v>EPA
United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory
Cincinnati OH 45268
EPA-600/7-80-023
February 1980
Research and Development
North Sea Pipelines
A Survey of
Technology, Regulation
and Use Conflicts in
Oil and Gas Pipeline
Operation
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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. Environmentaf 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 protectthe 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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EPA-600/7-80-023
February 1980
NORTH SEA PIPELINES
A Survey of Technology, Regulation and Use Conflicts
in Oil and Gas Pipeline Operation
by
William E. Nothdurft
Coastal Programs Division
New England River Basins Commission
Boston, Massachusetts 02109
Interagency Agreement No. 78-D-X0063
Project Officer
John S. Farlow
Oil and Hazardous Materials Spills Branch
Industrial Environmental Research Laboratory
Edison, New Jersey 08817
INDUSTRIAL ENVIRONMENTAL RESEARCH LABORATORY
OFFICE OF RESEARCH AND DEVELOPMENT
U.S. ENVIRONMENTAL PROTECTION AGENCY
CINCINNATI, OHIO 45268
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DISCLAIMER
This report has been reviewed by the Industrial Environmental Research
Laboratory, Cincinnati, U.S. Environmental Protection Agency, and approved
for publication. 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
When energy and material resources are extracted, pro-
cessed, converted, and used, the related pollutional impacts
on our environment, and even on our health, often require that
new and more efficient pollution control methods be used. The
Industrial Environmental Research Laboratory - Cincinnati (IERL-
Ci) assists in developing and demonstrating new and improved
methodologies that will meet these needs both efficiently and
economically.
This report describes the environmental effects of con-
structing and operating marine pipelines. Based on the infor-
mation presented here, more environmentally suitable pipeline
installations can be made. The information presented here is
of interest to those engaged in planning, installing and operat-
ing marine pipelines. Further information may be obtained
through the Resource Extraction and Handling Division, Oil and
Hazardous Spills Branch, Edison, New Jersey.
David G. Stephan
Director
Industrial Environmental Research Laboratory
Cincinnati
iii
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PREFACE
In 1977, the U.S. Environmental Protection Agency (EPA),
recognizing the New England River Basins Commission's (NERBC)
continuing interest in offshore oil and gas activities, requested
that NERBC undertake a study dealing with the environmental ef-
fects of submarine pipeline installation and operation. The
project, entitled "OCS Pipeline Construction and Operation - Po-
tential Environmental Problems and Recommendations for Mitiga-
tion of Impacts," was begun in January 1978.
This report, one in a series produced under this contract,
focuses on pipeline-related experiences gained in the North Sea
development area, a site of intensive offshore activity and a
proving ground for many of the latest advances in marine pipe-
line technology.
Material for the report was collected from detailed inter-
views with industry, government, and private individuals associa-
ted with pipeline decisions in Norway, England, and Scotland. In
addition, technical reports, engineering feasibility studies,
progress reports, impact statements, and construction specifica-
tions were examined to document how decisions have been made, for
what reasons, and with what effects. The report is a synthesis
of these interviews, supported in part by details from some of
the reports collected. It is not a detailed analysis of the
technical reports, but does highlight the most significant pipe-
line-related issues currently being dealt with in the North Sea.
The text is heavily footnoted for reference, and an appendix
listing of reports collected is included. Much of the informa-
tion has direct transferability to issues likely to arise during
Outer Continental Shelf (OCS) development in frontier regions.
iv
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ABSTRACT
This project was undertaken to provide information on North
Sea offshore pipelines and the processes used in route selection
decisionmaking. It is designed to be used by persons involved in
offshore oil and gas pipeline planning, including pipeline corri-
dors and landfalls. The bulk of the information for the report
comes from interviews with industry, government and private indi-
viduals associated with pipeline decisionmaking in Norway, Eng-
land and Scotland. Supplemental information is derived from
written sources.
A brief overview of offshore activity in both the United
Kingdom and Norwegian sectors of the North Sea is presented,
with special emphasis on the transportation systems established
or proposed for the major commercial fields. The report then
focuses on the specific issues arising from the installation and
operation of each of these transportation systems. These issues
include: regulations affecting pipeline placement, criteria for
route selection, pipeline trenching and burial, and conflicts
with the fishing industry in the North Sea.
This report is submitted in fulfillment of Interagency
Agreement No. EPA-78-X0063 by the New England River Basins Com-
mission under the sponsorship of the U.S. Environmental Protec-
tion Agency. This report covers the period August 1978 through
December 1978, and work was completed as of August 30, 1979.
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CONTENTS
Page
Foreword ..........................
Preface .......................... iv
Abstract .......................... v
Figures and Tables ..................... ix
Acknowledgments ...................... x
1. North Sea Oil and Gas Overview .......... 1
United Kingdom ................ 3
Pipeline systems ............. 6
Oil and gas terminals ........... 9
Norway .................... 11
Pipelines: the "Ekofisk Solution" .... 13
The current political environment ..... 13
Marine pipelines in the North Sea:
the key issues ................ 14
2. North Sea Pipeline Planning, Permitting , and
Regulation .................... 15
United Kingdom ................ 16
Norway .................... 19
3. North Sea Pipeline Routing and Landfall Siting . . 23
United Kingdom ................ 23
The Conoco-Viking field case ....... 24
The St. Fergus terminal .......... 24
Routing the Frigg gas lines. . . ..... 26
Routing the Brent gas line ........ 27
Forties Field to Cruden Bay ........ 29
The Brent Field to Sullom Voe ....... 30
The Piper Field to Flotta ......... 32
Norway .................... 35
The Ekofisk Pipelines ........... 35
The Statf jord-Sotra Pipeline routing
study ................... 38
4. pipeline Trenching and Burial. ... ....... 42
Recent practices and existing regulations. . . 42
Burying the Ekofisk-Emden gas line ...... 43
The validity of the safety/stability
rationale ......... .......... 45
vii
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Page
5. Consultation, Access, and Debris: The Fishing
Issues 49
Consultation 49
Loss of access 51
Debris 54
Appendix 57
vi
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FIGURES
Number Page
1 Oil and gas in the North Sea area 5
2 Mechanical pipe supports for span areas 41
3 Artificial burial using crushed stone 44
4 Anchor penetration 47
TABLES
Number Page
1 Estimated United Kingdom recoverable oil reserves ... 2
2 Estimated United Kingdom recoverable gas reserves ... 2
3 Estimated recoverable Norwegian oil and gas reserves. . 3
4 Physical constraints on pipeline landfalls
criteria for evaluation 36
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ACKNOWLEDGMENTS
The task of adequately acknowledging all of those who
assisted in a project this broad is a difficult one. We are
indebted to William 'E. Nothdurft, who researched and wrote this
report, and to a host of individuals scattered throughout Eng-
land, Scotland and Norway who provided valuable insight and as-
sistance. Special thanks go to Derek Lyddon, Chief Planner,
Scottish Development Department, Niall Trimble, British National
Oil Corporation, and Christian Hambro, Deputy General Director,
Norwegian Ministry of the Environment for their assistance in
making contacts and arranging appointments for Mr. Nothdurft
with industry and governmental representatives in the United
Kingdom and Norway.
Irvin M. Waitsman
Manager, Coastal Programs
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SECTION 1
NORTH SEA OIL AND GAS OVERVIEW
In the decade or so since the first discoveries of gas and
oil were made in the North Sea, exploration, development, and
production activities have grown steadily. While it is generally
accepted that most of the major fields have been discovered, new
discoveries continue to be made with surprising regularity. The
most recent rumor is that British Petroleum (BP) may have made a
big find west of the Shetland Islands. Driven by a complex array
of economic factors, including the instability of foreign crude
supplies, Britain's balance of payments problems, and the scale
of Norwegian investments secured by the promise of petroleum rev-
enues, offshore activity has expanded steadily into deeper water
in an environment which, even in the best of times, is extremely
hostile.
As of early 1977, proven recoverable oil reserves in the
United Kingdom (U.K.) sector totaled 9.6 billion barrels (1.33
billion tons)1 as compared to estimated recoverable reserves of
between 18.7 and 21.6 billion barrels (2.6-3.0 billion tons).2
Confirmed recoverable oil reserves in the Norwegian sector to-
taled 4.8 billion barrels (650 million tons).3 Total proven
recoverable gas reserves (both dry and associated) totaled 50-60
trillion cubic feet (1.42-1.70 trillion cubic meters) in the U.K.
sector4 and 22 trillion cubic feet (630 billion cubic meters) in
the Norwegian sector.5 Tables 1 and 2 provide a breakdown of oil
and gas reserves in the U.K. sector. Table 3 provides a break-
down of reserves in the Norwegian sector.
10ccidental North Sea Group, The Search for North Sea Oil,
1977, p.l. :
2
The Scottish Council, United Kingdom Oil and Gas; Situation
po-57-iow. 1978. D.8. ~~ ~
Norwegian Ministry of Petroleum and Energy, correspondence dated
November 27, 1978.
November 27, 1978
Scottish Council, Situation Review, p.9.
Norwegian Ministry of Petroleum and Energy, correspondence dated
November 27, 1978.
1
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TABLE 1. ESTIMATED UNITED KINGDOM RECOVERABLE OIL RESERVES
Barrels (billions)
Fields in production (7)
Fields committed to development (8)
Fields probably commercial and
under appraisal
Named and unnamed fields under or
awaiting appraisal
Total recoverable reserves
5.76-6.12
3.6-4.32
5.04-5.76
4.32-5.40
18.72-21.60
Tons (billions)
.8-. 85
.5-. 6
.7-. 8
.6-. 75
2.6-3.0
Source: The Scottish Council/(1978).
TABLE 2. ESTIMATED UNITED KINGDOM RECOVERABLE GAS RESERVES
Trillion cubic feet
Remaining southern North Sea dry gas fields 25
Frigg dry gas (67% Norwegian,35% UK) 9
Brent associated gas 4
Other-associated gas 12-22
Total recoverable reserves 50-60
Source: The Scottish Council* (1978)-
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TABLE 3. ESTIMATED RECOVERABLE NORWEGIAN OIL AND GAS RESERVES
Oil Gas
(billion barrels) (trillion cubic feet)
Ekofisk complex
Frigg (Norwegian sector)
Statf jord (Norwegian sector)
Valhall A
Other recoverable reserves
Total recoverable reserves
1.43
(gas only)
2.17
.23
.98
4.81
8.83
3.88
1.77
.71
7.06
22.25
Source: Norwegian Ministry of Petroleum and Energy,(1978),
The following is a brief overview of offshore activity in
both the U.K. and Norwegian sectors of the North Sea, with spe-
cial attention to the transportation systems established or pro-
posed for the major commercial fields. Subsequent chapters deal
with specific issues arising from the construction and operation
of marine pipelines and shore terminals.
UNITED KINGDOM
Since the mid-1960's, roughly 500 exploration and 200 field
appraisal wells have been completed in the U.K. sector of the
North Sea, with a success ration of 1 in 6, as compared to the
world offshore average of 1 in 20.6 During the peak exploration
period in 1974-75 up to 40 mobile drilling rigs were in operation,
but by the first quarter of 1978 this total had dropped to 17.7
Discoveries continue, however, and in 1977 five companies an-
nounced new finds (Conoco, BP, Total, Transocean, and Phillips).
During the early months of 1978 Elf Aquitaine announced an oil
and gas find west of the Shetlands and exploration began on the
first of the blocks granted in the fifth round of licensing with
the British National Oil Corporation (BNOC)'s drilling of a well
west of the Ekofisk complex.9
8
'Scottish Council, Situation Review, p.7.
^Scottish Development Department, North Sea Oil
Information Sheet, March 1978, p.3.
Ibid, p.14.
Ibid, p.3.
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In the U.K. system, offshore blocks (tracts) are granted
rather than leased to applicant companies or consortia, with a
nominal payment and a royalty agreement. Leases are granted
based on a variety of criteria, including:
technical capability to successfully develop the
block;
financial ability to follow through with tract
development;
degree to which British-based oil companies are
involved;
negotiated terms of participation by government-
owned companies (BNOC, British Gas);
proportion of goods and services to be ordered from
British firms (as monitored by the U.K. Offshore
Supplies Office); and
willingness to permit trade union involvement.
Although leases are generally granted following a set
schedule of licensing rounds, the government will occasionally,
upon application by a developer, grant blocks outside a licensing
round. This will occur if it is felt to be in the national in-
terest to develop the block. As an incentive to rapid develop-
ment of granted blocks, half of the acreage of a block must be
surrendered to the government after six years if the license
holder has failed to move forward with development. Future leas-
ing rounds are likely to involve additional conditions as govern-
ment moves to exercise its control over development and produc-
tion under recent legislation.
Since the installation of production platforms began in the
mid-1970's, the drilling of production wells has grown steadily.
