 2: ACTUAL REFINERY - 93/85 RON/MM LEAD F8ES OCTASE
1974
1975
1976
1977
1978
1979
1980
A
B
A
B
c
A
B
C
A
1-
C
A
I
C
A
B
C
A
B
C
Total Crude
12,029
12,028
12,880
12,879
12,884
13,655
13,668
13,681
14,491
14,534
14,573
15,232
15,291
15,307
16,218
16,277
16,354
17,386
17,490
17,506
A Crude
CI)
188
2,188
2,188
2,529
2,529
2,529
Purchased Power
100
100
106
106
106
113
113
111
119
119
119
127
125
125
132
132
129
140
136
140
APP
-
-
-
-
(2)
-
-
(2)
-
-
(3)
(4)
4
A PP, % of A
-
-
-
-
(1.77)
'
-
(1.58)
-
-
(2.27)
(2.86)
2.86
Refinery Fuel Consumed
1,050
1,050
1,118
1,118
1,119
1,187
1,189
1,189
1,261
1,264
1,284
1,329
1,337
1,347
1,407
' 1,429
1,459
1,499
1,539
1,555
Cat Crack Coke
77
77
82
81
83
86
90
93
90
99
96
94
105
111
97
107
108
100
112
111
Total Energy Consumed
1,227
1,227
1,306
1,305
1,308
1,386
1,392
1,393
1,470
1,482
1,499
1,550
1,567
1,583
1,636
1,668
1,696
1,739
1,787
1,806
TEC, % Crude
9.07
9.07
9.01
9.01
9.02
9.02
9.05
9.05
9.02
9.06
9.14
9.05
9.11
9.19
8.97
9.11
9.22
8.89
9.08
9.17
Atec
-
(1)
5
6
1
12
17
17
16
32
28
48
19
A TEC, % of A
-
(0.08)
0.38
0.43
0.07
0.82
1.16
1.10
1.03
2.00
1.71
2.76
1.09
A Energy Input^TSM+ApP-ilLPG
(1)
(I)
5
13
11
36
26
38
14
77
95
40
20
Base Energy Input=TRMl4-PP
12,978
13,772
14,484
15,245
15,917
16,823
17,806
A Energy Input, % of Base
(0.01)
(0.01)
0.04
0.09
0.08
0.24
0.17
0.24
0.09
Q.46
0.56
0.22
.11
V-36
-------
TABLE V-35 EMERGY BAMHCIS MB/CD
(6,3 MM Btu F.O.E.)
CASE 3: ACTUAL REFINERY - 7% GROWTH GASOLISE BIMATO
1974
1975
1976
1977
1978
1979
1980
A
B
A
B
C
A
B
C
A
I-~-
C
A
B
C
A
B
C_
A
B
£
Total Crude
12,02?
12,027
13,062
13,062
13,063
14,085
14)085
14,102
15,166
15,177
15,229
16,307
16,348
16,251
17,5X7
17,481
17,594
18,884
18,974
19,004
A C rude
_
-
1
-
17
11
52
41
(97)
(36)
113
90
30
A.Crude, % of A
-
-
0.01
-
0.12
0,01
0.34
0.25
(0,59)
(0.21)
0.65
0.48
0.16
. Purch. Refinery Fuel
490
490
441
441
441
387
387
387
325
325
325
257
257
257
181
181
181
_
_
_
Natural Gasoline
359
359
345
345
345
329
329
329
310
310
310
301
301
301
292
292
292
280
280
280
isobutane
_
-
_
-
_
_
_
_
_
_
-
_
_
_
_
_
_
_
63
Normal Butane
-
-
-
-
-
-
-
-
-
-
,
-
-
_
-
-
-
-
-
65
Total Raw Material In
12,876
12,376
13,848
13,848
13,849
14,801
14,801
14,813
15,801
15,812
15,864
16,865
16,906
16,809
17,990
17,954
18,067
19,164
19,254
19,412
h "Ml
-
-
1
-
17
11
52
41
(97)
(36)
113
90
158
L TRMLS % of A
-
-
0.01
-
0.11
0.07
0.33
0.24
(0.58)
(0.20)
0.63
0.47
0.82
OUTPUTS
LPG
220
220
231
231
231
243
243
243
256
256
276
281
291
291
286
306
306
301
324
324
A LPG
-
-
-
-
-
-
20
10
-
20
-
23
-
ALPG, % of A
-
-
-
-
-
-
7.81
3.56
-
6.99
-
7.64
-
Distillates
2,836
2,836
3,005
3,005
3,005
3,188
3,188
3,188
3,369
3,369
3,369
3,582
3,582
3,582
3,795
3,795
3,795
4,027
4,027
4,027
Low Sulfur Fuel
1,067
1,067
1,372
1,372
1,372
1,561
1,561
1,561
1,797
1,797
1,797
2,057
2,057
1,893
2,278
2,187
2,187
2,529
2,529
2.529
Purch. Power
100
100
108
108
108
117
117
117
127
127
127
144
141
. 140
149
152
151
160
165
162
K PP
-
-
-
-
-
-
-
(3)
(1)
3
(1)
5
(3)
A PP, % of A
-
-
-
-
-
-
-
(2.08)
(0.69)
2.01
(0.67)
3.13
(1.88)
Refinery Fuel Consumed
1,050
1,050
1,141
1,141
1,141
1,242
1,242
1,242
1,344
1,344
1,365
1,474
1,471
1,488
1,582
1,604
1,649
1,717
1,761
1,795
Cat Crack Coke
77
77
85
85
85
95
95
99
104
107
105
99
109
114
120
117
109
133
127
120
Total Energy Consussed
¦ 1,22?
1,227
1,334
1,334
1,334
1,454
1,454
1,458
1,578
1,578
1,597
1,717
1,721
1,742
1,851
1,873
1,909
2,010
2,053
2,077
TEC, % Crude
10.20
10.20
10.21
10.21
10.21
10.32
10.32
10-34
10.40
10.40
10.49
10.53
10.53
10.72
10.57
10.71
10.85
10.64
10.82
10.93
kt&c
-
-
-
-
4
-
19
4
21
22
36
43
24
Atec, % of a
-
-
-
-
0.28
-
1.20
0.23
1.22
1.19
1.94
2.14
1.19
A Energy lBput=kTKMI-lApp-4;LPG
_
_
1
-
17
11
32
28
(98)
(53)
112
72
155
Base Energy Input=TEMI+PP
12,976
13,956
14,918
15,928
17,009
18,139
19,324
^.Energy Input, % of Base
-
-
0.01
-
0.11
0.07
0.20
0.16
(0.58)
(0.29)
0.62
0.37
0.80
¥-37
-------
TABLE V-36
ENERGY BALANCES MB/CD
(6.3 MM Btu F.O.E.)
CASE 4: ACTUAL REFINERY - REDUCED LEAD FREE DEMANDS
1976
1979
A
B
C
A
B
£
'Total Crude
13,654
13,654
13,674
16,216
16,225
16,359
ACrude
-
20
9
134
ACrude, % of A
-
0.15
0.06
0.83
Purch. Refinefy Fuel
387
387
387
181
181
181
Natural Gasoline
329
329
329
292
292
292
Iaobutane
—
_
_
«-
—
_
Normal Butane
-
-
-
-
Total Raw Material In
14,370
14,370
14,390
16,689
16,698
16,832
ATRMI
-
20
9
134
ATRMI, % of A
-
0.14
0.05
0.80
OUTPUTS
L"PG
243
243
243
284
284
306
ALPG '
-
-
-
22
ALPG, % of A
-
-
-
7.75
Distillates
3,188
3,188
3,188
3,795
3,795
3,795
Low Sulfur Fuel"
1,561
1,561
1,561
2,188
2,188
2,188
Purchased Power
113
113
111
132
133
132
APP
-
(2)
1
(1)
APP, % of A
-
(1.77)
0.76
(0.76)
Refinery Fuel Used
1,187
1,187
1,189
1,407
1,409
1,456
Cat Crack Coke
86
86
92
97
100
98
Total Energy' Consumed
1,386
1,386
1,392
1,636
1,642
1,686
TEC, % of Crude
10.15
10,15
10.18
10.09
10.12
10.31
A TEC
-
6
6
44
A TEC, % of A
-
0.43
0.37
2.69
AEnergy Input=ATRMI+APP-ALPG
-
18
10
111
Base Energy Input13 TRMI + PP
14,483
16,821
AEnergy Input, % of Base
-
0.12
0.06
0.66
V-38
-------
ENERGY BALANCES MB/CD
(6.3 MM Btu F.O.E.)
TABLE V-37
CASE 5: ACTUAL REFINERY - RESTRICTED REFINING CAPACITY
Total Crude
ACrude
ACrude,. % of A
1974
A B
12,015 12,015
1975
A B C_
12,885 .12,891 12,891
6
0.05
1976
ABC
13,685 13,692 13,692
7
0.05
Parch. Refinery Fuel
490
490
441
441
441
387
387
387
Natural Gasoline
359
359
345
345
345
329
329
329
Isobutane
74
74
73
73
73
71
71
71
Normal Butane
77
77
52
52
52
74
74
74
Total Raw Material In
1.3,015
13,015
13,796
13,802
13,802
14,546
14,553
14,553
ATRMI
-
6
7
-
atrmi, % of A
-
0.04
~
0.05
—
OUTPUTS
LPG
22.0
220
231
231
231
243
243
243
alpg
-
-
-
-
-
ALPG, % of A
-
_
-
-
-
Distillates
2,836
2,836
3,005
3,005
3,005
3,188
3,188
3,188
Low Sulfur Fuel
1,067
1,067
1,372
1,372
1,372
1,561
1,561
1,561
Purchased Power
89
89
94
94
94
100
100
100
APP
-
-
-
-
-
APP, % of A
-
-
~
-
-
Refinery Fuel Used
1,055
1,055
1,116
1,125
1,125
1,189
1,200
1,200
Cat Crack Coke
94
94
98
97
97
105
102
102
Total Energy Consumed
1,238
1,238
1,308
1,316
1,316
1,394
1,402
1,402
TEC, % of Crude
10.30
10,30
10.15
10.21
10.21
10.19
10.24
10.24
ATEC
-
8
-
8
-
ATEC, % of A
-
0.61
-
0.57
-
A Energy Input=ATRMI+APP-ALPG
-
6
-
7
-
Base Energy Input=TRMI+PP
13,104
13,890
14,646
AEnergy Input, % of Base
-
0.04
-
0.05
-
V-39
-------
TABLE V-38
ENERGY BALANCES MB/CD
(6.3 MM Btu F.O.E.)
