CTD A U.S. Environmental Protection Agency
tl r\ Office of Research and Develooment
Energy,
Minerals and
Industry
EPA-600/7-77-046
May 1977
Review of Environmental
Issues of the
Transportation of Alaskan
North Slope Crude Oil
Interagency
Energy-Environment
Research and Development
Program Report
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of. and development of, control technologies for energy
systems; and integrated assessments of a wide range of energy-related environ-
mental issues.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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REVIEW OF ENVIRONMENTAL ISSUES OF THE
TRANSPORTATION OF ALASKAN NORTH
SLOPE CRUDE OIL
Contract: 68-01-3188
Project Officer: Richard Ball
Office of Energy, Minerals and Industry
Washington, D.C. 20460
Office of Energy, Minerals and Industry
Office of Research.and Development
U.S. Environmental Protection Agency
Washington, D.C. 20460
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NOTICE
This report has been reviewed by the Office of Energy, Minerals and
Industry, U.S. Environmental Protection Agency, and approved for publi-
cation. Approval does not signify that the contents necessarily reflect
the views and policies of the U.S. Environmental Protection Agency, nor
does mention of trade names or commercial products constitute endorsement
or recommendation for use.
ii
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FOREWORD
New large scale energy projects pose a challenge to man and his environ-
ment. Adverse physical, chemical, or biological conditions could occur as a
result of impacts upon the quality of air, land, or water. The Office of
Energy, Minerals and Industry conducts a multidisciplinary interagency
research program designed to identify health and environmental impacts
associated with new energy projects and to develop control equipment and
methods to minimize adverse effects.
This report focuses on the environmental issues associated with the
transportation of oil from Alaska and is part of our interagency program
responsibilities for integrated assessment of the impacts of energy develop-
ment. The purpose of this study is to identify research and development
needs with respect to the movement of North Slope oil. This report also is
useful as a summary of 1) the various factors which have contributed to the
need for transporting crude oil to areas outside of the West Coast, 2) the
various alternatives proposed to distribute the excess oil, 3) the environ-
mental considerations related to such distribution, as well as 4) the
research and development needs in areas where data are incomplete with
respect to environmental issues. This report also is useful in providing a
perspective as to where we have been and where we are in relation to the
movement of Alaskan oil, and to how we may prepare for the future to assure
environmental compatibility. It is envisioned that this report can be
utilized by analysts interested in the problems of Alaskan oil and by
administrators, scientists, and concerned citizens who have input to the
formulation of policy, decisions, and environmental programs associated with
the disposition of Alaskan Oil.
Stephen J. Gage
Deputy Assistant Administrator
for Energy, Minerals, and
Industry
ill
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PREFACE
During 1973, when the Trans-Alaskan Pipeline Authorization Act was
being debated, the Interior Department estimated that the demand for petro-
leum over that provided by domestic production would result in the complete
consumption of North Slope oil within California and other West Coast
states. Present conditions indicate that an excess in available crude oil
supply over demand will range from 600 thousand barrels per day in 1978 to
as much as 1.3 million by the end of 1985. Various alternatives have been
proposed for the distribution of this excess in ways which will allow it to
be utilized by other parts of the United States. The establishment of these
new distribution systems can pose problems with respect to the environment
and human health.
The purpose of this document is to describe the issues related to the
movement of North Slope oil to refineries, to review the state of knowledge
as it pertains to these issues, and to identify information gaps, inconsis-
tencies, and the need for specific research efforts. The focus of attention
is placed upon environmental implications.
It is the intention of this report to serve as a summary of existing
information and, except for recommendations for further studies, not produce
new information. This report may be utilized by policy and decision makers
as a concise summary of the state of knowledge relevant to the movement of
Alaskan oil.
iv
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ABSTRACT
This document is a summary of existing information related to the
transportation of Alaskan North Slope crude oil to U.S. markets. The
report focuses upon various factors which have contributed to the need for
transporting the crude to areas outside of the West Coast, the various
alternatives proposed to distribute the excess oil, the environmental issues
related to such distribution, and the research and development needs in
areas where data are incomplete with respect to environmental issues.
The onset of Alaskan and offshore West Coast oil requires a new pattern
of west-to-east movement of oil which is in excess of anticipated West Coast
demand. Proposals for this movement include Canadian and U.S. pipelines to
carry crude to Northern Tier States which face a decline in Canadian ex-
ports, pipelines from California to midwestern states, tanker traffic
through a canal in Central America or around Cape Horn, and exchanges of oil
with foreign countries.
Environmental issues center on impacts affecting air and water quality.
Air pollution as a result of offloading, venting, purging, ballasting, and
oil storage may require stringent mitigating measures or emissions tradeoffs.
The degree of water pollution is contingent upon the risk of oil spills and
probable oil spill trajectory associated with a particular alternative.
Information is needed in the following areas: 1) how present decisions
regarding pipeline routes may preclude future flexibility in meeting
unanticipated supply and demand patterns; 2) how decisions related to the
distribution of natural gas supplies affect the movement of crude oil; 3)
the resolution of localized supply issues; 4) the need for well documented
air quality models which describe impacts of marine oil terminals; 5) the
development of a regulated West Coast vessel traffic control system; and 6)
how present decisions requiring measures to mitigate air impacts may set a
precedent for future ventures.
This report was submitted in fulfillment of Contract 68-01-3188 by the
METREK Division of the MITRE Corporation under sponsorship of the U.S.
Environmental Protection Agency. This report reflects events through
January, 1977 and was completed as of March 1, 1977.
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CONTENTS
Foreword iii
Preface iv
Abstract v
Figures ix
Tables x
Abbreviations and Terms xii
1. Historical Perspective 1
Evolution of Existing Distribution Systems..... 1
Development of Alaskan Reserves 5
Establishment of a West Coast Surplus 14
2. Alternatives for the Disposition of Alaskan Oil 19
Focus on the Northern Tier States 19
Canadian Oil Curtailments 19
Trans-Provincial Pipeline 19
Canadian Exchanges 22
Trans-Mountain Pipeline 24
Cherry Point Proposal 24
Williams Pipeline 24
Minnesota Pipeline 25
Northern Tier Pipeline 25
North Slope Crude Oil and the Northern Tier States.... 26
International Exchanges 27
Focus on Eastward Movement 30
Tankers Through the Panama Canal 30
SOHIO Proposal 31
Central Alternatives 33
An Elk Hills Route 34
Other West to East Alternatives 35
Tankers/Tank Car Unit Trains 35
Reversal of Four-Corners Pipeline 36
Central American Pipeline 36
Around the Horn. 37
LOOP-SEADOCK 37
Other Solutions 38
Reduced Production of Alaskan Reserves 38
Strategic Storage 39
Enhancement of West Cost Consumption 39
Summary Comparison • 40
3. Environmental Issues Related to the Movement of North
Slope Oil 43
vii
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CONTENTS
(Continued)
Quantitative Analysis of Air Quality Issues 43
Mechanisms for Controlling Air Quality,. A3
Existing Air Quality 49
Quantitative Measurement of the Issues 51
Project Related Emissions Sources 53
Emissions Controls/Tanker and Storage Design 53
Basic Emission Factors 56
Combustion Pollutants 56
Hydrocarbon Emissions from Tankers 59
Hydrocarbon Emissions from Storage Facilities 63
Project Scenarios and Total Emissions 63
Scenario Probabilities 66
Air Quality Modeling Results. 68
Summary of Air Quality Analyses. 76
Water Quality 78
Tanker Status 79
Oil Spill Analyses.... 79
Pipeline Spills 99
4. Pressing Problems 103
National Concern 103
Future Crude Supplies - New Problems.. 105
Information Needs. 108
Broad Issues. .109
Special Issues .110
Studies Relating to Air Impacts 112
Studies Relating to Water Impacts .114
Setting a Precedent 114
References 117
viii
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FIGURES
Number • Page
1 Growth of Crude Oil Pipelines in the United States 3
2 Percentage of Refinery Requirements East of the
Mississippi River 4
3 Mileage of Petroleum Pipelines in the United States 6
4 Alaskan Production Areas 7
5 Alaskan Crude Oil Product ion 8
6 Projected Alaskan Crude Oil Production 13
7 North Alaska Crude Production (BAU) 1975-2000 15
8 Canadian Crude Oil Pipelines (1975) 20
9 Actual and Planned Canadian Exports to the United States.... 21
10 Major Alternative Transportation Systems 23
11 Transportation Savings Resulting from Exchanges with Japan.. 29
12 Summary Comparison of Alternatives... 41
13 Air Quality Quantitative Analysis 52
14 Oil Spill Zone ~ Kitimat 87
15 Oil Spill Zones — Northwest. 88
16 Oil Spill Zones — San Francisco 89
17 Oil Spill Zones — Offshore California and Los Angeles/
Long Beach 90
. 18 PADD V Supply/Demand Balance Forecast 106
19 Outlooks for North Alaska Crude Production in 1975-2000 107
ix
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TABLES
Number
1
?
3
4
•
A
Summary of NO Modeling Results — Port of Long Beach»>««
Summary of Oxidant Modeling Results — Port of Long
Annual Tanker and Terminal Spills by Region and
Page
44
47
48
50
58
60
62
64
. . 65
67
70
73
74
83
91
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TABLES
(Continued)
Number Page
19 Projected SOHIO Tanker Accidents in a 10 Year Period 93
20 Projected Tanker Accidents: Valdez to Puget Sound,
San Francisco 94
21 Accident Location and Oil Spillage 95
22 Sources of Oil Pollution From Tankers 96
23 Probability Per Year of Spills With Less Than Total Loss... 97
24 Probability Per Year of Spills With a Total Loss 98
25 Approximate Predicted Pipeline Statistics 100
26 Potential Maximum Oil Spills at Sensitive Locations 101
xi
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LIST OF ABBREVIATIONS AND TERMS
ABBREVIATIONS
API
AQMA
ARB
bbl/d
bpd
BLM
CARB
CBI
CO
CPUC
dwt
EPA
ERT
FEA
FOB
gal
HC
Ibs
LNG
m
mb/d
mmb/d
mmcf/d
NAAQS
NEPA
N0x
NPR1
NPR4
American Petroleum Institute
Air Quality Maintenance Area
California Air Resources Board
Barrels per day
Barrels per day
Bureau of Land Management (U.S. Department of the Interior)
California Air Resources Board
Chicago Bridge and Iron Company
Carbon monoxide
California Public Utilities Commission
Deadweight tonnage or the weight in long tons (2,240 pounds)
of cargo, fuel, etc. which a vessel is designed to carry
safely
U.S. Environmental Protection Agency
Environmental Research and Technology, Inc.
Federal Energy Administration
Free on board or without charge for delivery to and placing
on board a carrier at a specified point
Gallon
Hydrocarbon
Pounds
Liquefied natural gas
Meter
Thousand barrels per day
Million barrels per day
Million cubic feet per day
National Ambient Air Quality Standards
National Environmental Policy Act of 1969
Nitrogen dioxide
Oxide of nitrogen
Naval Petroleum Reserve No. 1 (located in Kern County,
California near Bakersfield, commonly known as "Elk Hills")
Naval Petroleum Reserve No. 4 (located in northwestern
Alaska between the Brooks Mountain Range and the Arctic
Ocean and recently, as per PL 94-258, renamed "National
Petroleum Reserve in Alaska")
xiii
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03
DCS
OPEC
Oxidant
PADD
PADD 4
PADD 5
PES
PIRS
PLB
PPHM
PPM
psia
RHC
S
SCAPCD
SCAQMD
SES
SMSA
so2
SOX
SOHIO
TSP
VTS
Ozone. This molecule is the primary oxidant standard
Outer Continental Shelf
Organization of Petroleum Exporting Countries
A substance used to determine the amount of smog formation
A Petroleum Administration for Defense District.
These areas were established during World War II
for the control of petroleum supplies and prices.
These areas are still utilized in the reporting of
oil production and consumption.
Includes Colorado, Idaho, Montana, Utah, and Wyoming
Includes Alaska, Arizona, California, Hawaii, Nevada,
Oregon, and Washington
Pacific Environmental Services, Inc.
Coast Guard Polluting Incident Reporting System
Port of Long Beach
Parts per hundred million
Parts per million
Pounds per square inch (absolute)
Reactive Hydrocarbon
Sulfur
Southern California Air Pollution Control District
South Coastal Air Quality Management District
Socio-Economic Systems, Inc.
Standard Metropolitan Statistical Area
Sulfur dioxide
Oxide of sulfur
Standard Oil Company of Ohio. The SOHIO Valdez, Alaska
to Midland, Texas alternative for the movement of
North Slope crude is being proposed by a subsidiary:
SOHIO Transportation Company of California
Total suspended particulates
Vessel Traffic Control System
TERMS
Ambient Air
Ballasting
Freshet
Hotelling
Purging
Air which surrounds a particular point on all sides
(generally refers to a non-enclosed environment).
Material, such as water, taken aboard a ship to provide
stability, especially when empty.
A sudden flood or surge of water in a stream.
The occupancy of a pier overnight by a ship while taking
on supplies, fuel, and allowing shore leave for the
crew.
With reference to tankers, it is the act of flushing
cargo holds with air or flue gases to remove an
explosive atmosphere in the cargo hold or to provide
an atmosphere compatible with crew entry (gas freeing)
xiv
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Segregated Ballast water that is introduced into a tank which is
Ballast completely separated from the cargo oil and oil fuel
system and which is permanently assigned to the
carriage of ballast water.
Seismic A determination of the consolidation of subsurface rock
formations through measurement of the rate of move-
ment of artificially induced shock waves.
Sweet Crude Crude oil which is low in terms of sulfur content.
Tradeoff With regard to air quality, it is the substitution
of a new, less polluting source of air pollutants
for an existing source which is more or equivalent
in terms of its contribution to air pollution.
Venting With respect to tankers, it is the process of allowing
gasses from a cargo hold to escape through an opening.
xv
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SECTION 1
HISTORICAL PERSPECTIVE
EVOLUTION OF EXISTING DISTRIBUTION SYSTEMS
Within the United States, the first successful exploration and develop-
ment of crude oil deposits occurred in western Pennsylvania. During 1845 to
1858, oil collected in salt wells near Pittsburgh was bottled and sold as
medicine or processed in a five-barrel capacity refinery to produce "carbon
oil" for lighting purposes. At this time other petroleum from western
Pennsylvania was sold as a lubricant to textile mills. Soon, demand
for such products exceeded the supply and the price of oil increased from
seventy-five cents to two dollars a gallon (1). The establishment of this
market demand provided incentive for increased collection and production of
oil for commercial purposes and led to the beginning of the modern oil
industry with the successful completion of a drilled oil well in 1859 by
"Colonel" Edwin L. Drake. This well, located in north-western Pennsylvania
near Titusville produced 20 barrels of crude oil per day and demonstrated
that a dependable supply of oil could be obtained by drilling. The success
of the well initiated an oil boom in the area including the first flowing
well which produced 300 barrels per day in 1861.
Refineries in Oil City near the production field and in Pittsburgh
were constructed to process the oil. The crude oil was transported to
the refineries in barrels on small boats travelling on freshets released
from impoundments in Oil Creek, adjacent to the oil field, and on larger
vessels for downstream movement on the Allegheny River to Pittsburgh. As
many as 1,000 boats were utilized to carry the oil and as a result of
accidents and huge oil losses this method of transporting oil became too
expensive and harzardous (2).
By October, 1861 a rail terminal was constructed at Titusville and
by 1864 a rail network provided an outlet for western Pennsylvania crude oil
to Cleveland and New York. At first the oil was carried in two wooden tanks
of forty barrel capacity mounted on a flat car. These were replaced by iron
boiler tank cars by 1869 (2).
During this period the movement of oil from the production site to
terminals for water or rail transportation proved difficult. Horsedrawn
wagons could carry up to seven 360 pound wooden barrels. On a single day as
many as 2,000 of these wagons would transport oil into Titusville. The
resultant hazards, congestion, and high cost (as much as $5.00 a barrel) led
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to the construction of pipeline collector systems. Charging only $0.25 per
barrel for the same service; i.e., providing a system for the gathering of
oil from field storage tanks, the pipeline as a transportation medium
quickly replaced teamsters after 1866.
Initially, railroads bought or constructed pipelines or promoted
combines to bring crude oil to rail heads and refused any non-railroad
owned pipelines permission to cross the railroad track. Public sentiment
against such a monopoly led to the enactment of legislation in Pennsylvania
and Ohio in 1872 to grant common carrier pipelines the privilege of eminent
domain in their acquisition of rights-of-way (2). This action allowed for
the construction of main trunk pipelines and thereby reduced the cost of
oil movement. By 1875 the Columbia Conduit System provided a capacity of
12,000 barrels per day to Pittsburgh refineries. The Tidewater Pipe Company
constructed a 6 inch pipeline from northwest Pennsylvania to Williamsport,
Pennsylvania, adjacent to the Susquehanna River in 1879 and on to Bayonne,
New Jersey by the end of 1888. These long distance pipelines resulted in
rate reductions by railroads for oil transportation and contributed to
the dissolution of the monopolistic transportation of oil by rail combines.
Until 1900 the production of crude oil centered in the east-central
states of Pennsylvania, Ohio, Indiana, West Virginia, and Kentucky. The
crude oil pipeline distribution system connected production areas to eastern
refineries (Figure 1). After 1900, declining production of crude in this
area forced the eastern refineries to obtain crude from newly discovered
deposits in Texas, Oklahoma, Louisiana, and California. Crude pipelines were
constructed to convey the crude from areas of surplus in the mid-continent
to meet eastern demand requirements. By 1940 more than 85 percent of crude
oil supplies to eastern refineries were derived from production areas
located west of the Mississippi River (Figure 2). During this period of
pipeline construction, the center of the U.S. population was shifting west
creating a demand which was satisfied through the erection of refineries
near navigable waters of the Great Lakes, Mississippi River, Texas Gulf, and
the coast of California (2). This period of expansion of pipeline systems
resulted in the connection of new oil producing areas to new and existing
refineries, and to marine terminals (Figure 1).
Prior to World War II large amounts of crude oil and refined products
were transported to the east coast by marine tankers and barges. In June
1940 these shipments averaged 1,472,000 barrels per day (2). The war
effort required the diversion of tank ships from domestic service and
exposed Gulf to East Coast shipping to submarine attack. In 1942, 48
of these remaining tank ships were sunk within four months, resulting
in less than one cargo to be delivered daily to the eastern seaboard.
As an interim solution to this supply problem, the railroads and the oil
industry coordinated the use of 107,000 oil tank cars in fuel trains which
would run on a fast schedule. These trains transported more than one
million barrels per day of crude oil or its products to the East Coast and
about 165,000 barrels daily to California.
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1909
1932
1975
Sources: Petroleum Extension Service (2)
American Petroleum Institute (3)
FIGURE 1
GROWTH OF CRUDE OIL PIPELINES IN THE UNITED STATES
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100
90 -
80 -
70
60
% 50
40
30
20
10
1911 1914 1940
Source: Petroleum Extension Service (2)
FIGURE 2
PERCENTAGE OF REFINERY REQUIREMENTS EAST OF THE
MISSISSIPPI RIVER SUPPLIED BY MID-CONTINENT
FIELDS LOCATED WEST OF THE MISSISSIPPI
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To aid acceleration of oil pipeline construction during the war,
Congress passed the Cole Act of 1942 which allowed the President the right
to grant a petroleum pipeline the right of eminent domain when acquiring
land and rights-of-way during wartime. Within two years this accelerated
construction provided more than 11,000 miles of new pipeline, 3,000 miles of
relocation and modernization of older lines, and 3,000 miles of reversed
flow in existant lines. Pipeline flow increased from prewar levels of less
than 50,000 barrels per day to the east coast to a maximum of 754,000
barrels.
Subsequent to the war many oil pipelines were taken out of service,
reversed, or converted to gas pipelines as military demands for petroleum
declined. Tankers soon became available for inter-coastal shipments.
During the war, large diameter trunk lines proved to be capable of trans-
porting large amounts of oil at a low cost per barrel relative to smaller
diameter lines. Such a condition marked the beginning of a new era in U.S.
pipeline construction which extended through the 1950's, 1960's, and to the
present time. This period of time is characterized by the construction of
large diameter trunk lines over long distances (Figure 1) and resulted in
greatly increased pipeline capacities. Many of these newly constructed pipe-
lines, especially in the 1950's, replaced older multiple small diameter
lines which served the same areas. These older lines were removed or con-
verted to product pipelines (Figure 3).
DEVELOPMENT OF ALASKAN RESERVES
In the early 1900's, discoveries of oil seeps were reported by
explorers in areas bordering the Gulf of Alaska; in a 190 mile wide area
known as Naval Petroleum Reserve No. 4 (NPR4) located in northwestern
Alaska between the Brooks mountain range and the Arctic Ocean; and on the
North Slope, an area between the Brooks range and the Beaufort Sea and
bordered on the west by the Colville River (eastern boundary of NPR4) and on
the east by the Arctic National Wildlife Range (Figure 4). During the
1940's the U.S. Navy drilled 37 exploratory wells in NPR4, but the effort
was unsuccessful in terms of commercial finds (6). After the Navy's effort,
oil companies continued to explore Alaska with seismic analyses and visual
observations. These led to the discovery of the Swanson River Field on the
Kenai Peninsula in 1954 and in 1963 to the Cook Inlet field. The first
refinery opened in 1963 to produce jet fuels and heating oils. By the late
1960's there were seven oil fields in south-central Alaska with production
reaching a peak in 1970 of over 80 million barrels (Figure 5). In March
1968 the Atlantic Richfield Company (ARCO) confirmed a flow rate of 1,152
barrels a day from a drill site located near Prudhoe Bay. In June of the
same year the company announced the discovery of oil at another site on the
North Slope. Within a few months, 14 companies were exploring the North
Slope and within a year the number of wells increased from two to thirty
(6). As a result, oil consultants estimated the North Slope field to
contain 5-20 billion barrels and speculated as high as 50 billion barrels
(8). Plans were formulated for the construction of tankers, pipelines, and
terminals for the movement of oil from the production sites. Estimates
of 1971 or 1972 at the latest were made for the debut of Alaskan oil.
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230
220
210
200
190
180
170
160
150
a
o>
•« *,
s 801
70
m
1
03
I 60
50
40
30
Total
Gathering lines
I
I
20
1950 1956 1962 1968
Source: American Petroleum Institute (4)
1974
FIGURE 3
MILEAGE OF PETROLEUM PIPELINES
IN THE UNITED STATES
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USSR
Source: Federal Energy Administration (7)
FIGURE 4
ALASKA PRODUCTION AREAS
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90
80
M
ed 70
Q) ' W
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In August 1970 the Alaskan Pipeline Service Company was formed to build
and operate a pipeline to transport oil from the North Slope to a warm water
port in South Central Alaska. Court injunctions obtained by Alaskan natives
and environmental groups forestalled early federal approval of the pipeline.
The Native Claims Act was finalized near the end of December 1971 and set
aside over five million acres, including the pipeline right-of-way. The final
Environmental Impact Statement for the Trans-Alaska Pipeline appeared in
March 1972. Opposition to the proposal by leaders of the Canadian govern-
ment and the U.S. Senate urged that approval be withheld in favor of the
construction of a Canadian Line (6). In May, 1972, Secretary of the
Interior Rogers Morton announced his decision to grant the right-of-way
permit for the trans-Alaska pipeline from the North Slope to Valdez as it
would be in the national interest to construct a pipeline "located under
the total jurisdiction and for the exclusive use of the United States"
(9). In June, 1972 a series of hearings conducted by the Joint Economic
Committee reviewed the pros and cons of an Alaskan vs. a Canadian pipe-
line route. Subsequent to these hearings three environmental groups claimed
that the Mineral Leasing Act of 1920 prohibited a right-of-way as wide as
that of the proposed pipeline and that the final Environmental Impact
Statement did not adequately consider a specific pipeline corridor through
Canada. In early, 1973, the Federal Court of Appeals ruled that the
proposed pipeline was in conflict with the Mineral Leasing Act of 1920. The
U.S. Supreme Court refused to hear an appeal. In the Spring and Summer of
1973 the Senate considered a bill authorizing the necessary right-of-way
through amendment of the Mineral Leasing Act and determining that the 1972
Final Environmental Impact Statement and other Federal actions satisfied the
requirements of the National Environmental Policy Act of 1969 (NEPA).
During the debates on the proposed pipeline, advocates included oil
companies with reserves in the Prudhoe Bay field, industry and trade assoc-
iations, and Alaskan administrators. Advocates of a Canadian route included
conservation organizations, commercial fishermen, state officials and
Members of Congress from the Midwest, and Canadian interests (10). In its
report to the Senate concerning the proposed pipeline authorization act, the
Committee on Interior and Insular Affairs summarized the controversy over
the ability of the West Coast to absorb all of the North Slope oil as
follows:
A surplus of crude oil on the West Coast of the United
States would have to be marketed east of the Rockies
with considerably greater transportation expense or
else exported. Advocates of the Alaska project now
acknowledge that the pipeline would have created a
crude oil surplus on the West Coast if it had been
completed in 1972 or 1973, as originally anticipated.
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The present throughput schedule, however, is not
expected to be sufficient to meet all of the District's
petroleum demands unless major new reserves are dis-
covered and developed offshore from California or
in the Gulf of Alaska. Accordingly, the likelihood
of major new oil discoveries in Southern Alaska or off
the California coast and the desirability of exporting
Alaska oil to other countries during an era of
domestic shortages are both among the critical issues
of controversy. (11)
At that time the press, the public, and Congress gave little attention
to methods of offsetting a potential for a surplus in PADD V (a geographic
area for data collection which includes Alaska, Arizona, California, Hawaii,
Nevada, Oregon, and Washington) such as voluntary limitation of production
by the oil companies or by the State of Alaska through regulation. It was
widely held that the North Slope oil producers favored the Trans-Alaska
pipeline-tanker route in part as it provided an opportunity for export
of excess supplies to Japan. Spokesman for these companies and the Depart-
ment of Interior maintained, however, that the PADD V demand would be more
than sufficient to absorb North Slope crude in addition to other PADD V
production and that, should an initial surplus develop, U.S. crude oil
prices would be high enough relative to other crudes available in the world
market to not provide an economic incentive for export (11).
Following the 1973 Arab-Israeli war, the Arab countries imposed an
oil embargo as a method of applying pressure on Western backers of Israel.
This action led to a substantial rise in oil prices and altered historical
supply and demand patterns. In November, 1973 Congress enacted and the
President signed the Trans-Alaska Pipeline Act of 1973. The main provisions
of the Act (as amended) include the following (12):
1. Amendment of Section 28 of the Mineral Leasing Act of 1920.
• Limitation of right-of-way width to fifty feet from a pipeline
unless a wider right-of-way is approved by the Secretary of
the Interior.
• The Secretary of Interior may require measures to provide for
the safety of workers and the public from sudden ruptures
and slow degradation of the pipeline.
• The Secretary also may impose extensive stipulations which
protect the quality of the environment from activities
associated with proposed or existing rights-of-way.
• Each right-of-way permit shall permit the Secretary the
right to grant additional rights-of-way in the same area
in order to minimize environmental impacts and the
proliferation of rights-of-way.
10
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• Pipelines and related facilities shall be constructed,
operated, and maintained as common carriers.
• A limitation on export wherein the President must find
that exports will not diminish the quantity and quality
of U.S. petroleum supplies and that the exports are in
the national interest. The President must submit his
findings to the Congress which has sixty days in which
to disapprove such exports. (Presumably, crude oil
produced on the outer continental shelf which is not
carried by a pipeline across federal lands could be
exported) (10).
2. Trans-Alaska Pipeline Authorization
• Authorization for the construction, operation, and
maintenance of the trans-Alaska oil pipeline system.
• Rights-of-way shall be subject to Section 28 of the
Mineral Leasing Act of 1920 as amended.
• The issuance of Federal rights-of-way, permits,leases,
and authorizations for construction and initial operation
of full capacity shall not be subject to judicial review
under any law (excepting claims against invalidity of this
Act).