By early 1978, about 280 production wells had been drilled and
approximately 400 more are planned during the next five to seven
years.10 Figure 1 illustrates major fields discovered as of^!978
and their associated pipelines. Since June 1975, nine oil fields
have begun production (see Figure 1 for locations). In order of
the beginning of production, these "onstream" fields are: (1)
Argyll (Hamilton Bros., June 1975); (2) Forties (BP, November
1975); (3) Auk (Shell, December 1975); (4) Montrose (Amoco, June
1976); (7) Piper (Occidental, December 1976); (8) Claymore (Occi-
Scottish Council, Situation Review, pp.7-8.
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LEGEND
Oil
Gas
SHETLAND
ISLANDS
ORKNEY
ISLANDS
Cormorant
Hutton
Heather
0 Balder
NORWAY
0;
Crawford .'
Brae
Q 0 Bream
Brisling
Renee 0
Buchan -O
Maureen
- Andrew
Mabel
-Albusk|ell
Tor
SETor
Ekofisk
Edda
r- Eldfisk
Valha
UNITED
KINGDOM
Flyndre
Josephi
W Ekofisk
Auk.-Q
Argyll _
Dotty
West Sola
Amethyst
WEST
GERMANY
Source: Bergen Bank, Petroleum Activities in Norway. 1978, p.7
FIGURE 1, OIL AND GAS IN THE NORTH SEA AREA,
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dental, November 1977); and (9) Thistle (Burmah-BNOC, March
1978).H The Frigg Gas field (Elf Norge/Total) began production
in September/ 1977.
Seven fields are currently in various stages of devel-
opment, from platform fabrication and installation to develop-
ment drilling: (1) Heather (Unocal); (2) Murchison (Conoco);
(3) Ninian (Chevron); (4) Tartan (Texaco); (5) Buchan (BP) ;
(6) Cormorant (Shell) ; and (.7) Dunlin (Shell) . Development
plans are under Department of Energy review for Beatrice (Mesa),
Fulmar (Shell), and Magnus (BP). Fields currently under devel-
opment are those discovered between July 1973 and December
1975.12 Thus, even under very heavy government pressure to
develop and produce, it appears to be taking from three to five
years to move from a field discovery to development drilling.
The same can be said for those fields which have begun produc-
tion. In all, 14 steel platforms have been installed and four
more are committed, and eight concrete platforms have been in-
stalled with two more committed, for a total of 28 at a total
cost of roughly $12 billion, not including installation.13 It
is estimated that as many as eight new steel platforms and seven
new concrete platforms may be needed by 1985, as well as four
semi-submersible conversions, three tension leg platforms, and
three subsea completion units.
Pipeline Systems15
There are currently seven oil and gas pipeline systems
which are either completely installed, under construction, or
planned. All but one are primarily marine pipeline systems.
The British Gas System. The British Gas Corporation
(BGC) was established in 1972 to consolidate and manage the 12
regional gas councils which themselves were created after World
War II to amalgamate over 1,000 individual gas companies/ some
in existence since 1812. The British Gas Corporation has a com-
plete monopoly over the purchase, distribution, and sale of gas
in the United Kingdom.
Scottish Development Department, Information Sheet, pp.10-11.
12Ibid, pp.11-12.
Scottish Council, Situation Review, 1978, p.10.
14Ibid.
The description of both pipeline and terminal systems is
drawn primarily from the Scottish Councils' Situation Review,
1978, pp.11-16.
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The BGC's Production Supply Division acts as a wholesaler,
buying gas at its point of landfall and distributing it to its 12
regions and to a few very large industrial consumers (e.g., pow-
er plants, petrochemicals) through a nationwide complex^of land
pipelines, virtually all of which have been laid since the mid-
19 60 's. Until recently, most of the gas supply for this distri-
bution system came from the Bacton terminal (4 billion cubic feet
(cu.ft.)/day) where processing of southern North Sea gas began in
1968, and from the Theddlethorpe and Easington terminals further
north along the east coast of England, established to handle gas
from the Viking and West Sole fields, respectively. Algerian
liquified natural gas (LNG) is landed at the Canvey Island ter-
minal near London.
British Gas is also empowered to explore for gas directly
through two of its wholly-owned subsidiaries: the Gas Council
Exploration Co. Ltd., which handles onshore exploration and re-
cently located a commercial field in Dorset, in the south of
England; and Hydrocarbons Great Britain Ltd., which is involved
in offshore activity and will be developing several blocks in
the Irish Sea.
The most recent and most important BGC pipeline system is
the group of installed and proposed lines, connecting the dis-
tribution system with the massive new terminal at St. Fergus,
Scotland. (The St. Fergus terminal is designed to handle gas
from the Frigg, Brent, and Piper fields in the northern North
Sea and is discussed in greater detail below under "Oil and Gas
Terminals.") As of June 1978, British Gas had completed two 36"
pipelines along a 200 kilometer (km) route from St. Fergus to
Bathgate, near Edinburgh. An additional 264 km 36" connecting
line is now under construction. A fourth line, 42" in diameter,
is also proposed along a more easterly route. The total capac-
ity of the three 36" lines will be 3 billion cu.ft./day. The
42" proposed line would boost line capacity (throughput) by an
additional 2 billion cu.ft./day. The estimated total cost of
the three 36" lines, including booster stations, is approxi-
mately $320 billion.
The Brent System. There are three distinguishable pipe-
line systems serving Shell's Brent field complex. Each is out-
lined below.
Oil is gathered and transported from the Brent Complex to
Sullom Voe Terminal in the Shetland Islands through a system of
gathering lines linking Brent, Dunlin, Thistle, Button, and Cor-
morant to a 36" trunk line 150 km in length. The gathering
lines comprise one 30 km 24" diameter pipeline and one 12 km
16" diameter pipeline. Maximum handling capacity is 1 million
barrels per day (b/d), and the estimated installed cost is
roughly $280 million. The system is expected to be operational
by late 1978 and eventually additional adjacent fields will be
linked to the system.
7
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Associated gas with large amounts of gas liquids will be
carried from Brent to St. Fergus Terminal through a 450 km 36"
diameter line. Planned capacity will be 1 billion cu.ft./day,
but it is expected that new associated gas from adjacent fields
will be transported through the pipeline. Construction was com-
pleted in July 1978.
Natural gas liquids (NGL) (i.e., ethane, propane, butane,
natural gasoline) will be separated from the methane in the
Brent gas stream and are proposed to be piped from St. Fergus to
the Mossmorran area, near Edinburgh, to a proposed gas liquids
treatment plant and terminal. The estimated cost of the pro-
posed 175 km, 16" - 18" diameter pipeline is roughly $90 million.
The Ekofisk System. Oil from the Ekofisk field complex in
the Norwegian sector is transported to a terminal at Teesside on
the east coast of England via a 354 km 34" diameter pipeline
with a maximum handling capacity of 1.0 million b/d. The ap-
proximate installed cost is $550 million.
The Forties System. Oil from BP's Forties Field is trans-
ported from the field to Cruden Bay via a 180 km 32" marine
pipeline with a maximum cost of $240 million. The crude oil is
transported from Cruden Bay to Grangemouth via a 220 km 36"
diameter pipeline with a 600,000 b/d throughput capacity. In
the Grangemouth area, liquids are removed at the Kinneil Sta-
bilization Plant and the crude is either piped to Grangemouth
for refining or to the Hound Point Terminal on the Firth of
Forth for export. Pipeline construction cost an estimated
$76 million.
The Frigg System. Recoverable gas from the Frigg Field is
transported by Total Oil Marine, Ltd. from Frigg to St. Fergus
via two 365 km 32" pipelines (one for U.K. owned production, one
for Norwegian owned production) roughly 70 meters apart. Ap-
proximately 100 km of smaller gathering lines may eventually
link the East Frigg, Odin, and Heimdal fields to the main sys-
tem. Both of the 32" lines pass through an intermediate com-
pressor platform roughly halfway along the route. All the gas
reserves from Frigg have been committed to BGC under twin 20-
year contracts. Maximum handling capacity of the lines is pro-
jected to be approximately 2.4 billion cu.ft./day and the esti-
mated total cost is $980 million.
The Ninian System. Oil from BP's Ninian field and Uno-
cal 's Heather field will be transported from Ninian to Sullom
Voe via one 165 km 36" diameter pipeline with a maximum capacity
of approximately 1 million b/d. Heather will be connected via a
35 km 16" diameter line. To date, the estimated total cost is
$270 million. Adjacent fields are likely to join the pipeline
at a later date.
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The Piper System. Occidental's Piper crude oil is trans-
port ed~~?roirTthT~Pxger[^£^^ Orkney, via one
235 km 30" pipeline with a throughput capacity of about 650,000
b/d. Oxy's Claymore field is linked to the pipeline for crude
transport via a 16" gathering line. Another 16" gathering line
is under construction for moving associated gas from Claymore to
Piper, where it will be linked to a completed 18" connecting
pipeline for transporting associated gas (120 million cu.ft./day)
from Piper Complex to Frigg Intermediate Platform and then trans-
ported via Total's 32" lines to St. Fergus. Texaco's Tartan
field will probably be linked to Piper as well. The approximate
installed cost of the oil lines to Flotta is $280 million; for
the gas lines $90 million.
Oil and Gas Terminals
The major, receiving terminals for oil pipelines are Sullom
Voe (Shetlands), Flotta (Orkney), Cruden Bay (Scotland), and
Teesside (England). Each is briefly described below, along with
the St. Fergus gas terminal complex.
Sullom Voe Oil Terminal. The S-ullom Voe terminal is de-
signed to receive crude oil from the two pipelines from the
Ninian and Brent systems. Constructed and, when completed in
late 1978, operated by the Sullom Voe Association (composed of
the oil companies in the Brent and Ninian Systems and the Shet-
land Island Council), the terminal will be capable of initially
handling 1.2 million b/d with a design capacity of 3 million b/d
when complete. Fifteen above-ground storage tanks provide stor-
age capacity of 9.4 million barrels of crude. A crude oil sta-
bilization plant will extract 45 million cu.ft./day of methane/
ethane and 3,500 tons/day of propane/butane. Refrigerated pro-
pane/butane will be stored in four insulated tanks with a total
capacity of 40,000 tons. Loading and berthing capacity are pro-
vided for tankers up to 300,000 deadweight tons (dwt). The to-
tal estimated cost of the project is over $1 billion.
Flotta Oil Terminal. The terminal at Flotta in the Orkney
Islands handles the shipments of crude oil from Occidental's
Piper and Claymore fields. Total storage capacity of the seven
crude tanks is 4.5 million barrels. The stabilization plant
handles up to 550,000 b/d of crude and extracts up to 25 million
cu.ft./day of methane/ethane and 1,600 tons/day of propane/bu-
tane. Loading and berthing facilities can handle tankers up to
150,000 deadweight tons. The total cost of construction was
approximately $25 million.
Cruden Bay Reception Terminal. Crude oil from BP's Forties
field is landed at Cruden Bay, below Peterhead, Scotland and
pumped south to Kinneil, then to the Grangemouth refinery or to
the Hound Point Terminal for export. The pumping station has a
-------
handling capacity of 540,000 b/d and is capable of expansion.
It was built at a cost of roughly $40 million. The Kinneil Sta-
bilization Plant near the Grangemouth refinery is capable of ex-
tracting approximately 50 million cu.ft./day of methane/ethane,
1,650 tons/day of propane/butane, and 500 tons/day of natural
gasoline. It was built at an estimated cost of $32 million. At
the end of the Forties pipeline system is the Hound Point Termi-
nal, which can export up to 500,000 b/d of crude not refined at
Grangemouth. Seven above-ground tanks store up to 3.7 million
barrels of crude. Loading and berthing facilities are capable of
handling tankers up to 250,000 dwt. The small terminal was built
at an estimated cost of $46 million. Quantities of gas liquids
are pumped to the Granton gas works in Edinburgh for the manu-
facture of synthetic natural gas to meet the daily demand of
Edinburgh.
Teesside Terminal. The stabilizing facilities at Teesside
are owned by Norpipe Petroleum U.K. Ltd., which is "owned jointly
by the Phillips Group and Norway's Statoil. The NGL facilities
and the utilities are owned by North Sea Pipelines Co. The
terminal is expected to receive up to 30 million tons of crude
oil per year at peaX production from the Ekofisk complex. At
peak it will produce almost 1.5 million tons per year of ethane,
propane, and butane. Ten storage tanks have a capacity of
750,000 barrels each and six refrigerated tanks are planned for
natural gas liquids. Loading and berthing facilities exist for
tankers of up to 150,000 dwt. The total cost for the entire
facility is expected to exceed $700 million.
The St. Fergus Gas Complex. The St. Fergus terminal com-
plex, one of the largest in the world, was officially opened in
May 1978, and is made up of three terminals. The Total Oil
Marine Separation Terminal was constructed to separate small
amounts of gas liquid from the predominantly "dry" gas stream
from the Prigg field. Two essentially separate systems treat
and meter the gas coming ashore through each of the two Frigg
lines before it is passed to the British Gas terminal at the
site. The handling capacity of the Total/Elf terminal is 2.4
billion cu.ft./day of raw gas, from which up to 250 tons/day of
liquids can be extracted, stored, and shipped by truck. Total
cost of the terminal is estimated at $185 million.