CASE 6; ACTUAL REFINERY - RESTRICTED CAPACITIES, FLEXIBILITY STUDIES
SUMMER (9.5 RV?)
WINTER (12 RVP^
1974
1975
1976
1974
1975
1976
A
B
A
B
£
A
B
C
A
B
A
B
C
A
£
Total Crude
12,449
12,449
. 13,072
13,072
13,072
13,742
13,742
13,742
12,449
12,449
13,072
13,072
13,072
13,742
13,742
13,742
ACrude
-
-
-
--
_
_
_
ACrude, % of A
-
-
_
-
_
-
-
-
-
-
Purchased Refinery Fuel
490
490
441
441
441
387
387
387
490
490
441
441
441
387
387
387
Natural Gasoline
359
339
345
345
345
329
329
329
359
359
345
345
345
329
329
329
Isofcutane
74
74
37
73
73
71
71
61
74
74
73
73
73
71
71
71
Normal Butane
30
31
52
50
49
45
59
2
77
77
76
76
76
74
74
74
Total Raw Material In
13,402
13,403
13,947
13,981
13,980
14,574
14,588
14,521
13,449
13,449
14,007
14,007
14,007
14,603
14,603
14,603
ATRMI
1
34
(1)
14
(67)
-
-
-
ATRMI, % of A
0.01
0.24
(0.01)
0.10
(0 *46)
-
-
-
-
UTPUTS
LPG
220
220
231
231
231
243
243
243
237
237
249
249
249
262
262
262
A LPG
-
-
-
-
-
_
.
_
_
_
A LPG, % of A
-
-
-
-
-
_
_
_
Distillates
2,984
2,986
3,010
3,068
3,073
3,232
3,175
3,062
4,229
4,238
4,158
4,158
4,158
4,342
4,342
4,342
Low Sulfur Fuel
1,190
1,190
1,304
1,330
1,330
1,517
1,490
1,437
1,686
1,690
1,801
1,801
1,801
2,038
2,038
2,038
Purchased power
90
92
95
95
95
100
100
102
81
81
87
87
87
90
90
90
App.
2
-
-
2
_
_
_
_
Am3 2 of a
2.22
-
-
-
2.00
.
-
-
-
Refinery Fuel Used
1,092
1,092
1,157
1,149
1,149
1*212
1,212
1,234
926
923
982
984
984
1,028
1,028
1,028
Cat Crack Cote
105
105
109
110
110
116
116
114
57
57
59
59
59
57
57
57
Total Energy Consumed
1,287
1,289
1,361
1,357
1,354
1,428
1,428
1,450
1,064
1,061
1,128
1,130
1,130
1,175
1,175
1,175
-TEC, % of Crude
10.34
10.35
10.41
10.38
10.36
10.39
10.39
10.55
8.55
8.52
8.63
8.64
8.64
8.55
8.55
8.55
A TEC
2
(4)
(3)
-
22
(3)
2
-
-
-
A TEC , % of A
0-16
(0.29)
(0.22)
-
0,15
(0.28)
0.18
-
-
-
V-40
-------
TABLE V-39 ENERGY BALANCES MB/CD
(6.3 MM Btu F.O.E.)
CASE 7: ACTUAL REFINERY - REDUCED PREMIUM DEMAND
Total Crude
ACrude
ACrude, % of A
Purch. Refinery Fuel
Natural Gasoline
Isobutane
Normal Butane
Total Raw Material In
ATRMI
ATRMI, % of A
OUTPUTS
LPG
ALPG
ALPG, % of A
Distillates
Low Sulfur Fuel.
Purchased Power
¦ APP
APP s % of A
Refinery Fuel Used
Cat Crack Coke
Total Energy Consumed
TEC, 1 of Crude
ATEC
ATEC, I of A
A Energy Input<=ATRMI+APP~ALPG
Base Energy Input=TRMI+PP
AEnergy Input., % of Base
1979
A
B
'c
16,218
16,241
16,308
23
67
0.14
0.41
181
181
181
292
292
292
16,691
16,714
16,781
23
67
0.14
0.40
284
284
306
-
22
7.75
3,795
3,795
3,795
2,188
2,188
2,188
132
135
135
3
_
2.27
-
1,407
1,423
1,439
97
95
99
1,636
1,653
1,673
10.09
10.18
10.26
17
20
1.04
1.22
26
45
16,823
0.15
0.27
V-41
-------
TABLE V-40 ESERGY BALANCES KB/CD
(6.3 MM
Btu F.G.
E„)
CASE
1; COMPLEX REFINERY -
UNRESTRICTED CASES
*
1974
1975
1976
1977
j 978
1979
1980
A
B
A ' B
C
h
* c
A
3
£ A
B
c
A
B_
c
A
B
C
Total Crude
11,994
11,994
12,853 12,853
12,
,-653
13,667
13,654 13,c80
14,491
:4,>J9
14,507 15,230
15,258
15,351
16,220
16,285
16,2o5
17,391
17,434
17,442
Crude
-
-
-
/
(13) 26
IB
(2)
26
93
65
(20)
43
8
-.Grade, % of A
-
-
-
(0.10) 0.19
* 0.12
(0.01)
o.ia
O.tol
0.40
(0.12)
0.25
0.05
Purchased Refinery
Fuel
490
490
44 1 441
441
381
3 87 387
325
325
325 257
25?
257
181
181
181
_
_
_
Natural Gasoline
359
359'
345 345
345
- 32 •)
329 329
310
310
310 301
301
301
292
292
292
280
280
280
Isobutane
74
74
73 73
73
b2
34 19
70
56
9 68
51
19
65
65
b5
63
63
63
Normal Butane
42
45
32 32
32
5
54 45
40
-
bb
bO
-
62
24
68
65
65
65
Total Raw Material
In
12,959
12,"962
13j744' 13,744
13
s 744
14,450
14,458 14,460
15,236
15,200
15,151 15,922
15,927
15,931
16,820
16,847
16,871
17,799
17,842
17,850
TRMI
3
-
-
8 2
(36)
(49)
5
4
21
24
43
8
ATRMI, % of A
0.02
. -
-
o
o
o
(0.24)
(0-32)
0.01
0.03
0.16
0.14
0.24
0.04
OUTPUTS
LPG
220
220
231
231
231
243
243
243
25b
2 56
256
270
2/0
270
284
284
29b
301
301
306
\ LPG
-
-
-
-
-
-
-
-
-
-
12
-
5
. i LPG, X of A
-
-
-
-
-
-
-
-
-
-
4.23
-
1.66
Distillates
2,836
2,836
3,005
3,005
3,005
3, 188
3.188
3,188
3,369
3,369
3, 3b9
3.582
3,582
3,5d2
3,795
3,795
3,795
4,027
4,027
4,027
Low Sulfur Fuel
1,067
1,067
1,372
1,372
1,372
1,561
1.561
1,561
1,797
1,771
1,7-1/
1,893
1.8'i3
1 ,893
2,188
2,188
2,188
2 j 529
2,529
2,529
Purchased Power
92
92
98
9rf
98
104
103
104
108
no
11!
11 3
i 13
117
119
119
124
125
129
132
, J. PP
-
-
-
(1)
1
2
1
-
4
-
5
4
3
A PP, % of A
-
-
-
(0.96)
0.9b
1.85
0 - 93
-
3, 54
-
4.20
3.20
2.40
Refinery Fuel Used
1,029
1,029
1,096
1.096
1,096
1,166
1,103
1,166
i\in
1 , >33
1.24o
1.289
1,2 9b
1 ,3 J 5
i ;3<>y
1 ,380
1,403
1,461
1,482
1,509
Cat Crack Coke
90
91
92
92
92
92
94
95
100
97
99
IDS
109
1H,h
109
118
120
112
124
127
Total Energy Consumed
1,211
1,212
1,28b
1,286
1,236
1,362
l,3o0
1,365
1,435
1,442
1 ,458
i ,510
] ,5iH
1,540
1,595
1,617
1,647
1,698
1,735
1,768
TEC, % Crude
10.10
10.11
10.01
10.01
10.01
9.97
9. 9b
9.98
9.90
9.94
ID.05
*>.91
9.y5
10.03
9.83
9.93
10.13
9.76
9.95
10.14
..-.TEC
1
-
-
(2)
5
7
22
22
30
37
33
/••TEC, % of A
0.08
-
-
(0.15)
0.37
0.49
i.li
0.33
i .4o
I . 38
1.88
2.18
1.94
Energy Inpat,03 5
16,939
17,924
•• -Energy Input, % of Base
0.02
-
-
0.05
0.02
(0.22}
(0.31)
0.03
0.05
0.16
0.10
0.26
Q.G3
s7-42
-------
TABLE V-41 ENERGY BALANCES MB/CD
(6.3 MM Btu F.O.E.)
CASE 2: COMPLEX REFINERY - 93/85 RON/MON LEAD FREE OCTANE
1976
1979
A
B
C
A .
B_
C
Total Crude
13,699
13,704
13,738
16,220
16,334
16,303
ACrude
5
34
114
(31)
ACrude, I of A
0.04
0.25
0.70
(0,19)
Purch, Refinery Fuel
387
387
387
181
181
181
Natural Gasoline
329
329
329
292
292
292
Isobutane
6i
32
—
65
37
65
Normal Butane
4
-
1
64
-
68
Total Raw Material In
14,480
14,452
14,455
16,822
16,844
16,909
atrmi
(28)
3
22
65
ATRMI, % of A
(0=19)
0.02
0,13
0.39
OUTPUTS
LPG
243
243
243
284
284
306
ALPG
-
-
-
22
aLPG, % of A
-
_
-
7.75
Distillates
3,188
3,188
3,188
3,795
3,795
3,795
Low Sulfur Fuel
1,561
1,561
1,561
2,188
2,188
2,188
Purchased Power
105
106
106
119
124
127
APP
1
-
5
3
APP, % of A
0.95
-
4.20
2,52
Refinery Fuel Used
1,166
1,170
1,177
1,367
1,416
1,432
Cat Crack Coke
92
92
93
110
116
119
Total Energy Consumed
1,363
1,368
1,376
1,596
1,656
1,678
TECj % of Crude
9.95
9.98
10.02
9.84
10.14
10.29
ATEC
5
8 ¦
60
22
ATEC, % of A
0.37
0.59
3.76
1.38
Energy Input=ATRMI+APP-ALPG
(27)
3
27
46
Base Energy lnput=TRMI+PP
14,585
16,941
AEnergy Input, % of Base
(0.19)
0.02
0.16
0.27
V-43
-------
TABLE V-42 ENERGY BALANCES MB/CD
(6.3 MM Btu F.O.E.)