• The actions relevant to the construction and operation at
full capacity of the pipeline, as described in the Final
Environmental Impact Statement shall be allowed without
further action under NEPA (the Department of Interior
draft Environmental Impact Statement on the proposed SOHIO
crude oil transportation system from Valdez, Alaska to
Midland, Texas examined impacts from tankers on the Valdez
air quality, but did not relate to the port operation due to
conflict with this section of the Act as impacts of the port
were covered under the Trans-Alaska Final Environmental
Impact Statement).
• Provisions for liability with respect to pipeline operation
and discharges of oil from tankers (12).
• Work on the pipeline began in April 1974 under the direction of the
Alyeska Pipeline Service Company and involved the construction of almost
800 miles of 48 inch pipeline, twelve pump stations, three crude oil topping
plants, an oil storage and shipping complex at Valdez, and various other
support facilities. When the first flow of crude oil reaches Valdez in
mid-1977, as scheduled, the terminal complex will include 18 storage tanks,
three ballast water tanks, a vapor recovery unit and a ballast water treat-
ment plant, and three fixed berths plus one floating berth serve to oil
tankers (13). When the pipeline reaches its initial planned flow rate of
11
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600,000 barrels per day (bbl/d), an average of one tanker per day will load
at the port and an average of 1.7 tankers will load each day when the
pipeline flow reaches it projected 1.2 million bbl/d rate in 1978 (14).
The mid-1975, Alaskan production of crude oil averaged 191 thousand
barrels per day (69,772,000 barrels for the year; Figure 5). Under the
Federal Energy Administration's business-as-usual (BAU) projection, Alaskan
crude production may reach a peak of 3.1 million barrels per day (mmb/d)
during 1985 with most coming from the Prudhoe Bay area of the North Slope
(Figure 6). The North Slope oil could account for about 21 percent of the
total anticipated domestic BAU crude production in 1985 (7).
The current lessees of interests in the Prudhoe Bay field in order
of the percentage of oil in place are: SOHIO (54%), Arco (20%), Exxon
(20%), Union (5%), and Phillips, Amerada Hess, and SOCAL (1%). The state of
Alaska owns a royalty interest in crude produced from the Prudhoe Bay field
and is entitled to 12.5 percent "off the top" of the allocation to each
company having production rights in the field. Under the terms of agreement
between the companies and the State, Alaska must give 60 days notice as to
whether that royalty will be taken in dollars or in oil-in-kind. As of this
date, Alaska has elected to take its first royalty in cash, probably because
the refineries being built are not ready to receive this oil. However, that
can be changed and probably will be changed to a receipt of oil-in-kind as
soon as the refineries are completed and provided, of course, the State has
exercised its 60 day notice to the companies. In addition to wellhead
taxes, the royalty interest provides an incentive for the State of Alaska to
encourage a low tariff for the oil passing through the trans-Alaskan pipe-
line system and high wellhead prices (16, 73).
At present about 9.6 billion barrels in the Prudhoe Bay field are
proven in terms of existence and economic viability. The remainder of
North Slope oil mostly has been discovered, but its volume and rate of
production has not been fully delineated. Based on present information,
North Slope reserves other than Prudhoe Bay are expected to be 3.2 billion
barrels. Other North Alaska oil deposits lie under the Beaufort Sea and in
the Naval Petroleum Reserve No. 4 (NPR 4). The reserves under the Beaufort
Sea currently are not proven, but are expected to be 2.3 billion barrels.
Thus the total proved reserves in North Alaska are expected under BAU
conditions to be about 15.1 billion barrels by 1989 (7). This figure does
not include oil fields in NPR 4 since they have not been discussed or
delineated. However, the U.S. Navy currently is drilling five wells in the
area and predicts a potential of at least five billion barrels of recover-
able oil in the area (15).
The current trans-Alaska pipeline capacity to serve the expected
production from the North Slope is 2.0 mmb/d. A two stage program to
add pipeline capacity in uphill segments (looping) can expand the capacity
to 2.6 mmb/d. Additional capacity would require a second pipeline.
Typically, dollar outlays for pipeline capacity are planned to be recovered
over an operating life of at least ten years. The Beaufort Sea production
coming on line after 1980 can barely fill the first stage looping capacity
of 2.5 mmb/d for the minimum 10-year economic life when combined with
12
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3.5
3.0
2.5
a
a
ai
c.
in
I-H
4)
a
03
c
o
2.0
1.5
1.0
0.5
II
II
1975 1980 1985 1989
Source: Federal Energy Administration (7)
*Based on business as usual production possibilities
at $13 import oil price.
FIGURES
PROJECTED ALASKAN CRUDE OIL PRODUCTION*
13
-------
the Prudhoe Bay and other North Slope production (Figure 7). Maintaining
the flow after 1985 will be dependent upon new findings in existing fields
or from potential new sources such as NPR-4.
ESTABLISHMENT OF A WEST COAST SURPLUS
Prior to the 1973 oil embargo crude oil prices remained relatively
the same from the 1950's to the early 1970's. The major oil producing
states held crude production well below full capacity until about 1970.
A large amount of relatively low cost foreign crude oil overshadowed the
world petroleum market. These factors created a situation marked by a
number of important features (7):
• Due to rising costs and low oil prices in the face of
cheap foreign oil and the lack of access to unexplored
Federal lands (OCS and Alaska), domestic oil drilling
declined after 1959.
• As a result, domestic oil reserves (except for the
Prudhoe Bay field added in 1970) declined after 1966.
• Domestic production reached a peak in 1970 and
subsequently declined steadily.
• Meanwhile, domestic oil consumption increased, reaching
a pre-embargo peak in 1973 of over 17 mmb/d.
• The ever widening gap between domestic consumption and
domestic production of oil was filled with low cost imports.
After the embargo, the historical trends in the factors which
determined petroleum supply and demand changed drastically. A new
situation prevailed which was characterized by expensive imports
(up to $12 a barrel, excluding import fees) and high domestic crude
prices (an increase from $3 to over $8 or to $5 when adjusted for
inflation). These factors determined the following conditions in
1974 and 1975 (7):
• Until the enactment of the Energy Policy and Conservation
Act in December 1975, price controls continued for "old"
oil (on the market before the embargo), but "new" oil
brought into production after the embargo sold at the
wellhead at a free market price.
• For the first time in recent history, domestic demand
declined.
• New drilling sites increased dramatically in 1974 and
1975 to the highest level since 1962.
• An accelerated pace of offshore leasing was undertaken.
14
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3.0 r-
I
« 2.0
n
0)
CO
O 1.0
0.0
Beaufort
Sea
V??
Other North Slope
Prudhoe Bay Field
I
1975 80 85
Source: Federal Energy Administration (7)
90
95
2000
FIGURE?
NORTH ALASKA CRUDE PRODUCTION (BAU) 1975-2000
-------
• The higher prices stimulated the use of advanced and
costly processes to increase oil recovery in existing wells.
• The rate of decline in domestic crude production began to
slacken.
• The Congress authorized full production from the Naval
Petroleum Reserve No. 1 (Elk Hills, California) which by
1980 will supply oil at a rate of 200 to 250 thousand
barrels per day to the West Coast (16).
These factors affected the energy supply and demand patterns for
the nation as a whole, but with respect to the potential consumption of
North Slope Crude, the situation changed even more significantly after
1973. In April of 1973, the Department of the Interior estimated that the
demand for petroleum in PADD V of 2.3 million barrels per day (bbl/d) and
its increase to over 4.0 million bbl/d in 1985 would result in full utiliza-
tion of the North Slope oil as well as the estimated production from de-
clining California fields (17). The combination of events of the oil
embargo, subsequent higher petroleum prices, an economic slowdown, and
energy conservation measures resulted in a decline in the consumption of oil
of over 6 percent in 1974 and 1975. Although domestic consumption is
increasing as the economy recovers, current price and conservation measures
are expected to result in an estimated growth rate of about 2 percent per
year as compared to a 4 percent rate forecasted in 1973 (17).
The production of North Slope crude oil will initially come from the
existing field at Prudhoe Bay. Various forecasts by energy companies,
research organizations, and Governmental bodies have been made of the
amount of North Slope crude oil which will be available to PADD V. These
range from 1.5 to 1.7 mmb/d in 1980 to 1.6 to 2.0 mmb/d in 1985 when
fields adjacent to Prudhoe Bay could be in production (16).
Another source of oil is from sweet (less than 0.5 percent sulfur)
and light (low specific gravity) crude oil imports which will be required
by some PADD V refineries (principally in the area of Puget Sound) that
can not utilize the relatively heavy North Slope crude containing about
one percent sulfur. In Puget Sound, three of the four major refineries
utilize the light, low sulfur crude from Canada and Indonesia. In Hawaii,
the existing refineries use Indonesian crude (16). The conversion of
existing refineries or the construction of new ones which process North
Slope crude may take some time owing to down time during modernization
in which new process and pollution control equipment are installed,
lengthy lead-time for new construction, and uncertainty with respect to
the price of North Slope crude. The Federal Energy Administration (16)
estimates that 300,000 to 500,000 barrels per day of foreign crude oil
could be imported into PADD V through 1980 and from zero to 500,000
barrels per day by 1985 depending upon the price of domestic and imported
crude and investment decisions by refiners.
Additional supplies to PADD V will be available as domestic produc-
tion from offshore drilling and enhanced recovery techniques are applied
16
-------
to existing wells in California. Assuming that domestic crude prices will
be decontrolled in 1979 and that a $13 a barrel price (in 1975 dollars)
will be in effect in 1980 and 1985, the Federal Energy Administration
estimates that the on-shore California production (excluding Elk Hills)
is expected to total 1 million barrels per day for 1980 and 1.2 million
barrels per day for 1985 (7). Offshore California production is expected
to be limited to only 10 and 20 percent of the total production within
the State by 1980 and 1985 respectfully. The Elk Hills Naval Reserve
production should supply oil at a rate of 200 to 250 thousand barrels
per day by 1980 and continue through 1985 should production be allowed
to continue past 1982 (current limit as established by legislation).
The total supply to PADD V as estimated by FEA (16) is
as follows:
(Million Barrels per Day)
1978 1980 1985
Alaska 1.3 1.7 1.9-2.3
California 1.1 1.2 1.4
Foreign Imports ._5_ .3-.5 .3-.5
2.9 3.2-3.4 3.6-4.2
Instead of the annual 5 percent growth in the demand for oil in PADD V
which was anticipated before the embargo, the demand declined in 1974 and
1975, and slowly increased in 1976. As a result, the current projected rate
of growth in demand is 2 percent per year. The actual demand for crude in
PADD V is largely due to its demand for products such as gasoline, distil-
lates, residual oil, jet fuels, etc. The product demand varies with geo-
graphical regions such as a Northwest need for gasoline and distillates over
residual oil (hydro-electric generating capability is presently negating the
need to burn residual oil) and a relatively greater need for residual oil in
California (which lacks huge amounts of hydroelectric power). Due to its
isolation from the rest of the country by the Rocky Mountains, PADD V has
tended to be self sufficient with respect to its production of finished
petroleum products (16). The Federal Energy Administration (16) has esti-
mated the total product demand in millions of barrels to be 2.3 (1976), 2.4
(1978), 2.3 (1980),* and 2.9 (1985).
Utilizing current information brought to light since the oil embargo,
most forecasts of petroleum supply and demand in PADD V predict a crude
oil supply surplus when North Slope oil is available. After examining
previous forecasts and assuming deregulation of oil and natural gas
prices, the Federal Energy Administration utilizes the following reference
case for characterizing the surplus (16):
*Relatively low demand for 1980 reflects FEA forecast of a decline in
the use of residual fuel oil in electric plants due to a greater
use of nuclear power. 1985 demand may be overestimated.
17
-------
(Millions of Barrels per Day)
1978 1980 1985
PADD V Production 2.4 2.9 3.3-3.7
Foreign Imports .5 .3-.5 .3-.5
Total Supply 2.9 3.2-3.4 3.6-4.2
PADD V Demand 2.4 2.3 2.9
Projected Excess .5 .9-1.1 .7-1.3
Current information indicates that substantial conversions in the
capacity of PADD V refineries designed to run on light, low sulfur crude
in order to process North Slope crude will not be made by 1978. Should
an economic incentive exist, conversions could be realized by 1985 (17).
Thus, it is highly probable that when the Trans-Alaska pipeline attains
a flow of 1.2 million barrels per day next year, a 500 thousand barrel
per day surplus will be available for movement from PADD V to other areas.
Should foreign crude imports not fall below 300 thousand barrels per day
and present assumptions concerning supply and demand remain unchanged with
time, this surplus could increase substantially by 1980 and by as much
as 1.3 million barrels per day in 1985.
A basic assumption of all forecasts has been that production would
not be shut-in to maintain an equilibrium between supply and demand in
PADD V (16). If this is true, a need exists to develop a transportation
method for moving the excess from PADD V to other parts of the U.S. such
as the central and eastern areas which are becoming increasingly dependent
upon foreign sources of crude oil. Such a west coast to eastward movement
would establish a new transportation network and would reflect a change
in emphasis from the traditional crude oil sources of the south-central
Gulf coast (Figure 1). The network, if established could serve as a distri-
bution system for crudes other than North Slope such as those from NPR-4,
Pacific Outer Continental Shelf including Alaska, and heavy oil from
on-shore California fields. The availability of nationwide markets for this
production at the lowest possible tariffs is an important incentive for
development of such a network (17). The following chapters discuss the
various transportation alternatives which have been proposed, the major
environmental issues and other matters related to these alternatives, and
various areas where further information is warranted to prepare for a
responsive approach to movement of North Slope crude.
18
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SECTION 2
ALTERNATIVES FOR THE DISPOSITION OF ALASKAN OIL
FOCUS ON THE NORTHERN TIER STATES
Canadian Oil Curtailments
The discovery of oil in the Canadian Province of Alberta prompted
construction of two major crude oil pipeline systems to serve Canadian
and U.S. refineries. In 1950 the Interprovincial/Lakehead System was
built eastward from Edmonton, Alberta to Superior, Wisconsin. In 1953
the line was extended to Sarnia, Ontario and in 1957 from Sarnia to Toronto.
The total length of the Interprovincial/Lakehead network is about 1,900
miles (Figure 8). An 800 mile Trans-Mountain Pipeline System was extended
westward from Alberta in 1953. It originated near Edmonton, crossed the
Rocky Mountains, and terminated at Vancouver (Figure 8). Short connecting
lines have since been added to the Ferndale and Anacortes areas of the
northwestern part of the State of Washington (3).
In late 1974, the National Energy Board of Canada announced plans
to systematically reduce and eventually terminate Canadian exports to
the United States. This decision affected many U.S. refineries which
were dependent upon Canadian oil. Some of these refineries located in
Ohio, Indiana, and Illinois could utilize alternative supply lines emanating
from the Midwest, Southwest, and Gulf Coast. Refineries within the Northern
Tier States (Washington, Montana, North Dakota, Minnesota, Michigan, and
Wisconsin) rely heavily on the Canadian imports. Only the State of
Washington can receive a substantial amount of crude directly from an
existing alternate source (imports of crude oil by tanker). The Northern
Tier refineries which have no alternative crude source have been given
priority status by the Federal Energy Administration to receive available
Canadian imports (18). The reductions in Canadian exports to the United
States as well as those which are planned are shown in Figure 9. These
reductions together with declining local crude production in the face of
increased demands pose a significant problem for the Northern Tier States.
The following are various alternatives which have been proposed to satisfy,
either wholly or in part, the crude oil supply problem.
Trans-Provincial Pipeline
This proposal to serve refineries in the Northern Tier States is
supported by the firms of Ashland Oil, Canada Ltd., Murphy Oil, Farmers
19
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CANADIAN PIPELINES
to
o
m
AUCOHTII
Sources: Petroleum Extension Service (2)
American Petroleum Institute (3)
FIGURES
CANADIAN CRUDE OIL PIPELINES (1975)
-------
&
Q
0)
(X
0)
i-l
0)
3
o
0)
•o
c
n
§
£
800
700
600
500
400
300
200
100
—
— \ ^Actual
\
- \
\
\
\
\
^^'Planned
— \^
\
\
\
\
\
v No exports
-x \
i 1 1 1 1 1 1 ^hJl
1974 1976 1978 1980 1982
Source: Federal Energy Administration (18)
FIGURE 9
ACTUAL AND PLANNED CANADIAN EXPORTS TO THE UNITED STATES
21
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Union Central Exchange, Koch Industries, Hudson's Bay Oil and Gas, and the
Interprovincial Pipeline Company. The proposal includes construction of a
deepwater port at Kitimat, British Columbia, which would serve a 750 mile,
30 inch pipeline to Edmonton, Alberta where distribution can take place via
the Interprovincial-Lakehead Pipeline System (Figure 10). The proposed
pipeline is designed to carry 300 thousand barrels per day (to be expanded
to 500,000 by 1985) of Alaskan, domestic offshore, Indonesian, and Persian
Gulf crudes, and could be operational within 16 to 22 months after permits
are finalized (18). The terminal would include two floating docks capable
of handling 16,000 - 320,000 dwt oil tankers. The Kitimat port would require
minimal dredging to accomodate larger oil tankers as its sheltered Douglas
Channel provides 450 ft. of water depth at low tide (19). However, the
narrow port entrance channel presents significant navigational problems and
allows for the chance of accidents and associated oil spills greater than in
most other West Coast ports (20). The Kitimat port does provide an alterna-
tive to the tanker transport of Alaskan crude further down the coast to Puget
Sound which has met considerable environmental opposition. Recent discus-
sions with tanker captains have indicated that the channel presents no
serious navigation problems for the 10,000 to 100,000 dwt class of tankers
(21). To date the British Columbia government is critical of the proposal
as it would provide few benefits to Canadians, the time schedule is too
tight for necessary environmental studies to be undertaken, and there is a
potential for tankers as large as 350,000 dwt to visit the port. These
likely would be flag-of-convenience ships possessing a minimum of navigation
standards and equipment. Such factors as conditions within the Channel
entrance and the status of tanker modernization, could contribute to the
likelihood of oil spills. Backers of the project hope to begin construction
this year with a completion date in early 1979.
Canadian Exchanges
One solution to the Northern Tier supply problem is to initiate
exchanges of crude oil between the Northern Tier area and refineries located
in the eastern provinces of Canada. Such exchange agreements would preclude
Northern Tier refineries from paying the additional cost for the acquisition
and transportation of acceptable crude from areas far removed from the
Northern Tier. Generally, Canada is willing to consider exchanges as an
interim solution to the Northern Tier supply problem until long-term
arrangements are established (16).
Since the heavy North Slope crude would only be acceptable to refiners
in eastern Canada (refiners in western Canada utilize light, low sulfur
crude), it is doubtful that the economic incentive for such a venture would
merit such a long distance movement of the North Slope crude. Other more
indirect and consequently complex exchanges can be arranged wherein the
North Slope crude displaces domestic crude which may be traded with Canadian
refiners for release of light, low sulfur Canadian crude to Northern Tier
refiners. This alternative would require international negotiation.
22
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— — — — Proposed Tanker Route
Proposed Pipeline Route
*Trans-Alaska Pipeline
A Port Angel es^^.73
*"
Source: Federal Energy Administration (18)
FIGURE 10
MAJOR ALTERNATIVE TRANSPORTATION SYSTEMS FOR THE
EASTWARD MOVEMENT OF NORTH SLOPE CRUDE
23
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Trans-Mountain Pipeline
This proposal involves the construction of a tanker terminal in
Puget Sound or the use of an existing deepwater terminal such as ARCO's
Cherry Point refinery terminal (22). Trans Mountain Pipe Line Company,
Ltd., plans to alternate eastward and westward shipments via its pipeline
in western Canada (Figure 8). This "yo-yo" proposal can utilize Trans
Mountain's current pipeline capacity of 420 thousand barrels a day.
Recently, the pipeline has been used for the importation of only 60
thousand barrels a day to four refineries in Washington (to be cut back
under Canada's oil curtailment plans) and 120 thousand barrels a day to
four refineries in the Vancouver area (22).
Under the proposal, Vancouver can be served by the westward flow of
Canadian (or U.S. imported) oil and northern tier refineries can be served
by an eastward flow to Edmonton where it could enter the Interprovincial
Pipeline System for transport to Minnesota and Illinois. The projected
initial eastward flow is 165 thousand barrels a day. Each reversal of
flow would take the pipeline out of service for two days (22).
Cherry Point Proposal
This proposal involves the construction of a 1,700 mile pipeline from
a terminal in Puget Sound near Cherry Point, Washington to Clearbrook,
Minnesota or to Sidney, Nebraska by the construction of a 1,400 mile pipe-
line. With little construction, the port could accommodate large Alaskan
tankers. Charges that the approaches to the site are too hazardous for
large tankers initiated the enactment of a 1976 Washington state law which
prohibited tankers of more than 125,000 dwt and required tugboat escort of
most smaller tankers (23). In September, a Federal three judge panel ruled
that the tanker law was pre-empted by Federal jurisdiction. The matter is
still in litigation. Owing to navigational problems, the oil spill risk
is high and such a spill could affect a rich biotic environment (20).
Williams Pipeline
This proposal is a phased expansion program of an existing products
pipeline system in the upper Midwest. The expansion would include 500
miles of 24-inch pipeline from Oklahoma to Iowa and could carry 350 thousand
barrels per day of Oklahoma crude oil to Minneapolis, Minnesota. The expan-
sion could be completed within 12 months. This pipeline, proposed by
Williams Pipeline Company also could carry oil from existing Gulf Coast
pipelines which would connect to the proposed SEADOCK deepwater terminal
near Freeport, Texas (18). It also could receive oil from pipelines which
would connect to the proposed SOHIO Long Beach - Midland pipeline. Should
this project be implemented, it would serve as a partial solution for the
crude oil requirements of refiners in Minnesota. It also could serve in the
distribution of Alaskan crude in the short term by carrying oil trans-
shipped through the Panama Canal to Gulf Coast ports and in the long-term by
serving the SOHIO pipeline.
24
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Minnesota Pipeline
The Minnesota Pipeline Company recently has announced plans to
construct a 490 mile, 24 inch crude oil pipeline from Patoka, Illinois
to St. Paul, Minnesota. This line also would connect with several major
crude trunk lines from the Gulf and West Texas coasts. The proposed line
would initially carry up to 250 thousand barrels per day. The pipeline
backers are the Ashland Oil Company and Koch Industries. Current plans are
to begin construction by early 1977 for an Autumn of 1978 completion date*
Northern Tier Pipeline
The Northern Tier Pipeline Company proposes to construct a 1,550
mile, 42" and 40" diameter pipeline for receiving Alaskan and foreign
crude at Port Angeles, Washington and transporting it to Clearbrook,
Minnesota where connections would be made with the existing Minnesota
Pipeline and Lakehead Pipeline. In addition, the system also would be
capable of deliveries to existing pipelines in Montana and North Dakota.
Through existing pipeline systems which have surplus capacity available,
the Northern Tier Pipeline would be capable of supplying refineries in
the Rocky Mountain, North Central, Midwestern and Eastern U.S. (24,25).
The design capacity of the system is approximately 740 thousand barrels
a day to Clearbrook with capability of delivering approximately 200 thousand
barrels a day to intermediate points in Montana and North Dakota. Provision
can be made in the pipeline design to accommodate an additional 350 thousand
barrels a day through the initial segment of the pipeline from Port Angeles
to Selleck, Washington to supply refineries in the Puget Sound area. To
supply these refineries, a connecting spur line 83 miles in length would be
constructed to tie in with the existing Trans Mountain Pipeline now serving
the four refineries in the Anacortes-Ferndale area.
The Northern Tier Pipeline Company is a Montana corporation formed
by six organizations and one individual experienced in the oil and trans-
portation industries (26). The Company is presently negotiating with
potential shippers to obtain the throughput committments necessary for
project financing and is proceeding to obtain state and federal permits.
The Company applied for Site Certification on July 6, 1976 in the state
of Washington with the Energy Facility Site Evaluation Council which admini-
sters the state's recently enacted Energy Siting Act* Pending permit
approvals, current plans are to start construction in mid 1978 with comple-
tion of construction scheduled for year end 1979 (26,27).
The Northern Tier pipeline proposal contains several important features.
The pipeline would supply the Northern Tier refineries and would not be
subject to future Canadian tariffs or regulations. The larger (42 inch)
pipeline laid around Puget Sound could reduce the need for oil to be brought
by tankers into the main body of the Sound and thereby decrease the likeli-
hood of oil spills in that area* The route crosses the Williston Basin, an
area with deep lying salt deposits along the Montana-North Dakota border*
The Northern Tier Pipeline Company indicates that these deposits could be
utilized for an inland strategic oil storage area served by the pipeline (25)*
25
-------
A local environmental group, the Coalition Against Oil Pollution,
favors the Port Angeles site for the marine terminal over one located in
Puget Sound (28), and the State of Washington's coastal zone management
program also is favorable to the project* As envisioned last year under
Governor Dan Evans, the State's coastal zone management policy "*%*positively
supports the concept of a single, major crude petroleum receiving and
transfer facility at or west of Port Angeles" (74),. The present Governor
(Dixy Lee Ray) views the facilities to be acceptable only if strong controls
exist over their development (29)* Recent interactions of the Bureau of
Land Management with environmental groups in and around the state of Washing-
ton indicated little public support for a large marine terminal at Port
Angeles (73)*
North Slope Crude Oil and the Northern Tier States
Most of the Northern Tier refineries are designed to utilize low-
sulfur Canadian oil and are not readily adaptable to operate with the
Alaskan Crude* If obtainable, Indonesia light crude with its relatively
low sulfur content may become the primary replacement for Canadian oil
(30)* The influx of Alaskan oil into the West Coast together with its
concomitant surplus and its occurrence at a time when the Northern Tier
states are experiencing a supply shortage has caused national concern
for the need to quickly identify a reasonable solution to the problem*
Such concern led the following legislative requirement to be adopted by
Congress and approved by the President on October 22, 1976 as part of the
Alaska Natural Gas Transportation Act of 1976 (31):
Sec* 18* Within 6 months of the date of
enactment of this Act, the President shall
determine what special expediting pro-
cedures are necessary to insure the equit-
able allocation of north slope crude oil
to the Northern Tier States of Washington,
Oregon, Idaho, Montana, North Dakota,
Indiana, and Ohio (hereinafter referred to
as the "Northern Tier States") to carry out
the provisions of section 410 of Public Law
93-153 and shall report his findings to the
Congress* In his report, the President shall
identify the specific provisions of law, which
relate to any determination of a Federal
officer or agency as to whether to issue or
grant a certificate, permit, right-of-way,
lease, or other authorization in connection
with the construction of an oil delivery
system serving the Northern Tier States and
which the President finds would inhibit the
expeditious construction of such a system in
the contiguous States of the United States*
In addition the President will include in his
report a statement which demonstrates the
impact that the delivery system will have on
26
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reducing the dependency of New England and the
Middle Atlantic States on foreign oil imports*
Furthermore, all Federal officers and agencies
shall, prior to the submission of such report
and further congressional action relating thereto,
expedite to the fullest practicable extent all
applications and requests for action made with
respect to such an oil delivery system..
Currently this report is in preparation and is to be completed by the
end of April this year*
INTERNATIONAL EXCHANGES
It is commonly assumed that all North Slope oil will be transported
into the contiguous States and thereby lessen dependence upon imports
of foreign oilv It is also commonly believed that the excess of such
oil, should it materialize on the West Coast, would be directed to states
east of the Rocky Mountainsv In the short term, however, it is unlikely
that an east-west pipeline transportation system will be in place by
1978 when the initial surplus is expected to occur* Consequently, the
excess oil will probably be transported by tankers to domestic markets
other than the West Coast or may be exchanged with foreign refiners -
possibly with the effect of releasing foreign oil for import into the
Gulf or East Coast. Such exchanges were addressed specifically in the
Trans-Alaska Pipeline Act's amendment of the Mineral Lands Leasing Act
of 1920 (12):
LIMITATIONS ON EXPORT
(u) Any domestically produced crude oil trans-
ported by pipeline over a right-of-way granted
pursuant to section 28 of the Mineral Leasing
Act of 1920, except such crude oil which is
either exchanged in similar quantity for con-
venience or increased efficiency of transpor-
tation with persons or the government of an
adjacent foreign state, or which is temporarily
exported for convenience or increased efficiency
of transportation across part of an adjacent
foreign state and re-enters the United States,
shall be subject to all the limitations and
licensing requirements of the Export Administra-
tion Act of 1969 (Act of December 30, 1969; 83
stat. 841) and in addition, before any crude
oil subject to this section may be exported
under the limitations and licensing requirements
and penalty and enforcement provisions of the
Export Administration Act of 1969 the President
must make and publish and express finding that
such exports will not diminish the total quantity
or quality of petroleum available to the United
States, and are in the national interest and are
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in accord with the provisions of the Export
Administration Act of 1969: Provided, that the
President shall submit reports to the Congress
containing findings made under this secton, and
after the date shall have a period of sixty
calendar days, thirty days of which Congress must
have been in session, to consider whether exports
under the terms of this section are in the
national interest. If the Congress within this
time period passes a concurrent resolution of
disapproval stating disagreement with the
President's finding concerning the national
interest, further exports made pursuant to
the aforementioned Presidental findings shall
cease.