The Shell/Esso Separation Terminal will separate substan-
tial quantities of gas liquids from the "wet" associated gas
stream from the Brent field. Total handling capacity of this
terminal will be 850 million cu.ft./day from which up to 6,000
tons/day of ethane, propane, butane, and natural gasoline will
be extracted. The separated gas liquids are expected to be
pumped through a 16"-18" land pipeline south to Mossmorran to a
proposed gas liquids plant and export terminal. Temporarily,
ethane will be piped directly to the new Boddam power plant.
10
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The treated methane is then passed on to the pumping and dis-
tribution terminal.
The British Gas Pumping and Distribution Terminal was con-
structed to receive, further treat, odorize, and compress up to
3 billion cubic feet/day of methane from the Shell/Esso and
Total/Elf separation plants. Eight compressors (two banks of
four - three operating, one standby) with a total capacity of
139,000 horsepower raise the pressure of the treated methane
from 600 psi to 1000 psi and pass it on to what will soon be
three trunk lines linking the terminal with the British Gas
distribution system roughly 200 km to the south. (In point of
fact, only the Frigg gas needs to be compressed; Brent" gas
comes ashore at 1100-1400 psi and is passed to British Gas at
1000 psi.) The estimated cost of the British' Gas facility is
$80 million.
With the substantial increase of petroleum and petroleum
feedstocks, the Scottish Development Department and Regional and
District planners are working on contingency plans for a variety
of downstream industries. An additional crude terminal and re-
finery is proposed for Nigg Point on the Cromarty Firth; an
ammonia plant has been proposed by a Norwegian consortium for
Peterhead; and a gas liquids treatment plant and ethylene crack-
er are proposed for Brent field gas liquids at Mossmorran.
Other proposals are likely.
NORWAY
Development in the Norwegian sector of the North Sea
dates from the Phillips discovery of the Ekofisk field in
1969.16 The massive Ekofisk complex consists of seven fields
situated in the southwest corner of the Norwegian sector:
Ekofisk, West Ekofisk, Cod, Tor, Edda, Albuskjell, and Eldfisk.
(See Figure 1.) Oil production from the Ekofisk complex aver-
aged about 97.2 million barrels per annum in 1976 and 1977 and
is expected to peak at about 215 million barrels in 1980-1981.
Gas production is expected to peak in 1981 at about 740 billion
cubic feet. Although Ekofisk was discovered and developed
before Norway had established a governmental infrastructure to
manage development, the transportation and production plans
submitted in 1973 were made contingent upon participation by
Norwegian companies. Statoil owns 50 percent of Norpipe A.S.,
which owns the pipelines, and Norpipe Petroleum U.K., Ltd.,
which owns the stabilizing facilities at the Teesside terminal.
Statoil is 100 percent owned by the Norwegian government.
16Much of the description of the Norwegian situation is drawn
from the Bergen Bank's Petroleum Activities in Norway, 1978, pp.6-15.
11
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The British gas field was declared commercial in 1972 and
was developed with the limited participation of Statoil, the Nor-
wegian equivalent of British National Oil Corporation (BNOC).
The field straddles the boundary line between the United Kingdom
and Norwegian sectors of the North Sea, and an agreement on the
split of reserves (60.82 percent (%) Norwegian; 39.18% U.K.) was
reached in December 1977. The field has estimated total re-
serves of gas of about 7 trillion cubic feet; production will
likely peak in 1981 at about 520 billion cubic feet per annum.
As indicated above, all the gas is sold under a 20-year contract
to BGC at the St. Fergus landfall.
The combined gas and oil Statfjord field is the most im-
portant field discovered to date in the North Sea. Declared
commercial in 1974, it, like the Frigg field, straddles the U.K./
Norwegian mid-line and reserves are split at 11.11% U.K. and
88.89% Norwegian. Total estimated Norwegian reserves are roughly
2.2 billion barrels of oil and 1.8 trillion cubic feet of gas.
Over a dozen oil companies comprise the Statfjord Group, but
Statoil, the Norwegian oil company, dominates with 44.4% of the
shares. Mobil (with a 13.3% share of the group) is the operator.
Oil production and transportation, using single buoy mooring
(SBM) and tanker from Statfjord A, the field's first producing
platform, is projected for late 1979; gas will be re-injected in
the first years. Statfjord1s second platform - B - is planned
for 1981 and Statfjord C is now being evaluated. A crude oil
pipeline to Norway is under study and discussed elsewhere in
this report. There are high hopes for the prospects of a new
block adjacent to Statfjord, currently being referred to as the
"Golden Block." A first well was successfully drilled in the
summer of 1978.
The Valhall field was declared commercial in 1976, as was
Hod just to the southwest. Both fields are close to the Ekofisk
complex. Total reserves are estimated at 302 million barrels of
oil and 706 billion cubic feet of gas. When production begins
in 1981, oil and gas will be transported through a link with the
Ekofisk pipeline system (oil to Teesside, gas to Emden). Peak
production of roughly 95,000 barrels/day of oil and 150-200 mi^T-
lion cu.ft./day of gas is expected to be attained by 1984.
The Murchison field northwest of Statfjord was declared
commercial in 1977. Total reservesestimated at 360 million
barrels of oilwill be split between the U.K. (80%) and Norway
(20%). The platform is under construction in the U.K. and will
be towed out in 1979. Production may start in 1980.
12
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Pipelines; The "Ekofisk Solution"
Norway's licensing laws specifically state that Norwegian
oil and gas shall be brought ashore in Norway, unless the King
decides otherwise.17 To date, however, the technical difficulty
of laying a pipeline through the Norwegian trench, which paral-
lels the coast, and the absence of a market for gas in Norway
have dictated that Norwegian hydrocarbons be sold elsewhere.
Currently, therefore, Ekofisk oil is transported 350 kilo-
meters (km) to a terminal at Teesside, England through a 34" dia-
meter pipeline which, with two booster stations, is capable of
handling 1 million b/d. A 442 km 36" gas line was built from
Ekofisk to the gas terminal at Emden, West Germany to handle Eko-
fisk gas and has a maximum capacity of approximately 2.12 billion
cu.ft./day. While neither the oil or natural gas is landed in
Norway, the entire system, built at an estimated cost of $1.45
billion, is owned by Norpipe A.S., a Norwegian pipeline company
and operated by Phillips.«» Transportation of oil started in
1975, dry gas in 1977, and transportation of natural gas liquids
is planned for 1979.
But this so-called "Ekofisk solution" is only grudgingly
accepted in a political sense. The Norwegian Parliament has
requested that the Statoil/Mobil Group conduct a $60 million de-
tailed feasibility study for an oil pipeline from Statfjord,
across the Norwegian trench, to Sotra, an island near Bergen,
Norway. The study, completed late in 1978, concluded that while
pipeline installation across the trench was technically feasible
with conventional pipelaying techniques, the cost of the pipeline
will probably not be justified by the Statfjord find alone.-19
The Current Political Environment
Norway is moving cautiously in its offshore development
program. Reserves identified to date represent roughly ten times
its petroleum needs. Norway's effort to control the pace of
development by limiting the number of block offerings has been
criticized by some in the media. There is a concern that when
Ekofisk and Statfjord are developed there will be a great lag
time before newer fields can pick up the slack in production.20
17
F
Ministry of Industry, Legislation Concerning the Norwegian
Continental Shelf, October 1977. "
18Norpipe, Brochure and Factsheet, 1978.
19Interview with Statoil officials.
20"Separation of Exploration and Production Phase", Scandinavian
Oil-Gas Magazine, Vol. 6, No. 5/6, p.22.
13
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Consequently, future licensing rounds are likely to stipulate
the government's right to postpone field development and regu-
late the production profile/ rather than simply delaying explora-
tion altogether.
Pressure to accelerate licensing and development stems
from three factors: (1) the prospect of peaking production from
existing fields from 1985 to 1990; (2) the need for additional
fields to be identified in the Statfjord area to justify the cost
of any pipeline; and (3) Norway's short-term economic problems
incurred on the promise of oil revenues.
Norwegian officials and oil companies are faced with a
difficult dilemma. The deep Norwegian trench and the limited
domestic market for petroleum products have so far made pipe-
lining to Norway a less than attractive prospect. Still, there
is strong political sentiment in the country to "bring Norway's
oil to Norway", and while the Ekofisk-Bravo blowout sensitized
Norwegians to the inherent dangers of offshore development, this
political sentiment remains strong and is likely to be an impor-
tant component of any future development policy.
MARINE PIPELINES IN THE NORTH SEA: THE KEY ISSUES
This chapter has provided a brief overview of the current
status of offshore activity in the North Sea, with special empha-
sis on the pipeline systems installed or under construction and
their respective shore terminals. Of significantly greater
interest, and the principal objective of this North Sea Pipeline
Survey, is a better understanding about how the transportation
decisions were made, who was involved, what kinds of impacts
have been encountered, and how the process has been regulated
by the governments involved. The following chapters address
these issues.
21
Bergen Bank, Petroleum Activities, p.19.
14
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SECTION 2
NORTH SEA PIPELINE PLANNING, PERMITTING, AND REGULATION
Until very recently, neither the British nor the Norwegian
government has had much involvement in marine pipeline routing,
construction, or operating activities. For the most part, both
governments have viewed such decisions as basically technical and
economic questions best dealt with by the companies involved.
The most critical concern is the safety and stability of the
pipeline and both governments have worked closely with industry
representatives and safety specialists to achieve consensus on
safety standards and to keep up with the rapidly developing
technology of pipeline construction.
In contrast, there has been very little involvement by
either government in the planning of offshore pipeline routes.
The policy in the U.K. has been to wait and react to proposals
from industry rather than conduct contingency planning in antici-
pation of industrial development proposals. Except for the
unique case of the Shetlands, U.K. planners seldom choose sites
for facilities ahead of time. The coastal planning guidelines
developed in Scotland, classifying sections of the coast as con-
servation, development, or unclassified zones, came the closest
to prior planning. This classification system appears to have
had some effect. Most of the major new industrial facilities
have been sited outside of conservation zones. However, when
major industrial developments have been proposed for conservation
areas, public policymakers have been successful in applying "na-
tional interest" override criteria to permit the facility to be
developed.22 The "wait and see" approach has also been applied
to the -question of regulations. The tendency in the U.K. is to
refrain from promulgation of regulations for a particular acti-
vity until something happens that indicates such regulations are
needed.2^
22Interview with British National Oil Company officials.
23Interview with Scottish Development Department officials
15
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The approach in Norway is similar. Ministry of Petroleum
and Energy officials wait for industry proposals, review and
comment, and recommend alternatives to be studied.24 Other
agencies check proposals for safety, but apart from identifying
potential landfalls, little pre-planning is evident until finds
are confirmed. The legislation governing Norwegian continental
shelf development tends to be very general.25 Regulations to
ensure compliance with legislative intent are drawn up by the
Norwegian Petroleum Directorate (NPD), but again these regula-
tions are generally concerned with issues of safety, inspection,
and in some cases pollution control systems offshore, rather than
methods of routing or siting decisions.
UNITED KINGDOM
The Petroleum and Submarine Pipelines Act of 1975, which
regulates the construction and operation of offshore pipelines,
is the principal vehicle for controlling the marine pipeline
siting process in the United Kingdom. Prior to the Act, the off-
shore activities were loosely monitored through a number of other
pieces of legislation. This section examines how onshore pipe-
line decisions are made, how marine pipelines were sited before
the 1975 Act, and how the terms of the Act have been applied
since it was passed.
Land pipelines fall under the control of the Pipeline Act
of 1962, which divides pipelines into two classes. The routing
of small pipelines under 10 miles in length requires planning
permission from the district or regional planning authority. In
the case of land pipelines greater than 10 miles in length, ap-
proval of the route and siting of associated structures is the
responsibility of the Secretary of State for Energy. The design
and external appearance of the pipeline's associated structures
must be approved by the planning authorities. The company pro-
posing lines greater than 10 miles must, upon application for
planning permission, advertise for a 28-day public review.2^
Planning authorities' comments can cover such issues as (1) the
effect of pipelines on future uses of the land (.including mineral
extraction); (2) the loss of prime agricultural land; (3) the
24
Interview with Ministry of Petroleum and Energy officials.
25
Ministry of Industry, Legislation Concerning the Norwegian
Continental Shelf, October 1977.
26
Interview with official at H.M. Pipelines Inspectorate,
Department of Energy.
16
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loss of environmentally sensitive areas; (4) the effect on ar-
cheological sites; and (5) the hazards to public safety. '
During the review period, the company, affected public, or the
local planning authority may arrange public meetings. If the
local authority raises an objection to the proposed pipeline,
the Secretary of State for Energy is bound by the legislation to
hold a public enquiry before making a decision. The effect of
the local planning authority's comments is strictly advisory for
lines over 10 miles, however; final authority rests with the Sec-
retary of State for Energy.