CASE 3: COMPLEX REFINERY - 7% GROWTH GASOLINE DEMAND
1976
1979
A
B
C
A
B
C
Total Crude
14,139
14,114
14,139
17,446
17,495
17,562
ACrude
(25)
25
49
67
ACrude, % of A
(0.18)
0.18
0.28
0.38
Purch, Refinery Fuel
387
387
387
181
181
181
Natural Gasoline
329
329
329
292
292
292
•Isobutane
—
37
9
65
58
65
, Normal ,
-
1
17
68
68
68
Total Raw Material In
14,855
14,868
14,881
18,052
18,094
18,168
ATRMI
13
13
42
74
ATRMI, % of A
0.09
0.09
0.23
0.41
OUTPUTS
LPG
243
243
243
284
306
306
alpg
_
-
22
-
ALPG, % of A
-
_
7.75
_
Distillates
3,188
3,188
3,188
3,795
3,795
3,795
Low Sulfur Fuel
1,561
1,561
1,561
2,191
2,188
2,188
Purchased Power
113
111
111
136
140
140
APP
(2)
4
_
APP, % of A
(1.77)
-
2.94
-
Refinery Fuel Used
1,229
1,225
1,226
1,539
1,584
1,604
Cat Crack Coke
93
97
101
132
121
129
Total Energy Consumed
1,435
1,433
1,438
1,807
1,845
1,873
TEC, % of Crude
10.15
10.15
10,17
10.36
10.55
10.67
ATEC
(2)
5
38
28
ATEC, % of A
(0.14)
0.35
2.10
1.55
Energy Input=ATRMI+APP-ALPG
11
13
24
74
Base Energy Input= TRMI+PP
14,968
18,188
AEnergy Input, % of Base
0.07
0.09
0.13
0.41
V-44
-------
TABLE V-43 ENERGY BALANCES MB/CD
(6.3 MM Btu F.O.E.)
CASE 4: COMPLEX REFINERY - REDUCED LEAD FREE
DEMAND
1976
1979
A
B_
C
A
B
C
Total Crude
13,667
13,633
13,668
16,220
16,223
16,312
ACrude
(34)
35
3
(11)
ACrude, % of A
(0.25)
0.26
0.02
(0.07)
Purch. Refinery Fuel
387
387
387
181
181
181
Natural Gasoline
329
329
329
292
292
292
Isobutane
62
71
71
65
65
29
Normal Butane
5
47
17
62
68
68
Total" Raw Material In
14,450
14,467
14,472
16,820
16,829
16,882
ATRMI
17
5
9
53
ATRMI, % of A
0.12
0.03
0.05
0.32
OUTPUTS
LPG
243
243
243
284
284
304
ALPG
_
-
-
20
ALPG, % of A
-
_
-
7.04
Distillates
3,188
3,188
3,188
3,795
3,795
3,795
Low Sulfur Fuel
1,561
1,561
1,561
2,188
2,188
2,188
Purchased Power
105
102
103
119
119
127
APP
(3)
1
-
8
APP, % of A.
(2.86)
0.95
-
6.72
Refinery Fuel Used
1,166
1,158
1,164
1,367
1,371
1,412
Cat Crack Coke
92
97
99
109
111
118
Total Energy Consumed
1,363
1,357
1,366
1,595
1,601
1,657
TEC, % of Crude
9.97
9.95
9.99
9.83
9.87
10.16
ATEC
(6)
9
6
56
ATEC, % of A
(0.44)
0.66
0.38
3.51
A Energy Input*=ATRMI+APP-ALPG
14
6
9
41
Base Energy Input® TRMI+PP
14,555
16,939
AEnergy Input, % of Base
0.10
0.04
0.05
0.24
V-45
-------
KM"UR*v_ GASOUME
3.5
1SOMPRATE
E.O
"O'
REPORMAT£
2.7
BTX
Ext
r^'v_^.K*T
RA.FFiMA.Tg.
2.0
4-4,0
DOM. CRUDE
IMP. CRUDE
CATAi Vt'iC
-M < 1G=
31 R-O
I5.&
RST^ORMATE
12 .C
4.6
JET FUEL.
4-. 3 _IG^T SASjCH-MsIE.
21.4
*-
~
o.s
JET FUEL
12.1
alkylate 4.6
PC=V1H IC4
POLY GASOLINE.
,a,o
9-8 GA.-bOl.lKiE.
22.0
DOM. CRUDE
7.5
5.2 CSTIUUATES
a i
: 1V.P. CRUDE
2.?
8.o
¦S LOBE BASB stocks
UGMT GA.SOt_t*JB
DISTILLATES
I4.T !
K.E./ PITCH
7&OSG-5
ARTHUR D- i-
ky cash:
.OW D'A
FIGURE V-l SIMP!
HDU
HQU.
AUCYLATIOM /
k>lvmek:z«-:on
HVORO
CRA.CK\MC=
CATALYTIC
CRACK.) U&
££>% COKiV. ¦
-------
2.9
1&OMFS.A.TE
'O"
o"
REFORHWe
2.7
BTX
i.O 'RA.r-"iMATS.
2.0
40.0
i DOM. CRUDE
'' 15.9
23.4,
rspormate
7.5
G>A*bOL-!Ma
9.8
O.l
UET FUEL
3,2
.MK.Y ¦£ 4* * &
. IC4
2Ki /
'XH3N
POLY &ASOUWE.
fc.S
.C.O
GA.SOl.IKig.
3.o v
HDU
5.3
D i ST i'^LAjE S
MP. CRJDE
4.4
1. 4 LUBE B*SB STOCKS
27.
UGw.T G\SO!-IWE
3.9
DISTILLATES
18-3
:*.£ / PITCH
3 - 3 AS.PU.A.L.T
7feOSG-5
ARTHUR D. c
CAoV: 1 , \97GA
FIGURE V-2 SIMP'
HOU
CCKER/'
T" VI&&SEAK
CAV/VS YT< C,
pl&pop.v1. ' rs
w AT A.Ly*T IC.
-w.RACK.t^-jO
<35>% COM V« ¦
-------
MATURE- GASOl
2.9
S5MFBATE
RE.pgFt.MATE.
2,7
l.o PA.PFiKiA.re-
2.0
; 40.o
- DOW. CRUDE
CATA- YT! C
P„E.FOR.MU4Ci
31 R-O
' IMP. CRUDE
15.9
23.4,
REFORMAT E
7.5
>_IG.I-iT &ASOLIM&.
0.7
JET FUEL.
-Z
ALKyUVTE. 4-,fe
PuM-Crr IC4
ALKYLAT'-OW /
POLYMER'. NATION
POLY GA.SOUM6.
16.S
10.0 SASOL1ME.
zo.o
DOM. Ct^UDE.
B.Z
W DU
5-3 DISTlU.t-A.TE6>
195
IMP, GRJ&E
27.8
t-4 LUBE BASS STOCKS
LIGHT GASOt-IWE
3.9
DISTILLATES
8.5
CCK.E / PITCH
3-3
RY CACM: 1,137GB
S.R,
FRACX
HD.U.
CAT.
RE FOR..
XSOM
CATALYTIC
CRACKING
<3S% CCkkV.
-------
Otsfe'
S.Z
UATURi\U GASOUME
EQy.PRA.TE
HDU.
REFORMME
2.7
• O BTX
SWEET
CRUDE
DE.T-
l.O TRA.FF1MATE.
40.0
DOM. CRUDE
' IMP. CRUDE
CAmi.VT! c.
REPORM1WG
S3 R.-O .
23.2,
REFORMATS.
2.O.
JET PU6.U.'
HOU
UlCVT GA'j.cuy.E.
19.8
*• HDU
MHYU^TE 4,8
FURCK. IC4' '
ALKYLA.TSOM /
POLYMER; ZjKTlOKi
POLY CjASOUUS.
lfa-5
lQ.4- GWaOUME
i l 3.7
20.0
DOM. CRUDE.
CATALYTIC
CRACKiUG
SS% COHV. I
7.5
HDU
S«5 DISTli-i.frTE=»
j j imp. cR^as
i j 27.9 -
1.4- i-UBE Basg STOCKS
U&HT GA.SOUWE
NAPHTHA.
VAC,
DtST.
3.9
'DlSTtLiATES '
183
' " COKE./PITCH
3.3 ASPHALT
7fe086-5
ARTMUR. S. L'TT'-E '.MC. 4/26/74^?
FIGURE V-4 SIMPLIFIED FLOVV Oi^GR.^K kCJUkL REFIMER'Y CASE
-------
(sJWURK- GASOUMS
z.z
ISOMFBATE
RSFORMATE
, O BTX
I.O RA.FFiKiA.TE.
z.o
: • 34 .o
: : DOM. CRUDE
' IMP. CRUDE
CA.T/X.I YTI C.
REFORM'! JG:
92 R-O
R.5FQRMATE
6.9
HDU
-:O^T GAftOUMt _
_—
4.0
ifc.O
HDU
< ¦
O.fe
3,9
ALKYLATE.
PURCH-IC4
ALKY L AT' OKJ / :
POLYMe R3AT"iOM
POLY &ASCUWE.
13,4-
-5/C.4-
9
-------
2.2
iSOMPBATE
REPOW.MWE.
2,7
I.O RA.FRMA.Tg.
z.o
34.O
DOM. CRUSE
IMP. CAUSE
CAT/V VT ' C.
fe.O
22,
RSFQRVATE
=35 R-O
HDU
G.A*33-1M£
, pv
lfe.8
O.
-------
GAS3UMS
15/ C&
XSOM.
SOMPRA.TE
HD.U.
BEFOB.WWE
2.7
¦ O BT X
,Q RAF F l MATE.
2.0
34 .O
: DOW. CRUDE
IMP. CRUDE
C/sTAi vnc
RcPO'Ry.'U'i
91 R-O
21.6
REFORMATS
LI GUT aAfbO-IME-
3.2
17.2
15.0
H^ORO
*" CRACX/iNG.
3,9
JET FUEL
AL>^y LA.TE 5.7
polymsr;:ahow
POLY SASOUMt
14.4
11.3 GASOLIME.
!7.0
DOM. CRUDE.
CATALYTIC
CRACK! U&
76% CCMV.
5.8 w
-isf
8.8
HDU
1ST'
¦ j IMP, CFUDE
: 39.3
l.'S LUBE BASE stocks
LIGHT GA.SOUME
HC.ok.er/ j
visbreakJ
VAC, I
DiST. i
DISTILLATES
CCK.E / P1TC14
3.Q ASPHALT
7&OS& -5
ARTHUR S. L'TTLg :MC, 4/26/74^»
&RY CASE U1379C
FIGURE V-7 SIMPLIFIED FLOW DiAGRaK AC.7UA
-------
3.5
lSGMPi=UA.T£
2.0
reformwe
2.7
l.o R^sFFIMATE,
2,0
44.0
O .€>
DCM.