The language of the Act does not prohibit crude exports absolutely. It was
recognized that under some circumstances "import-for-export" arrangements
might be desirable. It was also felt that a total ban might prevent or
handicap arrangements among oil importing countries to share their domestic
or secured foreign supplies in the event of an economically or politically
inspired embargo by exporting countries. A categorical prohibition against
exporting also could set a precedent and possibly set in motion a retali-
ation by countries now exporting to the U.S. Finally, it was recognized
that the U.S. might, at some time, become not only self sufficient again
but actually be in a position to export crude oil, thereby benefiting
balance of payments and the national economy (10). The thrust of the above
section was to assure that any such exports would be in the national
interest by prohibiting exports that would reduce net U.S. supplies, by
requiring accord with the licensing requirements of the Export Adminis-
tration Act which allows the President to set stringent export controls,
and by assuring Congressional and Presidential review.
As mentioned, Canadian exchanges are most likely not to involve
North Slope crude directly, owing to its relatively higher sulfur content
as compared to Canadian crude. However, a projected growth in demand
for foreign crude in Japan (totally dependent on foreign sources such as
the Middle East, Southeast Asia, Africa, and the Communist bloc nations)
where U.S. oil companies are heavily involved in the refining industry make
the country a prime candidate for such exchanges (16). Japan has the
capability to refine high sulfur crudes and can absorb any likely surplus
of North Slope crude. Japanese officials have openly asked U.S. officials
to allow export of North Slope crude to Japan (16).
For the short-term crude oil exchanges with Japan appear to provide
an economic incentive owing to reduced transportation costs over those
associated with the movement of North Slope oil to the Gulf Coast through
the Panama Canal (Figure 11). Such "swapping" agreements involve complex
negotiations and may take some time to finalize. Once established, however,
they may remove the economic incentive for the rapid development of east-
west pipeline systems. This could lock out future oil supply sources
such as onshore Alaskan, Pacific DCS areas, and enhanced recovery from
28
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NORTH SLOPE CRUDE FOB PRICES
VALDEZ
Japanese will pay
$10.72/bbl (FOB)
TOKYO
U.S. Gulf Coast will pay
$10.25/bbl
U.S.
GULF COAST
REFINERIES
Japanese will pay
$11.68/bbl for Arabian
Light or
$11.43/bbl for North Slope
Crude
g) HOUSTON
U.S. Gulf Coast will
pay $12.64/bbl for
Arabian Mght
or $12.39/bbl for
North Slope Crude
RAS TANURA
PERSIAN GULF
$11.25/bbl
(posted price less discount)
ARABIAN LIGHT
No-swap = B($.43/bbl) + B, ($2.14/bbl) = $2.57/bbl
swap = A($.71/bbl) + Ax ($1.18/bbl) = $1.89/bbl
Swap Savings = $.68/bbl (U.S. tankers-Valdez-Japan)
or = $1.05/bbl (foreign flag-Valdez to Japan)
FIGURE 11
TRANSPORTATION SAVINGS RESULTING FROM CRUDE EXCHANGE WITH JAPAN
Source: Federal Energy Administration (16)
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California fields from being readily available to midwest and eastern
refineries (16).
The main issues frequently raised relevant to foreign exchanges are
the following:
1. The U.S. participates in the Emergency Sharing
Program of the International Energy Agency wherein
participating countries agree to pool secured
exports for a coordinated response in the event of
an oil embargo. Although U.S. exchange agreements
would not affect its entitlement under the Program,
a certain amount of North Slope oil would be
required to continue to be exported during an
embargo. However, the U.S. would be receiving
compensating volumes of foreign oil (16). Public
officials are concerned that, in the face of public
opinion, it may be difficult to justify such exports
of domestic oil during an embargo (31).
2. At a time when the nation is striving for self-
sufficiency and a reduced dependency on foreign
energy sources (32) it is an apparent conflict
to export domestic oil.
3. The exchange option is not necessarily in the
National Interest since sufficient U.S. tankers
exist which are capable of transporting North
Slope crude through the Panama Canal.
Recently the Federal Energy Administration Administrator has voiced
opposition to such exchanges as it would be nearly impossible, logistically
and diplomatically, to suddenly switch from exporting oil to consuming it
domestically during another oil embargo (33). About the same time, Senator
Stevenson who chaired hearings on the subject favorably indicated that
such exchange agreements could produce higher profits for the oil companies,
lower costs for consumers, lessen environmental damage (do not require the
building of pipelines) and still permit use of all North Slope oil
production within the U.S. in the event of an embargo directed at this
country (34).
FOCUS ON EASTWARD MOVEMENT
Tankers Through the Panama Canal
The shipment of North Slope oil through the Panama Canal to the
Gulf Coast has received a national focus of attention recently since
this form of transportation may prove to be viable as a short term solution
for the eastward movement of excess crude. Two methods have been proposed
to tranship oil through the Canal to the Gulf terminals. One method
involves large tankers (120,000 - 250,000 dwt) which would carry the oil
from Valdez to the Pacific approaches to the Canal where it would be
30
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transhipped in smaller tankers capable of transiting the Canal. The other
method involves the use of small tankers (less than 68,500 dwt) to transport
North Slope oil over the entire distance. The Federal Energy Administration
has determined that the U.S. domestic fleet, augmented by U.S. flag tankers
currently in foreign trade service, would be adequate to carry the antici-
pated 500 thousand barrels of crude per day to the Gulf Coast ports in 1978
(16, 35). The use of small vessels over the entire route would eliminate
the need for off-loading at the Pacific entrance to the Canal, but would
increase the total number of loading and unloading operations as well as
increase the total number of ships travelling along the West Coast and
transiting the Canal. As a result the risks for the occurrence of oil
spills and ship collisions would increase (20).
An issue of concern is the status of treaty negotiations now underway
between the United States and the Republic of Panama. The outcome of
these talks may affect the security of the Canal as a passageway for
future domestic crude supplies (20).
SOHIO Proposal
The SOHIO Transportation Company of California, a wholly-owned
subsidiary of the Standard Oil Company of Ohio, has proposed a 3,500 mile
sea/land transportation system to move North Slope crude from the Trans-
Alaska Pipeline marine terminal at Valdez, Alaska, to Midland, Texas. From
Midland the crude could be distributed eastward through existing pipeline
networks. A tanker fleet would carry the crude 2,200 miles to the Port of
Long Beach, California where it would be delivered to a storage terminal and
then to Texas through a 1,026 mile pipeline system composed of 236 miles of
new pipeline and 790 miles of existing natural gas pipelines which would be
converted for the transportation of crude oil.
The system would provide delivery of 700 thousand barrels a day (SOHIO1s
54 percent share of Prudhoe Bay field production at the rate of 1.2 million
barrels per day) to the Port of Long Beach, where the crude would be off-
loaded at dockside storage facilities and then transported to an inland
storage terminal (Dominguez Hills) about 9 miles distant from the Port
facilities. From the inland storage terminal, SOHIO plans to distribute 200
thousand barrels a day of crude oil to local refineries and 500 thousand
barrels a day of excess crude oil to Midland through a 90 mile, new 42 inch
pipeline to Beaumont, California. At Beaumont the oil would enter a 121
mile, 30 inch converted natural gas line currently belonging to the Southern
California Gas Company which would carry it to Desert Center, California,
where it would enter a new 42", 39 mile long line pipeline to Ehrenberg,
Arizona. From Ehrenberg a new 30", 34 mile long line would connect with
another converted 30 inch, 669 mile long gas line currently belonging to the
El Paso National Gas Company. The El Paso line would transport the crude to
Jal, New Mexico where it would enter a new 42 inch, 73 mile long pipeline to
Midland (20).
This proposed Valdez to Midland transportation system can provide
a means to move North Slope crude, excess to the needs of California,
to the Gulf Coast, Midwest, and Great Lakes refining regions. Through
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utilization of the proposed expansion of the Williams Pipeline System,
a scenario put forth by the Federal Energy Administration postulates that
the SOHIO crude could be moved from Midland to Tulsa, Oklahoma where it
can be transported to refineries near the Northern Tier refineries of
Minneapolis/ St. Paul, Minnesota and Superior, Wisconsin (18). Under this
scenario, a small diameter pipeline could be extended from Puget Sound
terminals to serve the refineries near Billings, Montana (18). These and
other changes in the crude supply and product import/export patterns in
Montana and North Dakota could assist the Northern Tier refineries in the
replacement of their Canadian crude supply (18).
Both the Southern California Gas and El Paso natural gas pipelines
have been used for the transmission of natural gas from the Permian Basin
in West Texas to California. Both companies have applied for permission
(from the California Public Utilities Commission and the Federal Power
Commission respectively) to abandon the lines which SOHIO proposes to
utilize. Should these lines be abandoned, SOHIO plans to convert them
from east to west gas transmission to west to east crude oil transmission.
Decision on both applications for abandonment are not expected until
the environmental impact statement process has been completed by the
Federal Government and the State of California (20).
The conversion of the El Paso Pipeline (one of five presently being
used) for oil transmission has caused public concern that such action
may preclude the transportation of adequate natural gas supplies to meet
future California demand. It has been estimated that the loss of one
30-inch pipeline would reduce the throughput capacity of the Southern
California interstate gas network by about 5 percent (36). The pipeline
delivery curtailment is a result of rapidly declining supplies of natural
gas to California from sources located east of the State boundary. The
Bureau of Land Management has indicated that a very unlikely combination
of circumstances must occur before the abandoned capacity would be required.
These circumstances include (20):
• Total deregulation of wellhead prices for natural gas and the
subsequent dedication of interstate reserve additions (those
considered highly optimistic);
• Large volumes (400 MMCF/D) of imported LNG being distributed
through the Permian Basin; and
• Equally large quantities of Alaskan gas (600 MMCF/D) being
distributed through the Permian Basin.
Another area of public concern centers on the potential of further
deterioration of a degraded air quality condition in the Los Angeles
Basin. At present, temperature inversions occur about 90 percent of the
mornings (36). Such a condition, together with low wind speeds, causes
entrapment and poor dispersion of pollutants such as oxides of nitrogen and
reactive hydrocarbons. The abundant sunshine in this region promotes
photochemical reactions of these pollutants which produces ozone, a primary
constituent of smog. The SOHIO proposal poses a threat of releasing more
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pollutants, especially hydrocarbons, into the air during off-loading of
oil from tankers, from taking on ballast into cargo tanks, from the
engines of tankers and tugboats, and from storage tanks. In order to
assure that no "net" increase in air emission will result from this "new
stationary source", SOHIO proposes to utilize several mitigating measures
which may include the use of low-sulfur fuel, segregated ballast (4 of the
11 tankers carrying SOHIO North Slope crude will carry about 57 percent of
normal ballast capacity in segregated tanks; the remaining 7 tankers will
carry 100 percent of normal ballast capacity in such tanks), closed
inerting systems, exhaust scrubbers, avoidance of purging inside the port,
use of vapor recovery systems on storage tanks and, restricting taking on
ballast in cargo tanks while in the South Coast Air Basin, use of foam-
covering systems to blanket tank spills, oil spill contingency plans,
and the abandonment of 33 existing storage tanks (20, 36). A detailed
examination of the emissions of pollutants and air quality implications
associated with the proposed SOHIO project is presented in the next
chapter.
Since the transportation of North Slope oil to Long Beach or any
other West Coast port presents the possibility of oil spills, several
analyses have been performed to determine the likelihood of their occur-
rence and extent. These are summarized in the next chapter. With respect
to the SOHIO project, the most likely places for accidents resulting in
spills are in Prince William Sound and in the Santa Barbara Channel off
Southern California (36). There is a greater possibility for severe damage
to shore along the southern part of the route from Valdez to Long Beach
as tankers will be traveling closer to shore. The mitigation of these
hazards will be addressed in oil spill contingency plans currently being
prepared by SOHIO.
Central Alternatives
A centrally located route for the eastward movement of North Slope
crude has been under consideration for some time. The West Coast terminus
for such a route, conceptually, would be an offshore monobuoy system for
offloading. Such a mooring system would be located about 1.5 to 4 miles
offshore where water depth is sufficient for large tankers. The offshore
buoys would be connected by submarine pipeline to onshore storage and the
terminus of a trunk line located inland from the beach and steep foot hills
of the coastal range. This alternative would not require extensive dredging
and construction, but may result in an increased risk of accidents and oil
spills which are difficult to contain over an alternative which includes a
protected harbor (36).
Two sites frequently proposed for such a monobuoy system are Estero
and San Luis Obispo Bays along the coast of central California. Estero Bay,
approximatley 12 miles northwest of San Luis Obispo, contains the entrance
to Morro Bay, and important tidal estuary and aesthetic attaction in
central California. The proposed site in San Luis Obispo Bay lies south of
Avila Beach and west of Pismo Beach.
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Oil spills pose a threat to each area. The Morro Bay estuary has
a narrow entrance, mostly cutoff from the sea by a sandspit (allowing
boom protection to be relatively easy), and Morro Rock. The Bay supports
a sports fishery for gaper and Pismo clams and a commercial fishery for
Pacific clams. Many rare, endangered, and unique species have inhabited
the Bay including the Great Blue Heron, Black Brant, Peregrine Falcon,
the endemic Morro Bay kangaroo rat, and Harbor seals. The California
Department of Fish and Game has designated Estero Bay as a questionably
acceptable site because it is within the protected range of the sea otter
and due to the sensitivity of Morrow Bay (36).
The Avila Beach site in San Luis Obispo Bay to the south may be more
suitable for marine terminal in that Union Oil already utilizes the area for
oil-related activities and land is available for onshore facilities (36).
Currently, the California Office of Planning and Research is considering
San Luis Obispo Bay as a realistic and reasonable alternative to SOHIO's
Long Beach site (37). The Avila Beach area of San Luis Obispo Bay does not
have an estuary, but is within the northern range of the California sea
otter. The Fish and Game Department has designated the offshore area
between Avila Beach and Monterey Bay as the protected range for the sea
otter (range includes Estero Bay). The sandy coastline of Avila and Pismo
Beach also support a clam fishery (36).
The Avila Beach site has been suggested by the California Air Re-
sources Board as an alternative to SOHIO's Long Beach Terminal (37). The air
quality in the area of both Estero and San Luis Obispo Bays generally is
good and may be viewed as being a viable alternative site to avoid further
degradation of the Los Angeles basin where hydrocarbons are a special
problem. However, the project also could impact the downwind areas of
Estero or San Luis Obispo Bays which are characterized as being sensitive to
inversions and conditions suitable for oxidant formation (36).
Utilizing a monobuoy system off central California, a conceptual
pipeline could feed the midcontinent with an eastern terminus at Sidney,
Nebraska. Such a pipeline (roughly 1500 miles in length) could pass through
the Salinas River, a primary watershed of the central California coastal
range and the Los Padres and Tahoe National Forests in California and the
Wasatch Range of Utah (36). Another route could be to construct about 100
miles of new pipeline to Redlands, California for connection with the
proposed SOHIO pipeline or another pipeline which follows the same route.
An Elk Hills Route
The Naval Petroleum Reserves Production Act of 1976 directed that the
production from the Naval Petroleum Reserve No. 1 (Elk Hills) in central
California be increased to the maximum efficient rate consistent with
sound engineering practices and that pipelines and associated facilities
for transportation of the crude be provided to accommodate a minimum of
350 thousand barrels a day within three years (36). By 1980, this new
source of oil should be supplying oil at a rate of 200 to 250 thousand
barrels a day. While the Act authorizes production through 1982, it
is assumed that production will continue at its maximum recovery rate
through 1985 (16).
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The Navy has identified the following alternatives for the movement
of this oil (36, 38):
• A pipeline to Port Hueneme (near Oxnard, California) to tie into
a marine terminal for tanker transportation.
• A pipeline to Redlands, California to connect to the proposed
SOHIO pipeline.
• A pipeline to Coalinga, California to tie into pipelines serving
Getty, Shell, or Standard Oil of California refineries.
• A railroad/truck tank car train system for transport to
appropriate marketing facilities.
A tie into the proposed SOHIO pipeline would allow Elk Hills oil to
be transported easily to eastern states at relatively low cost. It is
possible that Elk Hills oil could be piped to Port Hueneme and moved by
tanker or moved directly by rail to San Francisco or Los Angeles at the
same time that North Slope oil is brought in by tanker and piped inland.
The selection of a central pipeline route for the eastward transport of
North Slope crude could provide another opportunity for a hookup from
Elk Hills (36). Currently the Navy is accepting bids for crude oil from
Elk Hills (no one buyer will receive more than 20%) and is selecting a
consulting engineer to design a pipeline (39, 40).
The Elk Hills production plays an important role in estimates of a
West Coast surplus of crude oil estimated to be between 300 and 600
thousand barrels a day as early as 1978 (41). One solution to the surplus
problem may be to shut down the production from Elk Hills or, as an
alternative, retain it within the strategic reserve system (35).
OTHER WEST TO EAST ALTERNATIVES
Tankers/Tank Car Unit Trains
Currently, railroads transport less than one percent of the crude oil
within the U.S. Typically, unit trains are composed of 90 tank cars which
carry a total of 50 thousand barrels. The spillage of oil and the control and
recovery of air pollutant vapors have been adequately maintained. Land use
conflicts present a problem in that each railroad terminal site would require
an area of one square mile (20).
Several unit train alternatives are being proposed. The most advanced
proposal, sponsored by the Burlington Northern Railroad, involves tankers
from Valdez to Point Westward, Oregon (or Puget Sound) and unit trains serving
Northern Tier refinery centers such as Cut Bank, Montana and Minot, North
Dakota, and Clearbrook, Minnesota. Port Westward is an existing port used by
the U.S. Army for Far Eastern supply with facilities available for docking
ships as large as 35,000 dwt (20). The sponsor claims that an initial volume
of 200 thousand barrels a day could be shipped (16).
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This concept provides a short term solution to meet the demand for
crude by the Northern Tier states and at the same time to partially relieve
the West Coast surplus. However, movement of oil by train is expensive - as
much as 2 1/2 times the cost of pipeline delivered oil. Refineries are more
likely to view the train concept as a last resort. Northern Tier refineries
may prefer to receive Indonesian crude by rail than Alaskan crude owing to low
sulfur content (16).
Reversal of Four-Corners Pipeline
Another alternative, though not of major significance is to reverse
the Four-Corners pipeline which now transports 30 thousand barrels a day from
Red Mesa, Utah to Los Angeles, California (42). From the Four-Corners area
the pipeline connects with lines which could carry oil to Texas (34).
Current projections indicate that the Four-Corners pipeline is likely to be
shutdown by 1980 (43). Recently, the Four-Corners line was acquired by the
Atlantic Richfield Company (ARCO) which proposes that a modest amount of the
West Coast surplus could be fed through the reversal of the Four Corners
Pipeline system to satisfy needs of refiners and industrial users in New
Mexico and Arizona (44).
Central American Pipeline
Currently there are four pipelines across the Isthmus of Panama which
were constructed by the U.S. Navy in the early 1940"s (20). Two of them are
in use and comprise a total pumping capacity of almost 113 thousand barrels
per day. Of the other lines, one (20 inch) was used for diesel fuel and the
other (10 inch) was never used. The system was designed for east to west oil
movement, but can be reversed. Additional lines would be required in order
to transport the expected North Slope West Coast surplus.
At present, any construction for the purpose of utilizing these pipelines
for commercial activity would be in violation of the 1936 U.S. treaty with
Panama. Should current negotiations with the Republic of Panama concerning
the future status of the Canal Zone include operation of the pipelines by a
Panamanian corporation, the alternative for commercial lease of the lines is
within the scope of the 1936 treaty (20).
Several routes have been suggested periodically, for the construction
of a pipeline across Central America. These include the countries of
Mexico, Guatemala, Honduras, Nicaragua, Costa Rica, and Panama (36). Recent
attention has focused on a proposed port on the Pacific Ocean near Las
Lisas, Guatemala with a proposed 227 mile, 42 inch pipeline extending to San
Francisco del Mar on the Caribbean Sea. The initial capacity of the pipe-
line is envisioned to be 600 thousand barrels a day with construction
completed 24 months after finalization of permits. The eventual capacity
could be as high as 1.6 million barrels per day. The sponsor is the Central
American Pipeline Company (16). Such pipelines would utilize deepwater
terminals on the Pacific sides to accomodate very large tankers (in excess
of 250,000 dwt). The Caribbean ports would probably use small tankers f
serve the Gulf Coast.
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The main issues relating to the construction of a Trans-Central-Ameri-
can pipeline include a degree of security which is somewhat less than that
offered by a U.S. point-of-entry and a U.S. pipeline (36), and the con-
sideration of the Trans-Alaska Pipeline Act which urges the use of a
domestic transportation system rather than one in or through a foreign
country (20).
Around the Horn
Another possibility for the west to east movement of North Slope
oil would be to use very large tankers traveling around Cape Horn. Such
was the marine transportation route for west coast/east coast trade prior
to construction of the Panama Canal. This route is still used by ships too
large for the Canal. Currenty, a number of these large U.S. supertankers
are available or on order but are subsidized when used in foreign trade.
The subsidies would have to be repaid for the ships to qualify for domestic
trade under the Jones Act (see the next chapter).
The 15,730 nautical mile distance from Valdez to Gulf coast terminals
presents a need for a system of weather prediction and navigational aids
to reduce the risk of accidents in the unfavorable weather and ocean
conditions near Cape Horn. No U.S. ports can handle such large tankers
at the present time (LOOP and SEADOCK would allow direct importation by
1980 at the earliest). The crude would need to be transferred onto smaller
vessels for import as crude or as bulk product after refinement in the
Caribbean islands (36).
Available data indicate that the total cost per barrel by the around
the Horn trip would be about twice the cost of a route similar to the
SOHIO proposal. A large amount of capital would be required for the
construction of a fleet of very large tankers for the movement of 500
thousand barrels per day of crude ($2.5 billion). During the round trip
from Valdez to the Gulf Coast, a 225,000 dwt tanker would consume one
barrel of bunker fuel for every 15 barrels transported - approximately
7.4 percent of the energy delivered (36). This option may be a viable,
but costly, method for the short term movement of part of the West Coast
crude excess until a long term, less energy consuming alternative can
be found.
LOOP-SEADOCK
Two offshore deepwater crude import terminals have been proposed
for the Louisiana and Texas Gulf Coast (Figure 10). The Louisiana Offshore
Oil Port (LOOP) would provide crude oil flow from St. James, Louisiana
through the Capline pipeline system to the Great Lakes region. SEADOCK
would provide crude flow from the Houston area through Texoma, Seaway,
and Explorer pipelines to Tulsa and Chicago. From Tulsa, the crude could
also enter the proposed Williams expanded system (18). Thus, North Slope
crude could be transported by 1980 through SEADOCK and LOOP to be dis-
tributed to midwest and northern refineries. The total capacity of the
terminals will be about 3.5 and 4.0 million barrels per day by 1980 and 1985
respectively. North Slope crude transported by the Cape Horn, new Central
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indirectly through crude exchanges could displace a portion of the expected
foreign imports. These deepwater terminals provide for west to east move-
ment of crude, but rely largely on various schemes of tanker traffic which
may entail a higher oil spill risk over a land based pipeline system. Also,
their use as an alternative for supplying crude to the Northern Tier states
would require supplying Washington, Montana, and North Dakota by another
means (18). Should the SOHIO crude vie with crude from SEADOCK for avail-
able capacity in the Williams pipeline or similar lines, capacity of these
distribution lines may need to be increased.
OTHER SOLUTIONS
Reduced Production of Alaskan Reserves
There will be a period of many months between the projected time that
the Trans-Alaska Pipeline will flow at 1.2 million barrels a day in 1978,
and thus exceed the rate of West Coast consumption, and the time that the
earliest of the Trans-Continental Pipeline projects will be completed. Thus,
if the North Slope crude is shipped to the West Coast during this period at a
rate not greater than the demand, there would be no West Coast surplus.
Actually if Alaskan oil reserves were continued to be conserved by reducing
production at or below the level of West Coast demand, projects such as the
SOHIO proposal apparently would not be needed. However, the West Coast
surplus merely represents an excess existant only in one area of the country.
The following are several factors mentioned at public meetings as worthy of
consideration before a reduction in the production of Alaskan reserves is
undertaken:
• The problem of providing a new crude oil supply to the Northern
Tier states may not be easily remedied without the availability
of the excess North Slope Crude.
• The Trans-Alaska Pipeline represents a substantial commitment in
both capital and to the nation's energy policy and thus should be
allowed to reach its fullest potential as soon as possible.
• The leasing program for the Alaskan Outer Continental Shelf is
proceeding rapidly, increasing further the production potential
as well as that from West Coast offshore deposits.
• Without the benefit of full production from these areas, even at
the cost of higher priced short term alternatives, the country would
have a still greater reliance on foreign imports.
• As some imports would not be displaced by Alaskan oil entering the
U.S. in modern tankers and marine terminals, the likelihood of
tanker accidents, similar to those which recently have received
public attention, would be higher than that which could be attained
utilizing an all U.S. tanker fleet.
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demand was recently summarized by Senator Stevens (45):
The expected surplus of crude oil on the West Coast
is not the disaster that some would like to call it.
Any domestic supply of oil which can displace foreign
imports and their attendent political volatility is a
national asset.
Our task now, recognizing that things have changed
since our earlier decision, is to determine what
systems can be installed most quickly and most in-
expensively to affect the most economical distri-
bution of the benefits of Alaskan oil throughout
the rest of the nation. And, after making that
determination, we need to take the necessary steps
jto assure that these systems are implemented in a
timely manner.
The shutting in of a portion of the North Slope production would be a matter
of Presidential commitment and national policy (36).
Strategic Storage
One alternative to the immediate transfer of the crude surplus to
eastern markets would be its strategic storage on the West Coast. Such
action would be consistent with the goals of the Strategic Petroleum Re-
serve System as established by the Energy Policy and Conservation Act (PL94-
163). Under the Act, the Federal Energy Administration plans to have 150 and
500 million barrels of petroleum in underground (salt domes and in salt or
limestone mines) storage by December 1980 and 1982 respectively (46). In the
event that suitable storage locations were found, should the reserves be
required, the North Slope crude stored near a West Coast port of entry would
still be remote from the eastern areas which would have a maximum need. Some
method for moving the crude to mid-continent demand centers would still be
required.
Enhancement of West Coast Consumption
An alternative to decreasing the West Coast supply and thus the excess
of North Slope crude is to increase the demand to the extent that the en-
tire production from Alaskan fields would be consumed on the West Coast.
Such a demand would need to exist over the next 20 years to keep ahead of
projected North Slope production. Meanwhile, some amount of light and
low sulfur crudes would still be required to meet the needs of existing
refineries. The increased crude usage probably would result in the
establishment of a substantial refined product export industry (36). This
large petrochemical processing industry would result in further air quality
impacts as well as land consumption and water quality impacts.
The feasibility of this option is limited by the length of time needed
to convert the present energy economy and industry. A substantial capital
39
-------
investment is required for such conversion. Since it is unlikely that a
significant increase in West Coast demand could materialize in less than a
decade, it is unlikely that the West Coast can absorb the projected surplus
by 1978 or soon after (36).