Local or regional planning authorities, accustomed to con-
trolling most land use decisions, express frustration at not
being able to decide on pipeline permit applications, even though
such applications may cover several local authorities. A princi-
pal frustration is that the required rights-of-way and density
limitations for-pipelines effectively eliminate substantial areas
of potentially developable land, preempting local long-term de-
velopment and infrastructure plans. For example, the required
right-of-way for a 36" pipeline is 40 feet on either side. How-
ever, codes of practice call for a density limitation within 1250
feet on either side of the pipeline of one person per acre along
each mile of pipe.28 The councils want to establish corridors to
minimize this "sterilization" of acreage by proliferating trunk
lines. The British Gas Corporation (BGC) argues that pipelines
should be independent and sited based on the product being car-
ried. While the BGC consults extensively with local authorities
in planning pipeline routes, the local authorities have only ad-
visory powers, except with respect to surface installations.
Offshore pipelines constructed prior to the passage of
the Petroleum and Submarine Pipelines Act (which is not retro-
active) were controlled through a variety of means. Proposals
were reviewed by both the Department of Agriculture and Fish-
eries, under the authority of the Dumping at Sea Act, and by the
Department of Trade, under their navigation responsibilities.
Upon review, these agencies gave authority to the Department of
Energy to proceed. Most of the pipelines to the U.K. have been
constructed under this loose arrangement, including Ekofisk to
Teesside, Forties to Cruden Bay, Frigg to St. Fergus, Piper to
Flotta, Brent and Ninian to Sullom Voe, and the several lines
from the southern gas fields.
2Interview with officials of the Grampian Regional Council.
28U.S. requirements (Title 49 CFR 192) specify that natural gas
pipeline design and operating conditions meet criteria based
on actual population density.
17
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The passage of the Petroleum and Submarine Pipelines Act
in 1975, however, consolidated and formalized the process of off-
shore pipeline application and approval. Under the terms of this
Act, the Department of Energy (DEN) can issue regulations to gov-
ern the form and process of pipeline application. To date, how-
ever, those regulations which have been drafted have been vague.
Because DEN's policy emphasizes performance over specific tech-
nologies used, and because the technology of offshore pipeline
construction is changing rapidly, DEN issues what it calls "guid-
ance notes" to assist companies applying for a pipeline construc-
tion authorization.
When DEN receives an application, it requires documentation
that the applicant is technically and financially capable of con-
structing and operating the pipeline safely and of discharging
any liability resulting from an accident. A detailed report on
the route/ design, construction, and operation of the proposed
pipeline must accompany the application. The company must adver-
tise a notice of application for 28 days and provide copies of
the proposal to several cities along the coast. No public en-
quiries are specifically required under the Act, but the compa-
nies must gather and respond to all "observations" made about the
proposal, not just the objections. The company must report the
results of consultations with affected parties, including commer-
cial fishermen, other offshore operators, and cable companies.
In the meantime, DEN handles notification and coordination with
other government agencies.
After all of these steps have been taken, notice of appli-
cation expired, and differences resolved, DEN issues a letter of
intent to formally authorize the pipeline. A further technical
report on the specifications of the pipeline is requested, dis-
cussed, and approved, and the company can then begin construction.
Actual formal authorization may take some time to process. There-
fore, the letter of intent serves to speed construction while the
paperwork is being completed and may specify any special require-
ments DEN wishes to issue as conditions for approval. DEN also
monitors the construction process, inspects the equipment, moni-
tors the testing results, and oversees inspection upon comple-
tion.29 In general, the companies are required to comply with
state-of-the-art standards on design and safety, such as those
established by the Institute of Gas Engineers, the British In-
stitute of Petroleum, the Department of Transportation's Office
of Pipeline Safety, and the classification firm specializing in
29
Interview with official at H.M. Pipelines Inspectorate,
Department of Energy.
18
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offshore engineering, Det Norske Veritas. The same is true of
land pipelines.
The Secretary of State for Energy cannot, on his own,
recommend a change in the route after authorization; rather, the
applicant must submit a request for a change of route. This
means that conflicts with other uses or users, if not antici-
pated prior to authorization, may be unresolvable after authori-
zation has been granted. (This may explain why final authoriza-
tion may be delayed until the line is virtually completed.)
Other problems may also arise now that the government is trying
to encourage the design and routing of pipelines to permit off-
shore hookups with new fields to reduce the proliferation of
pipelines to shore.
The Shell/Esso associated gas pipeline from the Brent field
to St. Fergus was the first to be constructed under the terms of
the new Act, Company officials reported that the principal ob-
jections raised during the review period were from other compan-
ies owning undeveloped offshore blocks along the proposed route.
Among the conditions stipulated by DEN for the pipeline were
(1) monthly progress reports; (2) immediate notice of incidents
threatening the pipeline; (3) DEN-monitored quality control pro-
cedures; and (4) compliance with state-of-the-art industry stan-
dards unless specifically waived. Shell/Esso officials note
that, although DEN has full authority to cancel an authorization
if established procedures are not followed, the agency has been
extremely receptive to advancing technology through research and
detailed engineering studies, rather than simply establishing
procedures which specify appropriate technologies.^O
NORWAY
Although no marine pipelines have been constructed to
Norway to date, a^number of mechanisms are already in place to
handle proposals in the future. Several agencies are involved.
The Ministry of Petroleum^and Energy is the principal offshore
petroleum development policy analyst. It manages the leasing
program and monitors development of the offshore fields. The
Norwegian Petroleum Directorate (NPD) is the regulatory agent
for day-to-day activities. The NPD is responsible for estab-
lishing regulations to implement the general policies approved
by the Parliament and deals with technical questions about the
interpretation of the law. Its regulations deal primarily with
safety-related issues rather than routing decisions. Statoil
30
Interview with Shell/Esso officials.
19
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manages Norway's commercial interests. Although it is wholly-
owned by the government, it functions as an ordinary oil company,
and will have majority participation in all future licensing
rounds in the Norwegian sector. Recently, Statoil was commis-
sioned by the Norwegian Parliament to conduct a $60 million
feasibility study of a pipeline from the Statfjord field to
Sotra, near Bergen. Norpipe A.S. was established in 1973 by the
Parliament to obtain control over the transportation system for
oil and gas in the southern portion of the Norwegian continental
shelf. The objective was for Norpipe to construct, own and oper-
ate the facilities.
Regulations developed by NPD to control offshore activity
tend to be extensive and tough. But because so few pipelines
are expected to be constructed to Norway, Norwegian officials
seem to prefer less regulation and more attention to the appli-
cation of specific stipulations to each case as it arises.
The Royal Decree of July 9, 1976 is the basis of the exist-
ing regulation of marine pipelines in Norway. Chapter 12, Sec-
tions 111-124 set out requirements for information disclosure
and transportation plan documentation; route surveys; safety
standards for load bearing capacity, weldability, corrosion, and
concrete coating; installation plans; construction practices;
trenching and burial; and emergency shutoff systems. For ex-
ample Section 123, which deals with burial, stipulates: "To the
extent reasonable, pipelines shall be protected" by burial or
other means to avoid mechanical damage caused by other activities
along the route, including fishing and hunting, shipping, and
exploration and exploitation of submarine natural resources."31
To translate the law into practice, NPD has specified the
depth requirements of burial under conditions applicable to the
Ekofisk situation (see Section 4 on trenching and burial) but
generic regulations have not been promulgated. Similarly, NPD
has specified inspection of the Ekofisk lines every six months
for the_first two years to carry out another legal requirement,
but again, these rules may not apply or may be strengthened in
other situations. The value of these inspections was dramati-
cally displayed when a severe buckle was discovered in the
Ekofisk-Teesside pipeline, caused by a dragging tanker anchor
coming in contact with a section of the pipeline near shore.
Ministry of Petroleum and Energy, "Royal Decree of July 9, 1976,
Relating to Safe Practice for the Production of Submarine Pe-
troleum Resources, Chapter 12, Section 123", Legislation Con-
cerning the Norwegian Continental Shelf. October 1977, p.255.
20
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The pipeline was shut down for six weeks while the section of
the pipe was replaced.
Perhaps the most unique aspect of the pipeline transpor-
tation and regulatory process in Norway is the degree of parti-
cipation and influence of Det Norske Veritas, a private ship
classification company that has become heavily involved in off-
shore activities. Under contract to the government and the par-
ticipating oil companies, Veritas oversees pipeline design,
(stress, materials, welding, corrosion protection, etc.), inspects
pipe mills and coating yards, certifies every pipe joint, certi-
fies the technical capability of the pipelaying barge and the
details of the construction process, monitors and inspects the
construction techniques (day and night), certifies underwater
tie-ins, comments on jet barge suitability for conditions
encountered, and conducts final tests (hydrostatic; video inspec-
tion) .32
On the basis of their experience offshore, Veritas has
published "Rules for the Design, Construction, and Inspection
of Submarine Pipelines and Pipeline Risers", along with other
codes including API codes which govern pipelaying safety
procedures in the Norwegian sector and elsewhere in the world.
They have been responsible for risk analyses and safety proced-
ures and have issued "certificates of approval" for many steel
structures in the Norwegian sector. In addition, the company
maintains a "pipeline condition record" which documents all
acceptable defects which occur during construction to simplify
the inspection process later.
While in most respects Norway, like the U.K., prefers to
react to industry's proposals rather than conduct extensive con-
tingency olanning programs, the pipeline/trench problem has
resulted in a fairly extensive siting study. Statoil/Mobil
Group's pipeline feasibility study, discussed in detail later in
this report, included a survey of 400 km of coastline from which
eight landfalls were singled out for more detailed investigation
of such factors as route length, water depth, rock outcrops, and
simplest route preparation.33 Because of the nature of the
western coast, the options were limited. Similar but signifi-
cantly more detailed surveys have been made on the pipeline
route itself. At the same time, the Statoil/Mobil Group, the
operator of Statfjord, is conducting feasibility studies on the
offshore loading alternative to pipeline transport.
32Interview with officials of Det Norske Veritas.
33lnterview with officials of Statoil.
21
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In conclusion, it is accurate to say that both Norway and
the U.K. tend to focus virtually all of their management atten-
tion on regulating pipeline construction and operation activi-
ties. The stimulus in both cases is an industrial proposal.
Neither country is involved to any significant degree in prior
planning of marine pipeline corridors or routes and, although
some attention has been given to alternative landfall locations,
these decisions are generally made by industry.
With this brief look at the planning and regulatory con-
text, Section Three examines the way in which routina and land-
fall decisions have been made in the North Sea during the last
decade.
22
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SECTION 3
NORTH SEA PIPELINE ROUTING AND LANDFALL SITING
The North Sea has been, and continues to be, a major prov-
ing ground for new pipeline technology. The hostile deep water
environment has spawned a whole new generation of pipelaying
barges and tremendous advances in pipe fabrication, coating,
welding, and trenching techniques. Given the scale of the en-
gineering problems encountered and the cost of laying pipe under
such conditions, it is reasonable to examine how North Sea
operators have made pipeline construction and routing decisions.
The routing choices made for North Sea pipelines can pro-
vide illustrations of how decisions were made on the following
types of issues: transportation by pipelines or tankers; loca-
tion of landfall and terminal sites; the route selection methods
themselves; causes of changes to planned routes; and the relative
effects of technical, economic/ environmental, and political fac-
tors in determining the final routes. In examining these issues,
this section focuses on the systems planned or currently in place
in both the U.K. and Norwegian sectors and emphasizes the deci-
sion process followed in each case rather than on the results of
detailed technical surveys conducted by the companies involved.
Information is derived largely from interviews with local and
central government officials and technicians with the companies
involved.
UNITED KINGDOM
Experience in the U.K. sector suggests that transportation
decisions are determined almost exclusively by technical and eco-
nomic criteria. Minor adjustments may be made for environmental
or political reasons, but, for the most part, routing and land-
fall decisions for marine pipelines have been determined on a
least-cost basis. As noted previously, there has been little
effort by central government in either England or Scotland to
influence offshore pipeline routing and landfall decisions, with
the unique exception of gas terminal siting. British Gas, with
a monopoly over gas distribution in the U.K., has largely deter-
mined where offshore gas will be landed, though they have had
little influence on how the gas gets there. This discussion
23
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looks first at the gas pipeline and landfall experience and
then examines the situation with oil.
The Conoco-Viking Field Case
Most of the gas from the southern North Sea gas fields,
discovered in the mid-1960ps, comes ashore at the big gas ter-
minal at Bacton, England. Until the opening of St. Fergus,
Bacton was the principal source of gas for the British Gas sys-
tem.