15.8
20.5
12.0
4.7
5.0
— J),
2,2
21.4
o.S,
O.fe
ckvj^'E 5-7
18.0
POLY ii.cjCL'WE.
)=>.! GASOLIKjE.
1.9
zz-.o
DOM
5.5 u
3.1
4-5 CiST:ui_^TE^
23.5
5 lOSE BASS STOCKS.
Q-4
3.5 ASPHALT
i VlSb^cAK
-.-*o^VT ok;
.'AT
3Z. R.-0
ST.
TfeC-SG -5
\R~-vUS. I. _
. 4/26/74 ,$3
FiGUR- 7-8 SlMPL'FitD Fl3v'/ DA'
:^v CA^>E 5 , i974Av
-------
40.0
ocvi, c.Po:.*r-
il.G
r- rw
HYDhC&B*
AJT.
c r; -
Swl.f:
i.O PAFPiMATE.
92 R-O
. VAC, I
9.&V-*~dist
V^'
yE . F OEw
¦-—M a, Jr . .
RACK-i^i
79% COklV.
7.2 ir
M D -u
LB >UB£ SAS5 STOCKS
0.4-
NiAsPMT'r4Av
CuKEk,.
V15&=?SAK.
D'.STILLA^ES
I8.£ i
3.3
20.0
jOM -""H s
28.0
7GOSG -o
I,- _
.. a/26/74^ FIGURE 7-9 SIMP'JFiED F-_3V/ L'A^
,^-v C/VoE 5, I97&A
-------
KIATVjPA.. 3ASO
2.9
(SOW* PRATE
S- ~r\.
FRACT,
HDU.
i
j
REFOFkMATE.
j
O RAF "inJAT V~
=Os_Y GA&OUUE.
Ifc.5
0.5
20.0
DOM, CRUC
4.6
Z^ACXi wi
73% COKJV.
3.5 cisth
IW.P. CC\J3S
28.0 -
8-0
t.3 i-UBE BASS STOCXS
COKES./
t V1S5REAK.
3.9
DISTILLATES
1.2
18.3
I
!
I
I
8-B a^rha.ut
FIGURE 7-10 SIM?
H Y
-------
VI. ANALYSIS OF REFINERY OPERATION
The purpose of the present section is to illustrate qualitatively
the changes in refinery operation as lead-free gasoline is introduced
and lead phase-down is implemented. This should allow additional
insight and interpretation to the Model Results of Section III, but
the results themselves will not be presented in the present section.
In considering the changes in refinery operation due to the introduction
of low lead gasoline, it is important to note that specific refinery
operation modes are obtained through a cost optimization (specifically
utilizing linear programming). Since the objective function is an optimized
composite, the computer optimizes all cost elements simultaneously,
including capital costs, raw material costs, and operating costs. Thus,
we cannot interpret the refinery operation changes in terms of any one
individual element (e.g., raw material intake, by-product production,
capital costs, lead additive costs), for such individual elements
represent only a portion of the overall optimization and may be out-
weighed by other elements in the selection of the refinery operating
units. If it is deemed important that conserving raw material supply
and maximizing by-products are the most important factors in refinery
operation, then these scenarios can be achieved by appropriate use of
high crude oil costs as data input to the model, as well as high
revenues for by-products. In general, this was not attempted in the
present study (except in Case 6, for gasoline and fuel oil maximization);
rather, all input and output factors were set at projected realistic
levels for the U.S. refining industry. There will therefore be limita-
tions on the ability to isolate any single factor as the cause for the
selection of specific refinery operating units, capacities and blending
strategies in the present section.
A. Crude Penalties
In order to evaluate the reasons for specific crude penalties,
one must consider the overall refinery material balances, because
significant changes in gasoline blending strategy are present when
moving from Scenario A to B to C. Such evaluations of material
balances allow a determination of, for example, the gasoline grade
into which FCC gasoline is blended in Scenario A versus Scenario C.
Furthermore, such material balance considerations also require evalua-
tion of intakes of major processing units among the various scenarios.
Figures V-l through V-10 present refinery flow diagrams for
selected cases and scenarios. These diagrams supplement the following
gasoline blending tables in that they define, among other things, the
reformer severity, intake rate and naphtha source. For clarity, the
diagrams are based on a nominal 100,000 B/CD refinery and the stream
flow rates are completely enumerated in these figures only for gasoline
streams. Since other product streams than gasoline, fuel oil and LPG
are held fixed and can be determined from Tables V-l through V-ll,
these were not included in Figures V-l through V-10. The complete
VI-1
-------
refinery stock balances will be Included, however, in the Phase II
report,
Figure VI-1 provides a chronological summary of the optimum
processing unit intakes for the Case 1, actual refinery, from 1974
through 1980, for Scenarios A, B, and C. On the catalytic reformer
intake graphs, the numbers shown represent the clear octane operating
severities for 1974, 1976, and 1980 for each scenario. The numbers
on the catalytic cracking graphs represent conversion for the same
runs,
One can observe a decline In the growth rate of the major conver-
sion processing units (catalytic cracking and hydrocracking) in Scenario
A over time. This is due to the increase in low sulfur residual fuel
oil yield (primarily at the expense of gasoline), In order to compen-
sate for the decreased growth rate of these conversion unit processes
which produce higher octane gasoline blending components, the relative
growth rate of catalytic reforming intake and severity are increased
over time for Scenario A.
A consistent trend in unit intakes in Figure ¥1-1 can be noted
in changing from Scenario A to B to C. The Scenario B unit intakes
always fall between those of Scenarios A and C, although the
difference is not always sufficient to justify a separate line in
Figure VI-1. This figure suggests that the lead-free gasoline pool
was produced by increasing FCC intake and severity to make more FCC
gasoline (with high clear octane number) and more FCC olefins. The
additional FCC olefins then lead to increased alkylation capacity,
thus providing an additional gasoline blend component with a high
unleaded octane number. Since additional gasoline is being introduced
into the pool from these sources, hydrocracker intakes are decreased
for Scenario C relative to Scenario A. This leads to less light
hydrocracker gasoline (which requires lead for blending) and less
heavy hydrocracker naphtha for reformer feed. From Figures V-5 through
V~7» the changes in unit intakes are displayed for 1979 (note particularly
that slight changes in the straight run component of the reformer intake
take place simultaneously). In addition, it should be noted that,
although catalytic reforming intake is decreased in Scenario C, the
operating severity is increased. The purpose of this is to replace
the octane barrels lost due to lead phase-down. However, the
simultaneous changes of all of these unit intakes leads to a far lower
crude penalty in producing a fixed gasoline production than would be
expected due to reformer severity alone (the reformer yield losses
may be calculated from Figures V-5 through V-7, and they are much
larger than the crude penalties summarized in Table V-12, 1979)~
It should also be noted that the clear pool octane number has
increased from Scenarios A to B to C. The table below summarizes the
clear pool octane numbers for Case 1, 1974A, 1976, and 1979. Because
of the increased fraction of lead-free gasoline in the pool from 1976
VI-2
-------
i
u>
Q
U
cQ
5
2
lii
*
4
h
-2
if)
D
J
b"
0
h
91 CKl
3Z/9S^Ai&
'&14-
^V-VC*
pwi
oo^cr")
c
'M-B.
I
IS
7G
—I
77
I—
?a
13
—I—
BO
FIGURE *21 - 1
PROCESSKiG UN IT INTAKES, ACTUM. RERKiERY
CASE S
-------
Gasoline Blending and Clear Pool Octane Numbers
R-0
B
M-0
1974
'1976
1979
89.4
89.6
89.5
89.6
90.7
90.0
91.8
81.2
81.2
81.0
51.2
31.8
81.4
82.6
through 1979, the clear pool octane increases with time from 1976 to
1979. Hence, the increase in pool octane between Scenarios C and A
becomes larger from 1976 to 1979.
It is important to note, however, that the average leaded research
octane in Scenario A, 1979 , is significantly higher than that of
Scenario C, 1979. This is because of the higher pool lead level in
Scenario A (see Table V-l), which thus provides a pool research octane
of ab.out 96 (fully leaded) compared to a pool octane for Scenario C
of perhaps 93 (some leaded gasoline combined with unleaded gasoline).
This lower octane level for Scenario C is, of course, a natural result
of the case definitions of Section II, and is entirely consistent with
lead phase-down regulations and announced octane requirements of
new automobiles. However, the crude penalty for lead phase-down in
Case 1 would thus be expected to be far lower than for a case for which
the pool octane is held fixed after lead phase-down, for example.
Such cases have been quoted as Indicating a penalty for lead phase-down
by some other sources, but we feel that such penalties are unrealistic
because they are based on unrealistic assumptions.
Further information regarding the refinery operations used to
achieve the lead-free gasoline pools of Scenarios B and C can be
obtained by evaluating the gasoline blending strategies used for selected
years. In Table ¥1-1 is shown the base case blend summary for Case 1,
1974, Scenario A. The refinery flow diagram for this case, shown in
Figure V-l, illustrates the source of the intake streams for reforming,
hydrocracking, and catalytic cracking. The scenarios for 1976 are
shown in Tables VI-2 through VI-4 and the corresponding refinery flow
diagrams are shown in Figures V-2 through V-4.
In 1974 and 1976, Scenarios A and B both require approximately
the same severity of reformer and cat cracker operation with only
1976C requiring a high severity reforming (100 Clear RON). In 1976
there is still no need for high severity catalytic cracking operation
even for Scenario C, However, comparison of Figures V-l through V-4
shows that hydrocracker feed is being reduced in 1976 versus 1974
(actually, less new capacity is added), and is diverted to catalytic
cracking for reasons discussed above. This also leads to decreased
VI-4
-------
Table VI - 1
Gasoline Blending Summary Case I, 1974 A
Units are MB/CD in 100 MB/D Refinery
Gasoline
Grade
Component
Premium
Regular
Lead-Free
Total
90 Reformate
4.27
12.39
.65
17.31
95 Reformate
3.76
-
-
3.76
Low Sev Cat Crk
5.68
4.14
-
9.82
Alkylate
4.56
-
-
4.56
n Butane
1.73
.83
.10
2.66
Light Hydrocrack
-
4.31
-
4.31
Coker Gasoline
-
.43
-
.43
Natural Gasoline
-
2.63
-
2.63
Straight Run
—
4.17
.25
4.32
Totals
20.0
28.90
1.00
49.90
reformer intake.. Tables VI-2 through VI-4 show that the lead-free
pool is produced by primarily using the reformate and alkylate previously
in the leaded gasoline in Table VI-2. In addition, there is more high
unleaded octane FCC gasoline and alkylate available in 1976c than
1976A, because of the unit intake adjustments discussed above. Also,
as shown in Table V-l, the pool lead was decreased, although the premium
and regular grade lead levels were increased. The presence of light
hydrocracker gasoline in the lead-free pool for 1976 was unusual
among the many cases run, because of its low unleaded octane number.