SUMMARY COMPARISON
A summary of the highlights of this chapter is presented in Figure
12. The short-term options for handling the projected West Coast surplus of
North Slope crude include international exchanges, trans-shipment through
the Panama Canal, transport by railroad, transport by tanker around Cape
Horn, Canadian exchanges (from present imports) to offset crude curtail-
ments to the Northern Tier states, reduced North Slope production, or
possibly strategic storage. By the end of 1978 at the earliest and prob-
ably in 1979 more permanent long term solutions could be realized in the
form of the Trans-Provincial Pipeline, Trans-Mountain Pipeline, Williams
Pipeline, Minnesota Pipeline, and the SOHIO pipeline. By the end of 1979
or during 1980 the Northern Tier Pipeline could be realized as well as a
pipeline across Central America. On line in 1981 could be the deep-water
ports of LOOP and SEADOCK, the reversal of the Four Corners Pipeline,
and perhaps an equitable balance between crude oil supply and demand on
the West Coast. The following chapter will address the environmental issues
which have received the most visibility and attracted the attention of state
and local governments when weighing the major West to East alternatives for
the movement of North Slope crude. These issues are the potential for air
quality impacts and oil spills.
40
-------
o
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r—
C Ol
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go.
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o
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.— J.
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01 S-
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Ol O
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i- .—
*J Ol
c o.
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c
3 C
O I-
s- o
f z
o
i o
a. a
o<
o LU
_i to
c
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ai o
o =>
3T3
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ai 01
re t-
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VI
10 T3
O> C
bi
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On line in 1977*
On line in 1978*
On line in 1979*
^
On line in 1981*
On line after 1981**
Supply to Northern Tier States
Partial Solution
International Agreement
Requi red
* Assuming start of construction at earliest expected date.
** The Central Alternative currently has no sponsors. No detailed studies have been undertaken.
FIGURE 12
SUMMARY COMPARISON OF ALTERNATIVES FOR THE WEST
TO EAST MOVEMENT OF NORTH SLOPE CRUDE
-------
SECTION 3
ENVIRONMENTAL ISSUES RELATED TO THE MOVEMENT OF NORTH SLOPE OIL
QUANTITATIVE ANALYSIS OF AIR QUALITY ISSUES
This section presents the results of studies that have been
performed with respect to air quality effects due to the transportation
of Alaskan oil. The section is relatively detailed and contains various
tables and discussions that are useful in comparing emissions and
air quality modeling analyses to clarify reasons why a wide range of
conclusions and results have occurred. A summary at the end of the
section has been provided for those readers interested in only the main
technical issues of this complex environmental area.
In the event that one of the west coast port alternatives is chosen
as the prime entry point for Alaskan crude, the air quality issues
center on the relative impact that large crude oil tanker arrivals and
the presence of crude oil storage tank facilities will have in the
immediate port area and its associated air basin. Along the Washington,
Oregon, and Northern California coasts the issue is one of possible
degradation of ambient air quality in areas that, except for some Puget
Sound port locations, are currently meeting state and federal air
quality standards. For the southern California alternatives, and
specifically the Port of Long Beach (PLB), the issue is one of possible
degradation of air quality at a time when extensive efforts are being
made to bring poor air quality to within state and national air quality
standards. Several studies have been performed to date that deal in
part, or entirely with, air quality issues and the transportation of
Alaskan oil. Most of these studies have been primarily oriented towards
evaluating the SOHIO/Port of Long Beach alternative. Table 1 contains a
reference list of the source documents used in the following air quality
discussion.
Mechanisms for Controlling Air Quality
The Clean Air Act of 1970 (and subsequent amendments) is the basic
authority for the national air pollution control program. This act auth-
orizes EPA to set the National Ambient Air Quality Standards (NAAQS) which
are the allowable levels of pollutants necessary to protect public health
(primary standards) and welfare (secondary standards). Standards have
been set for total suspended particulates (TSP), sulfur dioxide (S02),
nitrogen dioxide (NO ), carbon monoxide (CO), photochemical oxidants (0^),
43
-------
TABLE 1
REFERENCED
AIR QUALITY RELATED STUDIES RELATIVE TO
THE TRANSPORTATION AND DISPOSITION OF ALASKAN OIL
16. Federal Energy Administration. 1976. An Analysis of the Alternatives
Available for the Transportation and Disposition of Alaskan North
Slope Crude. Final Draft Report Dated November 30, 1976. Washington,
D.C. 891 pp.
20. Bureau of Land Management. 1976. Draft Environmental Impact Statement.
Crude Oil Transportation System: Valdez, Alaska to Midland, Texas
(As Proposed by SOHIO Transportation Company. Department of the
Interior, Washington, D.C.
24. Northern Tier Pipeline Company. 1976. Supplement Number 2 to the
Northern Tier Pipeline Company's Application for Site Certification.
Submitted to the Washington State Energy Facility Site Evaluation
Council on November 19, 1976.
36. Port of Long Beach and the California Public Utilities Commission
1976 Draft Environmental Import Report: SOHIO West Coast to Mid-
Continent Pipeline Project. September 1976.
43. Nehring, Richard. 1976. Mitigating and Offsetting Emissions from
West-East Oil Movement. Draft Working Note Dated December 21, 1976.
Rand Corporation, Santa Monica, California, 34 pp.
47. Pacific Environmental Services, Inc. 1976. Final Report-Air Quality
Analysis of the Unloading of Alaskan Crude Oil at California Ports.
Prepared for the Office of Air Quality Planning and Standards, U.S.
Environmental Protection Agency, Research Triangle Park, North Carolina.
48. SOHIO Transportation Company. 1976. Impact of the SOHIO Project on Air
Emissions in the Long Beach Port Area. Report Dated August 20, 1976.
Midland Building, Cleveland, Ohio.
49. Teknekron, Inc. 1976. Air Quality Impact Evaluation of Candidates Sites
for an Alaskan Oil Transfer Terminal in the Pacific Northwest. Draft
Report Dated July 31, 1976, Submitted to Region X, U.S. Environmental
Protection Agency, Seattle, Washington.
50. Chicago Bridge & Iron Company. 1976. SOHIO/CBI Floating Roof Emission
Test Program. Final Report Dated November 18, 1976, Oak Brook, Illinois.
51. MacKenzie, John R. and Charles T. Ran. 1976. Gaseous Hydrocarbon
Emissions During the Loading of Marine Vessels. Paper Presented at
the 69th Annual Meeting of the Air Pollution Control Association,
Portland, Oregon. June 27-July 1, 1976.
44
-------
TABLE 1 (Continued)
52. U.S. Coast Guard. 1974. Final Environmental Impact Statement-
Regulations for Tank Vessels Engaged in the Carriage of Oil in
Domestic Trade. Department of Transportation, Washington, D.C.
53. Office of Air and Waste Management. 1975. Compilation of Air
Pollutant Emission Factors. (2nd Edition) AP-42. U.S.
Environmental Protection Agency, Office of Air Quality Planning
and Standards, Research Triangle Park, North Carolina.
54. Esso Research and Engineering Company. 1974. Survey of Ship
Discharges. Final Report on Task I, Sub-Task 2 (Contract No.
C-l-35049). Prepared for the Office of Research and Development
Maritime Administration, U.S. Department of Commerce, Washington, D.C.
55. American Petroleum Institute. 1962. API Bulletin on Evaporation
Loss from Floating-Roof Tanks. (API Bulletin 2517). Washington, D.C.
75. Nehring, Richard. 1977. Mitigating and Offsetting Emissions from
West-East Oil Movement. WN-9719-CEQ. February, 1977. Rand Cor-
poration, Santa Monica, California, 47 pp.
76. Air Resources Board, State of California. 1977. "Preliminary
Analysis of the Proposed SOHIO Marine Terminal at the Port of Long
Beach. SS-76-035. December 16, 1977. Sacramento, California.
77. SOHIO Transportation Company. 1977. "Supporting Information for
the SOHIO Permit Application Prepared for the Southern California
Air Quality Management District." February, 1977. SOHIO Transpor-
tation Company, Cleveland, Ohio.
78. Port of Long Beach. 1977. "Overview SOHIO-West Coast to Mid-Continent
Pipeline Project." January, 1977. Environmental Affairs Division,
Port of Long Beach," California.
79. Office of Planning and Research, State of California. 1976. "Is
San Luis Obispo Bay a Realistic Alternative Meriting Further Study
if the SOHIO Proposal for a Deepwater Terminal to Receive Alaskan
Oil at Long Beach Fails to Meet Prescribed Environmental Standards?".
October 28, 1976. Sacramento, California.
45
-------
and hydrocarbons (HC). Table 2 summarizes the relationship between the
above pollutants and various potential emission sources associated with
the transportation and disposition of Alaskan oil.* Table 3 contains a
summary of current Federal air quality standards and State standards set by
California and Washington.
The Federal government controls, by emissions standards, pollutants
from new motor vehicles, certain newly constructed industrial sources,
and sources emitting hazardous pollutants. With respect to Alaskan oil,
regulations on new storage tank facilities and, indirectly, controls on
certain oil refinery processes are the principal emissions regulations
that apply at this time. However, air quality standards, the concept of
Air Quality Maintenance Areas (AQMA), and new source reviews currently
being promulgated may have a significant impact on (1) where a port
facility will be located, (2) constraints on ships which may call at the
facility, and'(3) the operating procedures to be allowed (e.g., simulta-
neous offloading of two or more tankers, purging, etc.).
The AQMA concept is designed to protect growth areas, especially most
Standard Metropolitan Statistical Areas (SMSA), from future violations of the
NAAQS by requiring states to submit plans on how future emissions growth
(and thus air quality) will be controlled. The most uncertain part of this
concept is the rate at which economically viable technological advances in
air pollution controls can offset the potential emissions due to growth.
Due to this uncertainty, current EPA proposed guidelines (72) call for a
review of new major projects with a criteria for permit approval that is
dependent on emissions "tradeoffs". These tradeoffs would have the affect
of substituting new low polluting equivalent facilities for older facilities
(thus reducing emissions), or allowing growth of new facilities having an
emissions output less than those of replaced older facilities. While the
EPA guidelines are proposed, the State of California, and specifically the
South Coast Air Quality Management District (SCAQMD) has adopted this
type of policy and has explicity included "...those (emissions) that result
from the operation of the carriers' engines; the purging or other method of
venting of vapors; and from the loading, unloading, storage, processing,
and the transfer of cargo." Further, the SCAQMD rules limit emissions
of NO , HC, and SO from new and modified sources to 15 pounds/hour or
150 pounds/day unless it can be shown that best available technology has been
used. Emissions of NOx, HC, and SOX may not exceed 25 pounds/hour or 250
pounds/day if it is determined that such emissions would cause violations
of, or interfere with the attainment or maintenance of air quality stand-
ards. An exemption to the above would be allowed only if a stationary
source with higher emissions rate is replaced at the same location.
The legal authority for controlling air emissions in port and once a
tanker is underway has become an important issue. The placing of constraints
*Analyses have indicated that CO and particulate emissions due to
Alaskan oil transportation are not major and therefore are not discussed
in this report.
46
-------
TABLE 2
PRIMARY POLLUTANTS EMITTED BY PROJECT
Related Sources
SOURCE DESCRIPTION
Oil Storage Tanks
Tankship Operations
Construction Equipment
Oil Spills
Oil Refining
Power Generation
Pollutant Species
HC
X
X
X
X
X
NO
X
X
so.
X
X
Source: BLM(36)
47
-------
POLLUTANT
Oxidant(Ozone)
Carbon Monoxide
Nitrogen Dioxide
Sulfur Dioxide
Suspended Particur
lates
Sulfates
Hydrogen Sulfide
Hydrocarbons
(Corrected for
Methane)
TABLE 3
AMBIENT AIR QUALITY STANDARDS (PPM)
AVERAGING TIME NATIONAL STANDARDS2 CALIFORNIA- WASHINGTON3
1 Hour
12 Hour
8 Hour
1 Hour
Annual^
1 Hour
Annual
24 Hours
3 Hours
1 Hour
1 Hour
(twice in 7 days)
Annual^
(Geometric Mean)
24 Hour
24 Hour
1 Hour
3 Hour
PRDIARY
.03
—
9
35
.05
—
.03
.14
—
—
—
74 Mg/m3
260 Mg/m3
—
—
.24
SECONDARY
.08
—
9
35
.05
—
—
.49
—
—
60 Mg/m3
150 Mg/m3
—
—
.24
.10
10
40
—
.25
.04
—
.5
—
60 Mg/m3
100 Mg/m3
25 Mg/m3
.03
__
.08
—
9
35
.05
—
.02
.10
—
.39
.25
60 Mg/m3
150 Mg/m3
—
—
.24
1 California values are not to be met or exceeded.
2 National Standards are not to be exceeded more than once/year.
3 Washington values are not to be exceeded more than once/year.
4 Annual Standards are not to be met or exceeded.
5 This Standard is under litigation and not currently enforced.
48
-------
on allowable operations while in port may be difficult due to the common
carrier status of a port facility (e.g. tankers unable to meet the constraint
requirements could not use the facility). After getting underway, the
tanker captain, Coast Guard, Environmental Protection Agency, and/or the local
or state agency may each have varying authority over operations. Current
statutes are not explicit as to where legal responsibility for underway tanker
emissions lie and no explicit limiting regulations exist. In California, this
lack of explicit legal authority is a key factor in the evaluation of the
proposed SOHIO project in the Port of Long Beach (76).
Existing Air Quality
Evaluation of the significance of air pollution effects with respect to
proposed port facilities located in Puget Sound, central California, and
Los Angeles-Long Beach cannot be done without considering existing air
quality. The following section, summarized from Reference 75, describes
air quality conditions at the these alternative port locations.
Air quality along the Pacific coast at the three principal
candidate port locations varies widely. Table 4 provides
a few indicators of these differences. The Table provides
1975 air quality data for selected pollutants at several
monitoring stations within each of the candidate port air
basins. The pollutants selected are those which will either
be emitted from a west-east oil transport system or oxidants
created from these emissions. The stations selected in
the South Coast Air Basin (Los Angeles-Long Beach) were
the one nearest the proposed tanker terminal (Long Beach)
and those in a variety of locations downwind from the proposed
terminal. The stations selected are downwind from the terminal
55 percent of the year in the middle of the morning, and 80
percent of the year in the middle of the afternoon. During
the periods of heaviest pollution, they are downwind from the
terminal 90 percent of the time during the middle of the day.
Because neither of the other two locations of proposed port facili-
ties have major pollution problems, air quality data are not as
readily available. Within central California, Santa Maria is the
closest monitoring site to a proposed terminal located in south or
central San Luis Obispo Bay. San Luis Obispo, in the Los Osos
Valley, is a monitoring point twenty miles north of the proposed
terminal. The four monitoring sites in the Puget Sound/Northwest
•Basin are dispersed throughout the area of the Sound and provide an
indication of maximum pollution levels in the area. Extensive data
for locations nearer proposed Puget Sound Ports e.g., March Point or
Cherry Point, could not be obtained.
Pollution in the South Coast Air Basin is severe. Federal primary
standards for oxidants (0.08 ppm averaged over one hour) are
exceeded over a broad area during 80 to 90 percent of the days
from May through October and 15 to 30 percent of the days from
November through April. State standards for nitrogen dioxide
49
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TABLE 4
SELECTED AIR QUALITY DATA FOR THE SOUTH COAST. SOUTH CENTRAL COAST, AND PUCET SOUND/NORTHWEST AIR BASINS. 1975
Air Basin
Monitoring
Station
South Coast
Long Beach
Los Angeles-
Downtown
Pasadena-Walnut
Pomona
Rlverslde-
Rubldoux
Uplsnd-ARB
South Central
Coast
San Luis Oblspo
Santa Maria1
Puget Sound/
Northwest
Bslllngham, PAHS
Everett, Medical-
Dental
Seattle, Du-
wasilsh
Tacoaa, Hess
Building
Oxldant (Oione)
f Days
w. Hrs.
>0.08 PPM
9
157
184
167
196
216
3
0
0
N.A.
0
I10
f Hours
>0.08 PPM
15
616
982
837
1092
1372
36
0
0
N.A.
0
19
1 Hr. Max.
(PPM)
0.14
0.25
0.32
0.33
0.31
0.41
0.11
0.062
0.072
N.A.
0.062
0.132
Sulfur Dioxide
Annual
Average
(PPHM)
2.1
2.0
1.6
1.4
0.8
N.A.
N.A.
N.A.
1.0
0.6
0.6
2.0
24 Hr.
Max.
(PPM)
0.06
0.06
0.04
0.04
0.03
N.A.
N.A.
N.A.
0.04
0.07
0.05
0.04
1 Days
w. Hrs.
>0.40 PPM
0
0
0
0
0
N.A.
N.A.
N.A.
0
i2
0
0
t Hours
>0.04 PPM
0
0
0
0
0
N.A.
N.A.
N.A.
0
5
0
0
Dally Max.,
1 Hr. Mean
(PPM)
0.23
0.14
0.07
0.09
0.06
N.A.
N.A.
N.A.
0.08
0.50
0.22
0.22
Nitrogen Dioxide
Annual
Average
(PPHM)
6.2
6.7
8.2
7.2
3.0
4.8
2.1
N.A.
N.A.
N.A.
N.A.
N.A.
1 Days
w. Hrs.
>0.25 PPM
23
30
35
13
0
1
0
N.A.
N.A.
N.A.
N.A.
N.A.
Dally Max..
1 Hr. Mean
(PPM)
0.4S
0.56
0.49
0.35
0.21
0.26
0.10
N.A.
N.A.
N.A.
N.A.
N.A.
in
O
Key: PPM - parts per million
October to December only.
Oione.
-------
(0.25 ppm average over one hour) are exceeded 5 to 10 percent of
the days of the year. National primary standards for N02 (5.0 pphm
annual average) are also exceeded in many parts of the basin.
National carbon monoxide standards (9 ppm averaged over eight
hours) are exceeded on as many as 20 percent of the days at some
locations. State standards for suspended particulate matter (100
micrograms/m averaged over 24 hours) are exceeded more than half
the days of the year at some locations, often by large margins.
Although state one hour standards for sulfur dioxide are
rarely exceeded, state 24-hour standards (0.04 ppm) have been
exceeded in the South Coast Air Basin. The national annual
average standard has not been exceeded at any location in
recent years. State 24-hour sulfate standards (25 micrograms/m3)
are exceeded frequently at some locations.
In the San Luis Obispo Bay area, standards are exceeded
infrequently and only by small margins. Oxidant standards are
occasionally exceeded at San Luis Obispo. Nitrogen dioxide standards
are met by considerable margins. Carbon monoxide and sulfur dioxide
standards are also not exceeded. State standards (24-hour averages)
for suspended particulates are exceeded occasionally in Santa Maria,
most likely because of wind-blown dust.
Air quality problems in the Puget Sound/Northwest Air Basins
are also minor. Because of the cooler, cloudier weather and
a relative paucity of sources, oxidants, nitrogen oxides and
hydrocarbons are not significant. Ozone standards are ex-
ceeded only at some locations by small margins at infrequent
intervals. Sulfur dioxide is a minor problem. State and Federal
secondary standards for suspended particulates are exceeded
infrequently in some cities and metropolitan areas (including
one location in Port Angeles). Carbon monoxide standards
are exceeded at some locations in the Seattle and Tacoma
metropolitan areas.
Quantitative Measurement of the Issues
An objective evaluation of the air quality impact of any of the proposed
alternative port facilities involves quantifying anticipated project emissions
and relating them to their impact on resultant air quality. A generic des-
cription of the analysis approach is illustrated in Figure 13 in which each
box represents a source of uncertainty that can affect the conclusions about
the acceptability of the new emissions sources.
Two measures of impact are indicated. First, emissions inventories
can be calculated with and without the new sources in order to identify the
magnitude of the problem and indicate future growth. With the "tradeoff"
criteria possibly becoming a policy for evaluating new source acceptance,
the most accurate emissions calculations obtainable are needed since the
calculations will likely be involved with permit and regulatory proceedings.
Second, because emissions growth does necessarily cause violations of
51
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EMISSIONS
CONTROLS
El
F/
DEFINE
EMISSIONS
SOURCES
Ln
to
METEROLOGICAL
DATA
DISPERSION/
REACTIVE MODEL
EMISSION
FACTORS
111
*
SCENARIOS
CALCULATE
EMISSIONS
EXAMINE
TRADEOFFS/
MITIGATING
MEASURES
EXAMINE
VIOLATIONS
OF
STANDARDS
CONCLUSIONS
FIGURE 13
AIR QUALITY QUANTITATIVE ANALYSIS
-------
ambient air quality standards, an analysis is required to evaluate the
effects that meteorological conditions and pollutant reactivities have on
resultant air quality. As will be seen, the quantification of the problem
to date has been, with respect to either measure, difficult due to differing
assumptions concerning tanker fleets, the operations that can and/or will be
performed in port, and the adequacy of analytical models to reflect the
emission/air quality relationship.
Project Related Emissions Sources
Before a quantitative analysis of air quality effects can be performed,
it is necessary to define (and agree upon) project related emission sources.
Table 2 identifies the most reasonable set of sources that can be directly
attributed to a new tanker port facility and an accompanying pipeline. Of
these, oil storage tanks and tankers have the greatest impact. Accidental
oil spills,'if large and near land, would have a significant short term
impact on air quality with respect to evaporative hydrocarbons. However,
the expected frequency of such an occurence is small enough to preclude its
consideration as a "worst case" emissions source (but, of course, consitutes
a very real and more long lasting water pollution hazard). Electrical
generation as an explicit pollutant source could have an impact at remote
locally powered pipeline pumping stations in areas with little or no current
emissions (e.g., the desert). An indirect air quality impact of a proposed
marine terminal and pipeline would be oxides of sulfur and nitrogen from
fossil fuel powered electrical generation plants. In the Pacific Northwest
this will be minimal since electrical power is obtained principally from hydro-
electric plants. It has been estimated that from 1300-4600 pounds/day of
sulfur oxides (SOX) and 700-2500 pounds/day of oxides of nitrogen (NOX) emis-
sions may be associated with the generation of power for the SOHIO project
(36,76). Since it would not be possible to attribute these emissions to
any one plant in a power grid, air quality impact studies due to a
marine terminal/pipeline project would be impossible. However, for the
purposes of "emissions tradeoffs" it is likely that these emissions
would be included in the overall emissions "balance sheet."
In addition to the sources indicated in Table 2 non-project related
emissions within the local environment must be considered. HC and NO
are both reactive pollutants and their affect on air quality (specifically
Ox generation) is dependent on the local emissions. Therefore, emissions
from local area (e.g., mobile) sources and large point sources (e.g., re-
fineries and power plants) must be considered as well.
Emissions Controls/Tanker and Storage Design
The primary emissions controls involve basic design features built
into tankers and storage facilities. In tankers segregated ballast,
separate fuel storage tanks for burning low sulfur fuel, and inerting
systems that suppress cargo tank emissions and reduce the presence of
explosive conditions are the main controls used to reduce emissions.
Floating roof designs with double seals and vapor recovery systems are the
principal design practice used to reduce fixed storage emissions.
53
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Ballasting—
After discharging cargo, an oil tanker without sufficient segregated
ballast capacity will take some sea water aboard in cargo tanks to ensure
proper propeller immersion and to provide stability and sea-worthy
characteristics. The amount of ballast taken aboard depends upon the
anticipated weather conditions, the distance and route of the ballast
voyage, the vessel's lightship displacement (weight), length to depth
ratio, and other vessel characteristics. The amount of ballast taken
aboard in port varies from 15 to 20 percent of the vessel's total cargo
carrying capacity, but may be greater during periods of severe bad
weather (52).
Tankers currently in trade and under construction can take on
ballast in three alternative configurations:
1. All of the necessary ballast is taken on in cargo tanks (with
the minor exception of fore and aft peak tanks).
2. A portion of the necessary ballast is taken on in segregated
ballast tanks, and the remainder is taken into cargo tanks.
3. All the necessary ballast is taken on in segregated ballast
tanks.
The main advantages of having segregated ballast compartments on
tankers is that of eliminating the need to discharge oil contaminated
ballast water to the environment and reducing potential cargo loss as
the result of a collision and/or grounding (depending on the location of
the segregated ballast compartment). A secondary advantage is that
hydrocarbon vapors present in an unloaded cargo tank need not be vented
to the atmosphere due to displacement by the loading of ballast water
into the cargo tank. The majority of Alaskan trade tankers will have
sufficient segregated ballast to leave port (15%) and new vessels* of
70,000 dwt or more will have fully segregated (approximately 35 percent
of the dead weight tonnage) ballast facilities (52). This is a U.S.
Coast Guard requirement in compliance with amendments to the Ports and
Waterways Safety Act of 1972. The Inter Governmental Maritime Consultive
Organization (IMCO) has aso passed a similiar requirement (76). The
majority of the tankers in world trade currently do not have 15-20
percent segregated ballast tanks; thus ballasting currently is largely
accomplished in cargo tanks in port (52).
Separate low sulfur fuel storage—
Sulfur oxide emissions are a direct result of fuel combustion in
the tanker's boilers. The emission rate is directly proportional to,
* A new vessel, as defined by the Coast Guard, means a U.S. vessel in
domestic trade that (a) is constructed under a contract awarded after
December 31, 1974; (b) in the absence of a building contract, has the
keel land or is in a similar stage of construction after June 30,
1975; or (c) is delivered after December 31, 1977.
54
-------
among other factors, the percent of sulfur in the bunker fuel. In port,
during the offloading operation, the tanker boilers are operated at a
relatively higher percent capacity in order to pump crude oil off the
tankers. This operation, which may run from 10-15 hours, produces
significant emissions of sulfur oxides. To offset these high emissions,
some of the Alaskan trade tankers will utilize low sulfur (0.5%S or
less) from special fuel bunkers in port with a resultant 400-600 percent
decrease in normal SOX emissions. The overall affect on total sulfur
emissions will depend on the number of vessels calling in port which
have separate fuel storage capability.
Inert ing systems—
As a measure to reduce corrosion in the tanker crude oil storage
compartments and reduce the risk of explosion of petroleum gases, the
vapor space of the cargo compartments is filled with oxygen poor flue gas
from the ships' boiler stacks. The flue gas is washed clean and cooled
before delivery to the cargo hold. Approximately 17 percent of the flue gas
is diverted from entering the atmosphere in tankers of the 120-165K dwt size
which reduces total stack emissions proportionately. During loaded passage
the inert atmosphere in the tanks is maintained by periodic repressuring.
Upon offloading, as the oil is pumped out of the tanks, inert gas blowers
ensure that the tank atmosphere remains inert (oxygen-poor). With proper
operating vent control valves and careful monitoring it should be possible
to discharge all oil cargo with no release of hydrocarbons to the atmosphere
during the entire unloading process.
Once at sea for the return voyage, empty inerted storage tanks may
be cleaned to remove oil residues so that clean ballast water can be
taken aboard (if necessary), or to prepare the storage tanks for a
different cargo type. For those inerted Alaskan trade tankers that will
shuttle between Valdez and the west coast and have sufficient segregated
ballast, tank cleaning will likely occur infrequently. If the empty
inerted tanks make the entire return voyage undisturbed, the inerted
hydrocarbon mixture will be vented to the atmosphere through displacement
during the crude onloading process at Valdez. Finally, while unlikely,
it is possible that due to emergency maintenance requirements, purging
of all hydrocarbon emissions (gas freeing) could occur at any time
following unloading. In summary, the inerting system acts as a safety
measure, reduces tank corrosion, diverts stack emissions to the storage
tanks during the unloading process, and minimizes the probability of
hydrocarbon emissions in port following unloading.
New Source Performance Standard for Storage Tanks —
The Federal New Source Performance Standards specify that petroleum
storage facilities holding 40,000 gallons or greater must have a floating
roof, vapor recovery system, or their equivalent when the true vapor
pressure is between 1.5 and 11 psia. Since the Alaskan crude vapor
pressure is in the 7-9 psia range, any reasonably sized new storage
facility will have one of the above features. As will be discussed
55
-------
later, there is a question over the proper formula to use in computing
the level of hydrocarbon emissions from new floating roof tank facilities.