When Conoco made its Viking gas field discovery slightly
north of the center of the southern North Sea gas field complex,
it proposed a 60 mile pipeline south to the Bacton terminal. For
Conoco's purpose, it was both technically and economically the
best pipeline/terminal alternative. Instead, British Gas Cor-
poration (BGC) ordered Conoco to bring its gas ashore at Thed-
dlethorpe north of Viking on the English coast. BGC felt that
the Bacton site had grown so large and important that it was
becoming^a security problem and that it would be safer to, in a
sense, diversify their sources of supply. Despite the fact that
the new route was substantially longer {86 miles) and therefore
more costly and would encounter sand waves, Conoco had no choice
but to cooperate. As a result of having to go the longer, more
costly route, Conoco was able to negotiate a better price for
their gas. They also obtained planning permission without diffi-
culty after^nly 12 months of consultation with local officials.
Conoco attributes some of this success to having a company rep-
resentative "on the ground" a Conoco employee who moved into
the area, worked closely with the local authorities, and walked
the application through the approval process with British Gas.
Although the process went smoothly for Conoco, it is an excellent
example of the effect central government can have in the U.K. on
pipeline routing decisions through control of landfall options.34
The St. Fergus Terminal
In an effort to find a suitable landfall site for gas from
the northern North Sea, BGC was again in charge. A preliminary
survey of the northeast Scottish coast yielded two alternatives:
(1) Wick, a small community near the farthest northeast tip of
Scotland; and (2) the area south of Rattray Head, another head-
land roughly 50 miles north of Aberdeen. Both areas had reason-
ably gentle shore approaches and low population densities.
34
Interview with Conoco officials.
24
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Both sites were roughly equidistant from the Frigg field,
Total's major gas field, for which the terminal was initially
being designed. However, British Gas Corporation, responsible
for laying the land lines to link the terminal to the distribu-
tion system in the south, immediately ruled out Wick as prohibi-
tively expensive, and the beaches south of Rattray Head were sur-
veyed in more detail. Total, which wanted to bury the pipeline
10 - 15 feet below the seabed nearshore, conducted a survey of
landfall approach alternatives and chose a spot near the village
of Crimond, behind a shallow brackish pond called the Loch of
Strathbeg. The site included an abandoned airfield still held
by the government and a solid line of trees screening it from
view from the road and village. The companies applied for plan-
ning permission to establish the terminal.
Unfortunately, the Crimond site is both a national nature
reserve and an international reserve of the highest classifica-
tion on four separate accounts: (1) it is an important migratory
wildfowl habitat; (2) it is an important plant community; (3) the
dune structure is a recent (1700's) and rare formation and unsta-
ble; and (4) the shallow brackish loch is highly productive and
similarly rare.
In response to the proposal, an environmental liaison
group was formed by researchers at the University of Aberdeen.
The University liaison group organized meetings with the indus-
try representatives and the Aberdeen County Council. At the
request of the Scottish Development Department, further offshore
surveys were conducted and an alternative landfall was located
at St. Fergus, just a few miles south of Crimond.36
British Gas Corporation claimed that they could have con-
structed the facility in such a way as to minimize the distur-
bance of plant life and bird habitat on the site and possibly
cross the loch without significant disturbance. They admit, how-
ever, that they would have had to stabilize the shifting dune to
bring in the pipe and that would have significantly altered the
dune structure.37
In the end, however, the decisive blow was struck by the
Department of Defense, which held the airfield. They wanted it
preceding discussion is drawn from interviews with British
Gas officials.
36Interview with Brian Clark, University of Aberdeen, and corres-
pondence from the Scottish Development Department.
37
Interview with British Gas official.
25
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for a NATO radio center and ultimately refused to release it.
Of interest, however, is the assertion by both industry and the
county clerk's office that the environmental liaison group based
at the University, and not the government planning application
review process, had the greatest effect in the negotiations be-
fore the Defense Department stepped in.
Total went on to a section of beach near St. Fergus where
a narrow break in the offshore rock outcrops below Rattray Head
provided enough space for their two pipelines and where substan-
tial open land was available behind the stable barrier dune sys-
tem for British Gas Corporation to establish a 500 acre terminal.
The soil, however, was boggy and unstable and a significant
amount of surface soil had to be removed (to a depth of 15 feet
in some places) and replaced with crushed rock and steel pil-
ings. Jb In addition, since it lacked the natural tree screen
from the highway that the Crimond site had, the St. Fergus site
had to be planted with thousands of small fir trees.
Routing the Frigg Gas Lines
The anchor pattern deployed by a lay barge is such that if
two lines are being laid parallel, they must be laid either at
least two kilometers apart or very close together (70 meters),
with the lay barges straddling the first line already on the
seabed. Total had planned to lay their two 32" lines fairly far
apart, but because of the problem of crossing other companies'
blocks, the lines were laid close together. Between 1974 and
1977 approximately 60,000 12 meter joints were laid in depths of
over 150 meters (490 feet). At Invergordon, Scotland, each joint
was concrete-coated through a cage of reinforcing wire at thick-
nesses varying from 1 7/8 to 4 5/8 inches. Three lay barges,
two bury barges, one diving support ship, two mini-submarines
and their support ship, and 60 supply boats, tugs, and pipe
transporters were employed in the job. Lengths of completed
pipeline were joined in a chamber at the seafloor by a hyperbaric
welding process developed by Total. An intermediate platform was
installed 186 km from the field along the pipeline route.39
O p
Interview with Total Oil Marine official.
39
Total Oil Marine, Frigg; Gas from the North Sea, 1978
26
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The pipeline route was fully surveyed, and sediments con-
sisted mostly of sands and soft clays. The route chosen was
direct, with deviations near the field to avoid other licensed
blocks. Near shore, Total identified, with the help of local
fishermen, an offshore rock formation known as Rattray Rocks.
They diverted the line around the rocks and a boulder clay struc-
ture for two reasons: (1) it was a valuable fishing area; and
(2) crossing it presented a costly engineering problem. On the
shore approach, considerable amounts of rock had to be blasted
to clear a path for the pipe. Cross currents were strong and the
pipe was heavily coated and fitted with flotation tanks to pre-
vent its buckling during the laying and pulling process. The
coastal dunes were excavated and a sheet pile trench was cut to
the terminal. The dunes were subsequently reinstated and vege-
tation was restored with the help of the Geography and Horticul-
ture Department of the University of Aberdeen.
Routing the Brent Gas Line
Like Total, the Shell/Esso Group began by charting the
shortest, so-called "great circle" route for their 450 km 36"
pipeline to St. Fergus for Brent associated gas. The route of
the line, known as the Far North Liquids and Associate Gas System
(FLAGS) Gasline, has the following predominant characteristics:
80% of the route is in depths of over 100 meters,
with a maximum depth of 165 meters;
» there are deep trenches and "pockmarks" along the
route;
» in deep water the seabed is mainly soft silts and
clays; and inshore is mainly sands and hard clays,
rock, and rubble;
tidal currents (though negligible in deep water)
reach 1% meters/second along the coast;
the route crosses several fishing banks; and
like Frigg lines, the line crosses Occidental's
Piper line at a depth of over 100 meters.41
Because of the length, depth, and general expense of the
project, Shell/Esso commissioned a number of independent surveys
and consulted frequently with other users along the routef in-
cluding fishermen's associations and other offshore operators.
40Interview with Total official.
41Interview with Shell Expro and Esso Expro officials.
27
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The results of the studies were summarized by NERBC and the
trenching study results are reported elsewhere in this report.
The first deviations to the shortest route were made to
avoid several trenches over 100 meters in depth and an area of
"pockmarks", wide, relatively shallow holes or craters, which
would cause pipeline spanning and decrease the safety and sta-
bility of the line. Consultations with the fishermen's associ-
ation resulted in several additional routing changes. The ori-
ginal route crossed several prime trawling grounds and the fish-
ermen initially proposed an alternate route to avoid the grounds.
A third compromise route was finally agreed upon which skirted
the edges of the grounds. Subsequently, however, the fishermen
requested that the original route (or one very nearly like it) be
followed because they preferred to trawl the edges of the banks,
not the centers. A route running roughly down the center of
each of the grounds and avoiding an area of 20-30 foot sand
waves was agreed upon. (Active sand wave areas were avoided
along the entire length of the line, although Shell/Esso engi-
neers are confident that it is technically feasible to safely
place a pipeline through these regions.)
At the northern end of the line, the route was altered to
avoid any conflict with the Ninian complex. After extensive sur-
veys of the shore approach, the line's southern end was laid
through roughly the same gap in the rock outcroppings as the
Total lines has been. In all, surveys took roughly a year to
complete. The pipelaying was completed in mid-June, 1978.43
However, because the Brent field gas is "wet," i.e., has
a high liquids content, the Shell/Esso Group also needed a sys-
tem for shipping gas liquids (ethane, propane, butane, etc.)
from St. Fergus. Their original proposal was to link St. Fergus
to a natural gas liquids (NGL) plant and to ship propane and bu-
tane from a terminal at Peterhead, which met the 10 - 12 meter
depth requirement of NGL tankers. However, several major objec-
tions were raised. First, many felt the harbor was too busy and
too small for safe maneuvering of NGL tankers. Secondly, the
density of residential development around the harbor was felt to
be at risk. Thirdly, and most significant in the long run, water
a finding by the company that the seawall forming the protected
harbor would need to be substantially improved in order to pro-
vide protection from high storm waves. Moreover, the local fish-
ing association argued persuasively that the fishing boats be
given priority entry in port during storms, thus making the
berthing problem for tankers that much more complex.
Interview with Shell/Esso officials.
43
See footnote 42.
28
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Shell/Esso eventually dropped the Peterhead NGL terminal
proposal in favor of a 175 km land pipeline south to Mossmorran
on the Firth of Forth linking up to an ethylene cracker and NGL
shipping terminal. The proposed terminal met with stiff opposi-
tion from residents in the area who were skeptical of the safety
of the proposed facilities; tentative approval was granted how-
ever and, subject to the Sectetary of State being satisfied with
the safety of the project, it is likely to proceed.44
Forties Field to Cruden Bay
BP is, by experience, a pipeline company. Although it is
their practice to develop a series of transportation scenarios
even before the field is fully developed, the company has gener-
ally discovered large, high-pressure fields for which pipelines
were the only economic transportation option.
This was the case with the Forties Field where BP chose
pipelines to deliver the crude oil to shore. The closest land-
fall to the Forties Field is Cruden Bay, which lies almost due
west of the field and is one of the few "soft landing" sites on
the Northeast Scottish coast. In planning the route, BP worked
closely with fishermen. Through these consultations, BP was able
to locate rock outcrops, boulder zones, and fishing grounds which
were subsequently avoided in the 110 mile long final route. Di-
versions cost the company $1 - 2 million, one to two percent of
the total cost of the line.45
The pipeline was designed and built in four years. Con-
struction covered three seasons from 1973 to 1975. The majority
of the route was in depths of 350 - 450 feet with seabed condi-
tions ranging from sand waves to stiff clays. Approximately
ninety percent of the route consisted of loose materials such as
sand and silt.
Survey work covered roughly three years from 1971-1973.
A preliminary survey was conducted in 1971, followed by consulta-
tions with a variety of interested parties, and culminated in a
detailed survey in 1972. Survey techniques included sidescan
sonar, echo soundings, and use of a sub-bottom profiler. Core
samples and photographs were collected and current meters de-
ployed along the route. In 1973, further surveys were undertaken
in an area of sand waves to establish whether they had moved dur-
See footnote 42.
45Interview with BP officials.
29
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ing the preceding winter. In all, surveys cost roughly
$500,000.46
BP had considered Peterhead as the pipeline landfall at
first but soon ruled it out because of harbor traffic, the pres-
ence of substantial rock outcrops, and the cost of rights-of-
way. (In this regard, BP officials note that the landfall deci-
sion can be determined as much by ability to purchase rights-of-
way at reasonable cost as by such recognized factors as dis-
tance. ) 4 '
BP feels that the Cruden Bay landfall was made with limited
public disruption. Environmental effects (which appear to be min-
imal) have been monitored by researchers at the University of Ab-
erdeen. BP officials jokingly commented that their biggest land-
fall problem was disrupting the local golf course. Regional
Council officials were pleased with the quality of the restora-
tion of the beachfront and right-of-way.
The Brent Field to Sullom Voe
The 36" trunkline linking the Brent System (including
Brent, Cormorant, Dunlin, Hutton, and Thistle) to the oil termi-
nal at Sullom Voe, Shetland is a joint venture of some 17 compa-
nies, with Shell Expro as the operator. Design began in 1973 and
construction took place from 1975- 1977.48
While Shetland was clearly the closest feasible pipeline
landfall to the northern North Sea area, Shell encountered numer-
ous engineering difficulties in the shore approach through Firths
Voe to the landfall chosen for the terminal.
The unusually rugged seabed through Yell Sound approaching
Firths Voe made pipelaying difficult. For approximately six
miles offshore, the seabottom consists mainly of rock outcrops,
pinnacles, and cliffs, in addition to smoothly undulating bed-
rock and occasional boulder cover. Following initial surveys to
find a suitable route, Shell contracted for engineering studies
to determine methods to deal with sea bottom conditions. After
examining a number of plans, the method chosen included three
activities:
46
D.B.L. Walker, A Technical Review of the Forties Field Subma-
rine Pipeline. Paper prepared for 1976 Offshore
Conference, 1976, pp.819-821.