The more extreme case represented by a higher level of unleaded
gasoline in the pool is summarized in Tables VI-5 through VI-7 and
Figures V-5 through V-7. The changes in unit intakes in Figures V-5
through V-7 are again consistent with the trends from Scenario A to B
to C noted above, but are more extreme for 1979. The FCC and reforming
severities are significantly increased from Scenarios A to B to C,
producing more high unleaded octane gasoline and more olefins.
Because of reformer yield losses and decreased intake, the total
quantity of reformate is decreased, but this is more than compensated
for by increased FCC gasoline and alkylate. The lead-free gasoline
pool may thus be achieved, as noted in Tables VI-5 through VI-7, by
blending all the available reformate, and large fractions of FCC
gasoline and alkylate in Scenario C relative to Scenario A. Hence,
the lead-free pool requirements can be met without sacrifice of total
gasoline (all scenarios produce 47,000 B/CD), or, otherwise stated,
with little crude penalty. The crude penalties discussed in Section
III C, by the way, would represent about 0.1% of the total gasoline
VI-5
-------
Table VI
Gasoline Blending Summary Case 1, 1976 A
Units are MB/CD in 100 MB/D Refinery
Component Premium
90 Reformate 2,73
95 Reformate 4.60
Low Sev Cat Crk 5.50
Alkylate 4.63
n Butane 1.65
Light Hydrocraclc
Coker Gasoline
Natural Gasoline
Straight Run
Gasoline Grade
Regular Lead-Free
12.34
4.53
.90
4.13
.40
2.18
4.40
.65
.01
,10
,25
Total
15.08
5.25
10.03
4.64
2.65
4.13
.40
2.18
4.65
Totals
19.11
28.89
1.01
49.01
Table VI - 3
Gasoline Blending Summary Case 1, 1976 B
Units are MB/CD in 100 MB/D Refinery
Gasoline Grade
Component
Premium
Regular
Lead-Free
Total
90 Reformate
1.28
6.08
7.61
14.97
95 Reformate
3.32
-
2.03
5.35
100 Reformate
-
-
-
-
Low Sev Cat Crk
4.69
5.35
-
10.04
Hi Sev Cat Crk
-
_
-
_
Alkylate
1.83
-
2.81
4.64
n Butane
.83
.56
1.25
2.64
Light Hydrocrack
1.76
1.68
,68
4.12
Coker Gasoline
-
.40
-
.40
Natural Gasoline
-
2.18
_
2.18
Straight Run
—
4.34
.31
4.65
Totals
13.71
20.59
14.69
48.99
VI-6
-------
Table VI - 4
Gasoline Blending Summary Case 1, 1976 C
Units are MB/CD in 100 MB/D Refinery
Gasoline Grade
Component
Premium
Regular
Lead-Free
Total
90 Reformate
-
5.89
5.74
11.63
95 Reformate
4.97
-
2.03
7.00
100 Reformate
-
-
1.28
1.28
Low Sev Cat Crk
4.17
6.23
-
10.40
Alkylate
2.67
-
2.12
4.79
n Butane
.96
.65
1.04
2.65
Light Hydrocrack
.92
.92
2.14
3.98
Coker Gasoline
-
.40
-
.40
Natural Gasoline
-
2.18
-
2.18
Straight Run
—
4.33
.35
4.68
Totals
13.69
20.60
14.70
48.99
Table VI - 5
Gasoline Blending Summary Case 1, 1979 A
Units are MB/CD in 100 MB/D Refinery
Gasoline Grade
Component
Premium
Regular
Lead-Free
Total
90 Reformate
2.87
10.54
-
13.40
95 Reformate
5.61
-
.59
6.20
Low Sev Cat Crk
5.23
4.37
-
9.60
Alkylate
4.41
-
.01
4.42
n Butane
1.68
.77
.09
2.54
Light Hydrocrack
-
3.98
-
3.98
Coker Gasoline
-
.38
-
.38
Natural Gasoline
-
1.66
-
1.66
Straight Run
—
4.60
.22
4.82
Totals
19.80
26.29
.91
47.00
VI-7
-------
Table VI - 6
Gasoline Blending Summary Case 1, 1979 B
Units are MB/CD in 100 MB/D Refinery
Component Premium
90 Bsformate
95 leformate
100 Reformate
Low Sev Cat Crk 3.83
Hi Sev Cat Crk
Alkylate 1.25
n. Butane
Isobutane .28
Light Hydroerack 1.74
Coker Gasoline
Natural Gasoline
Straight Run
Gasoline Grade
Regular
4.23
.13
.71
.38
1.66
3.18
Lead-Free
8.38
4.73
5.80
1.97
3.53
2.06
1.74
.1.66
Total
8.38
4.73
5.80
8.06
1.97
4.78
2.19
.28
3.92
.38
r. 66
4.48
Totals
7.10
10.29
29.60
46.99
Table VI - 7
Gasoline Blending Summary Case 1, 1979 C
Units are MB/CD in 100 MB/D Refinery
Component Premium
90 Reformate
95 Reformate.
100 Reformate
Low* Sev Cat Crk
Hi Sev Cat Crk 3.61
Alkylate 3.07
n Butane ,02
Isobutane .37
Light Hydroerack 1.03
Coker Gasoline
Natural Gasoline
Straight Run
Gasoline Grade
Regular
4.88
.83
.24
2.20
.34
Lead-Free
5.66
.19
11.52
2.73
2.79
1.91
.05
1.66
3,11
Total
5.66
.19
11.52
4.88
6.34
5.69
2.17
.37
3.23
.39
1.66
4.92
Totals
7.10
10.30
29.62
47.02
VI-8
-------
in Table VI-7. The trends in pool lead discussed above for 1976 are
also evident in 1979.
Refinery flow diagrams for selected years of restricted unit
capacities (Case 5) are shown in Figures V-8 through V-10, which can be
compared to the unrestricted capacity runs (Case 1) in Figures V-l through
V-4. As can be seen by comparing Table V-l to Table V-5, the product
outturns from these cases are identical, but significant additional
butanes must be purchased for Case 5 because of lower hydrocracking
unit intakes. Comparison of the appropriate refinery flow diagrams
shows how significantly different refining unit size distributions can
provide the same product outturns from the same crude run. Hence, it
is not surprising that the crude penalties and energy penalties were
relatively insensitive to the case under evaluation, as discussed in
Section III C.
The gasoline blending summaries for the flexibility study
(ability to maximize either gasoline or fuel oil with lead phase-down)
are shown in Tables VI-8 and VI-9, for winter operation and summer
operation, respectively. From these, tables, it is apparent that the
reformer intake varied quite widely from summer to winter. The
alkylate availability was much higher in the summer, due to the production
of FCC olefins from higher FCC unit intakes (Table V-6).
The clear pool octane is higher in the winter, 91.0/82.6, than
in the summer, 90,0/81.0. This is obtained by operating at a very
much higher reformer severity in the winter than summer but, at the
same time, not requiring any high severity cat cracking in the winter
(Table V-l7). This results from the fact that maximum fuel oil
production is not consistent with maximum conversion of cat cracker
feed to gasoline, and the pool octane must then be made up, producing
high octane reformate blending stocks. Additional detailed discussion
on Case 6 is contained in Section VI C.
VI-9
-------
#
Table VI - 8
Gasoline Blending Summary Case 6, 1976 A Winter
Units are MB/CD in 100 MB/D Refinery
Component Premium
90 Reformate -
95 Reformate 2.14
100 Reformate 8.40
Low Sev Cat Crack -
Alkylate 2,13
Poly Gasoline
n Butane 1.69
Isobutane -
Light Hydrocrack .69
Coker Gasoline
Natural Gasoline
Straight Run
Gasoline Grades
Regular
3.89
1.24
6.63
.93
1.33
.24
1.19
.40
2.18
4.74
Lead-Free
.37
.11
.03
.11
.14
Total
3.89
3.75
8.51
6.63
3.06
.03
3.13
.24
1.88
.40
2.18
4.88
Totals
15.05
22.77
.76
38.58
Table VI
Gasoline Blending Summary Case 6, 1974 A Summer
Units are MB/CD in 100 MB/D Refinery
Component Premium
90 Reformate
95 Reformate 4.70
100 Reformate
Low Sev Cat Crk
Hi Sev Cat Crk 6.88
Alkylate 5.74
Poly Gasoline -
•n Butane 1.46
Light Hydrocrack .57
Coker Gasoline
Natural Gasoline
Straight Run -
Gasoline Grades
Regular Lead-Free
11.19
5.20
2.57
1.13
1.16
1.12
1.78
5.10
.27
,07
.32
.09
.25
Total
11.19
4.97
5.20
9.52
5.74
.32
2.68
1.73
1.12
1.78
5.35
Totals
19.35
29.25
1.00
49.60
VI-10
-------
B. Economics
The new capital investment for the period 1974-1980 is estimated
to be about 8 billion dollars (1974 dollars) for all cases studied,
except for Case 3 (71 gasoline growth), which is estimated to be 11.75
billion dollars. The table below shows a detailed summary of new capital
investment for Cases 1, 2 and 3, A, B, and C plus Case 5.
TABLE VI-10
Cumulative New Capital Investment Above 1974
Billions Dollars (1974 $)
1975
1976
1977
1978
1979
1980
Case
1
Complex
• (A)
1.25
2.66
3.80
5.11
6.67
8.29
A
which plots cumulative net capital investment for C-B and
B-A for Case 1 Actual and Complex. It is not likely that Case 1 Actual
will show a cumulative capital investment credit for C - B as is shown in
this figure. What the studies do show is that in any given year the
magnitude of the deltas (B-A or C-B) is small (less than 5%) of the
capital investment in that year, i.e., the difference in capital invest-
ment between the two lead phase-down scenarios is too small to be accurate-
ly determined without more time. However, the new capital invest-
ment figures themselves are reliable and accurate. This study does show
that new capital investment requirements are not sensitive to any of the
parameters studied except for rate of gasoline growth. They also show
that the model simulation "complex" requires a higher cumulative delta
plant investment than the model simulation "actual".