Basic Emission Factors
The second step in quantifying port related emissions is establish-
ing a set of basic emission factors. These factors relate to a specific
operation associated with the previously identified emission sources and
are derived from various sources such as: experimental results, emis-
sions controls, equipment specifications, physical and chemical equations,
assumed fuel and crude composition, etc. The sensitivity of the magni-
tude of the final emissions inventory to the assumed basic emissions
factors is great since relatively small differences in the assumed
emissions factors propagate into large differences in emissions.
Examples of these factors are: fuel sulfur content, crude hydrocarbon
composition, fuel consumption rate, combustion gas composition, pumping
time, fuel density, etc. Nominal values and the sources for each of
these factors are discussed in detail below.
Combustion Pollutants
The tankers delivering crude oil will emit air pollutant products
of combustion from their stacks at various rates during their entry into an
air basin, maneuvering to dock, "hotelling" at the pier (idling), and during
pumping and ballasting operations. The two principal pollutant products
will be SO and NO with lesser amounts of particulates, hydrocarbons, and
CO also present. Tankers burn more fuel in berth than other ships as
onboard pumps are used to unload the crude in a relatively short time.
Combustion products are emitted by assisting tugboats as well but their
impact is minimal with respect to the analysis.
Calculation of emissions have been performed in various reports related
to the SOHIO project and Alaskan crude transportation in general (16, 20,
36, 43, 44, 77). These reports assume fuel consumption rates for various
operations and tanker sizes and then use stack emission factors to generate
pollutant emission rates and totals. The methodologies are similar in each
report but differing assumptions cause many different values to evolve.
The following sections illustrate the values used for calculating SOX and
hourly emissions.
Oxides of Sulfur —
The basic equation used to calculate SO emissions is as follows:
E. . = C. . • 1 • S • F. I
56
-------
where: i = index for tanker type i;
Eij = sox stack emissions from tanker type i in operation j
(pounds/hour);
j = index of operations tanker type i performs;
C^j = fuel consumption rate for tanker type i during
operation j (pounds/gallon);
D = fuel density (pounds/gallon);
S = % sulfur content in fuel;
F = stack emission factor (pounds (%S)/103 gallons);
and
I = inerting reduction factor.
Except for open sea operations, the maximum hourly emissions were found
to occur when the tankers are pumping (offloading) the crude. Table 5
summarizes the values used to calculate S02 emissions for pumping
operations*.
Not all columns and rows contain values since certain studies did
not compute values for all tanker sizes and not all studies contained
information on computational assumptions. For "worst case" analyses
purposes, BLM is the most conservative since by far the most sensitive
factor in Table 5 is the fuel percent Sulfur content. BLM also used the
lowest fuel density factor (which equates to a higher stack emission
factor) and the highest consumption rate. Given that only "best control
technology" tankers would be allowed to use a port facility, the single
tanker "worst case" is that indicated by the 165K dwt inerted tanker
burning .5 %S fuel computed by PES. (The BLM analyses did not apply an
inerting reduction factor to their low sulfur burning cases). The 120
pound/hour value is above California state maximum allowable value and
would be subject to the previously discussed project acceptance criteria.
Subsequent to these studies, the South Coast Air Quality Maintenance
District (SCAQMD), SOHIO and the California Air Resources Board (CARB)
jointly agreed upon a further set of tanker emissions factors that will
likely be used in the evaluation of the SOHIO project permit applications
(77). These results are given in the columns labeled "SCO". The
principal differences in the emissions factors used in the "SCD" column
are due to assumed fuel consumption rates which produce higher emission
rates for the 80K dwt tankers and lower emission rates for the 165K dwt
tankers than found in the previous studies.
*In certain cases the reports did not contain explicit values for each
column. In these cases, where possible, calculations were performed
to "back into" values. Also roundoff errors will cause certain columns
to not total properly.
57
-------
TABLE 5
MAXIMUM HOURLY SOX EMISSIONS RATES USED BY VARIOUS STUDIES (PUMPING)
Tanker Size (DWT)
7 OK
8 OK
80K (inerted)
120K
120K (inerted)
165K (inerted)
Tanker Size (DWT)
Consumption Rate (Ibs/hr)
Fuel Density (Ibs/gal)
PES
5320
7093
-
12040
12040
14373
BLM
7093
-
12040
-
14373
PLB
_
-
-
13739
TEK
5579
6336
10745
10745
12846
FEA
_
-
-
-
-
Stack Factor (lbs(ZS)/103
SCD
_
9378
9378
11556
11556
10350
gal)
PES
8
8
_
8
8
8
BLM
_
7
_
7
_
7
PLB
_
7.88
Inerting
TEK FEA
8.2
8.2
- -
8.2
8.2
8.2
Factor (Z)
SCD
_
8
8
8
8
8
PES
BLM PLB TEK FEA SCD
70K
80K
80K (inerted)
120K
Every Study Used: 159.5
.85 .83
120K (inerted)
165K (inerted)
Tanker Size (DWT)
70K
80K
80K (inerted)
120K
120K (inerted)
165K (inerted)
Pounds/Hour (lbs(ZS)/hour)
PES
109
142
-
240
204
240
BLM
-
160
-
275
-
322
PLB TEK
109
123
-
209
278
228 212
FEA
109
142
121
240
204
240
Tanker SOX
Tanker Size/Type
70K
80K
80K (inerted)
120K
120K (inerted)
165K (inerted)
PES
.58
_
71
-
-
102
120
25
218
284
-
480
408
480
BLM
.58 38
_ _
480
-
824
137
161
PLB
.58
_
-
-
-
114
SCD
-
187
163
230
200
180
Emission
TEK
1.58
164
185
313
267
318
.85 - .85 .85 .83
.83 .83 .85 .85 .83
Sulfur Assumptions Used in Analyses:
PES:
BLM:
PLB:
TEK: 1.
FEA: 1.
SCD:
(Ibs/hr)
FEA
1.5S
164
213
182
360
306
360
5ZS If Separate Fuel Storage;
2ZS Otherwise
5ZS If Separate Fuel Storage;
3ZS Otherwise
5ZS Only; Other Vessels not
Allowed
5ZS In All Vessels
5ZS In All Vessels
5ZS In All Vessels
SCD
.58 28
_
94 376
82 326
115 460
100 400
90 360
Sources; PES (47), BLM (20), PLB (36), TEK (49), FEA (16), SCD (77)
58
-------
Even without considering fuel sulfur content, the results display signif-
icant variability in computed values. Any computation of emission totals
therefore will be sensitive to these hourly rate differences.
Oxides of Nitrogen—
Oxides of nitrogen (NOX) are a byproduct of combustion both due to
reactions with nitrogen contained within the fuel and through high temperature
reactions with nitrogen in the air. Since maximum fuel consumption while in
port will occur during offloading, maximum hourly NOX emissions will occur
during this operation. The approach to calculating NOX emissions is similar
to that used for SOX with the exception that none of the analyses consider
nitrogen fuel content in the calculations.
Table 6 summarizes results obtained in various reports. Three different
stack emission factors were used that reflected a sizable difference in
assumed emission rates. The middle value (63.6 pounds NOX/103 gallons) used
by BLM and PLB was taken from AP-42, the EPA handbook of emissions factors
(53). This value reflects full power fuel consumption. The highest value
used by PES, Teknekron, and, indirectly, FEA reflect factors given in a study
by EXXON Corporation for the Maritime Administrative Office of Research and
Development (54). The joint SOHIO, SCAQMD, and CARS (SCD) value was based on
emissions test by Scott Environmental Technology, Inc., on an inerted tanker
in December, 1976 (77). The resultant stack emission factor was twenty
percent less than the AP-42 value and less than half the value in Reference
(54).* As with the SOX calculations, the results give several values for
each tanker type. Primarily due to the stack emission factors used, the
PES and FEA estimates were the highest and the SCD emissions estimates were
the lowest.
Hydrocarbon Emissions From Tankers
Tanker HC emissions evolve from five tanker operations: boiler combus-
tion, ballasting, fueling, venting, and purging. Fueling and boiler combus-
tion HC emissions were found to be negligible in the various studies and will
not be considered here. Additional hydrocarbon emissions are a result of
losses from fuel storage tanks that would be associated with a port terminal
facility. Very few analyses have been performed on the tanker loading emissions
at Port Valdez. BLM has indicated that analyses have shown that air quality
at Port Valdez will be impacted due to increased tanker traffic (20). Since
tanker cargo loading is not anticipated for the Alaskan trade tankers at any
point but Port Valdez, all the analyses to date have disregarded this HC
source.
*These results were preliminary and subject to further examination.
59
-------
TABLE 6
MAXIMUM NO EMISSIONS (LBS/HOUR)
x
Tanker Size (PUT)
70K
80K
80K (Inerted)
120K
120K (inerted)
165K (inerted)
Tanker Size (DWT)
70K
80K
80K (inerted)
120K
120K (inerted)
165K (inerted)
Tanker Size (DWT)
70K
80K
80K (inerted
120K
120K (inerted
165K (inerted
Consumption Rate (Ibs/hr)
Fuel Density Ubs
PES
5320
7093
—
12040
12040
14373
BLM
_
7093
—
12040
—
14373
PLB
_
-
-
-
-
14368
TEK
5579
6336
—
10745
10745
12846
FEA
_
-
-
-
—
-
SCD
_
9378
9378
11556
11556
10350
PES
8
8
-
8
8
8
Stack Factor (lbs(N09)/1038al)
PES
103.8
103.8
-
103.8
103.8
103.8
BLM
_
63.6
-
63.6
-
63.6
PLB
_
-
-
-
-
63.6
TEK
103 is
103.8
-
103.8
103.8
103.8
FEA
—
-
-
—
-
—
SCD
—
48.3
48.3
48.3
48.3
48.3
PES
«
-
-
_
.85
.83
BLM PLB TEK
8.2
7 - 8.2
_ _
7 - 8.2
8.2
7 7.88 8.2
Inerting Factor
BLM PLB TEK
— «. •
_
_
_ - -
.85
.83 .85
FEA
_
-
-
-
-
-
(I)
FEA
^
-
.85
_
.83
.85
SCD
_
a
8
8
8
8
SCD
—
-
.87
_
.87
.87
Pounds N09/Hour
PES
70
92
-
156
132
156
BLM
—
64
-
109
-
130
PLB
_
-
-
-
-
96
TEK
71
80
-
136
116
138
FEA
80
92
86
156
132
156
SCD
_
57
49
70
58
54
SOURCES:
PES (47), BLM (20),
TEK (49), FEA (16),
PLB (36),
SCD (77).
-------
Differences in "worst case" hourly HC emission estimates have evolved
principally due to assumptions about which tanker operations will, or will
not, occur in a port during unloading and ballasting operations. Table 7
presents the hourly values reported by the various studies of the issue
(16^20,36,47,49,77). As with NOX and SOX, considerable differences in
values are found between studies. Ranges were used in the PES, FEA, and
SCD studies to reflect a range of hydrocarbon densities that might be
present in the tanker cargo hold during the assumed operations. In
addition the SCD report included in-transit ballast and purging emissions
rates to Point Conception, or approximately 160 miles from the Port of
Long Beach. The BLM report used a ballast emissions factor based upon a
report describing cargo tank emissions during loading operations (51).
The PLB report used the computations given in EPA-42 (53) for fixed roof
storage facilities to estimate venting losses. All studies used a
correction factor to reflect reactive hydrocarbons that ranged between
94% to 97%.
The single largest emission source, purging, if performed in
port would cause a considerable impact on ozone concentrations in
Southern California alternative port locations (16,47). For the proposed
Port of Long Beach facility, the applicant (SOHIO) claims that this
operation will not be performed in port and the Coast Guard has stated
that only tank washing or maintenance activities would warrant tank
purging (16). An evaluation of how often unscheduled purging is required
has not been performed by any study.
Assuming no purging will be performed in port, the issue becomes
one of the magnitude and extent of ballasting emissions. Since it is
expected most of the Alaskan trade tankers above 70K dwt will have
sufficient segregated ballast to at least leave port, only non-segregated
ballast tankers need be considered. The BLM value for these emissions
was above the maximum value computed by PES and FEA. If only fully
segregated ballast tankers were allowed to use a port facility, no
ballast emissions would occur.
If an inerting system is used and/or properly operating vent
pressure—vacuum valves are used on tankers then no, or negligible,
venting emissions will occur. These emissions are a result of HC
evaporation within the tanker storage compartments due to ambient
temperature changes and can be controlled by proper valve settings and
positive inert gas pressure. Given segregated ballast, inerting, and no
purging in port, tanker hydrocarbon emissions will be near zero.
For the SOHIO project, there is an issue as to whether or not HC
emissions from tankers after leaving port, but within the Los Angeles
area (e.g., to Point Conception), should be considered. These emissions
could occur due to continued purging of tanks or from taking on ballast
up to the 35 percent dwt level for sea voyage in those tankers with less
than 35 percent segregated ballast. The majority of the principal
Alaskan crude tankers calling at the proposed SOHIO terminal are projected
to have 35 percent segregated ballast. However, as a common carrier
facility some question has arisen as to what other types of tankers may
use the facility.
61
-------
TABLE 7
MAXIMUM HC HOURLY EMISSIONS (LBS/HOUR)
Venting (Inerted/Non-Inerted)
Tanker Size PES
70K NE/0-350 NE
80K NE/0-400 NE
120K 0/0-600
165K 0/NE
BLM
NE
NE
NE
NE
PLB
NE
0/238
0/308
0/410
TEK
-
-
-
_
FEA SCD
NE/GG-158'
NE/100-2407 0/50 ; 0/1109
0/150-3607 0/708; 0/1709
0/NE
0/1008; 0/2449
Ballasting (Seg/Non-Seg)
Tanker Size
70K
80K
120K
165K
Tanker Size
70K
80K
120K
165K
PES
0/525-17503
0-19783/NE
0/NE
0/NE
PES
0
0
0-5990
0-8740
BLM
2129
NE
NE
NE
BLM
NE
NE
NE
NE
PLB2
NE
0/1450
0/2175
0/3000
Purging
PLB
NE
2280
3440
4719
TEK4 FEA
0/420-16807
0/640-25607
0/NE
0/NE
(Inerted)
TEK* FEA
NE
NE
2580-6200;?' 7;
3500-8300°';
2820-67805.'/,;
3500-8450 '
SCD
0/8008; 0/10669
0/008; 0/16009
0/008; O/O9
SCD
2160-32807'8;
1440-21887'!
3240-4920;»J;
2160-3282;'I
4460-6760;»J;
2970-45207'9
1 PLB values given on a per visit basis. Assume 10. hours.
2 PLB values given on a per visit basis. Assume 4 hours.
3 Low value based on 3% HC concentration. High value based on 10% HC.
4 Draft report, reference (49), did not contain HC computations.
5 Purging value based on sequential purging of tanks during first hour.
6 Purging value based on simultaneous purging of tanks during first hour.
7 Low value based on 3% HC concentration. High value based on 12% HC.
8 In port emissions.
9 In transit to point conception.
Sources: PES (47), BLM (20), PLB (36), TEK (49), FEA (16), SCD (77).
62
-------
Hydrocarbon Emissions From Storage Facilities
All studies used the API Bulletin 2517 (55) for computing the emissions
from storage facilities associated with a port facility. The results ranged
in value from 75-175 pounds/hour given different throughput assumptions,
locations, meteorological conditions, and corrections for reactive HC. These
emissions, while not as high as some of the maximum tanker operating emissions,
are continuous and on a yearly basis will be quite sizable. A recent study on
a scale model facility using latest technology indicates that the API Bulletin
2517 formula may overestimate emissions by a factor as high as 300-500% (50).
Since the API Bulletin is based upon older technology, the storage emission
computations may reflect overestimates.
Project Scenarios and Total Emissions
In general, the newer larger tankers tend to have more emissions
controls (e.g., separate ballast, inerting) and therefore, scenarios run
to date with larger tankers tend to indicate lower average emissions.
Scenarios describing "worst-case" short term (emissions) cases are more
dependent on the particular operations assumed. The fleet mix, in these
cases, affects the probability that a particular operation will occur.
Almost all the analyses to date have emphasized the "worst-case" short
term scenarios. However, all the analyses have differed as to what
constitutes a valid "worst-case" scenario and what probabilities can be
assumed. The probabilities associated with the scenarios should be
those that reflect the emissions and air quality standards requirements.
For example, hourly National standards should not be violated more
frequently than once per year. Therefore the "worst" scenario associated
with a chance of occurrence equal to or greater than 2 in 365x24 hours
should be considered. For states such as California where no violations
are permitted, the relevant probability would be equal to 1 in 365x24
hours.
Tables 5, 6, and 7 previously described the "worst-case" hourly
emission on a per tanker basis. Table 8 summarizes the worst case combustion
scenarios that have been examined to date, and Table 9 summarizes the
fugitive HC emissions scenarios. On an average daily basis the estimates
of SOX emissions range from 342 pounds/day to 11,000 pounds/day. These
differences arise from the assumptions made about sulfur content of the
fuel burned, the length of stay in port, the number of visits per year,
in and out of port distances , and the types of ships in the assumed fleet.
The FEA scenarios assumed 24 hour pumping times and 40 hour port visits.
The PES scenarios assumed 10-15 hour pumping time and approximately 40
hours in port. Both of these studies also included a sizable emission
contribution due to maneuvering to and from berths under power. The
ranges on the PES and FEA estimates reflect assumed throughputs of between
500,000 bpd and 1,000,000 bpd. The PLB estimate, based on 700,000 bpd
throughput and .5%S fuel content, assumed a total SOHIO fleet calling at the
Port of Long Beach for an average of 24 hours. The ARB estimates include
190 mile transit emissions between the Port of Long Beach and Point
Conception. The SOHIO estimates were those submitted in their application
to SCAQMD.
63
-------
TABLE 8
COMBUSTION POLLUTANTS - SCENARIOS
STUDY
PLB
PLB
BLM
BLM
BLM
PES
PES
PES
PES
PES
PES
FEA
FEA
FEA
ARE
ARB
ARB
SOH
SCENARIO NAME
Max. 3-165K (.5%S)
Average (.5%S)
Max. 3-120K (3%S)
Max. 3-120K (3%S)
Max. 3-120K (3%S)
Max. 3-16 5K (2%S)
Cen. Ca. Offshore (1.5%S)
Cen. Ca. In port (1.5%S)
Treasure Island (1.5%S)
So. Ca. Offshore (1.5XS)
S. Ca. Inport (1.5%S)
Most Probable 2-120K (1.52S)
Average-California Inportd.
Max. 3-16 5K (1.5%S)
Max. 1-1 20k, 2-1 65K
(includes 190 mi Transit)
Max. 2-62k, 1-71K
(includes 190 mi Transit)
Max. 1-1 20k, 2-1 65K
(includes 190 mi Transit)
Max. 2-1 6 5k, 2-1 65K (.5ZS)
S02(lbs)
342
1,130
824
2,472
11,370
1,428
4010-8230
4774-8992
8,360
4059-8021
4092-8064
612
5%S) 8,092
1,080
11,370
6,790
5,760
3,800
NO (Ibs)
289
880
-
-
-
462
1778-3647
2177-4097
3,816
1805-3557
1844-3630
264
4,097
465
8,780
3,910
8,780
2,400
1IME PERIOD
1 hour
24 hour average
1 hour
3 hour
24 hour
1 hour
24 hour average
24 hour average
24 hour average
24 hour average
24 hour average
1 hour probable
24 hour average
1 hour
24 hour
24 hour
24 hour
24 hour
2
2
2
2
2
3
PLB Throughput: 700,000 BPD
2PES Throughput: 500,000-1,000,000 BPD
3FEA Throughput: 500,000-1,000,000 BPD
Source: PLB (36), BLM (20), PES (47), FEA (16), ARB (76), SOH (77)
64
-------
TABLE 9
HYDROCARBON POLLUTANTS - SCENARIOS
STUDY
PLB
BLM
PES
PES
PES
PES
PES
PES
PES
PES
PES
PES
ARB
ARB
ARB
SOH
SCENARIO NAME
All Emissions Average
Max. 3-70K Ballasting
Max. 3-165K Purging
Cen. Ca. Offshore (No Purge)
Cen. Ca. Inport (No Purge)
Treasure Island (No Purge)
So. Ca. Offshore (No Purge)
So. Ca. Inport (No Purge)
Cen. Ca. Offshore (Purging)
Cen. Ca. Inshore (Purging)
So. Ca. Offshore (Purging)
So. Ca. Inshore (Purging)
Max. 1-1 20K, 2-1 65K
Purging/no Ballasting
Max. 2-62K, 1-71K Ballasting
Max. 1-1 20K, 2-1 65K No Purging/
No Ballasting
Max. No Tanker Emissions
HC(lbs)
3,240
6,239
25,000
1,961-4,065
2,739-4,800
1,961-4,215
2,057-4,125
2,083-4,172
20,104-31,895
6,844—20,190
18,108-29,402
18,134-29,449
184,000
11,100
0
480
TIME PERIOD
24-Hr. Average
Hourly
Hourly3
24-Hr. Average2'3
24-Hr. Average2'3
24-Hr. Average2'3
24-Hr. Average2'3
24-Hr. Average2'3
24-Hr. Average2'3
2 3
24-Hr. Average '
24-Hr. Average2'3
24-Hr. Average2'3
24 Hours
24 Hours
24 Hours
24 Hours
PLB Throughput 700,000 BPD
- 2PES Throughput 500,000-1,000,000 BPD
PES 12X HC Concentration Assumption
Sources: PLB (36), BLM (20), PES (47), ARB (76), SOH(77)
65
-------
The various PES and FEA scenarios displayed relative insensitivity
to the port locations considered except for the "central California in-port"
scenario. This was due primarily to the increased number of trips assumed
necessary to deliver crude at a 500,000 to 1,000,000 bpd rate.
Average NOX emissions were also forecast to be lower by PLB than
by, FEA and PES. Besides the above mentioned differences in assumed
calling and pumping times, the hourly NOx emissions factor used by FEA
and PES was approximately 70% higher than that of PLB. The ARE NOX
emissions included the in-transit emissions. The SOHIO estimates
reflect the low stack emission factor previously described.
The one-hour S02 maximum rates calculated by the different studies differ
mainly due to the sulfur content assumed in the fuel. The BLM scenario for the
Port of Long Beach assumed all SOHIO tankers would burn .5%S fuel and thus
utilized three 120K dwt non-SOHIO tankers burning 3%S fuel as the "worst case".
The maximum 1 hour "worst-case" NOX emissions ranged from 289 to 465 pound/hour.
This difference is entirely due to the difference in assumed stack emissions
factors used by PLB and PES/FEA.
The hydrocarbon emissions scenarios resulted in far higher emissions
ranges than those due to combustion. This is due to an uncertainty as
to what operations will, or will not occur in port. The PES scenarios
illustrated in the Table 9 reflect emissions occurring with the worst assumed
HC concentrations. The average value calculated by PLB and SOHIO for its
application assume minor levels of tanker emissions but included other sources
in their HC calculations. The ARB estimate assumes all three tankers would purge
within the 24 hours time period at port and in transit to Point Conception.
The major difference depicted in Table 9 is that related to the purging
assumption. The sensitivity of the overall HC emissions level to this assump-
tion is evident when the PES "with purging" and "without purging" scenarios
are examined.
Scenario Probabilities
Scenario probabilities were calculated in the BLM report to relate
"worst case" analyses to their chances of occurring during operations at the
Port of Long Beach. Table 10 presents the results of these calculations.
Case A reflects a "best fleet" configuration; Case B a "worst fleet" config-
uration; and Case C reflects a fleet expansion from handling 700,000 bpd to
1.2 million bpd. A "best fleet" would have larger vessels with segregated
ballast, inerting systems, and low sulfur fuel handling capability than a
"worst fleet". Ballasting for HC emissions and pumping for combustion
emissions were considered in generating "worst case" hourly emissions (purging
was considered to be not allowed in port and therefore had a zero probability
of occurrence).
66
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TABLE 10
ANNUAL PROBABILITIES OF OCCURRENCE FOR AIR QUALITY IMPACT SCENARIOS
FLEET
CASE
A
A
A
A
B
B
B
B
C
C
C
C
C
C
Source
Tanker Oper-
De script ion ation
SOHIO pa
165,000 DWT
SOHIO Bb
165,000 DWT
Non-SOHIO P
70,000 DWT
Non-SOHIO B
70,000 DWT
SOHIO P
165,000 DWT
SOHIO B
165,000 DWT
Non-SOHIO P
120,000 DWT
Non-SOHIO B
120,000 DWT
SOHIO P
165,000 DWT
SOHIO B
165,000 DWT
Non-SOHIO P
120,000 DWT
Non-SOHIO B
120,000 DWT
Non-SOHIO P
70,000 DWT
Non-SOHIO B
: BLM (20)
Pumping .
b Ballast ing.
Operation Simultaneous Events
Duration
(hrs)
15
2.2
15
2.2
15
2.2
15
2.2
15
2.2
15
2.2
15
2.2
1
.1531
.0225
.1225
.0180
.1400
.0205
.1100
.0161
.1594
.0234
.1250
.0183
.5088
.0746
2 3
.0234 .0036
5.04xlO~4 11.3xlo"6
.0150 .0018
3.23X10"4 5.80xlo"6
.0196 .0027
4.22X10"4 8.66X10"6
.0121 .0013
-4 -6
2.60x10 4.20x10
.0254 .0040
-4 -6
5.46x10 12.8x10
.0156 .0020
3.36xlO"4 6.16xlO"6
.2588 .1317
.0056 4.15X10"4
67
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The probabilities, while indicative of relative outcomes, overestimate
the chances of simultaneous events which involve 2 or 3 ships performing oper-
ations for at least one hour. This is the relevant probability when consi-
dering the effect on one hour air quality concentrations. In addition,
Table 10 does not reflect the joint probability with a characteristic set
of "worst-case" meteorological conditions. With these caveats, all the
3-ship pumping scenarios exceed the hourly once a year probability of
occurrence (l.lxlO~^). The "70K dwt worst case" ballasting scenario exceeds
the probability of once-a-year occurrence only in the expanded fleet case.
The overall conclusions based on these probabilities are that the pumping
scenarios for "worst case" conditions (e.g., those used for SO and No
emissions and air quality assessments) have a reasonable chance of occur-
ring at least once per year and that the HC ballasting "worst-case" scenarios
have a less than reasonable chance of occurring.
A study by ARE also evaluated various scenario probabilities (76).
Through a queueing model the number of times simultaneous operations would
occur for one, two, or three tankers regardless of type was calculated
in terms of hours per year. The results were similar to the BLM analysis
with the 3 ship (regardless of size) ballasting scenario having a less than
1 in 365x24 probability of occuring, and the 3 ships offloading scenarios
very likely exceeding that probability. Future work should be performed to
further evaluate emissions probabilities.
Air Quality Modeling Results
The relationship between emissions and resultant air quality is complex
and dependent upon many conditions such as emissions height, emissions temp-
erature and velocity, wind speed and direction, terrain topography, etc. In
order to relate emissions to predicted air quality levels in a geographic area,
various mathematical computer models have been developed. These models are
useful in indicating steady state air quality concentrations at points where
no actual measurements are available and thus can save the expense of costly
on-site monitoring. However, a process of calibration of the model through
comparisons with real data at selected geographic locations is desirable to
reflect actual conditions at a location. When actual data are not available,
as in predicting the effects of a new source, the results may suffer in
accuracy.
For pollutants that are relatively "non-reactive" atmospheric dispersion
models can be used. These models use wind data, actual air quality measure-
memts, and atmospheric stability curves derived from empirical experiments
to mathematically "disperse" emissions and give their contributions to
estimated air quality concentrations in the area of interest. Thus, one can
quantitatively estimate the incremental contribution to air quality concen-
tration of a project and, alternatively, the incremental decrease in concen-
tratons due to "tradeoffs".
For reactive pollutants, such as HC and NO, models have been developed
to describe the concentrations of resultant pollutants such as oxidants in
an area through the use of chemical equations and empirical meteorological
relationships. These models are used to compute total concentrations and
68
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are dependent on a good emissions inventory of the surrounding environment
and extensive calibration.