47
Interviews with BP officials.
48
M. Daniels and J.C. Swank, Northern North Sea Pipelines
the Brent System. Paper prepared for the 1976 Offshore Tech-
nology Conference, 1976, p.803.
30
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blasting bedrock and boulders to eliminate
rock pinnacles and level off the sea bottom;
depositing stone fill on the seabed to cover
unacceptable bedrock and boulders, maintain-
ing a minimum depth of two feet; and
grading the fill to provide a bed for pipe-
laying.
In addition, sidescan sonar and echo sounding revealed
three distinct zones, totaling approximately 3000 feet, which
were unacceptable for pipeline laying. This bottom profiling
was also used to determine the minimum acceptable bed width -
60 feet.49
The preparation effort required a survey vessel, six stone
transport ships, and a variety of auxiliary tugs. A total of
45,000 tons of crushed stone was mined from two quarries near
Peterhead, transported to quayside at Peterhead Harbor (3,900
truck loads) , and shipped 200 miles north to Yell Sound in the
Shetlands. It was determined that the vessels, moored alongside
a work barge, could dump a gravel bed roughly 120 feet x 80 feet
to a depth of four feet with each 1,000 tons released in roughly
150 feet of water. Careful diver inspection for alternative
routes reduced what was anticipated to be a substantial blasting
effort to almost nothing.
The laying operation itself, through the six miles of Yell
Sound, involved depths of over 300 feet and currents of up to
six knots Under these conditions, an extremely complex posi-
tioning system, involving twenty surveying and electronic tech-
niques, was required to lay the 36" pipe on a 60 foot prepared
bed. Vickers Oceanic's Pisces II submarine was used to monitor
pipe touchdown on the narrow bed whenever conditions permitted.
Submarine surveys after installation showed considerable
spanning over the entire six mile stretch of the route through
the sound, and steps to stabilize the line, including placing
grout-filled mattresses and crushed gravel under the pipe, were
planned for October 1975. In September 1975, the pipe floated
to the surface over a distance of some 400 feet. After the pipe
had been re-stabilized (using concrete saddles), inspection
showed a loss of concrete coating over 60 percent of the pipe.
It was concluded that vertical vibrations of the pipe caused by
the vortex of bottom currents around the spanned pipe had caused
the pipe to hammer repeatedly against the sea floor, breaking
off the concrete coating. Despite the floating incident and the
49
Ibid, p.805.
31
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loss of weight coating, the pipe itself was apparently undam-
aged. -)U
BP, faced with the same problem in routing their pipeline
to Sullom Voe from the Ninian complex, chose to avoid the high
currents and difficult bottom conditions in Yell Sound in favor
of a longer and, initially at least, somewhat more expensive route
through an ancient sandy-bottom fault leading to Lunna Ness.51
The Piper Field to Flotta
Though, like BP, they tend to favor pipelines, Occidental
officials outlined a number of reasons for choosing the 30" pipe-
line to the Orkney Island of Flotta to transport Piper, and later
Claymore, oil and associated gas liquids. From the beginning,
Occidental was confident of at least 250,000 barrels/day (b/d)
production from Piper and optimistic about the chances of dis-
covering other fields in the area. The expected production lev-
els suggested that tankering would be clearly uneconomic. In ad-
dition, the company had had a series of bad experiences with
single buoy systems elsewhere in the world (especially the Medi-
terranean) and found maintenance to be a problem. Finally, the
tanker loading downtime likely from bad weather in the northern
North Sea made stable production extremely unlikely.5^
The choice of a landfall at Flotta in Scapa Flow in the
Orkneys was less than a straightforward decision and illus-
trates the occasional importance of considerations other than
economic feasibility in site selection. As soon as piper was
discovered (January 1973), Occidental "walked" the northeast
coast of Scotland in search of a suitable landfall and terminal
site. The coastline directly opposite Piper, near Wick, is gen-
erally characterized by steep cliffs rising directly out of the
sea. Nevertheless, nine potential sites were identified. The
Orkneys were included primarily because of a chance airplane
conversation between an Occidental official and a retired Royal
Navy captain living in the Islands who suggested that, because
of the deep waters of Scapa Flow and availability of land, the
Orkneys should be considered.53 Flotta, though more isolated
than other Scapa Flow landfalls, was chosen as the site likely
50Ibid, p.807.
Interviews with BP officials.
52
Interview with Occidental North Sea Group officials
See footnote 52.
32
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to cause the least effect on traditional patterns of life and
the natural environment. 4
Occidental's final decision to go to Flotta was based pri-
marily on the warm welcome they received from the Orcadians.
They attribute this to several factors. First, the consortium
was one company, not several (as in the case of the Shetlands),
and they were easier to cope with. Second, the consortium in-
cluded the Thomson North Sea Group: a Scottish family involved
in several newspapers and other operations, who had intimate
knowledge of the way things are done in the Islands and were
trusted by the Orcadians. Third, there was land available and,
though it had to be designated for industrial use, the Islands
had already been singled out as a development area by Scottish
authorities. Fourth, the Orkneys had been the site of a large
naval base for many years during and following World War II.
The 18,000 Orcadians were used to supporting a 30,000-man naval
force and wanted to regain the economic benefits they had lost
when the base was decommissioned. Fifth, the Orkney Islands'
authorities were pleased with Occidental's willingness to meet
their development conditions, negotiate terms, and proceed cau-
tiously. Outline planning approval was granted to Occidental
within a year of the Piper find, something of a record.-*
Route selection from Piper posed no significant problems
offshore. The pipeline runs in a straight line from Piper to
Scapa Flow. Inside Scapa Flow, Occidental's engineering consul-
tants (Bechtel) identified a number of wrecks and navigation
barriers from the war and the pipeline was routed around them.
Sediments along the route were suitable for trenching in most
areas and gravel beds were laid in areas of rock outcrop. Con-
crete saddles (covering roughly 500 meters) were laid for extra
stability in some areas and to provide access for subsea pipeline
hookups at a later date.^"
With the completion of these main oil and gas trunk lines
it is unlikely that many more will be proposed to the U.K. There
are a number of reasons for this conclusion. For one thing, as
production from the early finds levels off and begins its de-
cline, it makes sense economically to use the excess capacity in
existing trunk lines to accommodate the production requirements
of new fields. In addition, the government is under some pres-
sure to limit the proliferation of offshore pipelines, shore ter-
minals, and land trunk lines, except insofar as British Gas must
54
Occidental North Sea Consortium, The Flotta Story: Development
of an Oil Handling Terminal (Second Ed.), July 1978, p.11.
55Interview with Occidental officials.
See footnote 55.
33
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plan for ensuring the security of gas supplies. Moreover, ener-
gy conservationists (and some Scottish nationalists) are arguing
persuasively for stretching out the duration of productivity by
flattening the peak in the production profile of fields current-
ly being developed.57
Consequently, most of the recent pipeline proposals have
been for relatively short offshore lines to link new fields to
existing major trunk lines. In this regard, for example, Conoco
negotiated an agreement in 1976 with the operators of the Brent
oil pipeline system to link their Murchison field to Dunlin by
means of a ten-mile, 16" diameter pipeline. Conoco evaluated
tankering, but the uncertainty of offshore loading, the cost of
a concrete storage platform, and the relatively high proportion
of volatile gas liquids in the Murchison oil stream, persuaded
them that the pipeline was the best and most economical alterna-
tive. Similarly, Texaco is negotiating with Occidental to link
its Tartan field to the Piper line to Flotta,58 with associated
gas transferred, also via Piper, to the Frigg gasline to St.
Fergus.
There are some potential exceptions, however. The near-
shore Beatrice field being developed by Mesa will, under gov-
ernment order, require a pipeline to shore. However, the tech-
nical problems of pipelining oil with as high a wax content as
Beatrice oil have been difficult to resolve. There is specula-
tion that Pan Ocean's Brae field may have sufficient capacity
to justify yet another gas line to St. Fergus. British Gas is
rumored to be looking for another Scottish terminal site beyond
St. Fergus, again to increase the security of the supply system.
And the possibility of substantial reserves west of the Shet-
lands may mean a new pipeline to the northern coast of Scot-
land. -*y
Finally, pursuing its interest in a gas gathering trunk
line running roughly down the median line in the North Sea to
link up marginal and, as of yet, undeveloped gas fields, Gas
Gathering Pipeline Company, on behalf of the British government,
has completed a survey of potential new pipeline landfalls. The
report was still under review by the Department of Energy in
July 1978, but onshore, coastal, and offshore siting criteria
have been developed for screening pipeline routes and landfalls.
Interview with Gordon A. MacKay, University of Aberdeen.
5 8
Interview with Conoco officials.
59
Interview with British National Oil Corporation official.
34
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The criteria, listed in Table 4, are largely technical and econ-
omic considerations for judging prelimiary suitability. Obvi-
ously, these are "best case" conditions. Pipelines and landfall
sites with many of the negative criteria on the list have already
been built because other factors, generally economic, have out-
weighed the technical problems.
NORWAY
Norway's experience in marine pipeline construction is
limited to the Ekofisk lines to Teesside, England (34" oil) and
Emden, West Germany (36" gas) and ownership of one of the Prigg
gaslines to St. Fergus. Considerable study has been done on the
feasibility of pipelines from Frigg to KaymjzJy (gas) , from Stat-
fjord to Sotra (oil) and gas gathering lines along the boundary
between Norway and the U.K. Norwegian law calls for all oil and
gas found in the Norwegian continental shelf to be brought ashore
in Norway, unless specifically excepted by the King.
In the case of Ekofisk, Phillips requested exceptions for
both gas and oil. Phillips' request was based on their conclu-
sion that it was not economically or technically feasible to con-
struct a gas pipeline through the Norwegian trench and that even
if it were possible, there was simply no significant market for
gas in the country. Phillips cited similar reasons for request-
ing exception for Ekofisk oil and further claimed that the tech-
nology for offshore loading was not good enough to handle pro-
duction conditions in the North Sea. Subsequently, both requests
were approved.
The Ekofisk Pipelines
The heart of the Ekofisk operation is Ekofisk Center, a
huge concrete gravity platform, with a one million barrel storage
capacity, that separates the well stream, processes the oil and
gas, and controls the production rate. The oil pipeline is 220
miles long and includes two intermediate pumping platforms at
roughly the one-third points along the line. Water depths along
most of the route exceed 200 feet, with maximum depth of 314
feet. The sea bottom is mostly sand and silty sand. One area
Of rock outcrops was encountered roughly five miles from shore
in about 100 feet of water. Tidal and storm currents are low.bu
The route of the oil line is essentially a straight line
from Ekofisk to Teesside with two variations. The first was to
avoid a ship anchorage area near the Tees Harbor entrance.
60Phillip S. Massey, "Ekofisk-Teesside Line to Operate Continu-
ously," Oil and Gas Journal, February 24, 1975, p.86.
35
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TABLE 4
PHYSICAL CONSTRAINTS ON PIPELINE LANDFALLS
CRITERIA FOR EVALUATION
Onshore (above limit of marine activity)
1. 500 acres land with slope under five percent; well
drained; average bearing capacity.
2. within one mile of coast; or
3. two sites with similar physical characteristics:
one 50 acres within one mile of coast, one 500
acres within five-ten miles of the coast.
Coastal (from low water mark to upper limit of marine activity)
1. less than ten percent slope.
2. sediment at least three meters.
3. absence of unstable/very mobile sediments.
4. absence of hard untrenchable rock outcrops.
5. absence of high velocity currents.
6. absence of rock cliffs (ten meter high soft sediment
cliffs permissible).
7. absence of unstable sand dunes.
8. space for landing two pipelines (100-200 meters).
Offshore (low water mark to depth of 100 feet)
1. less than ten percent slope, low to moderate undu-
lation.
2. sediments at least two meters deep.
3. absence of mobile seabed sediments, especially sand
waves.
4. absence of high velocity currents.
5. absence of untrenchable rock.
6. absence of deep trenches; other major seabed
irregularities.
7. absence of minor seabed irregularities.
Source: Gas Gathering Pipeline Company, (1978).
36
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Another was required to avoid a sharp change in bottom profile
which would have resulted in an unacceptable span. In general,
however, the route surveyed turned out to be relatively smooth
and presented Norpipe, the owner, and Phillips, the operator,
with little difficulty. Three laybarge spreads completed the
pipeline in one year (1973-1974).&1 The processing and terminal-
ing operation at Sea Sands, Teesside is located on approximately
1.8 square kilometers (km) of reclaimed land. At the facility,
natural gas liquids will be separated from the crude stream and
shipped by tanker to Norway's Rafnes petrochemical plant at Bam-
ble at a lower than present market price.62 Crude oil is stored
at Norpipe's Greatham tank farm, roughly 4 km north of the termi-
nal, in"ten tanks with a total capacity of one million tons (7.2
million barrels). In 1977, roughly half of the crude shipped
from the terminal was divided equally between the U.S. and U.K.