¥1-11
-------
if
fo
&
xf-
£
-j'
2
0
j
5 ''s"
t 1.4-
1
uJ
I 1.2-
if)
0! l-O
>
?0,8"
h
2°'G
4
Jn,4-
d
<3
111
>
5
j
3
2
3
o
0.2-
O -
-0,2 -
B-A
C~B
1 J 1 ! ! 1 1
197-4 75 76 77 7& 79 SO
1 r 1 1 j 1 1—
1974 75 76 77 78 79 8G
FIGURE IH-Z
DELTA* CUMULATIVE lUVESTMtUT NUMMARY
COMPLEX VS. ACTUAL
-------
As an example of this consider the year 1979, Case 1
actual and complex. Tables V-23 and ¥-29 indicate that the
"actual" refinery in 1979 Scenario B requires an additional
investment of $130,000,000 (1974 $) relative to Scenario A and
that Scenario C is $290,000,000 cheaper in Investment than
Scenario B, For the complex refinery in the same year Scenario
B is $200,000,000 more expensive than Scenario A.and Scenario C
is $430,000,000 more expensive than Scenario B» This same type
of situation is also represented by the cumulative delta plant
investments shown in Figure VI-2« In all cases for both
"actual" and "complex" Scenario B is more expensive than
Scenario A, with the increment being smaller for the actual
refinery. However, the differences for B-C show an anomaly-
Scenario G is cheaper than Scenario B for the years 1979 and
1980 for the actual refinery. For the complex refinery
Scenario C is more expensive than B for all years.
This may be explained by reference to the Basic Data
in Tables ¥-1 and ¥-8,a-portion of which are condensed and
tabulated below for Case 1.
TABLE ¥1-11
Intakes MB/CD
ACTUAL COMPLEX
79 A
B
C
79 A
B
C
Cat Reform
4617
4609
4400
4369
4307
4418
Cat Crack
3374
3432
3644
3814
4110
4181
Hydro Crack
2349
2318
1984
1224
1107
1278
Coking
599
599
599
599
599
599
Alky
807
872
1038
929
1000
1013
H2 Production
2756
2568
2025
1387
1114
1213
Desulf (NAP)
4606
4624
4660
4667
4700
4689
(Gas Oil)
255
298
387
1253
1255
1221
(V60)
1193
1136
1289
1911
2056
1863
Note that in the "complex" relative to the "actual"
refinery the catalytic cracker capacity and gas oil desul-
furization capacities are substantially higher and the hydro-
cracking and hydrogen manufacturing capacities are substan-
tially lower. The other process capacities are more nearly
equal between the two scenarios. To explain the apparent
anomaly between investment costs for Scenarios B and C, the
table below is instructive.
VI-13
-------
TABLE VI-12
Delta Intakes MB/CD
79 ACTUAL 79 COMPLEX
Delta B-A Delta'/C-B Delta B-A Delta C-B
Cat Reform
(8)
(209)
(62)
111
Cat Crack
58
212
296
71
Hydro Crack
(31)
(334)
(117)
171
Coking
—
—
—
Alky
65
166
71
13
H2 Production
(188)
(543)
(273)
. 99
Desulf (NAP)
18
36
33
(11)
(Gas Oil)
43
89
2
(34)
(VGO)
(57)
153
145
(.193)
Scenario C (actual) will be less expensive in terms
of investments than B because of the large reduction in cat
reforming,, hydrocracking and hydrogen plant capacities all
of which are expensive units to build. Similar reductions
did not occur in the complex refinery, and changes in ca-
pacities were positive and hence investment will increase
from B to C. When looking at the numbers one must bear two
important features in mind.
1) The LP program optimizes an objective function
which represents a composite of capital, operation,
and raw material costs (less by-product credits), not
merely investment cost.
2) As discussed previously the "actual" refinery has
a more restricted set of processing options relative
to the complex refinery.
Hence, the two refinery sequences, actual and complex,
will not have the same processes and capacities even though
the product specifications, etc. are identical. The com-
plex refinery has more freedom in stream blending.
To further illustrate this argument the penalty in
VI-14
-------
cants per Barrel of total gasoline for the various cases
Is shown below;
Complex Actual
B~A C-B B-A G-B
2.0 3.9 1.4 . 4.0
Note that now the complex refinery has a" smaller pe-
nalty for C-B than does the actual refinery, despite the fact
that the investment was higher.
For 1979 Scenario C the Actual Refinery found it
attractive to increase pool octanes (91.8/82.6 from 90.7/81.8)
by a combination of increased catalytic' cracking feed rate
(3,644 from 3,432) and conversion (76 from 68). . This al-
lowed substantial reductions in the capital intensive pro-
cesses (hydrocraeking,catalytic reforming, and H2 production).
This operating mode was not as efficient from a raw material
utilization and 133,000 B/CD of additional crude and volatiles
were consumed. In the complex model only 41,000 B/CD addi- 1
tional raw material was needed for 1979 C.
Another aspect which must be considered is the im-
pact of the various scenarios and cases on the construction
industry. Figure VI-3 shows the total U.S. intake (1974 -
1980) for the catalytic cracking, catalytic reforming, hy-
drocracking and alkylation units for Case 1 complex. This
particular case is selected for discussion in this section,
because it represents the largest capital expenditure pen-
alty (C-B), and therefore probably the most demanding new
construction schedule. The maximum new construction in
barrels per calendar day required for the period 1974 - 1980
(referred to Scenario A 1974) is shown below:
SCENARIO
Process
A
B
C
Alkylation
203,000
300,000
321,000
Catalytic Reforming
1,078,000
1,043,000
1,087,000
Catalytic Cracking
773,000
1,204,000
1,292,000
Hydrocracking
237,000
254,000
249,000
Hydrogen Prod.
889,000
545,000
610,000
Desulfurization (Naphtha)1,631,000
1,660,000
1,660,000
(Gas Oil)
422,000
425,000
372,000
(VGO)
1,583,000
1,684,000
1,627,000
VI-15
-------
5-
A/B = Si
92
65
Z-
UYPRgCR^CKmG_ - -^- — -
k\ v^Vl AA^\S PRODUCT}
kiC
B#C
)974
7&
79
SO
FIGURE TZL-3
PROCESSING UM IT !NTKK£5
COMPLEX REFINERIES CttSE i
-------
The new construction requirements for crude distil-
lation, coking and vacuum distillation are not listed above because
they are essentially the same for all cases studied other than Case
3 (7% gasoline growth). The differences in barrels per calendar
day between B-A and C-B scenarios are tabulated below:
Process
AB-A
%A
. AC-B
%B
Alkylation
97,000
47.8
21,000
7.0
Catalytic Reforming
(35,000)
(3.25)
44,000
4.22
Catalytic Cracking
431,000
55.8
88,000
7.31
Hydrocracking
17,000
7.17
(6,000)
(2.36)
Hydrogen Prod,
(344,000)
(38.7)
65,000
11.9
Desulfurization:
Naphtha
29,000
00
-
-
Gas Oil
3,000
0.71
(53,000)
(12.5)
VGO
101,000
6.38
(57,000)
(3.38)
By comparison the maximum new construction in barrels
per calendar day for Case 1 Actual is shown below, (This case
had the smallest capital expenditure penalty for B-A and C-B).
Process
SCENARIO
B
Alkylation ' 18$,000 315,000 404,000
Catalytic Reforming 1,129,000 1,079,000 968,000
Catalytic Cracking 804,000 892,000 1,050,000
Hydrocracking 654,000 623,000 366,000
Hydrogen Prod. 1,246,000 964,000 681,000
Desulfurization:
Naphtha 1,603,000 1,647,000 1,655,000
Gas Oil None required
VGO 1,161,000 1,101,000 1,174,000
The differences in barrels per calendar day between B-A
and C-B scenarios are tabulated below:
VI-17
-------
Process
Alkylation
Catalytic Reforming
Catalytic Cracking
Hydrocracking
Hydrogen Prod.
Desulfurization:
Naphtha
Gas Oil
VGO
AB— A /ok
130,000
70.3
(50,000)
(4.43)
88,000
10.94
(31,000)
4.74
(282,000)
(22.6)
44,000
2.74
60,000
5.16
AC-B %B
89,000 28.3
(111,000) (10.3)
158,000 17.7
(257,000) (41.2)
(283,000) (41.6)
8,000 0.48
73,000 6.22
A major conclusion to be drawn from these is that in general
the incremental construction requirements between scenarios are
•quite small compared to the total construction requirements for
any scenario between 1974 and 1980. For example, the total new
refining capacity required between 1974 and 1980 is 6,027,000 B/D
for Scenario A or an average of 5 new 200,000 B/D refineries
per year.
VI-18
-------
G. Refinery Flexibility
Section IV has stated that the refiner loses no flexibility
in capability to maximize either gasoline or fuel oil due to lead
phase-down through 1976, during which time he is constrained to the
use of individual unit capacities as they exist today. Attached
Table VI-13. summarizes refinery intakes and out-turns, selected unit
intakes, and operating cost figures, which will 'now be discussed in
more detail.
The total refinery crude run in Case 5 is shown to be 15,404 i
MB/CD for Scenarios A, B, and C, whereas for Case 6 the total crude
run is 15,460 MB/CD for all scenarios, both summer and winter. As
concluded In Section IV, there is no incremental crude penalty in
comparing Scenarios A, B, and C in each category because the un-
leaded gasoline represents only 30% of the gasoline pool for B & C.
It is not surprising that the total crude run for Case 6 exceeded
that of Case 5, because the total product out-turns were designed
to differ. Specifically, Case 6 Summer was intended to maximize
gasoline relative to Case 5 and Case 6 winter was designed to maxi-
mize fuel oil. However, it is important to note that the Case 6
Winter and Summer results were obtained with the consumption of the same
crude level, that is, the refinery was run to capacity in both cases
as reflects current refinery practice in summer versus winter opera-
tion.
Purchased butanes also varied in a reasonable level in Table .
VI-13. Butanes are produced in the refinery principally by reform-
ing, hydrocracking, and catalytic cracking. Other butane inputs are
of course, purchased butanes and distillation of crude and natural
gasoline. Butanes are consumed in the refinery by gasoline blend-
ing, LPG blending, and alkylation of olefins with isobutane. Natu-
ral gasoline was purchased to the limit of its availability, so it
was invariant. Comparing Case 5 to Case 6, Summer, a minimum LPG
production of 402 MB/CD was fixed in both cases to meet projected
market demands, so it was invariant. Alkylation was run to capa-
city to produce gasoline alkylate, so . it could not change between
the cases. When 9.5 RVP gasoline was maximized in Case 6, only
about 100 MB/CD additonally was produced compared to the 10 RVP
gasoline production of Case 5. The increased butane production
from increasing cracking unit intakes, coupled with the lower RVP
gasoline in Case 6, allowed decreased purchase of butanes. In-
deed, Case 5 C compared to Case 6 C, Summer, exhibited the
following unit operations:
VI-19
-------
TABLE VI-
13 FLEXIBILITY ANALYSIS - MB/CD
1976
1
Case V,
10 RVP
Case VI
,Summer,
9.5 RVP
Case 6,
Winter
12 RVP
\
A
B
C
A
B
C
A
B
C..