Unfortunately, there is considerable uncertainty associated with
the results of either type model. The complex photochemical relationships
involving reactive pollutants such as HC and NO are not fully understood
and various simplifying assumptions must be made. Further, reactive model
validation has usually been carried out over large areas for which principal
emissions come from well mixed auto exhausts and other area emissions
and elevated stacks. The characteristics of tanker emissions (ballasting,
purging, and venting) lie somewhere between the two categories and may
be different enough to justify separate model parameters. In addition,
factors such as atmospheric stability, changing terrain topography (e.g.,
water to land or flat to mountainous) and variations in wind direction and
speed over time add to result uncertainity, especially over longer averaging
periods. When combined with the preciously discussed emissions inventory
uncertainties, it becomes clear that the results obtained from these models
must be used cautiously. They do illustrate trends and the relative air
quality impact at different locations from project related emissions and
should be analyzed with this perspective.
Atmospheric pollution models are very sensitive to assumed meteorological
conditions. Two short-term conditions tend to cause high ground concentrations
to develop from plumes of elevated emissions sources (such as the tanker
stacks). With high wind speed a plume will tend to flatten horizontally,
disperse rapidly, and reach the ground quickly. With low wind speed, a plume
will tend to rise higher, spread slowly, disperse less rapidly, and reach the
ground slowly. Further, in a low level atmospheric temperature inversion when
pollutants become trapped by a "lid" and there are low wind speeds, a plume
tends to rise and become concentrated at the inversion level. Depending on
the time and nature of the inversion break-up and the stability of the air
under the inversion, the ground concentrations can become high or remain
low.
SO Results—
Table 11 summarizes the air quality results for SO^ from various studies
pertaining to the proposed Port of Long Beach/SOHIO project. Since the
emissions are totally dependent on the assumed tanker scenarios and the
assumed meteorological conditions are independent of the location (except
for expected frequency), these results could apply to any proposed port
location with similar terrain features. The presence of nearby hills or
sloping terrain, if close to the port area, could alter the point and
magnitude of maximum concentrations. All of the model results discussed in
Table 11 assumed flat terrain features.
Of particular interest is the lack of agreement with respect to
almost any of the parameters between the four reports. For the one-hour
scenarios, the results ranged from "worst-case" incremental effects of
6 pphm (SOHIO) to 73 pphm (PES - Urban stability class A). Even comparii
the four results for a common stability class, D, (using the PES-Urban
model) the results range from 6 pphm to 62 pphm. Of course, much of the
69
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Study Scenario
PLB 3-165K DWT Fiaping (.SZS)
PLB 1-165K DOT Puling (.5X5)
PLB 1-1201 mn Plotting (.szs)
PLB 1-SOr DDT Pinning (.SZS)
PLB 3-16SK DWT Puling (.SZS)
BLM 3-120K DWr Puling (3ZS)
BLM 3-120K DVt Puaplng (3ZS)
BLM 3-120K DOT Poping (3ZS)
PBS 3-165* DWT Pumping (2ZS)
SOB 2-16SK DWT Puaping (.SZS)
TABLE 11
SUMMARY OP SO, AIR QUALITY MODELING RESULTS FOR THE PORT OF LOHG BEACH
Effective
Ealaalona
Uba) Model
342
114
N/G
H/C
M/G
824
2472
11370
1080
M/G
H/G
3800
3800
Geuaeleo
Dispersion
(Pluae Rlee
Source Mot
Given)
Causalan
Dlaperalon
Brigge Pluae
Rlee
PTMTP
AMPAX
PTMPT
AMPAX
Wind Stack
(M/Sec) Height 01)
1 144
1 144
1 135
1 112
(ASSUMED CONDITIONS
9.5 N/G
9.5 H/C
9.5 H/G
2 94
1-5 H/G
Low H/G
1-5 H/G
Low H/G
Mixing Stability Averaging
Height (M) Claea Tin (Hra)
180
180
180
180
FROM DECEMBER
High
High
High
120
325-360
N/G
325-360
H/G
D 1
D 1
D 1
D 1
12. 1969)
D 1
D 3
D 24
Urban A 1
D
F
Rural A
D
F
D 1
C-D 1
D 24
C-D 24
Maxlatm Con-
centration (M)
2500
H/G
H/G
H/G
2000
1000
•
H/G
H/G
250
800
4400
450
3500
14000
H/G
1100
H/G
6800
Concentration
(FPHM)
10
5.08
4.84
5.58
.45
29
20
6
73
62
25
68
27
9
6
9
1
3
Source.: PLBO6). BLM(20). PBS(47, SOH(77).
-------
cause for this range is due to the assumed "worst-case" scenario. If the
scenarios are normalized to reflect .5%S fuel, the results "agree" relatively
well. They indicate a range of 5 pphm (BLM) to 15 pphm (PES) incremental
increase in S0x concentration when 3 large tankers simultaneously offload
crude in port.
The assumed meteorological conditions also differed greatly between
analyses which, as was previously discussed, affect the estimated pollutant
dispersion and the point where the ground is touched. BLM chose high
wind speed conditions causing a ground maximum concentration at 100 meters
downwind. PLB, SOHIO,and PES assumed low wind speeds and inversion conditions.
The PES Urban stability parameters account for increased dispersion in an
urban environment which brought the maximum concentrations closer to the
emission source. With the tankers emitting over water, stability classes
A-C are less likely to occur until land is reached (16). The SOHIO analysis
used actual worst day conditions recorded in Long Beach. The analysis
indicated that the incremental addition would not cause standards to be
exceeded (77).
All the reports used the same source for exit velocities and temp-
erature for input to the effective heights calculation. However, as can
be seen in Table 11, different formulae were used to calculate the effective
height.
In summary the results of the one-hour "worst-case" air quality
analysis indicate that while considerable disagreement exists as to a proper
scenario, the three relatively independent studies indicate that a baseline
"worst-case" of three 165K (or 120K) DWT tankers burning .5%S fuel off-
loading simultaneously will cause a maximum 5-15 pphm incremental increase
in SOX air quality concentrations at some point downwind. A directly pro-
portional incremental increase can be expected for tankers burning higher
sulfur fuel and a directly proportional incremental decrease can be expected
if fewer tankers are offloading during the one-hour period.
Since California* and Washington currently have one-hour air quality
SOo standard, the incremental value of the "worst-case" would have to be
added to the ambient (or "worst-case") air quality level at the location
of maximum concentration in order to evaluate violations of the standard
and the number of persons exposed. It should be noted that the SOHIO
proposal would involve a berthing facility approximately 2 miles (3200
meters) from a residential area and any offshore buoy system would be even
further'offshore. Maximum ground level concentrations therefore may likely
to occur over water or within a port facility.
For longer averaging times the wind and meteorological conditions can
no longer be considered constant and further dispersion can be expected, thus
lowering the magnitude of the maximum incremental contribution the tankers
*The California one-hour standard is under litigation and is not
currently in force.
71
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would contribute to the air quality level. The BLM report indicated
a 33% decrease in maximum concentration for 3 hour averaging (to 20 pphm)
and a 500% decrease (to 6 pphm) for 24 hour averaging. The PLB report
indicated a 2200% decrease for 24 hour averaging (to .45 pphm). The SOHIO
analysis indicated a 1-3 pphm incremental increase for 24-hour averaging.
Since the BLM report assumes 3%S sulfur content, the three reports together
indicate a maximum incremental increase of .5-3 pphm in S02 air quality
levels if 2-3 large tankers were offloading simultaneously over a 24 hour
period and were each using .5%S fuel.
None of the reports indicated the effect on yearly air quality
averages. It would appear that the entire project would meet the EPA
definition of a large point source and could have a noticeable effect on
annual SC>2 air quality averages in the local area. Also the relationship
between SO2 emissions and the formation of sulfates were not evaluated in
the reports.
NOX Results—
Modeling the relationship between NOX emissions and resultant air
quality is difficult since NO, the usual combustion emission, reacts over
time with other pollutants and oxygen to form NC>2 and other products. The
speed of reaction is also dependent on atmospheric conditions and the
relative ratios to other pollutants. Dispersion modeling was used by
PLBM, PES, and SOHIO in evaluating the SOHIO project NO,, concentrations
X
downwind for 1-hour averaging times. These results are directly proportional
to the S0xresults since physically the same plume would contain both pollutants.
Table 12 indicates that the "worst-case" situation would produce expected
incremental concentrations ranging from 4 pphm to 22 pphm (excluding the
A-C stability cases). There is relatively close agreement between the
three studies if the emissions are normalized to the same value, and stability
Class D is chosen in a "rural" setting.
There were no attempts to evaluate yearly incremental NOX concentrations
for analysis with respect to National N0« standards.
HC Results—
Table 13 summarizes the results from 3 studies of the SOHIO proposal
using reactive models to simulate HC emissions from both tanker emissions and
storage facilities. Because reactive models give results on an absolute basis
rather than an incremental basis, each study ran scenarios to represent a
baseline case (e.g., without a project), a storage facility only case, and a
tanker scenario only to reflect incremental changes. The studies were
performed for the proposed facility at the Port of Long Beach and might not
be representative of alternative sites with lower background emissions. As
in evident from Table 13, each study assumed different levels for the
"worst-case" and thus had different absolute concentration results.
72
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TABLE 12
SUMMARY OF NOX AIR QUALITY MODELING RESULTS FOR THE FORT OF LONG BEACH
U)
Study Scenario
PLB 3-165K OUT Pumping
FES 3-I6SK DWT Pumping
Emissions (Ibs)
289
462
SOH 2-165K DVT Pumping N/G
N/C
Model
Gaussian
Dispersion
Gaussian
Dispersion
PTMTP
AMPAX
Effective
Wind Stack
(M/Sec) Height (H)
1 144
2 94
1-5 N/G
Low N/G
Mixing Stability
Height (M) Class
180 D
120 Urban A
D
F
Rural A
D
F
325-360 D
N/G C-D
Distance of
Averaging Maximum Con-
Tlme (Hrs) centratlon(M)
1 2500
1 250
800
4400
450
3500
14000
1 N/G
1 1100
Maximum
Concentration
(PPHM)
8.4
33
22
15
31
12
4
5
8
Sources: PLB(36). PES(47), SOH(77).
-------
TABLE 13
SUMMARY OF OXIDANT AIR QUALITY MODELING RESULTS FOR THE PORT OF LONG BEACH
PLACE/TIME OF START/
MAXIMUM
STUDY
PLB
BLM
PES
DTP
SCENARIO
Total Emissions
Baseline
Storage Only
1-7 OK Ballasting
3-70K Ballasting
Baseline
Storage Only
1-120K, 1-70K Ballast
1-120K Purging
2-80K Ballast/Venting
3-165K Purging
12 Storage Tanks
PROJECT TTHF OF MAXIMUM
3240LBS/DAY DIFKIN July 25. 1973/Not Given Pomona /8AM/ 3PM
0 ARTSIM Sept 29, 1969/Not Given Fullerton/8AM/1230PM(Storage)
Huntington Beach/ 1200PM (Pier J)
74LBS/HR
2129LBS/HR
6234LBS/KR
0 REM July 11. 1975/Wind:2-5M/SEC, Pomona /8AM/ 2PM
117LB/HR Mlxipo: 17H-240M
500LB/HR
1500LB/HR
5000LB/HR
25000LB/HH
13LB/1
-------
The "storage-only" scenarios represent an implied tradeoff since
emissions were calculated for a new facility less the emissions for the
current storage facilities that would be removed. Each of the studies
indicated that an ozone increase of .1 to .2 pphm would result from the new
facilities. When consideration is made for model inaccuracies and the
possibility that the emissions from the new storage facilities may be
overestimated, the results indicated little, if any, air quality impact from
a new storage facility.
The tanker scenarios were very sensitive to assumed emissions.
The PLB report did not evaluate tanker emissions since it was assumed
only inerted tankers with segregated ballast would use the facility.
There were definite differences indicated between the results given by
the BLM reactive model and the PES reactive model. The worst-case BLM
scenario involved three 70K dwt tankers taking on ballast simultaneously
into empty crude oil storage tanks. The 6239 pound/hour HC emissions
resulted in a 7.5 pphm increase in ozone concentrations. The "worst-case"
PES scenario involved 3-165K tankers purging in port. The 25000 pound/
hour HC emissions resulted in an 8.0 pphm increase in ozone concentrations.
The large emissions difference between the two studies would not be expected
to produce similar ozone concentration increases. It is suspected that the
cause for this difference is related to model differences rather than
assumed meteorological conditions. The models used by PLB and BLM are
similar and their results were similar. (The PLB report had data to indicate
that a scenario involving emissions on the order of 6239 Ib/hr would create
an 8 pphm incremental increase in ozone concentrations.) Therefore either
the PES model results in estimates that are low or the PLB and BLM model
estimates are high.
It is obvious that the range of results is very dependent on
the HC emissions scenario that is the most realistic "worst-case"
situation. Purging in port, if allowed, would represent a "worst HC"
emissions scenario. However, the necessity to purge in port is not all
clear, except in an emergency, if inerting systems are used and if tank-
washing is performed at sea (16). The frequency with which an emergency
situation will require in-port purging was not discussed by any of the
reports. It appears likely that the "worst-case" HC emissions will involve
instances where non-segregated ballast tankers will simultaneously take on
ballast in port. The probability of this occurring was previously discussed
in the discussion of emissions scenarios probabilities.
One final analysis was performed that relates HC emissions from
a proposed storage tank farm at Port Angeles to incremental air quality
concentrations (24). The results indicated that, under severe meteor-
ological conditions and persistent wind speed, the HC 3 hour standard
would be violated approximately 1.3 kilometers downwind. While the lack of
HC measurements in the area and the reactivity of HC with other possible
pollutants weaken validation of these results, the emissions levels are
less than those predicted for the Long Beach facility. This could indicate
3-hour standards violations at Long Beach under similar conditions. None
of the other studies evaluated the 3-hour HC standard.
75
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Summary of Air Quality Analyses
It appears that the air quality impact due to the building of port
facilities to handle large quantities of Alaskan oil can be minimized by
placing constraints on the set of tankers that may use these facilities.
Constraints on allowable tanker operations that could be performed indiv-
idually and simultaneously while in port would further reduce emissions and
air quality impacts. A current issue involves the legal mechamisms for
implementing constraints and which agencies would be responsible for enforce-
ment. The "worst case" conditions that have been presented for air quality
analyses are associated with extremely low probabilities when consideration
is given to the joint probability of the emissions scenario and meteorolo-
gical conditions used in the analyses. Further work should be performed to
evaluate the "worst" cases with probabilities that match the hourly and
daily air quality standards (e.g. 1 in 365 days and 1 in 365x24 hours).
HC—
Tanker purging, ballasting, and venting and storage facilities are the
three principal potential contributors to HC emission in port. By 1979
there will be enough tankers in the Alaskan trade with segregated ballast
to eliminate this source of emissions (16). Even tankers with partially
segregated ballast can leave port without displacing cargo hold vapors
and can complete the ballasting operation at sea. It would seem feasible,
and is currently proposed, that all Alaskan trade tankers using a facility
be required to have sufficient segregated ballast to leave port without
emitting ballast related HC (16,36,77).
Purging a cargo tank has the potential of producing severe air quality
deterioration as demonstrated in the PES and ARB scenarios for 3-165R DWT
tankers. It has been stated that the need to purge is associated mainly
with tank cleaning and maintenance operation (16). Tank cleaning would
normally be performed at sea or at a port facility that can handle the oily
water. It would be advantageous to have a closed vapor recovery system at
such a facility. It has been stated by SOHIO that no purging would occur at
the Port of Long Beach by its inerted tankers (36).
A ban on this operation, as with ballasting, could become an adminis-
trative operating rule for any inerted tanker delivering Alaskan crude. One
problem that may occur with such a rule is the mechanism of enforcement.
Monitoring equipment and inspection would be required to regulate the
rule.
Venting HC to the atmosphere occurs in non-inerted ships following
unloading. From both a safety standpoint and an emission standpoint,
inerting systems appear to be desirable. Many of the Alaskan trade tankers
will be inerted. The cost and effort of converting non-inerted tankers
has not been discussed by various reference reports. Therefore, the
feasibility of requiring all Alaskan trade tankers calling at a port
facility to be inerted is unknown.
76
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The crude oil storage facility emissions had a moderate effect on
resultant ozone concentrations when air quality models were used for the
proposed Port of Long Beach facility (1 pphm increase without tradeoffs).
Given the results from the CBI scale model testing the evaluation of true
emission factors through further field study is desirable since a consid-
erable overestimation of emissions may be involved. Further work in
possible vapor recovery techniques with respect to these facilities is also
desirable. Tradeoffs have been suggested for the Port of Long Beach such
as removing older higher polluting storage facilities with equivalent
emissions to the proposed facility (36).
In summary, hydrocarbon emissions can be controlled to a large extent
through administrative controls of tanker types and operations to be
allowed in a port facility. Except for inerting tankers and designing
vapor recovery systems for the large storage facilities, it appears that
these measures can be accomplished with little impact on the proposed fleet
in terms of time and cost. The impact on air quality, if these measures are
taken, should be minimal.
sox~
The SOX air quality analyses for "worst-case" short term emissions
scenarios (e.g., 3 tankers simultaneously offloading for at least one
hour) indicated maximum ground level incremental increases in ambient
air quality concentrations that would be less than existing Washington
and California standards. The maximum ground level values were found
to occur relatively near tanker berths. The various models relative to the
SOHIO project or proposed offshore unloading facilities did not take into
account the effects of water/land meteorological conditions or topography
and differed in results due to assumed meteorological conditions and fuel
sulfur content. To minimize the probabilities of the "worst-case" occurring
operational restrictions on simultaneous offloading might be imposed if (1)
severe meteorological conditions are present and (2) high sulfur fuel is
being used by 2 or more tankers simultaneously.
From an emissions growth viewpoint, the impact could be minimized
by allowing only .5%S fuel to be utilized by Alaskan trade tankers in
port. Some of the proposed Alaskan fleet will have this capability
through the use of separate fuel tanks. Further measures to offset
emissions growth would require all tankers (including foreign flag tankers)
calling at a facility to burn low sulfur fuel. Since the presence of
separate fuel tanks for in-port use does not guarantee low sulfur fuel
will be used, monitoring and inspection equipment would be required to
insure compliance. There is also an implied reduction in sulfur emissions
due to low-sulfur fuel used by Alaskan trade tankers replacing foreign
tankers delivering equivalent foreign crude. This "tradeoff" will be
dependent on the market and traffic at the chosen alternative location.
NO —
x
The NO air quality results were very sensitive to the emission
factors used in the various studies. The PES "worst-case" analysis
77
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indicated that California 1-hour standards violations could occur due to
the project alone. The Port of Long Beach report, for the same emissions
scenario showed a maximum concentration that was 30Z of the standard.
The number of NOX violations in the PLB area and South Coast air basin,
in general, indicate that NO air quality may deteriorate in the local
area. Since NO is also a precursor for oxidant production, it would seem
that, from an air quality viewpoint, NO may be the most important pollutant
to examine by further field measurements.
The emissions scenarios used in the NO "worst-case" involve the
offloading of crude by 3 165K dwt tankers. Administrative controls
similar to those suggested for SOX could be imposed to prohibit this
situation or similar ones. This would reduce the probability of one-hour
N02 standards violation. However, this control could seriously delay
throughput since there is a relatively high probability that 3 berths
will simultaneously have tankers pumping. It may be necessary to control
simultaneous pumping operations only on meteorologically poor days.
Emissions tradeoffs involving NOX are difficult to identify. Inerting
will reduce NO emissions by approximately 15% but does not appear feasible
in smaller tankers. A SOHIO analysis indicates that the substitution of
Alaskan trade vessels for foreign crude carrying vessels at the Port of
Long Beach will result in SOX emissions reductions but also will result in
NO emissions growth over time (48). Since nationwide NO emissions are
forecast to become a major problem in the 1980-2000 period, the lack of
controls and/or tradeoff opportunities appear to be a serious problem. As a
long term solution, results of current EPA research in nitrogen removal from
fuel and improved combusion techniques may allow for reduction in these
emissions. Short-term tradeoffs have been proposed by SOHIO such as installing
NO emission reducing equipment on stationary internal combustion engine sources
in the LA area (77).
WATER QUALITY
Many sources of pollutants may impair water quality as a result of the
construction and operation of pipelines, marine terminals, and associated
tanker movements. Such sources include downstream sedimentation from
construction at stream crossings, oil spills from pipline breakage or leakage,
the discharge of water used for hydrostatic testing, the flushing of ballast
tanks, discharges of bilge water and sewage, and turbidity during dredging
of harbor sediments. Many of these sources can be easily abated or con-
trolled. The oil from the North Slope, however, will be carried by a fleet
of U.S. tankers from the Port of Valdez to potential distribution points
on the West and Gulf Coasts. This large amount of oil being moved by
a number of tankers has focused public attention on the likelihood of
the occurrence of massive spills which pose a threat to the coast ecosystem
and public safety. Such public attention has been heightened by a series
of tanker catastrophes near coastal U.S. waters during the months of
December, 1976 through January, 1977 (56, 57, 58). Many of these inci-
dents involve human error or faulty equipment. Should a large oil spill
78
-------
occur in the open ocean, especially under turbulent conditions, such common
containment and clean up equipment or agents as booms, absorbent materials,
surface collecting agents, and skimmers may not be highly effective, although
weathering and dispersal in the open ocean would attenuate coastline impacts.
Current emphasis is on oil spill prevention as a measure to minimize the
occurrence of oil spills.
Tanker Status
All of the tankers which will transport North Slope crude to U.S. ports
will be subject to the regulations of the Merchant Marine Act of June 5, 1920
(46 U.S.C.A. Section 883), commonly known as the Jones Act. The Act requires
that such coastal movement between domestic ports be carried out by U.S. built
and owned tankers operated under the U. S. flag by U. S. masters and crews.
U. S. tankers currently operating in foreign trade are capable of meeting
Jones Act requirements and may enter the domestic coastal trade if construc-
tion subsidies are repaid or if operational subsidies are suspended. Such
vessels are subject to regulations for tank vessels engaged in the carriage of
oil in domestic trade which were promulgated by the U.S. Coast Guard as one
step in the implementation of the Ports and Waterways Safety Act of 1972 (PL
92-340). These requirements for vessels larger than 70,000 dwt include distri-
buted segregated ballast, two slop tanks (for retention of tank washings,
oil residues, and dirty ballast residues) and an oily residue tank for the
containment of oil leakages and sludge (52). The Coast Guard currently
is extending these standards to U. S. vessels in foreign trade as well
as foreign vessels entering U. S. waters. These measures are intended
to substantially reduce the amount of oil released to the ocean by U.S.
seagoing tank vessels as well as foreign tankers in U. S. waters. Since
these requirements apply to Jones Act tankers and therefore to tankers
carrying North Slope crude to U. S. ports, the entire fleet of tankers
carrying North Slope oil is expected to possess fully segregated ballast
by 1980 (16). Also by 1980 approximately 50 percent are expected to have
collision avoidance radar systems and about 35 percent to have double bottoms
or hulls, segregated tanks for the carrying of low sulfur fuel, and inert gas
systems.
Oil Spill Analysis
Several extensive studies have been performed to evaluate the prob-
ability of oil spills and assess the potential environmental damage associ-
ated with the transportation of Alaskan crude. FEA (16) has presented
hitherto unpublished statistical results based on analysis of 1973-1975
data from the Coast Guard Polluting Incident Reporting System (PIRS).
The data base, while not restricted to Alaska information, gives a good
indication of historic risk patterning between alternative west coast
port facilities. Based on the data analyses, quantitative rankings of
spill risks of each alternative port are given. Summary information
is also given pertaining to the environmental setting at the port altern-
atives. A comparative qualitative ranking of site by various environmental
criteria is presented.
79
-------
The BLM Environmental Impact Statement for the proposed Port of
Long Beach/SOHIO pipeline project contains the results of spill risk
analyses as well as an extensive discussion of spill trajectories.
These studies used historic data to compute probabilities of spills and
their expected volume due to terminal interface operations and vessel
accidents. In addition, ERT (59) computed separately the probability
of total loss of cargo and its associated volume over the life of the
project and for each year. The following sections summarize the results
from each of these studies.
FEA Risk Analysis—
Since the data base used to derive relative risk rankings contains
the most up-to-date statistics on west coast oil spills, background
statistics were provided on the oil pollution problem in general and
the subset associated with tankers. Some of the findings were:
a. There is a high variability in spill volumes from year to year
with catastrophic spills distorting badly most gross volume
stastistics. Tankers, which produced only 20% of the known
spill incidents contributed 34% of the volume spilled. Marine
terminal spills, on the other hand contributed 9% of all known
spills but only 1% of the volume.
b. Approximately 42% of all known oil spill incidents involved
personnel errors with vessel collisions and groundings accounting
for 2%. From a volume standpoint, however, personnel errors
accounted for 5% and grounding and collisions 33% of the pollutants
(Equipment failure accounted for another 33% of volume and 25%
of the known incidents). When examined across alternative
regional port locations, a consistent 70% of the known incidents
were due to personnel error. Even when only tanker spills were
considered the personnel errors were responsible for 60% of the
known incidents;
c. Only 12% of vessel and terminal spill incidents occurred in
areas outside of the port activity;
d. Tanker collisions with vessels account for only 15% of tanker
casualties with groundings and collisions with fixed or submerged
affects accounting equally for the remainder;
e. Tanker spill incidents are highly correlated with tanker traffic
and crude volume transferred at terminals;
f. Tanker age does not appear to correlated with polluting incidents;
and
g. There does not appear to be a relationship between tanker size and
frequency of spill incidents.
80
-------
Based upon some of the above information and risk criteria, a relative
risk table was formed for candidate locations. An excerpt of that table
is presented in Table 14 for the current set of ports that will receive
Alaskan oil, or are prime candidates to become major Alaskan oil terminals.
The analysis indicates that Offshore Estero Bay and Avila Beach have the
lowest risk characteristics and the San Francisco port the highest risk
characteristics (Port Angeles and Kitimat were not ranked in the table).
If only the highest correlative criterion is used, that is per tanker
arrivals and throughput, then the rankings would appear as in Table 15.
Port Angeles was included in these rankings and is considered a "low"
relative risk location. Since many spills are associated with the
tanker terminal interface, the results indicate that in-port terminals
are, in general, higher risk locations. It should be noted that these
rankings are based on spill frequency results only and do not reflect
spill volumes. Since spill size does not appear to be related to geographic
location, it need not be weighted into the rankings.
The statistics used for the "off-shore" configurations have been
questioned by the Port of Long Beach (78). The facilities necessary for
large tankers to offload offshore would involve two or three single point
mooring (SPM) buoys anchored 3 to 5 miles offshore. At these moorings
the tankers must have space to be able to revolve a full 360° about the
mooring and have adequate maneuvering room to approach the buoy from any
direction with adequate bottom clearance. These requirements would tend to
place the buoys in relatively open ocean areas. The statistics develped for
the "offshore" configuration by FEA came from facility configurations that
are more protected from the open ocean and use fixed mooring for offloading.
The relative difference in risk rates between these two configurations (if
any) is not reflected in the statistics. Further analyses are now being
conducted relative to the problem.
Given the above results, projections were made of the expected number
of spills at the various alternative port sites as a function of projected
throughput volume and assumed fleet mixes. Using spill size distributions
derived from the data base, Table 16 was then produced. The affect of low
volume in-port oil spills and their relationship to the number of arrivals
becomes obvious in this Table when the San Francisco alternatives with and
without dredging are compared.
Finally, Table 17 was developed to reflect the capability of containment,
These results were based on relative rankings of criteria such as visibility,
high w'inds, calm seas, currents, high seas, etc. Given there is a spill,
using these criteria the relative protected ports of Los Angeles and
Long Beach have the highest probability of containment. The San Francisco
and Puget Sound harbor ports have both high spill risks and poor containment
probabilities. If spill risk and containment alone were the criteria for
choosing a port, the analysis would favor Offshore Estero Bay and Avila
Beach, with the Southern California ports and Port Angeles ranked next.
There is, in addition to the spill risk analysis, a substantial
amount of information on potential environmental impacts that may occur at
81
-------
TABLE 14
RELATIVE SPILL RISK
As Suggested By Some Indicators
(1 - Higest Risk, 10 - 10 times lower risk.)