The balance went to France (ten percent), Norway (thirteen per-
cent) , West Germany (nine percent), Sweden (five percent) and
others.63
The routing and construction of the gas line to Emden was
considerably more complex. The pipeline crosses the continental
shelves of Norway (48 km), Denmark (50 km), and West Germany
(342 km)-64 nine active communication cables; and the busiest
shipping'channel in the world. Norpipe augmented initial surveys
done by Phillips with additional sidescan sonar, magnetometer,
and echo sounder surveys to lay out a formal route.b
Four laybarges were used to lay the marine section of the
pipeline (250 miles) and two intermediate booster platforms were
installed at the approximate one-third points in the line. All
but three kilometers were laid in one season (1974). Construc-
tion permits were required from all three governments (as were
operating permits later). Several adjustments were made to the
line to avoid various geologic problems.
Communication cables posed special problems. The pipeline
had to be buried two meters below each of the cables along the
route and be no closer than 1.5 miles from a cable repeater sta-
61Ibid.
C. *}
Interview with Norpipe officials.
63Norpipe, Annual Reports and Accounts, 1977, p. 15
Norpipe, Brochure, p.3.
65
Interview with Norpipe officials,
37
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tion. Cable companies, given estimated notices of laybarge
approach to the cables, would cut the cable and lay it back a
half mile in each direction. The pipe was laid, one to one and
one-half miles of it was trenched (usually three to four passes
were required to reached desired depths), and the cable spliced
by the cable company.
The shore approach to Emden was through a broad mudflat
area in which a 2,000 foot dike was dredged. At the shore two
rows of sheet piling were driven and a 15 foot ditch was dug from
the land side. The pipe was pulled from the laybarge, which was
anchored 1,500 feet offshore. Further offshore a 15 mile ditch
was constructed to provide two meter cover in mud and tidal flats
and three meter cover at all channels. German authorities halted
construction work along a two mile section near Juist Island dur-
ing the winter because of fear that the ditch would cause erosion
damage to the south end of the island.66 other route problems
encountered by Phillips, particularly with respect to trenching
requirements, are dealt with elsewhere in this report.
The "Ekofisk Solution" was an innovative answer to the pro-
blem posed by the Norwegian trench. But because of the legal
requirement to land Norwegian petroleum in Norway and the public
pressure to bring it to shore, extensive route planning programs
have been initiated, primarily for the Statfjord field in the
northern sector of the North Sea.
The Statfjord-Sotra Pipeline Routing Study
The Statfjord field was discovered in 1974 and the opera-
tors, the Statoil/Mobil Group, immediately undertook an examina-
tion of the feasibility of an oil pipeline to the Norwegian
coast. A report covering deepwater technology and landfall pro-
blems (primarily rock outcrops) was prepared in 1975 and for-
warded to the Ministry of Industry (responsible at that time for
continental shelf development), and then to Parliament. From the
beginning, the private companies (Mobil and others) favored off-
shore loading, but Statoil claimed the pipeline could be built
with existing technology and that view prevailed in the prelimin-
ary report.67
fifi
Don P. Shaub, "Line from Ekofisk to Emden Nearly Completed,"
Oil and Gas Journal, January 12, 1976, p.82.
Interview with Ministry of Petroleum and Energy officials.
38
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Parliament, in an attempt to find ways of bringing Nor-
wegian petroleum to Norway, requested that Statoil undertake a
$60 million detailed route planning and feasibility study. It
also asked the licensees to examine the offshore loading question
in more detail. In the interim, a temporary permit is expected
to be granted for tankering oil from the Stratfjord A platform.
The terms of the permit require segregated ballast water for all
tankers used.
The feasibility study, completed in late 1978, covered
deepwater technology, route planning, construction schedules and
costs, and proposed terminal sites. The following discussion,
drawn from interviews with Statoil officials, discusses the sur-
vey, and the solutions proposed in the study for pipeline routing
and landfall selection.
The slope from the Statfjord plateau to the Norwegian
trench is relatively gentle and bottom sediments consist gen-
erally of a thin layer of soft sediment (20 cm) overlaying hard
clays. On the shoulder of the slope (along which the proposed
route runs diagonally) the sediments consist of dense sands giv-
ing way to soft clays near the bottom. The trench bottom itself
consists of soft oozy clays, as deep as 40 meters in places, all
the way to the nearshore area. The depth of the trench in the
area of the proposed pipeline is 300-350 meters (985 to 1,050
feet) .
The proposed route deviates in a number of places along
the trench to" avoid pockmarks characteristic of the northern
North Sea. The pockmarks, running anywhere from ten to one hun-
dred meters in diameter, are thought to be formed by the slow
seepage of migrating natural gas.
Offshore surveys were done with high-precision echo
sounders, shallow (50 meters) seismic profilers, and high resolu-
tion sidescan sonar equipment. The sidescan sonar, towed 20
meters above the bottom, allowed Statoil to clearly delineate
pockmarks along the route and also identified trawl door marks
which helped them determine the intensity and direction of trawl-
ing along the route. Bottom profile passes were made at every
600 meters offshore, 50 meters nearshore, and 15 meters near the
shore approach.
Current readings were hampered by loss of current meters
to trawl fishing, but evidence suggested minimal bottom currents,
and sidescan sonar showed very limited backfilling in areas
marked by trawl doors.
68Interview with Ministry of the Environment official
39
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Severe problems were encountered in the effort to find a
suitable shore approach and landfall. The entire coastline out
to depths of 100 to 200 meters consists of crystalline gneiss
outcrops, shelves, cliffs, and pinnacles. The coastline was
examined for a distance of some 400 kilometers and eight poten-
tial (but still very difficult) landfall and terminal areas were
identified.
Based on its proximity to Bergen, the most likely candidate
area for a terminal was the Island of Sotra. Subsequently, two
areas on the south side of Sotra were eliminated due to difficul-
ties in the approach a rock cliff rising straight up from a
depth of 200 meters. Three other potential landfalls were elim-
inated based on videotapes taken by submersible. Finally, Vinde-
ness, on the eastern side of the island, was tentatively selected
as a terminal site by officials, based in large part on the har-
bor's existing infrastructure.
The actual landfall site chosen was strictly a case of
"the lesser evil." The site is some 20 kilometers north of the
terminal site on a small island northwest of Sotra. The route to
the terminal site involves eleven inter-island crossings, onshore
trenching, and three tunnels (the longest of which is 700 meters).
The subsea profile of this landfall indicated that it was the most
acceptable, though still difficult, option. A 1.3 kilometer
boulder zone in 60 meters of water needs to be blasted and the
gullies filled with crushed rock. In areas where gravel dumping
is impractical to fill span zones, the mechanical devices illus-
trated in Figure 2 will be employed to support the pipe.
One additional site, an area designated by the local gov-
ernment as a recreation area, has been chosen as an alternative
landfall site.
The study concluded that a pipeline across the Norwegian
trench is feasible. However, results suggested that landfall
problems were as significant as crossing the trench in deter-
mining the feasibility of constructing the line. Tests have also
proved that deepwater repairs are feasible, a vital consideration
in establishing the security and feasibility of the project.
However, many Norwegian officials speculate that finds to date
from Statfjord alone will not justify the cost of constructing
the Statfjord to Sotra pipeline and place their hopes on a major
find in the "Golden Block." Other officials note, however, that
even if it proves economically inadvisable, the pipeline proposal
may go through for political reasons.
40
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mmabk jack
pipe
Source: NERBC, 1978.
FIGURE 2, MECHANICAL PIPE SUPPORTS FOR SPAN AREAS,
41
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SECTION 4
PIPELINE TRENCHING AND BURIAL
Like so much of offshore technology, the notion of sub-
marine pipeline trenching and burial comes from onshore experi-
ence, where pipelines were buried to protect them from a variety
of obvious land-based risks. Offshore, however, the risk is
vastly less. Pipelines are trenched, and subsequently buried by
either natural or artificial processes, to ensure the stability
of the line against bottom currents and the safety of the line
against bottom fishing equipment and dragging ship anchors.
Until recently, both governments and oil companies have
accepted this operational theory. But as pipeline construction
moved out of the relatively calm, shallow waters and sandy bot-
tom of the Gulf of Mexico to the harsh climate, deep water, and
alternating soft sediments and hard clays of the North Sea,
developers have begun to question the accepted wisdom of trench-
ing. It is a complex issue, involving the limits of deepwater
technology, the nature of the deepwater environment, and the con-
flicting needs of users of the seabottom.
RECENT PRACTICES AND EXISTING REGULATIONS
All but one of the major pipelines in the North Sea have
been trenched and buried or are in the process of being buried.
Despite the fact that no rigid requirements have been set by
either the United Kingdom or Norway, the developers have felt
heavily pressured to bury pipelines. Occidental's pipeline to
Flotta is trenched along its entire length to a depth of two
meters. Gravel beds fill areas where unacceptable spans were
detected, and concrete saddles have been installed to cover
hydrocouples and existing or potential tie-in areas.69 Total
Oil Marine followed similar procedures for its two gas lines
from the Frigg Field, as have BP and others.70
Interview with Occidental officials.
70Interview with Total Oil Marine officials.
42
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The requirement for trenching is an operating regulation,
rather than law, in both the U.K. and Norway. For example, Nor-
wegian law calls for protection of submarine pipelines "through
trenching or other means."71 The Norwegian Petroleum Directorate
has issued interim regulations which call for three meter burial
of pipelines within two miles of a platform, five miles of a
multi-platform complex, or at the shore approach out to a water
depth of 50 meters. Elsewhere along the pipeline, trenching
must be to a depth of one meter. In point of fact, however,
these regulations were developed for the Ekofisk pipeline, and
Norwegian officials suggest that, since'they expect few pipe-
lines, they will review each case individually and issue regu-
lations appropriate to each case. '2
BURYING THE EKOFISK-EMDEN GAS LINE
Norpipe has experienced a number of burial problems with
their pipelines from the Ekofisk complex. For gas lines to
Emden, a total of twelve trenching barges were contracted to
trench the line. An average of 3.2 passes were required, with a
maximum of 9 passes in one area of hard clay, to trench the line
to required depths. Underwater videotape inspection revealed
that natural backfilling had not occurred at the time of start-up
along sections of the pipeline in the Danish sector of the con-
tinental shelf. As a condition of start-up, Danish authorities
requested that Norpipe backfill the entire Danish section of the
line to a depth of"50 centimeters (cm) by July 1, 1980. Because
of the absence of available systems for deepwater artificial
burial, Norpipe selected two companies, the Aker-Volker Group
and Stolt-Nielson Rederi, to develop proposals for burying the
pipeline. Though neither company had operational systems avail-
able, the proposals are likely to involve massive modifications
to dredging and stone hopper vessels which will be designed to
drop crushed stone over the exposed pipe. Figure 3 illustrates
this general concept.
Norpipe currently estimates that something on the order of
200-400,000 tons of crushed stone will be required to provide
50 cm of cover for the 50 kilometers (km) that the pipeline
crosses the Danish shelf, at an estimated cost of $90 million.
71Ministry of Petroleum and Energy, Legislation Concerning the
Norwegian Continental Shelf, October 1977, p.255.
?2Interview with Norwegian Petroleum Directorate officials.
3Interview with Norpipe officials.
43
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PROTECTION OF PIPE:
Coatings
Cathodic protection
Depth of cover
Source: Det Norske Veritas, Safety, Life, Property,(1978). p.11.
FIGURE 3, ARTIFICIAL BURIAL USING CRUSHED STONE,
44
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THE VALIDITY OF THE SAFETY/STABILITY RATIONALE
When the Shell-Esso Group began plans for their massive
gas line (FLAGS) from the Brent field to St. Fergus, they initi-
ated a number of studies to test the validity in deep water of
the notion that trenching and burial effectively protects a
pipeline from damage from trawl doors and anchors and ensures
stability. The results of these studies are discussed in NERBC's
Tech Update series. To summarize, however, Shell-Esso found
that:
there is insufficient bottom current in deep water
areas to provide sediment transport and resulting
natural burial;
trenches cut in the soft sediments which characterize
deep water areas tend to have a wide profile rather
than a narrow, well-defined profile;
current technology in concrete coating and steel rein-
forcing on pipelines is such that impacts from trawl
doors will cause no more than a scratch (16 mm deep)
on the pipeline coating and damage to the pipe will not
occur;
concrete coating does a more reliable job of weighting
the pipe for stability than trenching;
trawl doors sliding into a shallow or wide profile
trench have more chance of being damaged than if the
pipe had been laid directly on the sea bottom; and
burial will not protect a pipeline from dragging rig
or tanker anchors.74
In addition, consultations with fishermen revealed that
artificial burial through the use of crushed stone caused more
problems than it solved. According to the fishermen, the stone
gets gathered into the cod end of their nets, wears a hole,
releases both the fish and the stone, leaving the fishermen with
no catch, damaged gear, and nowhere to go for compensation. /;>
Others involved in pipeline construction in the North Sea
have watched the Shell-Esso studies with interest. The United
Kingdom Department of Energy was sufficiently impressed by the
results to let the FLAGS line be built substantially untrenched,
74Interview with Shell Expro and Esso Expro officials.