Domestic Sweet Crude
6,184
6,184
6,184
6,184
6,184
6,184
6,184
6,184
6,184
Domestic Sour Crude
3,092
3,092
3,092
3,092
3,092
3,092
3,092
3,092
3,092
Imported Sweet Crude
1,793
1,793
1,793
1,793
1,793
1,793
1,793
1,793
1,793
Imported Sour Crude
4,327
4,335
4,335
4,391
4,391
4,391
4,391
4,391
4,391
Sub Total Crude
15,396
15,404
15,404
15,460
15,460
15,460
15,460
15,460
15,460
Natural Gasoline
448
448
448
448
448
448
448
448
448
Purchased Refinery Fuel
387
387
387
387
387
387
387
387
387
Iso Butane
108
108
108
108
108
93
108
108
108
Norm Butane
108
108
108
65
86
3
108
108
108
Total Input
16,447
16,455
16,455
16,468
16,489
16,391
16,511
16,511
16,511
BTX
155
155
155
155
155
155
155
155
155
Naphtha \
247
247
247
247
247
247
247
247
247
Kerojet
897
897
897
897
897
897
897
897
897
Kerosene
216
216
216
216
216
216
216
216
216
High Sulfur Fuel
155
155
155
155
155
155
155
155
155
Lube Base Stocks
216
216
216
216
216
216
216
216
216
Asphalt
510
510
510
510
510
510
510
510
510
Cok;e
216
216
216
216
216
216
216
216
216
Subtotal Fixed
2,612
2,612
2,612
2,612
2,612
2,612
2,612
2,612
2,612
Prem Gaso
2,953
•2,118
2,118
2,992
2,342
2,364
2,327
1,820
1,820
Reg Gaso
4,468
3,185
3,185
4,526
3,033
3,061
3,520
2,356
2,356
Lead-Free Gaso
155
2,273
2,273
153
2,304
2,325
119
1,789
1,789
Subtotal Gaso
7,576
7,576
7,576
7,671
7,679
7,750
5,966
5,965
5,965
Distillates
3,448
3,448
3,448
3,496
3,434
3,312
4,696
4,696
4,696
Low Sulfur Fuel
1,6,39
1,639
1,639
1,593
1,565
1,509
2,140
2,140
2,140
LPG
402
402
402
402
402
402
433
433
433
Total Products
15,677
15,677
15,677
15,774
15,692
15,585
15,847
15,846
15,846
Refinery Fuel
1,189
1,200
1,200
1,212
1,212
1,234
1,028
1,028
1,028
Purch. Power-Mil KWH
63
63
63
63
63
64
57
57
57
Lead Level-Prem.
1.27
1.81
1 .'81
1.29
2.22
2.19
.59
.82
.82
Reg.
1.24
1.79
1.79
1.84
2.74
1.85
1.27
1.45
1.45
Intake-Cat Reform
3,482x
3,530
3,530
3,316
3,381
3,527
3,480
3,480
3,480
Cat Crack
3,664
3,565
3,565
4,040
4,035
3,981
1,991 .
1,993
1,993
Hydrocrack
983
980
980
994
1,007
1,002
986
986
986
Coking
597
597
597
597
597
597
597
597
597
Alky (Prod)
897
897
897
897
897
897
478
487
487
H2 (MMSCFD)
772
741
741
931
900
799
589
. N580
580
Desulf (Naph)
3,916
3,953
3,953
3,969
3,969
3,969
3,941
3,943
3,943
(Gas Oil)
• 669
770
770
289
295
349
960
960
960
(VGO)
1,339
1,240
1,240
1,721
1,715
1,661
1,050
1,050
1,050
Operating Cost $ MM
8.19
8.19
8.19
8.53
8.65
8.50
7.05
6.98
6.98
Capital Charge $ MM
12.80
12.75
12,75
12.94
12.97
13.02
11.68
11.69
11.69
Cat Cracker Conversions
79
79
. 79
77
77
82
65
65
65
Cat Reformer Severity '
92
92
92
92
92
92
97
97
97
Gasoline Pool Octanes R-0
90.6
90.5
90.5
90.0
90.1
90.9
91.0
91.0
91.0
VI-20
-------
Case 5 C
Case 6 C, Summer
FCC Intake
FCC Conversion
Hydrocracker Intakes
Cat Reformer Intake
3565 MB/CD
3981 MB/CD
82%
79%
980 MB/CD
3,530 MB/CD
1,002 MB/CD
3,527 MB/CD
92
Cat Eefome^Sevgjigj
92
Since each of these units produce as much or more butanes for
Case 6 C than Case 5, since the volume of the gasoline pool in-
creased only 100 MB/CD for Case 6 C, Summer, and since the vapor
pressure of the pool is lower for Case 6 C, decreased purchased
butanes is expected. Also, the amount of purchased butanes
should be less for Case 6 C, Summer than Case 6 A, Summer, by
the same reasoning. Finally, because both isobutane and normal
butane were purchased at $6.74/bbl,, the use of isobutane as a
higher octane blend stock and as alkylation plant feedstock would
require that purchases of normal butane be restricted preferentially,
as observed in Scenarios A, B, and C of Case 6, Summer.
In Case 6, Winter, by contrast, minimum LPG production was
•raised to 433 MB/CD to meet projected market demands. In addition,
the R¥P of the gasoline was raised to 12 psi, the FCC intake was
drastically reduced to maximize fuel oil production, and the
butane production from the hydrocracker remained about constant.
Furthermore, the propane production in the FCC unit (a primary
blend component for LPG) was similarly reduced by two-thirds.
Hence, it is not surprising that butane purchases had to be in-
creased to the maximum possible level of 108 MB/CD in Case 6,
Winter. Note, however, that the consumption of butanes for al-
kylation also decreased ( due to limited FCC olefin supply ), but
not in sufficient amounts to offset the above effects. Finally,
it can be seen from Table VI-13- that the reformer severity and intake
was higher for the winter than the summer. Because of the decreased
LPG production of the FCC unit under maximum fuel oil operation
and the inability of the hydrocracker to make more LPG without
increasing jet fuel and gasoline production, the incremental LPG
had to be made on the reformers. This, of course, made LPG from
gasoline (as desired under maximum fuel oil operation), but also
significantly increased reformer severity (97 in winter versus
92 in summer) and thus increased gasoline pool octane. Referring
to Table VI-13 it can be seen that Case 6 A had a summer pool
octane of 90.0 whereas the winter octane for Case 6 A was thereby
increased to 91.0, in order to meet LPG demands. By contrast,
Case 6 C Summer pool octane was 90.9 in order to meet unleaded
gasoline requirements; hence, the increase of Case 6 CWinter to a pool
octane of 91.0 to meet LPG demands resulted in no dramatic
penalty in refinery flexibility. It may thus be concluded that
increased LPG market demands due to natural gas curtailments will
allow unleaded gasoline to be produced in the winter with no
flexibility penalty. In general, strong market prices for LPG
¥1-21
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in the future are very important in that they will cause a signi-
ficant shift in economic incentives to the refiner, thereby
making past experiences an inaccurate predictor of future operating
penalties regarding unleaded gasoline.
In this regard, it is important to note that, although the
Case 6, Summer, results do not deviate from normal refinery
practice (i.e. refinery gasoline production is not limited by
purchased butanes), the Case 6, Winter, results are atypical.
This is due to the rather extreme variations in FCC intake allowed
in the absolute maximization of fuel oil in the winter. For
example, although the Winter results represent refinery capability,
gasoline demand in the December, 1973, substantially exceeded 6,000
MB/CD, so this does not represent refinery practice. Hence, even
though refiners often directed propane or butane to fuel in the
winter (before the strong LPG market demand), the extreme situation
of Case 6, Winter, does not necessarily conflict with this practice.
Finally, the low purchases of butanes in Case 6, Summer, may not
actually take place if LPG market pressures increase, However, it
is encouraging to note that, since the Summer butane purchases
are less than projected availability, the refiner still has
flexibility for additional LPG production if prices justify it.
Indeed, Scenario C has the greatest flexibility for increased
LPG production, due to the increased propane and butane produc-
tion described above in making lead-free gasoline.
As shown in Table VI-13 total refinery input is generally
less for Case 6, Summer, than for Case 6, Winter, due to the
reasons described above for lower butane purchases. Also, as
discussed above for total crude run, Case 5 and Case 6 total
inputs cannot be expected to be identical, due to different pro-
duct out-turns resulting from Case 6.
As shown in Table VI-13 all product out-turns other than
gasoline and fuel oil were constrained to be identical by fixed
market demands. The distribution among the several gasoline grades
in Scenarios A, B, and C was set by expected market demand, and was
invariant. The yield to crude varied from about 40% in the
winter to a maximum of about 50% in the summer, which is reason-
able in terms of refinery capability (but not refinery practice).
It has been noted in Section HI that the capability for maximizing
gasoline is not decreased in Scenario C relative to Scenario A
in the summer (Case 6). In fact, it is Increased somewhat! In
addition, the clear pool octane numbers for Case 6, Summer,
shown below illustrate a significant improvement of pool octane
accompanying this increased production:
Scenario
A
B
C
90.9
81.6
Pool Research Octane, Clear 90.0
Pool Motor Octane, Clear 81.0
90.1
81.0
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The increased clear gasoline production is seen from Table
VI-13 t0 be achieved by increasing reformer feed rate signifi-
cantly and increasing FCC conversion. Increased reformer feed
is achieved in part by inclusion of more cokcr naphtha in the
reformer feed; the major contribution, however, is obtained by
removing straight run naphtha from the jet fuel pool and directing
it to the gasoline pool after reforming. The contribution of
FCC gasoline to the pool Is only slightly increased for Scenario
C relative to Scenario A because the increased FCC conversion is
offset by decreased FCC feed rate. By this combination of
changes in the refinery blend structure, it is apparent that the
lead-free gasoline yield can be greatly increased, and the pool
octane can be increased without increasing reformer severity.
The jet fuel directed to reformer feed was replaced by increasing
the recycle cut point on the hydrocracker and by desulfurizing
additional light gas oil. Note also, that the octane number of
the premium grade gasoline was.also achieved by a two-fold in-
crease in lead level in that grade of gasoline. The increased
production of FCC olefins in Scenario C versus Scenario A could
not be used in Case 6 as alkylation plant feedstock because of
•capacity limitations on that plant; if the refinery were "de-
bottlenecked" by increasing alkylation plant capacity (additional
isobutane can also be purchased in Scenario C), even more lead-
free gasoline could have been produced. With the limited plant
capacity, however, the olefins were directed to refinery fuel in
the present model; in actual refinery practice, these olefins
would have higher value as a petrochemical feedstock.