CO
01
in
Ol
Anacortes
Ferndale
Long Beach Harbor
Los Angeles Harbor
Offshore Avila Beach
Offshore Estero Bay
Richmond (San Francisco)
Treasure Island (San
Francisco)
iH
•H JJ
O. 9
CO (X
M 00
Jl g
BMP
co o> j3
H B.H
5
3
4
3
7
7
3
3
r-i
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r-1
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01 >
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10
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iH
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to
01 01
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3
2
4
2
8
8
2
2
§
a w
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" 1
01 9
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3
10
4
7
10
10
2
2
9
oo
CO
0
M CO
a M u
CO 01 M
H a<
2
10
3
7
10
10
2
2
§
co
CO
o
Li
CO 01 M
H CXCJ
2
10
4
7
10
10
2
2
•H
a
CO 4J
9
C 00
EMM
01 (!) .C
H O.H
2
5
4
3
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a
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iH
SiH
CO
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S -rl
C M M
01 0' M
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1
7
4
3
10
10
4
1
Source: FEA (16)
82
-------
Table 15
UNWEIGHTED OIL SPILL RISK RANKINGS
(In alphabetical order by group)
Feasible terminals with the lowest relative frequency of tanker spills and
casualties per tanker arrivals and oil throughput volumes: (9.0-10.0)
- Offshore Avila Beach
- Offshore Estero Bay
- Port Angeles
Feasible terminals with relatively moderate tanker spill and casualty
frequencies per tanker arrivals and oil throughput volumes: (3.5-6.5)
- Ferndale (Puget Sound)
- Long Beach Harbor
- Los Angeles Harbor
Feasible terminals with a greater relative frequency of tanker spills and
casualities per tanker arrivals and oil throughput volumes: (2.0-3.5)
- Anacortes (Puget Sound)
- Richmond (San Francisco)
- Treasure Island (San Francisco)
The following terminal sites received no tanker arrivals or oil deliveries
during 1973-1975 or insufficient data exists to allow for their evaluation:
- Kitimat
Source: FEA (16)
83
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TABLE 16
ANNUAL TANKER AND TERMINAL SPILLS BY REGION
AND SPILL SIZE (gallons), 500,000 bpd
ADJUSTED FOR REGIONAL SPILL RATE DIFFERENCES
0-100 100-1000 1000-10,000 10,000-100,000 100,000
British Columbia 5.85 0.60 0.25 0.15 0.05
Fjord Sites (Kitamat)
Northwest Ports 6.90 0.75 0.30 0.15 0.05
(North Puget Sound)
Northwest Ports 9.70 1.00 0.45 0.20 0.05
Small Tanker Scenario
San Francisco Bay 14.60 1.55 0.70 0.35 0.10
Without Major Dredging
San Francisco Bay, 8.90 0.95 0.40 0.20 0.05
With Major Dredging
To Treasure Island
Central California 2.20 0.25 0.10 0.05 0.01
Offshore
Southern California 6.30 0.65 0.30 0.15 0.05
In-Port
Source: FEA (16)
84
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TABLE 17
UNWEIGHTED SPILL CONTAINMENT RANKINGS
(In Alphabetical Order, by Group)
Feasible terminals with the greatest frequency of conditions allowing effective
spill containment in the vicinity of their berths or buoys:
- Long Beach Harbor
- Los Angeles Harbor
Feasible terminals with relatively moderate frequencies of conditions
allowing effective spill containment in the vicinity of their berths or
buoys:
- Offshore Avila Beach
- Offshore Estero Bay
Feasible terminals with relatively low frequencies of conditions allowing
effective spill containment in the vincinity of their berths or buoys:
- Anacortes (Puget Sound)
- Ferndale (Puget Sound)
- Kitimat
- Port Angeles
- Richmond (San Francisco)
- Treasure Island (San Francisco)
Source: FEA (16)
85
-------
alternative port sites due to oil spills. The analysis defines two zones
of impact. The first is a construction and operations zone which encompasses
the area surrounding the terminal that would be potentially impacted.
Second, since most spills occur within, or at the entrance to harbors, a
loci of spill points were defined that followed tanker routes within one
mile of an in-port terminal, one mile around each offshore mooring buoy,
and along all pipelines from the offshore buoys and in-port berthing
facilities. Using ocean current data, wind patterns, and in the case of
Puget Sound and San Francisco tidal currents, oil spill impact zones were
created that estimated the area covered after a three day period. Figures
14 through 17 are illustrative of the resulting area covered. These
results, when taken with the spill risk and containment analyses, again
show offshore Estero Bay and offshore Avila Beach as being the "safest"
alternative. The Port Angeles area, although relatively open to the
Juan de Fuca Strait, has a relatively small oil impact zone. All the other
locations have the potential of exposing large areas to spilled oil.It
should be noted that in protected harbors such as the Port of Long Beach,
the spill area exposed would be very much smaller if the spill occurred
within the port area.
One final analysis was performed to assess the relative environmental
importance of various criteria at each alternative location. The results
of this analysis are shown in Table 18. The Estero Bay alternative
would involve placing highly sensitive Morro Bay estuary in risk. The
Avila Beach alternative although near Estero Bay, would tend to lessen the
risk to the estuary. State Water Resources Board and the California
Department of Fish and Game have indicated that the Avila Beach alternative
may be more sensitive to an oil spill than indicated by Table 18 (79).
Locations further south in San Luis Obispo Bay such as Guadalupe Dunes
have been recently discussed as being a less sensitive location.
When these results are compared with the risk analysis, containment analysis,
and impact zone analysis, the following general conclusions can be drawn:
1. Given that the risk assessment is correct, Offshore Estero Bay is
attractive from all but an environmental/ecological importance
viewpoint.
2. Port Angeles, except for poor relative containment probabilities
is attractive as a site. However, the relatively low spill risk
ranking for this alternative may be due to chance since relatively
small amount of traffic is handled there.
3. The Southern California ports (Long Beach and Los Angeles)
rank next with the big positive being excellent containment
probabilities. One aspect of the risk analysis not discussed by
FEA or BLM with respect to accident risks at these ports involves
the possibility of increased navigational hazards due to the
presence of exploratory and production offshore oil well rigs in
Santa Barbara Channel. The affect of traffic to and from the
rigs as well as the platforms themselves has not been discussed
with relationship to the relatively large tankers that will be
using the sea route in the Channel.
86
-------
BRITISH
COLUMBIA
Source: FEA (16)
FIGURE 14
OIL SPILL ZONE-KITIMAT
87
-------
Vancouver Island
Source: FEA (16)
Seattle
Tacoma
FIGURE 15
OIL SPILL ZONES-NORTHWEST
88
-------
San Francisco Bay
Sacramento River
Monterey Bay
NORTH '
. 24 MI.
•I Spill Zone
Source: FEA (16)
FIGURE 16
OIL SPILL ZONES-SAN FRANCISCO
89
-------
•Estero Bay
Santa
Barbara
Channel
Los Angeles
Long Beach
Source: FEA
^...4^^^|f,,^ '//,, ,
:^^W? J ^^^
FIGURE 17
OIL SPILL ZONES-OFFSHORE
1 CALIFORNIA AND LOS ANGELES/LONG BEACH ;
V.%%%%V.V.V.%V.V.^^^^
90
-------
vO
TABLE 18
ENVIRONMENTAL AND
ECOLOGICAL RELATIVE RANKINGS
Potential Effects On:
Kitiinat
Ferndale (Cherry Point)
Anacortes (March Point)
Port Angeles
Treasure Island (San Francisco)
Richmond (San Francisco)
Offshore in Estero Bay
Offshore Avila Beach
Los Angeles Harbor
Long Beach Harbor
Range of "Lowest" Group:
Range of "Relatively Low" Group:
Range of "Moderate" Group:
Range of "Greater Relative" Group:
TS 0)
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2.5
3.7
2.5
2.5
2.5
3.7
2.5
5.0
5.0
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5
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1.2
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1.2 1.2 2.5
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grass Beds
oductive
CO CO rH M
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3.7
UNWEIGHTED ECOLOGICAL RANKINGS
Range of
Range of
Range of
Range of
"Lowest" Group:
"Relatively Low"
"Moderate" Group:
"Greater Relative
Group:
1.7-2
2.5-3
3.4-3
" Group: 3.8-4
.0
.2
.6
.4
Source: FEA (16)
-------
4. Offshore Avila Beach, or more likely a point at the southern end
of San Luis Obispo Bay,except for the moderate spill containment
probability, ranks as the most desirable location using the
above analysis criteria. The feasibility of this location with
respect to the ultimate distribtution of the crude and the
economics of development of the location as a major port for
Alaskan crude are not included in this conclusion. An additional
factor that is not included in this assessment is the relative
secondary impact the development of a major marine terminal might
have on the various areas. It would appear that the long term
secondary environmental and socioeconomic impacts on the already
developed port areas in Puget Sound and Long Beach would be far
less than in the more undeveloped locations.
These values are subjective, but, when viewed across criteria for a par-
ticular location, give a definitive view of the type of oil pollution issues
a proposed location would encounter.
BLM Risk Analysis—
The BLM discussion of oil spill probabilities references work per-
formed for the Port of Long Beach (36) and an ERT study (59). The two studies
used different techniques for assessing spill risks but ended up with similar
estimates of probable losses. The approach to the analysis used was one
of first assessing probable accident rates and then relating these to spill
probabilities and size.
Accident rates compiled from various sources reveal that the Port of
Long Beach has a relatively low tanker accident rate (1.9-2.4 per 1000
trips). This is at least partially attributed to the vessel traffic system
(VTS) in place there (a similar system is under construction in Prince William
Sound and Valdez). Tables 19 and 20 indicate the expected accident frequency
by type and location for the assumed tanker fleet. The relatively high
accident rate in San Francisco is attributable to higher traffic rates of
small tankers due to harbor depth limitations.
Tables 21 and 22 were then used to generate spill probabilities and
volumes. The ERT report examined the affects of a catastropic loss and
found a .56 probability of a loss during the 25 year project life. Included
in their analysis were factors for tanker age, inerting systems, a VTS,
ballast tank placement, and double hull construction where applicable.
Tables 23 and 24 were then computed to indicate the impact a catastropic
loss would have on average spill volumes.
The volume of spills on San Pedro Bay with less than a major loss,
as indicated in Table 24 (130 barrels), can be compared with the FEA results
in Table 16. Assuming the one-third value for each interval and excluding
the 100,000 or greater interval, the results of multiplying Long Beach spill
rates yield a total of 153 barrels/year. The ten year estimate by PLB was
1726 barrels or 172.6 barrels/year. Given the relative independence of
technique and data sources between the three analyses, the results are remark-
ably similar and lend credence to each analysis.
92
-------
TABLE 19
PROJECTED SOHIO TANKER ACCIDENTS
IN A 10-YEAR PERIOD (LOCATION)
ACCIDENT
CAUSE
Prince William
Sound (Valdez)
a
MMbbl/d
0.7
At Sea
MMbbl/d
0.7
Santa Barbara
Channel
MMbbl/d
0.7
San Pedro Bay
(Long Beach)
MMbbl/d
0.7
Collisions, 9.4
rammings,
groundings
Structural 0.1
failures
Fires, 1.1
explosions,
breakdowns
Total
10.6
0.3
3.3
2.4
6.0
2.5
0.1
0.6
3.2
3.1
0.0
0.4
3.5
Source: BLM (20)
Million barrels per day throughput.
93
-------
TABLE 20
PROJECTED SOHIO TANKER ACCIDENTS OVER 10 YEARS
VALDEZ TO PUGET SOUND AND SAN FRANCISCO*
ACCIDENT
TYPE
Collision,
ramming, grounding
Structural failure
Fire, explosion,
breakdown
Total
Valdez
18.9
0.1
1.1
20.1
Coastal
At Sea Waters
0.4 3.82
4.9 0.1
3.7 0.9
9.0 4.82
Puget
Sound
1.5
0.0
0.1
1.6
San Francisco
Bay
16.8
0.1
1.0
17.9
Source: BLM (20)
3Assuming 100,000 bbl/d to Puget Sound, 325,000 bbl/d to San Francisco.
94
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TABLE 21
ACCIDENT LOCATION AND OIL SPILLAGE
ACCIDENT
LOCATION
At sea
Coastal
Entrance
Harbor
Pier
Percent of Accidents
Involving Spills
19.5
22.6
22.2
16.9
16.2
Percent of Total
Oil Spillage
55.7
14.1
19.3
5.3
4.5
Source: BLM (20)
95
-------
TABLE 22
SOURCES OF OIL POLLUTION FROM TANKERS
CAUSE
Tank cleaning
b
Discharges
Terminal operations
Casualties
Total
Annual Outflow3
967,000
100,000
70,000
250,000
1,387,000
Percent
69.7
7.2
5.0
18.0
100.0
Source: BLM (20)
Metric tons.
Includes bilge pumping, leaks and bunkering spills,
96
-------
TABLE 23
PROBABILITY PER YEAR OF SPILLS WITH LESS THAN TOTAL
VESSEL LOSS WITH AVERAGE SPILL VOLUMES IN BARRELS
SPILL
LOCATION Probability Volume
Prince William Sound (Valdez) 0.11 389
Prince William Sound to San Francisco 0.13 439
San Francisco to San Pedro Bay 0.077 302
San Pedro Bay (Long Beach) 0.037 130
Total 0.35 1,260
Source: ERT (59)
97
-------
TABLE 24
PROBABILITY PER YEAR OF SPILLS WITH TOTAL VESSEL LOSS
AVERAGE SPILL VOLUME IN BARRELS
SPILL
LOCATION
Prince William Sound (Valdez)
Prince William Sound to San Francisco
San Francisco to San Pedro Bay
San Pedro Bay (Long Beach)
Total
Probability
0.12
0.14
0.086
0.040
0.39
Volume
6,730
7,333
3,883
2,243
20,189
Source: ERT (59)
98
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Pipeline Spills
Information on the projected number and size of pipeline oil spills
was provided in the BLM report. An average loss of 1.33 barrels per mile
of line per year occurred during 1974 for the transportation of 9 billion
barrels of products. Based on throughput and length the SOHIO pipeline
would expect a loss of 1400-1600 barrels/year. Based upon these values
and an assumed distribution of spill types, Table 25 was compiled to in-
dicate the expected volume of oil that will be spilled.
Certain locations (such as river crossings) will be especially sensitive
to a major rupture in the pipeline. Based upon computations of the total
volume between the closest valve on either side of the location and with
allowance for automatic cutoff delay tmes, the maximum oil spill volume was
calculated and is given in Table 26.
99
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TABLE 25
APPROXIMATE PREDICTED PIPELINE STATISTICS (OVER-10-YEAR PERIOD)
EVENT
Number
of Spills
Size Total Volume of Oil Spilled
of Spill
(bbl) Percent bbl
Leaks below
detection system
threshold
Leaks above
detection system
threshold
Ruptures
400 (max) Indefinite
1 (max)
3,000 plus
25
4 to 20 500 to 3,000 50
25
9,000 (max)
7,000 to
20,000
9,000 (max)
Source: BLM (20)
100
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TABLE 26
POTENTIAL MAXIMUM OIL SPILLS AT SENSITIVE LOCATIONS
LOCATION~Volume (bbl)
Santa Ana River 9,930
Whitewater River 13,428
Colorado River 5,417
Gila River 139
San Pedro River 4,260
Rio Grande 1,805
Pecos River 8,103
San Andreas Fault system 9,261
Source:BLM (20)
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SECTION 4
PRESSING PROBLEMS
NATIONAL CONCERN
An urgent national concern affecting Alaskan oil was expressed in the
Trans-Alaska Pipeline Act of 1973. The Act stated that
"the early development and delivery of oil and gas from Alaska's North Slope
to domestic markets is in the national interest because of growing domestic
shortages and increasing dependence upon insecure foreign sources".
Today, the need to find solutions to the various problems of importing Alaskan
oil still exists. Although it demonstrated that the U.S. is vulnerable
to severe supply disruptions and oil price increases, the 1973/1974 oil
embargo did little to curb U.S. dependence on foreign oil. Imports accounted
for 23 percent of U.S. total oil consumption in 1970. Declining domestic
production and rising demand has led to a rapid growth in imports which
now amount to more than 40 percent of U.S. crude oil supplies (7). Thus, the
need for a decrease in dependence upon foreign sources, a more favorable
balance of payments situation, and a need for a secure supply of crude oil has
caused considerable concern and determination by Federal and State officials
as well as the private sector to seek new sources of crude oil and to develop
efficient transportation systems for the huge untapped reserves of the
North Slope.
The search for a system to carry the North Slope crude to market has •
been in effect since an Alaskan pipeline was first proposed in 1969 (6).
By 1972 the following alternatives were being evaluated (60):
1. New pipelines from the U.S. West Coast to markets east of the
Rockies.
2. Selling Alaskan oil to Japan in return for increased imports
on the East Coast of the United States.
3. A new pipeline in Central America for transporting Alaskan
oil to East Coast markets.
4. Transporting the oil through the Panama Canal to Gulf Coast
ports.
5. Shipping oil around Cape Horn to East Coast markets.
Today these and other routes such as those of the Trans-Mountain and Trans-
Provincial pipelines, which generally follow the original route of the Trans-
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Canadian Pipeline (an overland alternative to the Trans-Alaska Pipeline), are
envisioned to serve not only eastern U.S. markets, but also to provide a
source of crude to the Northern Tier States.
Such solutions, in the form of proposed transportation routes, must relate
to one or both of these problems:
• To dissipate the expected West Coast crude excess - hopefully
by movement to demand areas east of the Rocky Mountains.
• To supply the Northern Tier States which confront a decline in oil
exports from Canada.
In the face of these problems, the Federal Government must respond in a
manner consistent with the Trans-Alaska Pipeline Act to assure equitable
allocation of North Slope crude oil (12):
Section 410. The Congress declares that the crude
oil on the North Slope of Alaska is an important
part of the Nation's oil resources, and that the
benefits of such crude oil should be equitably
shared, directly or indirectly, by all regions
of the country. The President shall use any auth-
ority he may have to insure an equitable allocation
of available North Slope and other crude oil resources
and petroleum products among all regions and all of
the several States.
•
A question, often voiced at public meetings held for the purpose of
discussing North Slope crude transportation alternatives is "Who decides?"
(61). It is likely that decisions will be made by all levels of government
and by agencies representing a wide variety of interests. Many decisions
will be made in response to applications by a proposal sponsor for a permit
to conduct a specific activity relevant to the proposal venture. Usually
these applications are accompanied by detailed engineering plans which,
together with the application, are available for public scrutiny during a
period set aside for public comment or at public hearings. Examples of such
permits are the following:
AGENCY PROPOSED ACTIVITY PERMIT
Corps of Engineers Dreding of a port; Permit for work
Construction of in navigable
breakwater; Pipeline waters.
across large river.
Environmental Installation of new Permit to
Protection stationary source of construct.
Agency air pollutants.
Department of the Construction of Granting of
Interior pipeline across Federal rights-of-way.
lands.
U.S. Coast Guard Operation of marine Approval of
facility. operation.
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Generally, large scale cross country pipeline projects, especially
if they cross a number of Federal lands requiring the granting of rights-
of-way by the Department of the Interior, constitute "a major Federal
action significantly affecting the quality of human environment" and come
under the provisions of the National Environmental Policy Act of 1969
(PL91-190). Such an action requires the preparation of a Federal Environ-
mental Impact Statement (EIS). The purpose of the EIS report is to
document all environmental effects of the proposed actions and their
alternatives for public understanding and to list measures to avoid or
minimize effects of proposed actions and to restore or enhance environmental
quality as much as possible. As early in the decision making process as
possible, and in all cases prior to agency'dec is ion, a draft statement is
prepared for review by appropriate Federal, State and local environ-
mental agencies as well as the public. After comment, the statement is
prepared in final form, incorporating all comments and objections received
on the draft and indicating how significant issues raised during the
commenting process (includes public hearings) have been resolved. Both
the draft and final statement are filed with the Council on Environmental
Quality and made available to the public (62). This EIS statement process
is used successfully by Federal agencies to improve decisions affecting
the environment and provides a useful tool to incorporate public opinion,
as well as that of diverse agencies, into the decision making process
(63). Currently this process is being applied to the movement of North
Slope crude. A draft environmental impact statement has been prepared by
the Bureau of Land Management (Department of the Interior) for the SOHIO
proposal. A draft environmental impact statement may be prepared by the
Department of the Interior for the Northern Tier Pipeline proposal.
The responses by appropriate governmental units with respect to
North Slope crude will require a concerted effort to establish and main-
tain a high level of communication and coordination. Varying parts of the
U.S. will have varying needs for energy and environmental protection.
Approved transportation systems will need to be flexible to provide for
changes in future energy patterns. In the development and finalization of
these projects the environmental impact statement process will aid in
alerting agency decision makers, the public, and ultimately Congress and
the President to the environmental risks involved and allow for a responsive
approach toward the establishment of environmental compatibility.
FUTURE CRUDE SUPPLIES - NEW PROBLEMS
•
In the future, changes in the sources of crude supplies on the
West Coast are inevitable. Foreign high sulfur crude will be replaced by
heavy, high sulfur crude from the North Slope (Figure 18). Should an
optimistic rate of North Alaskan crude production be realized, as proposed
by the Federal Energy Administration (Figure 19), the West Coast may be
subjected to a substantially greater excess of crude supply over demand.
Increased production, above current expectation, for the Bering Sea, the
Aleutian Island chain, the Gulf of Alaska, and the West Coast outer
continental shelf could further aggravate a surplus situation. Estimates
of undiscovered recoverable Alaskan oil range from 12 billion to over 76
billion barrels (15).
105
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4.0
3.0
0
Q.
CD
2.0
1.0
supply
demand
demand
1974
1978
supply
1982
EXISTING PADD V SOURCES
NEW SOURCES (NON-NORTHERN ALASKA)
PRODUCT IMPORTS
FOREIGN CRUDE LOW SULPHUR
FOREIGN CRUDE HIGH SULPHUR
NORTHERN ALASKA CRUDE
FIGURE 18: PADD V SUPPLY/DEMAND BALANCE FORECAST
SOURCE: Bureau of Land Management (20)
106
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5.0 r-
4.0
3.0
2.0
1.0
0.0
•mmb/d
NPR-4
Optimistic
Taps
Capacity
1075
80
85
90
95
2000
FIGURE 19: Outlooks for North Alaska crude production in 1975-2000
SOURCE: Federal Energy Administration (7)
-------
The problem which emerges is how to handle the surplus. As many as
7,500 miles of pipeline solely within Alaska may be required (15). Thus,
future Alaskan production may necessitate a new overland pipeline passing
through Canada and which connects Alaskan crude reserves with eastern U.S.
markets. Such a need was expressed in the Trans-Alaska Pipeline Act (12):
A supplemental pipeline to connect the North Slope
with a trans-Canada pipeline may be needed later and
it should be studied now,...
Provisions were made within the Act for such a study to be conducted as
well as for interactions with Canada on the terms and conditions under which
pipelines (or other transportation systems) could be constructed across
Canadian territory.
Thus, the potential for a large Alaskan and West Coast crude production
to be realized within the next decade may require the development of a
highly flexible and integrated crude oil distribution system. Such a system
could serve all parts of the U.S. and could shunt oil from one port to another
contingent upon supply or demand. The network also could serve to transport
crude as needed during a national emergency and to circumvent faulty or
destroyed trunk lines by circuitous routing in order to serve areas with low
crude supplies.
An influx of unexpected crude production could induce a greater use of
energy to the point where demand is equal to total crude supply. The judicious
development of new crude reserves should be coupled with an effective fuel
conservation policy. In this way, any newly found surplus of domestic crude
could be substituted for foreign crude imports.
It may be in the national interest to develop a crude oil transpor-
tation system which will link various parts of the country. This system
could provide long-term assistance in meeting future supply and demand needs.
Current major transportation proposals such as the SOHIO Valdez to Midland,
Texas project and the Northern Tier Valdez to Clearbrook, Minnesota should be
able to fit into an overall transportation scheme. To promote flexibility, such
a scheme also should include the ability of U.S. refineries to enter into
large volume and long term exchange agreements with Canadian refineries. Such
an intergovernmental linkage should be economically advantageous owing to lower
transportation costs as compared to other options.
INFORMATION NEEDS
The following are a number of research or data compilation requirements
identified during the course of this review. These studies are not necessarily
recommended to be conducted by EPA, but indicate areas which warrant additional
information, independent of agency sponsorhip.
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Broad Issues
Perspectives Study—
Sometime early in 1978, more than a million barrels of oil each day
will flow southward through the Trans-Alaska pipeline from Alaska's North
Slope and will be loaded into tankers' holds at the Port of Valdez. The
oil's route after that is still uncertain (64). A study should be performed
to explore how various transportation alternatives, if decided upon favorably,
could preclude future flexibility to handle optimistic projections of future
crude flows. The study should establish various scenarios concerning crude
supplies through the year 2000 and project possible transportation solutions
including an integrated crude distribution network. This study should
address ramifications for various major crude oil transportation systems
which compete for pipeline capacity such as the SOHIO crude vying with
SEADOCK for space in the Williams and similar pipelines (Figure 10). The
study should also explore the establishment and nature of a permanent inter-
agency task force or commission to coordinate and oversee the development of
petroleum transportation systems. The systems would include crude and
product trunk lines and could be extended to encompass new, large scale gas
transmission lines.
Implications of Alaska Gas Transportation Scheme for Crude Oil Transportation
Alternatives—
The future of natural gas supplies to California is uncertain. Supply
from both traditional sources and potential new sources cannot be reliably
predicted. In the case of traditional sources, such as those east of the
Rockies and Canada, an uncertainty exists as to the amount of gas which
will be available. As for new sources such as liquified natural gas, syn-
thetic natural gas, reserve additions, Alaskan gas, the timing of such
projects is uncertain (36).
Three proposals are now before the Federal Power Commission for recom-
mendation to the President. Congressional decision after review of the
recommendation of the President could occur as early as November 1, 1977.
The proposals in question are those of the Alaskan Arctic Gas Pipeline
Company which favors bringing North Slope gas to the lower 48 states by a
pipeline across Canada; the El Paso Alaska Company which proposes a pipeline
parallel to the Trans-Alaska oil pipeline to a terminal near Valdez where the
gas will be liquified (at a temperature of about minus 260 degrees Fahrenheit)
and placed aboard special tankers for transport to California; and the
Northwest Energy Company which proposes a pipeline from the North Slope along
the Alcan Highway to points in northern British Columbia and Alberta where it
may be connected to existing pipelines linked to the U.S. Any decision
relevant to the amount of natural gas available to California, such as a
decision to route gas from the Arctic Gas or Northwest systems exclusively to
the Midwest and East, a position recently favored by the staff of the Federal
Power Commission (65), or by converting the existing El Paso Texas-to-California
gas pipeline to oil, could significantly affect economic and environmental
conditions within the State (61). A reduction in natural gas supplies could
lead to higher rates, limited use by residential consumers, interruption in
109
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gas service for commercial and industrial users (with possible job losses),
and a curtailment of gas supplies to electric utilities. Consequently, the
power plants would be forced to burn more fuel oil or to build new coal fired
power plants in the California desert or in Utah, Arizona or Nebraska.
Both alternatives could contribute to degradation of air quality. In addition,
if substantial supplies of natural gas are diverted away from California, the
state is likely to turn to the increased development of crude oil delivery
and storage facilities, including deepwater ports with requisite dredging
and other marine disruptions and possible air quality degradation. Such
actions as these may have severe air quality implications for California as
emissions of nitrogen oxides (precursors in the formation of smog) are
increased 50 percent when fuel oil is burned instead of natural gas (66). In
contrast, should the El Paso proposal be approved, California may not need to
be so dependent upon crude oil for a residential or commercial energy source.
In the President's message upon signing the Alaska National Gas
Transporation Act of 1976, he stated (67):
This represents reducing U.S. oil import needs by about
one-half million barrels per day. This will be a signifi-
cant step towards energy independence. If the next Congress
acts on my proposal for deregulation of new natural gas
prices, long-term relief from natural gas shortages can be
achieved.
Clearly, there are many areas where decision upon gas distributions systems
interact with decisions based on oil distribution systems. A perspectives
paper should be prepared which characterizes the interactions and subsequent
implications of decisions based upon oil and gas alternatives. The report
should suggest how communication and coordination may be established among
the appropriate agencies. The report should also address the capability
for fuel switching among various classes of interruptible customers and
evaluate the adequacy of supply availability of alternative fuels, particu-
larly in California, assuming normal, above average, and below average
temperatures during a given heating season (68).