Because of the increased production of refinery C^ - C2
gases associated with more lead-free gasoline production and more
C4 production (resulting in less C^ purchases), it is not sur-
prising that the total product out-take is decreased in Case 6,
Summer, as the refinery is changed to meet the product require-
ments of Scenarios A, B and C. Since more energy is similarly
required to produce the higher pool octane and the higher -
C2 yield from the fixed crude slate, it is not surprising to
observe that the total energy requirements (purchased power,
refinery fuel and FCC coke) are increased in Scenario C in the
summer. Also, as shown in the table below, the arguments re-
garding the conditions required to meet the LPG demands in the
winter would suggest that little or no incremental energy is
required to meet the lead-free pool demands in the winter.
Scenario
TOTAL ENERGY USED, MB/CD FOE
A
B
C
Case 6, Summer
Case 6, Winter
Case 5
1428
1175
1394
1428
1175
1402
1450
1175
1402
VI-23
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Although the product out-turns in Case 5 are designed to
differ from those of Case 6 (thus preventing a detailed comparison
of the cases), the energy consumption is generally consistent with
the average of the Summer and Winter, Case 6, energy consumptions.
The capital and operating charges shown in Table VT-13
are similarly consistent between Cases 5 and 6. These charges
are significantly less for Case 6, Winter, relative to Case 6,
Summer, as would be expected due to the maximum fuel oil versus
maximum gasoline operations,. The primary cost advantages in
the Winter, therefore, are due to the lower FCC unit, H2 unit,
and V.G.O. desulfurization (for FCC feed, in part) intakes, which
outweigh the increased gas oil desulfurization costs. For the
Scenarios A, B, and C within the Summer and Winter cases, the
economic penalties are so small as to be insignificant. Generally,
however, the capital costs follow the energy requirements, as
expected, and for the same reasons. The operating costs in the
Summer are highest for Scenario B due to lead charges; the slight
improvement for Scenario C relative to Scenario A is due to the
effects of lower lead requirements outweighing the slight incre-
mental contribution of capital charges to operating costs.
¥1-24
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D. Energy Penalties
1979 Actual vs. Complex
The total energy consumed (purchased power, refinery fuel, and
cat cracking coke) for Case 1 actual and complex for the year 1979 is
summarized below — both energy and crude are reported in F.E.O. bar-
rels (see Tables V-33 and V-40):
Actual Complex
A
B
C
A
B
C
Total-MB/CD
1636
1654
1676
1595
1617
1647
% Crude
10.09
10.18
10.29
9.83
• 9.93
10.13
This shows
that for
any given
scenario,
A, B,
or C, the
com-
plex refinery consumes less energy, both as a total quantity and as
a percent of crude. This is to be expected since the processes used
in the "actual" refinery (Table VI-11) emphasized hydrocracking and
hydrogen production, both of which consume large amounts of energy
(relative to the decreased hydrocracking of Case 1 Complex). However
the installed U.S. average hydrocracking capacity in 1974 is slightly
less than 900 MB/CD (Table V~5), whereas the 1974 hydrocracking capa-
city in 1974 for Case 1, Actual, is 1,695 MB/CD (Table V-l) and for
Case 1, Complex, is 1,127 MB/CD (Table V-8). Hence, the absolute
level of energy consumption tabulated above may be too large compared
to the expected levels in 1979 for all the above scenarios.
The above table also shows that Scenario B comsumes more energy
than A and that Scenario C consumes more energy than B. This is true
when -the consumption is expressed either in total barrels of equiva-
lent fuel oil or as a percent of crude. As expected the refinery in-
ternal generation of fuel increases from A to B to C. For example,
in 1976. and 1979, the internal fuel generation (F.O.E., MB/CD) is
shown below:
ABC
1976 375 (31.6%) 375 (31.6%) 388 (32.6%)
1979 * 419 (29.8%) 465 (32.7%) 506 (35.1%)
%
The numbers in parenthesis indicate the percent of total refinery fuel
consumed which is internally generated. Note that these percentages
also increase from A to B to C as would be intuitively expected — the
.processes to make lead-free gasoline such as reforming also produce
significant quant.1 tites of fuel, as discussed extensively in Section
VI C.
VI-25
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TABLE VI - 14
1974
. A B
Case 1 1227 1227
Case 2 1227 1227
Case 3 1227 1227
Case 4
Case 5 1238 1238
Case 7
1975
ABC
1305 1305 1305
1306 1305 1308
1334 1334 1334
1308 1316 1316
Total Energy Consumed
(Actual Refinery)
MB/CD
1976
1977
A
B
C
A
B
1386
1386
1392
1470
1474
1386
1392
1393
1470
1482
1454
1454
1458
1578
1578
1386
1386
1392
1394
1402
1402
¥1-26
1978
ABC
1550 1557 1573
1550 1567 1583
1717 1721 1742
1979
ABC
1636 1654 1676
1636 1668 1696
1851 1873 1909
1636 1642 1686
1980
ABC
1739 1773 1784
1739 1787 1806
2010 2053 2077
1636 1653 1673
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TABLE VI - 15
Total Energy Consumed
(Complex Refinery)
MB/CD
1974 1975 1976 1977 1978 1979 1980
ABABC ABC ABC ABC ABC ABC
Case 1 1211 1212 1286 1286 1286 1362 1360 1365 1435 1442 1458 1510 1518 1540 1595 1617 1647 1698 1735 1768
Case 2 1363 1368 1376 1596 1656 1678
Case 3 1435 1433 1438 1807 1845 1873
Case 4 1363 1357 1366 1595 1601 1657
VI-2 7
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Tables VI-14 and VI-15 present the total energy consumed for
the years 1974 to 1980 for various cases, for the "actual" refinery
and the "complex" refinery, respectively. Both these tables show that
for any given scenario (A, B, C) the energy consumption is essentially
independent of the parameters varied except for Case 3 — a 7% per
year growth in gasoline demand illustrates that a larger gasoline pool
will increase energy consumption as well as the penalty between
scenarios. Changing the octane number from 92/84 to 93/85 R0N/M0N
(Case 2), altering the lead-free demand structure (Case 4), restricting
capacity (Case 5), or reducing the premium demand (Case 7) had very
little effect on energy consumption. These two tables also show that,
for reasons discussed above, Scenario B consumes more energy than A,
and Scenario C more energy than B. However, in some years, particular-
ly 1974 - 1976, the differences are very slight, being less than Case 5
versus Case 1 simulations of the refining industry. Specific conclu-
sions regarding energy penalties are discussed in Section III C.
VI-28
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VII. RECOMMENDATIONS FOR FUTURE STUDIES
The main emphasis of future studies on the impact of lead-free
gasoline and lead phase-down should focus on classifying simpler
modules of U.S. refining capacity to specifically address regional
and atypical refining configurations and the sensitivity of capital
investment requirements. At a minimum one should consider at least one
composite refinery for each PAD (Petroleum Administration for Defense)
district. The unique crude supply and product demand/specification patterns
should be developed for use in the regional models.
Several individual refining modules should be postulated to
represent different categories of actual refineries by selectively
dropping one or several potential processing units from those available
for optimization. For example, a refinery would be created with only
catalytic cracking, alkylation and catalytic reforming as the sole
secondary processing options. (If this configuration refinery needs to
process sour crude, then additional hydrotreating facilities would also
be made available.) Then a coker should be added and coke out-turn
increased above the composite volume produced within the region to that
level of production experienced by those refineries who actually have
coleers (which will be two to three times the average production level
within the district). These refineries would, of course, make much less
residual fuel oil. A hydrocracker can be added in lieu of coking and also
the hydrocracking/reforming configuration could be analyzed with no
catalytic cracking/alkylation allowed. These models would selectively
consider varying by-products by increasing respective levels of manufacture
to that experienced by the major producers of the individual by-products.
In this category we would include BTX and other petro-chemical feed stocks,
as well as asphalts, lubes and other specialties.
Finally, we would recommend that further studies be made of
seasonality in refinery crude supply, operations and product out-turn,
although this overview analysis considered some seasonal variations.
VII-1
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completingj
1. REPORT NO, 2,
EPA-450/3-74-032-A
3. RECIPIENT'S ACCESSIOWNO,
4. TITLE AND SUBTITLE
IMPACT OF MOTOR GASOLINE LEAD ADDITIVE REGULATIONS
ON PETROLEUM REFINERIES AND ENERGY RESOURCES -
1974 - 1980 PHASE I
5. REPORT DATE
May 1974
6. PERFORMING ORGANIZATION CODE
7, AUTHOR(S)
N. A.
B. PERFORMING ORGANIZATION REPORT NO.
9, PERFORMING ORGANIZATION NAME AND ADDRESS
Arthur D. Little, Incornorated
Acron Park
Cambridge, Massachusetts 02140
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO,
68-02-1332
Task No. 4
12. SPONSORING AGENCY NAME AND ADDRESS
13. TYPE OF REPORT AND PERIOD COVERED
Final Report
14. SPONSORING AGENCY CODE
15, SUPPLEMENTARY NOTES
18. ABSTRACT
The report presents results of a study to assess the imoact on operations of
petroleum refineries and on enerqy resources of two requlatlons promulgated by the
Environmental Protection Agency to control the level of lead additive in motor
gasoline. The first of these regulations requires the availability of low-octane,
lead-free gasoline for vehicles which will be eouinped with lead sensitive catalytic
converters designed to meet 1975 automotive emission standards. For health reasons,
the second regulation reauires a gradual nhase-down of the lead content of the total
gasoline nool (including higher octane gasoline to satisfy the remain inn hiqh-comnre-
ssion ratio engines). The study considers senarately the impact of each reoulation.
Effects on overall refinery Yields, refinerv operation flexibility to maximize pro-
duction of qasoline and/or heatinq oils, and on enerqv resources reouirements have
been considered. Other parametric studies evaluate suonositions of a need for a
higher octane lead free qasoline and a hiqher demand for lead free aasoline than
now forecast.
«
17. KEY WORDS AND DOCUMENT ANALYSIS
a. DESCRIPTORS
b. IDENTI Fl E RS/OPEN ENDED TERMS
c, COS AT I Field/Group
Gasoline
Gasoline Engine
Tetraethyl Lead
Octane Number
Refineries
Lead-free gasoline
Lead phase-down
Motor Gasoline additives
13B
18. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (This Report}'
Unclassified
21, NO, OF PAGES
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73) VII-?
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