Special Issues
Puget Sound - A Special Case—
More than 500 ships travel through Puget Sound each day. Increasing
numbers of these are tankers carrying crude to local refineries, often under
foggy conditions (69). New proposals exist for an expansion of a deepwater
marine terminal at Cherry Point within the Sound. The Northern Tier Pipeline
Company proposes a marine terminal at Port Angeles on the Strait of Juan de
Fuca. A unit train concept also involves a terminal in the Sound. Several
variations of alternatives involve the building of an overland pipeline to
connect Port Angeles with refineries north of Seattle. In 1978, FEA projects
that almost 18 percent of the North Slope crude will be imported via the
Sound (16).
Several alternatives which have been considered for importing oil into
the State of Washington involved the construction of terminals and transfer
110
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systems on the Olympia Peninsula. These alternatives would provide for the
transport of oil to existing refineries in northern Puget Sound (Ferndale and
Anacortes areas). A report by the Oceanographic Commission of Washington
(80) has indicated that a submarine pipeline crossing, particularly in the
area of Admiralty Inlet, is technically feasible. Such a concept, except for
relatively low volume service to refineries located in Tacoma, could alleviate
the need for substantial tanker traffic to enter Puget Sound.
Studies of the economic and environmental aspects (81,82) of alter-
native marine terminal locations within the State of Washington have been
conducted. These studies deal to some extent with the construction of
pipelines to serve northern Puget Sound refiners, but lack in-depth analyses
of comparative oil spill risks or other environmental impacts associated with
a number of proposed sites for marine crossings.
The concept of utilizing submarine pipeline crossings to serve northern
Puget Sound refineries should be explored in greater detail. Such a study
should include the probability of oil spill risks in terms of frequency,
oil spill trajectory, and environmental impacts. The study could compare
environmental impacts of the present and projected transhipment of oil
through the Sound with various land-submarine pipeline proposals, including
an all submarine route.
New Approaches—
Two new approaches to deal with the projected surplus of North Slope
crude oil on the West Coast have been proposed (70). These have not been
fully explored and should be studied in detail. These include:
A. The expansion and modernization of existing West Coast
refineries in order to increase their capacity to process
sour (high sulfur) crude; and
B. Construction of one or more facilities (at Valdez, Kitimat,
Port Angeles or elsewhere) to desulphurize and raise the
gravity of North Slope crude oil, in order to use it in
existing West Coast or Northern Tier refineries.
Secondary Impacts—
A study should be made of the environmental implications of induced
development as a result of the importation of North Slope crude into Cali-
fornia. The study should include a proposal by Dow Chemical to build a major
new petrochemical plant in the Montezuma Hills, Solano County; a fuel refinery
near Martinez proposed by Urich Oil Company; a fuel refinery at Carlsbad, San
Diego County proposed by the Macario Independent Refinery Company; and a $1
billion petrochemical facility proposed by Atlantic Richfield Company which
would adjoin the Dow plant in Solano County (61).
Ill
-------
Studies Relating to Air Impacts
Field Studies and Data Collection—
The environmental assessment of the SOHIO project has required data
to be collected from emission sources not normally sampled. These sources
include tanker stacks, fugitive emissions from cargo holds, and floating
roof storage tanks. Barely any work had been performed which involved
measurement of emissions from tankers during the unloading process until the
SOHIO project evaluation was well underway. Operational data need to be
collected for baseline reference analyses on these sources. For example,
should an inerting system fail to operate, venting to the atmosphere could
take place. The rates of failure and the occurrence of resultant venting
should be documented.
A field study also should be conducted on the sources of NO during
combustion prior to stack emissions from tankers. There is some question as
to whether the NO emissions are derived largely from nitrogen in the fuel or
from the combustion process with atmospheric N£. Should fuel nitrogen
be a large contributor to NO emissions, removal procedures involving fuel
treatment would be necessary to reduce emissions.
Air Quality Models—
The results of the models utilized by various consultants when evaluating
the impact of the SOHIO-Port of Long Beach marine terminal differed consider-
ably, especially for reactive hydrocarbons and for oxides of nitorgen.
Special considerations may be required to model tanker emissions which are not
currently incorporated into generalized models.
Of critical importance in the analysis of emissions impact on air
quality is the calculation of probabilities, or likelihoods, of situations
occurring that will result in maximum emissions at meteorologically poor
times. These probabilities of joint events of various types (including
meteorological conditions) occurring for extended periods of time were not
included in the studies to date. Futher, the relevant probabilities for
"worst case" situations should be related to air quality standards such as:
-rr-r = probability of violating California daily standard
2
•777- = probability of violating National daily standard
-?TT ^probability of violating California hourly standard
2
77-5, probability of violating National hourly standard
112
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The models assumed worst imagined combinations of events which led to extreme
air quality degradation. But, in the final analysis it was understood
that the chances of the worst case ever happening within a reasonable length
of time were remote, so that the worst case was discounted as being unlikely.
What is actually going to occur within the lifetime, and as a result, of the
project is important, not the rare combination of events which will cause the
most severe pollution load.
Generally there is a need for the development of an analytical model
which would be well documented with respect to assumptions, constants,
background data, etc. The model would first simulate in-port queueing to
establish emissions rates. Steady-state conditions would be assumed with
the exception of delays due to seasonal weather conditions. Inputs to the
queueing model would include operational modes and times, tanker types,
emission factors, etc. In conjunction with the queueing model, meteorologi-
cal conditions would be categorized (e.g. wind speeds and direction, stabil-
ity, etc.) and their probabilities of occurrence calculated by season. An
air quality analysis for each meteorological condition and season combination
would then be performed in a "backward" mode to determine the emissions
necessary to cause air quality standard violations. The resultant emissions
levels would then be compared to the queueing model results to determine the
frequency of violations, if any, and their associated probability of occur-
rence. Such a model should be published, widely circulated, and treated as
non-proprietary information. A detailed user's manual should accompany the
model.
Guidelines for Assessing Terminal Air Quality Impacts—
A set of guidelines should be developed which provide conformity in the
establishment of assumptions which set the stage or conditions upon which
emission factors are determined for the air quality analyses of proposed
marine terminals. The guidelines would recommend approaches to the develop-
ment of scenarios involving numbers of tankers in port simultaneously, the
duration of such a joint condition, the length of travel into port associated
with air quality implications, etc. The guidelines would provide common
ground for the development of worst case, business-as-usual, and best case
scenarios and consequent emission factors for the evaluation of new port
facilities.
Assessment of Tanker Emissions and Controls—
This report has summarized various studies which have evaluated potential
impacts'upon air quality associated with emissions from tankers expected
to transport North Slope crude oil. Such impacts may be existent to some
degree in ports currently engaged in the loading and unloading of crude oil
or the products of its refinement. A broad, nationwide technology assessment
should be undertaken to define the current and projected magnitude of the
problem, the state of current control technology practice, the potential
individual and system integrated control measures, the policy and institutional
mechanisms for implementing emission abatement measures, and national control
strategy scenarios with concomitant economic, environmental, and social
effects.
113
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The study should include: current and projected tanker traffic patterns
and cargos associated with U.S. ports; current and projected emission factors
and their potential impacts within various air quality control regions;
existing and potential use of vapor recovery systems, on board gas scrubbers
and inert ing systems, terminal waste gas treatment, complete segregated
ballast capability, combustion modification for emission control, on board
and dockside closed system monitoring of oil or product volume and rate of
flow, use of low sulfur fuel, bilge and cargo hold cleaning, and curtailment
of emissions via operational controls; and existing or potential water, land,
or noise impacts associated with the abatement of air emissions from tankers
or conversely, impacts upon air quality associated with the control of water,
land, and noise pollution.
Studies Related to Water Impacts
Vessel Traffic Control System—
A study should be undertaken to determine the feasibility of developing,
implementing, and operating a multi-regional vessel traffic control system.
The study should consider an area extending from Valdez, Alaska to the
Panama Canal. Such a system could utilize standard, durable, and certified
equipment including preferred corridors of tanker traffic movement, naviga-
tional buoys, primary and backup radar, Loran C, transponders which auto-
matically report position and identification, ship-to-ship and ship-to-shore
radio, primary and backup gyrocompasses, Fathometers, emergency generators,
fire fighting and damage control equipment and procedures, operating rules
for pilots and tugs, backup boilers, rudder systems, propellers, and certifica-
tion of officers and crew (70,71). It is envisioned that such a system could
operate similar to an air traffic control system and would be under jurisdic-
tion of the U.S. Coast Guard. Legislation may need to be enacted to provide
legal authority over U.S. and foreign vessels operating in a pre-defined zone
(perhaps 200 miles offshore) as proposed in current legislation (83,84).
Double Hulls--
Proponents of double hull tankers maintain that the sides and bottom
of a tanker's cargo compartment should be separated from the ship's outer
hull to prevent accidental oil spills should the hull be pierced. This
outside compartment could be used to store ballast water to prevent its
contact with the oily cargo. Adversaries of the concept maintain that such
double bottoms could cause explosions by providing an enclosed space into
which oil fumes could leak (71). Some maintain that a double hulled tanker
which has pierced its hull in a grounding is difficult to refloat. Others
feel that double sides in addition to double bottoms are not warranted for
tankers. A study of the state-of-knowlege concerning these tankers should be
undertaken to evaluate the pros and cons of the concept.
Setting a Precedent
The SOHIO project is the first major energy project to come under
the policy that trade-offs for new stationary source air emissions would be
a required mitigation measure as set forth in newly proposed stationary
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source review rules. The location of the project in a non-attainment area
has forced stringent mitigating measures to be employed in order to be in
compliance with accepted air quality regulations. Some of these measures may
include the use of low-sulfur fuel, segregated ballast, inerting systems,
avoidance of purging operations in port or near shore, use of exhaust scrubbers,
vapor recovery systems on storage and cargo tanks, restricted ballasting in
port (for ships with partially segregated ballast), automatic closing valves
on the pipeline, foam-covering systems to blanket oil spills, and trade off
of project derived hydrocarbon emissions by the curtailment of local hydro-
carbon emissions by an equal or greater amount.
The imposition of these measures as permit conditions by regulatory
agencies could be detrimental to an incentive on the part of proponents of
similar energy projects. Such sponsors may not possess the financial backing
in the form of capital to invest in the use or development of relatively
expensive pollution abatement devices. Thus, in similar situations where a
project which provides an energy supply seeks to attain environmental com-
patibility, the SOHIO project could represent a model. It is suggested that
this situation be explored for its precedent setting potential and resultant
ramifications.
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REFERENCES
1. Office of Communication. 1976. Success at Oil Creek August 27, 1859.
Department of the Interior, Washington, D.C. 16 pp.
2. Petroleum Extension Service. 1966. Introduction to the Oil Pipelina
Industry. The University of Texas, Austin, Texas. 84 pp.
3. American Petroleum Institute. 1975. Crude Oil Pipeline Map of the
United States and Southern Canada. Washington, D.C.
4. American Petroleum Institute. 1975. Basic Petroleum Data Book.
Petroleum Industry Statistics. Washington, D.C.
5. National Petroleum Council. 1971. Environmental Conservation.
The Oil and Gas Industries/Volume One. Washington, D.C. 106 pp.
6. Dyas, Norma W. 1972. North Alaska Oil and Related Issues.
Congressional Research Service, Washington, D.C. 105 pp.
7. Federal Energy Administration. 1976. National Energy Outlook.
Washington, D.C.
8. Business Week. 1969. Alaska Strikes It Rich. February 1, 1969,
pp. 49-53.
9. Concluding remarks in a statement by Secretary of the Interior,
Rogers C. B. Morton Concerning the Application for a Trans-
Alaska Pipeline Right-of-Way. May 11, 1972, Department of
the Interior Press Release.
10. Tussing, Arlon. 1974. The Trans-Alaska Pipeline and West Coast
Petroleum Supply, 1977-1982. A Staff Analysis Prepared at the
Request of the U.S. Senate Committee on Interior and Insular
Affairs Pursuant to Senate Resolution 45 (National Fuels and
Energy Policy Study).
11. Excerpt from a report to the U.S. Senate from the Committee on
Interior and Insular Affairs which Accompanied the Federal
Lands Right of Way Act of 1973 (S. 1081).
12. Trans-Alaska Pipeline Act of 1973 (PL 93-153). Enacted by Congress
November 13, 1973, and signed by President Nixon November 15;
Amended by the Energy Policy and Conservation Act, PL 94-163,
December 22, 1975.
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REFERENCES
(Continued)
13. Engineering News - Record. 1976. $l-Billion Alaska Oil Terminal
Braces for Snow and Quakes. June 3, 1976, pages 18-19.
14. Wilson, Howard M. 1976. Beefed-up Tanker Fleets Readied for North
Slope Oil. The Oil and Gas Journal, June 14, 1976, pages 23-26.
15. Hodgson, Bryan. 1976. The Pipeline: Alaska's Troubled Colossus.
National Geographic 150(5): 684-717.
16. Federal Energy Administration. 1976. An Analysis of the Alternatives
Available for the Transportation and Disposition of Alaskan North Slope
Crude. Final Draft Report Dated November 30, 1976. Washington, D.C.
891 pp.
17. Hill, John A. 1976. Statement Before the Senate Interior and Senate
Commerce Committees. September 21, 1976.
18. Federal Energy Administration. 1976. Crude Oil Supply Alternatives
for the Northern Tier States. Washington,D.C. 61 pp.
19. Canadian News. 1976. Interprovincial and Trans-Mountain Pipe Line.
Pipeline and Gas Journal, August, 1976. p. 16.
20. Bureau of Land Management. 1976. Draft Environmental Impact Statement.
Crude Oil Transportation System: Valdez, Alaska to Midland, Texas (As
Proposed by SOHIO Transportation Company. Department of the Interior,
Washington, D.C.
21. Oilweek. 1976. Kitimat Studied for Crude Oil Pipeline. May 31, 1976,
pp. 82-83.
22. The Oil and Gas Journal. 1976. Canadian Oil Line Plans Yo-Yo Operation.
December 13, 1976. p. 41.
.23. National Fisherman. 1976. Washington Determined to Control Tanker
Movements in Puget Sound. December, 1976.
24. Northern Tier Pipeline Company. 1976. Supplement Number 2 to the
Northern Tier Pipeline Company's Application for Site Certification.
Submitted to the Washington State Energy Facility Site Evaluation
Council on November 19, 1976.
25. Northern Tier Pipeline Company. 1976. The Northern Tier Pipeline
Concept. Billings, Montana.
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REFERENCES
(Continued)
26. Beasley, James R. 1977. Review Comments on The MITRE Corporation's
Draft Report "Seeking Environmental Compatibility: A review of
Environmental Issues Related to the Transportation of Alaskan North
Slope Crude Oil." Butler Associates, Inc., Tulsa, Oklahoma.
27. The Oil and Gas Journal. 1976. Northern Tier Wants Permits, Then Oil
Buyers. June 14, 1976. p.27.
28. The Oil and Gas Journal. 1976. The Puget Sound. March 29, 1976.
p. 74.
29. Richards, Bill. 1977. Energy vs. Environment: Clash on West Coast.
The Washington Post. January 10, 1977.
30. Federal Energy Administration. 1976. North Slope Crude: Where to?
How? Washington, D.C.
31. Concern expressed by Assemblyman Charles Warren of the California
Legislative in a Speech Entitled "The State Government's Response to
Alaskan Oil and Gas" Presented at the "Oil and Gas from Alaska: Choices
for California" Conference held at the University of South California,
Los Angeles and Sponsored by the Center for California Public Affairs,
Claremont, California. November 20-21, 1976.
32. A Goal of Project Independence launched by President Nixon on November
7, 1973. For a Discussion of the Program Policy see: Hana Umlauf.
1974. Project Independence? The Hard Questions Ahead. ln_ The World
Almanac and Book of Facts 1975. Newspaper Enterprise Association, Inc.,
New York. 976 pp.
33. Hornblower, Margot. 1976. Zarb of FEA Opposes Exporting Alaskan Oil
Surplus. The Washington Post. December 1, 1976.
34. Gregg, Bill. 1976. Oil Swap With Japan Gets Strong Backing. The Oil
Daily. December 9, 1976.
35. The Oil and Gas Journal. 1976. FEA Sees N. Slope Oil Exports Needed.
September 27, 1976.
36. Port of Long Beach and the California Public Utilities Commission 1976
Draft Environmental Impact Report: SOHIO West Coast to Mid-Continent
Pipeline Project. September 1976.
37. Platt's Oilgram News Service. 1976. California Board Reported Eyeing
Offshore Crude Port. November 16; 1976.
119
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REFERENCES
(Continued)
38. Naval Facilities Engineering Command. 1976. Environmental Impact
Assessments of Alternate Routes for Crude Oil Transport Naval Petroleum
Reserves in California-Elk Hills. Office of Naval Petroleum and Oil
Shale Reserves, San Bruno, California.
39. Platt's Oilgram News Service, 1976. Navy Issues Bid Invitation.
November 16, 1976.
40. Pipeline and Gas Journal. 1976. Navy Plans Pipeline from Elk Hills
Field. November, 1976.
41. Jackson, Henry M. 1976. Opening Statement Before the Joint Interior
and Commerce Hearing on the Effort of the Trans-Alaska Pipeline on the
West Coast Crude Oil Supply. September 21, 1976.
42. Wilson, Howard M. 1974. Prudhoe Oil Will Bring Profound Change to West
Coast Crude-Flow Patterns. The Oil and Gas Journal, March 18, 1974,
pages 96-100.
43. Nehring, Richard. 1976. Mitigating and Offsetting Emissions from
West-East Oil Movement. Draft Working Note Dated December 21, 1976.
Rand Corporation, Santa Monica, California, 34 pp.
44. Platt's Oilgram News Service. 1976. Senators Hear Contrasting Views of
SOHIO Terminal's Eco-Effects. December 8, 1976.
45. Stevens, Ted. 1976. Statement Before the Senate Commerce and
Interior Committees Regarding Distribution of North Slope Crude Oil.
September 21, 1976.
46. White, Robert A. 1976. FEA to Meet Early Storage Goal—Noel. High-
lights, October 26, 1976. Office of Communications and Public Affairs,
Federal Energy Administration, Washington,D.C.
47. Pacific Environmental Services, Inc. 1976. Final Report-Air Quality
Analysis of the Unloading of Alaskan Crude Oil at California Ports.
Prepared for the Office of Air Quality Planning and Standards, U.S.
Environmental Protection Agency, Research Triangle Park, North Carolina.
48. SOHIO Transportation Company. 1976. Impact of the SOHIO Project
on Air Emissions in the Long Beach Port Area. Report Dated August 20,
1976. Midland Building, Cleveland, Ohio.
49. Teknekron, Inc. 1976. Air Quality Impact Evaluation of Candidates
Sites for an Alaskan Oil Transfer Terminal in the Pacific Northwest.
Draft Report Dated July 31, 1976, Submitted to Region X, U.S. Environ-
mental Protection Agency, Seattle, Washington.
120
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REFERENCES
(Continued)
50. Chicago Bridge & Iron Company. 1976. SOHIO/CBI Floating Roof Emission
Test Program. Final Report Dated November 18, 1976. Oak Brook, Illinois.
51. Mackenzie, John F. and Charles T. Ran. 1976. Gaseous Hydrocarbon
Emissions During the Loading of Marine Vessels. Paper Presented at the
69th Annual Meeting of the Air Pollution Control Association, Portland,
Oregon. June 27-July 1, 1976.
52. U. S. Coast Guard. 1974. Final Environmental Impact Statement-
Regulations for Tank Vessels Engaged in the Carriage of Oil in Domestic
Trade. Department of Transportation, Washington, D.C.
53. Office of Air and Waste Management. 1975. Compilation of Air Pollutant
Emission Factors. (2nd Edition) AP-42. U. S. Environmental Protection
Agency, Office of Air Quality Planning and Standards, Research Triangle
Park, North Carolina.
54. Esso Research and Engineering Company. 1974. Survey of Ship Discharges.
Final Report on Task I, Sub-Task 2 (Contract No. C-l-35049). Prepared
for the Office of Research and Development, Maritime Administration,
U.S. Department of Commerce, Washington, D. C.
55. American Petroleum Institute. 1962. API Bulletin on Evaporation Loss
from Floating-Roof Tanks. (API Bulletin 2517). Washington, D.C.
56. Time. 1977. Oil is Pouring on Troubled Waters. January 10, 1977.
57. Kifner, John. 1977. Tanker Loss Record Set Last Year. The Washington
Star. January 10, 1977.
58. United Press International. 1977. Tankers' Troubles Spread Globally; 1
Missing 7 Days. The Washington Star, circa. January 10, 1977.
59. Environmental Research & Technology. 1976. SOHIO Crude Oil Transporta-
tion System Tanker Traffic Study. Prepared for the Bureau of Land
Management, Department of the Interior. (Contract No. YA152-CT6-181).
60. Cicchetti, Charles J. 1972. Alaskan Oil: Alternative Routes and
Markets. Resources for the Future, Inc., Washington, D.C. 142 pp.
61. Center for California Public Affairs. 1976. Background paper prepared
for participants in the conference entitled Oil and Gas from Alaska:
Choices for California held at the Davidson Conference Center, University
of Southern California, November 20-21, 1976.
62 Harris, Carolyn. 1972. In Productive Harmony: Environmental Impact
Statements Broaden the Nation's Perspectives. Office of Public Affairs,
U.S. Environmental Protection Agency, Washington, D.C.
121
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REFERENCES
(Continued)
63. Council on Environmental Quality. 1976. Environmental Impact
Statements: An Analysis of Six Years' Experience by Seventy Federal
Agencies. Washington, D.C.
64. Los Angeles Times. 1976. Letting the Oil In. September 21, 1976.
65. Anderson, Allan W. Jr., and Brian J. Heisler. 1976. Position Brief of
the Commission Staff. Federal Power Commission, Washington, D.C.
December 7. 1976 (Docket No. CP 75-96, et al).
66. Federal Power Commission Staff. 1975. Comments on behalf of the
Southern California Air Pollution Control District Regarding the Staff's
Draft Environmental Impact Statement. Contained within the Final
Environmental Impact Statement, El Paso Natural Gas Company (Docket No.
RP 72-6) 502 pp.
67. Ford, Gerald R. 1976. Statement upon signing S.3521 (The Alaska
Natural Gas Transportation Act of 1976) into Law. Presidential Documents
12(44):1563.
68. Interagency Natural Gas Task Force. 1976. Recommended Actions to
Alleviate the Natural Gas Shortage in California. Energy Resources
Conservation and Development Commission, Sacramento, California.
69. Graves, William. 1976. Sea of the Pacific Northwest: Puget Sound.
National Geographic 151(1):71-97.
70. The Washington Star. 1977. Senate is Readying Probe of those Oil
Tanker Spills. January 9, 1977.
71. Mayer, Allan J. 1977. How to Make Tankers Safer. Newsweek:
January 17, 1977.
72. U.S. Environmental Protection Agency. 1976. Review of New Sources and
Modifications. Federal Register 41(246): 55558-55561, December 21,
1976.
73. Bureau of Land Management. 1977. Review comments on The MITRE
Corporation's Draft Report, "Seeking Environmental Compatibility: A
review of environmental issues related to the transportation of Alaskan
North Slope Crude Oil." Department of the Interior, Los Alamitos,
California.
74. U.S. Environmental Protection Agency. 1977. Review comments on the
MITRE Corporation's Draft Report, "Seeking Environmental Compatibility:
A review of environmental issues related to the transportation of
Alaskan North Slope Crude Oil". Region X, Seattle, Washington.
122
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REFERENCES
(Concluded)
75. Nehring, Richard. 1977. Mitigating and Offsetting Emissions from
West-East Oil Movement. WN-9719-CEQ. February, 1977. Rand Corporation,
Santa Monica, California, 47 pp.
76. Air Resources Board, State of California. 1977. Preliminary Analysis
of the Proposed SOHIO Marine Terminal at the Port of Long Beach.
SS-76-035. December 16, 1977. Sacramento, California.
77. SOHIO Transportation Company. 1977. Supporting Information for the
SOHIO Permit Application Prepared for the Southern California Air
Quality Management District. February, 1977. Cleveland, Ohio.
78. Port of Long Beach. 1977. Overview SOHIO-West Coast to Mid-Continent
Pipeline Project. January, 1977. Environmental Affairs Division,
Long Beach, California.
79. Office of Planning and Research, State of California,. 1976. Is San
Luis Obispo Bay a Realistic Alternative Meriting Further Study if the
SOHIO Proposal for a Deepwater Terminal to Receive Alaskan Oil at Long
Beach Fails to Meet Prescribed Environmental Standards? October 28,
1976. Sacramento, California.
80. Oceanographic Commission of Washington. 1975. Submarine Pipeline
Crossings of Admiralty Inlet, Puget Sound: A study of technical
feasibility. Seattle, Washington.
81. State of Washington. 1976. Assessment of Alternative Crude Oil Marine
Terminal Locations in Washington State. Economic Policy Analysis
Division, Department of Commerce and Economic Development, Seattle,
Washington.
82. State of Washington. 1976. A Report on: A Comparative Assessment of
Three Proposed Operational Port-Terminal Facilities. Department of
Ecology, Seattle, Washington.
83. Senate Bill 182. The "Federal Tanker Safety and Marine Anti-Pollution
Act of 1977." 95th Congress, 1st. Session.
84. Senate Bill 682. The "Tanker Safety Act of 1977". 95th Congress,
1st. Session.
123
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
ca-70088
1. REPORT NO.
EPA-600/7-77-046
2.
i. TITLE AND SUBTITLE
Review of Environmental Issues of the Transportation
of Alaskan North Slope Crude Oil
3. RECIPIENT'S ACCESSION-NO.
5. REPORT DATE
flay 1977.
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
Richard D. Brown, Richard M. Helfand
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
The MITRE Corporation
METREK Division
Westgate Research Park
McLean, VA 22101
10. PROGRAM ELEMENT NO.
1NE 624C
11. CONTRACT/GRANT NO.
68-01-3188
12. SPONSORING AGENCY NAME AND ADDRESS
Office of Energy, Minerals & Industry
Office of Research & Development
U.S. Environmental Protection Agency
Washington,.TKC. 20460
13. TYPE OF REPORT AND PERIOD COVERED
Final Report
14. SPONSORING AGENCY CODE
EPA/600/17
15. SUPPLEMENTARY NOTES
This project is part of the EPA-planned and coordinated Federal Interagency
Energy/Environment R& D Program. »
16. ABSTRACT
The onset of Alaskan and offshore West Coast Oil requires west-to-east movement
of oil which is in excess of anticipated West Coast demand. Proposals for this move-
ment include Canadian and U.S. pipelines to carry crude to Northern Tier States which
face a decline in Canadian exports, pipelines from California to mid-western states,
tanker traffic through a canal in Central America or around Cape Horn, and exchanges
of oil with foreign countries.
Environmental issues center on impacts affecting air and water quality. Air
pollution as a result of offloading, venting, purging, ballasting, and oil storage may
require stringent mitigating measures or emissions tradeoffs, especially in non-
attainment areas. The degree of water pollution impact is contingent upon the risk of
oil spills, probable oil spill trajectories, and the environmental characteristics
associated with a particular alternative.
Information is needed in the following areas: the future flexibility in meeting
unanticipated supply and demand patterns, how the distribution of natural gas supplies
affect the movement of the crude oil and its environmental impacts, accurate air
quality models, a West Coast vessel traffic control system, and how present decisions
requiring measures to mitigate air impacts may set a precedent for future ventures.
17.
(Circle One or More)
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
Energy Conversion
Physical Chemistry
Materials Handling
Inorganic Chemistry
Organic Chemistry
Chemical Engineering
other: air quality, water quality
b.lDENTIFIERS/OPEN ENDED TERMS
Alaska, crude oil,
pipelines
:. COS AT i Field/Group
8H}10A (10B
- —•* ^~ -^
7B 7C|/T3BS
13. DISTRIBUTION STATEMEN1
Release Unlimited
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
175
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
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