75Interview with official of the Scottish Fishing Vessel
Owners Association.
45
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except for sections near shore. There is also some indication
that the Statoil/Mobil Group, Norway's state-controlled oil com-
pany, will endorse the Shell-Esso findings and will apply them
to the proposed Statfjord-Sotra pipeline.76 On the other hand,
BP contests the fundamental contention that there is little deep-
water current and sediment transport, citing their own studies
that water near the bottom in deep areas had too much sediment to
be used for well injection.77
Det Norske Veritas (DNV), the classification company most
involved in safety studies and risk analyses, has also closely
examined the Shell-Esso studies and has decided that existing
pipeline coating and reinforcing technology is sufficient to
protect pipe from any trawl damage and that trenching has an
only marginal effect on pipeline stability. DNV reasons that:
(1) vessels will never, even in cases of equipment failure,
anchor in mid-sea; and (2) most vessel anchors used in the North
Sea do not penetrate very deeply. Tanker or rig anchors, on the
other hand, ; penetrate very deeply and existing trenching methods
cannot trench pipelines deep enough to provide protection from
dragging rig or tanker anchors. Figure 4 illustrates this
point. DNV's conclusion is that there is no effective way to
protect against dragging rig and tanker anchors, except to route
pipelines around areas with a high likelihood of tankers or rig
traffic.78
As a consequence of both the Shell-Esso studies and their
own independent risk analyses, DNV now recommends against trench-
ing in deepwater areas to achieve safety and stability. Appar-
ently, the United Kingdom and Norway agree. The FLAGS line was
installed largely untrenched and Norwegian officials now suggest
they may drop the trenching requirement altogether for coated
and reinforced pipe with a diameter of greater than 16 inches if
the pipeline is otherwise sufficiently protected. To protect
pipe in work areas (e.g., 30-50 meters from a platform) concrete
saddles may be required.7^
Interview with Statoil officials.
Interview with BP officials.
78Interview with Det Norske officials.
79.
Interview with Norwegian Petroleum Directorate officials.
46
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Most vessels
Rigs and tankers
buried
pipe-
Source: NERBC, (1978).
FIGURE 4, ANCHOR PENETRATION,
Phillips has abundant evidence
dragging anchors are concerned, DNV's
valid. Last year a 50,000 dwt tanker
the Ekofisk-Teesside oil line 4 miles
subsequent inspection revealed a five-
was shut down for six weeks while the
repaired.80
that, at least insofar as
conclusions are largely
dragged its anchor across
off the harbor mouth. A
inch dent and the pipeline
section was removed and
80
Interview with Norpipe officials.
47
-------
These observations raise a final finding on the trenching
controversy. DNV and others are now persuaded that the major
cause of pipeline problems (such as the floating incident near
Sullom Voe and the anchor incident at Teesside) is loss of con-
crete coating from passes by jet sleds during the trenching pro-
cess. And, the deeper a pipe is trenched, the more passes are
required by the jet sleds and the more likely that damage to or
loss of concrete coating will occur. *'
It seems clear, from interviews with both Norwegian and
United Kingdom officials, oil company representatives, and the
fishermen, that there is no longer a reasonable rationale for
trenching and burial and that the theory that worked onshore
simply does not hold up in deep water. In view of this conclu-
sion, it may well be that subsequent North Sea pipelines will
not be trenched, except in high current areas where weight coat-
ing alone is insufficient to guarantee stability. In such areas
natural backfilling will, in most cases, ensure sufficient
cover.
81
Interview with Det Norske Veritas officials.
82
Work is now underway by Kvaerhar Myhren, a Norwegian firm, to
modify trenching machines which will enable them to dig deeper
with each pass. By reducing the number of passes required to
reach desired trench depths, risk of damage to pipelines and
coating may also be reduced.
48
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SECTION 5
CONSULTATION, ACCESS, AND DEBRIS; THE FISHING ISSUES
As a general rule, commercial fishermen and their represen-
tative organizations, have exerted less political influence in
Norway and the United Kingdom than have their American counter-
parts. Moreover, there is little evidence in either North Sea
country of the kind of legislative support that fishermen in the
United States have enjoyed. As a result, there is a high degree
of frustration among fishermen in their ability to influence the
government-industry offshore development decision process, simply
and succinctly explained by the head of one Scottish fishermen's
organization: "The decisions are made above our level."^
CONSULTATION
In the United Kingdom, the official vehicle for consulta-
tion is the Fisheries and Offshore Oil Consultative Group, an
organization created in 1974 (largely as a result of pressure
from fishing industry organizations) to serve as a forum for
broad term planning and coordination among oil companies, fisher-
men, and government officials. Though the organization has been
in existence for several years, and provided the impetus for
establishment of a compensation fund for damaged gear, most of
the participants seem to agree that the group does not work well.
Participants describe the Consultative Group as defensive and com-
bative, a forum for trading charges of abuse.
Still, the fishermen recognize that the Group is, at pre-
sent the only method they have for holding the oil industry and
government accountable in a public forum, in which the fishermen
are equal participants.
83IntervieW with official of the Scottish Fishing Vessel
Owners' Association.
84Interviews with oil company executives, Department of Energy
official, and representative of the fishing industry.
85Interview with official of the Scottish Fishing Vessel
Owners' Association.
49
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Presently, no such official forum exists in Norway. The
principal way in which fishermen are kept abreast of oil-related
developments is through meetings called by the Ministry of Petro-
leum and Energy about every six months.^
In point of fact, however, informal bilateral coordination
between the fishermen and the individual oil companies is the
most effective means of consultation on both sides of the North
Sea. Predictably, the results vary with the degree to which in-
dividual companies wish to cooperate. Fishermen give high marks
to BP, Shell, and Total for their efforts to consult frequently
on pipeline proposals, the route deviations they made based on
fishermen's requests, and their efforts to give prior notice for
any construction activity planned in an offshore area.87 Other
companies have been less accommodating and, if they entertain
fishermen's advice and requests, showed little evidence of taking
their requests seriously. The United Kingdom Offshore Operators'
Association (UKOOA) operates primarily at the policy level in
London and maintains no personnel in Aberdeen, the center of U.K.
offshore operations.
The United Kingdom's Submarine Pipelines Act, discussed in
Section 2, requires oil companies to apply for permission for
pipeline construction. The legislation provides specifically for
the Department of Energy to consult with fishermen's organiza-
tions before granting permission. This has generally meant meet-
ing with the Scottish Fishermen's Federation which represents the
smaller commercial operators, or the Aberdeen Fishing Federation
Ltd., which represents the larger operators.
In practice, however, the oil companies seek the advice of
these organizations privately in the pipeline pre-planning stage
before submitting a request to the Department of Energy. In ad-
dition, the U.K. Department of Agriculture and Fisheries serves
as a "go-between" in government circles to ensure that the needs
of the fishermen are considered. While this agency played a very
active role prior to passage of the Act, it is not clear to the
participants how the agency will operate now that the Act in in
force.88
Interview with representative of the Ministry of Petroleum
and Energy.
87
p Q
Interview with representative of the Scottish Fishing Vessel
Owners' Association.
t
Interviews with representatives of several oil companies.
50
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In Norway, the fishermen have gained some important con-
cessions from government. Two of four areas planned for develop-
ment north of the 62nd parallel have been dropped due to fisher-
men's opposition and many of the blocks in the areas still sched-
uled for development have been withdrawn.
Two issues predominate in discussions with those close to
the fishing interests: the de facto loss of access to fishing
areas caused by platform, wellhead, and pipeline installations,
and the damage caused by debris left on the bottom during the
construction of pipelines and the operation of rigs, platforms,
and supply vessels. Each is examined in some detail below.
LOSS OF ACCESS
Although both Norway and the U.K. have specified safety
zones around drilling and production installations^ (500 meters),
neither government has designated limitations on fishing activi-
ties along pipelines. Nevertheless, commercial trawl fishermen
feel pressured, both by circumstance and by oil companies,_not to
trawl in the vicinity of pipeline installations. This in itself
is curious, given the contention by several companies, notably
Shell and Statoil, that trawl gear cannot damage exposed coated
pipe.
In the U.K., willful and negligent damage to pipelines is a
statutory offense for which the skipper/owner of the vessel in
question is fully liable.89 And despite the fact that pipelines
in the North Sea are largely buried, they do become exposed, they
do span, they do lose their concrete coating, and they are vul-
nerable. The fishermen, though they tend to be risk-takers, are
fully aware of this. The possibility that a pipe may be vulner-
able, combined with the debris normally accompanying trenching
operations, is sufficient to make any operator cautious. The
cost of being wrong is enormous, and even if it is ruled as acci-
dental, the results of hooking a pipe, in terms of lost gear and
time, can be significant.
What it all boils down to is compensation. Damage to gear
from debris is covered by a standard procedure for compensation
in both Norway and the U.K. No such procedure exists for com-
pensating the fishermen for loss of access to fishing grounds,
whether de jure (i.e., with respect to safety zones required
by law around installations) or de facto (i.e., areas effec-
tively sterilized by existence of a pipeline).
89Interview with representatives of the Scottish Fishing Vessel
Owners' Association.
51
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Thus, if pipeline debris causes damage to, or loss of, gear,
compensation can be sought. But if a fisherman chooses not to
trawl near pipelines for fear of such damage, or of hooking a
pipeline span, no compensation is forthcoming, despite the fact
that a loss of catch occurs in both cases. In the case of deb-
ris, the loss is obvious; in the "avoidance" case, however, some
other demonstration is necessary, and this is extremely dif-
ficult.90
In the U.K., the Offshore Operators Association has de-
clared that it prefers to compensate fishermen for cutting their
gear loose if they hook a pipeline, rather than risk damage to a
pipeline. Compensation of gear is obviously cheaper. But it
also takes time and there has been no parallel offer to compen-
sate the fishermen for lost catch and lost time. Consequently,
it is understandable that the fishermen will treat large areas
around a pipeline as de facto "sterilized."91
A University of Aberdeen study, commissioned by the Bri-
tish Fishing Federation and the Scottish Fishermen's Federation,
though hampered by inconsistencies in available catch data and
the difficulty of arriving at acceptable methodologies for calcu-
lating loss, estimates that existing pipelines cause a loss of
access for fishing of between 30.9 ahd 771.8 square miles and a
corresponding estimated loss of catch of between 66 and 1650 tons
annually. The variation in estimates reflects whether one as-
sumes a 100 meter or 500 meter sterilization zone around pipe-
lines . 92
Of special concern to the fishermen is the proliferation
of trunk lines to shore and gathering lines among fields. The
latter is the source of significant current discussions among
fishing and oil interests and government policy makers. Already,
there are powerful economic arguments for linking new .fields to
existing trunk lines where excess capacity exists, or where
throughput is declining as a field ages. However, the tendency
for triangular pattern of gathering lines to be constructed
among producing areas sterilizes not only the area along the
90
Department of Political Economy and the Institute for the
Study of Sparsely Populated Areas, Research Report 1; Loss
of Access to Fishing Grounds Due to Oil and Gas Installations
in the North Sea, University of Aberdeen, March, 1978, p.2.
91Ibid, p.11.
92Ibid, p.54.
52
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pipe, but, according to the fishermen, the area of water inside
the triangular boundaries as well.^3
U.K. policy on the matter of new pipelines is unclear.
And the picture is somewhat muddied by independent pressure
groups in Scotland who want production slowed. At issue, how-
ever , is whether the U.K. will even out its production profile
to extend the life of the fields, or accentuate it with new
pipelines to offset its balance of payments problems, not whether
pipelines significantly reduce fishing access.
Another access problem of potentially greater impact in the
U.K. is development of blocks in the Moray Firth, a rich fishing
area already being developed by MESA at the Beatrice field, and
east of the Shetland Islands, where new finds have been announced
by BP and others. The fishermen point to U.S. policy on "nega-
tive nominations" and claim there are national interest values
in protecting these especially valuable areas for fishing.y4
Their point is made clearly by a fishing organization rep-
resentative, who explains: "It's a fair deal we're asking for;
we don't even want monetary compensation, if they'd just not
lease prime fishing areas. But if they do sterilize important
fishing areas, we'll expect compensation."9J
Of course, the loss of access or "sterilization"
applies just as powerfully for the fishermen to rig operations,
platform siting, pipeline junctions and sub-stations, and well-
head locations at survey work. It is this type of prevention of
access that most affects Norwegian fishermen, who do not yet have
to contend with pipelines in their waters.
9Interviews with both oil industry and fishing industry
representatives.
94Interview with Gordon A. MacKay, Institute for Sparsely
Populated Areas, University of Aberdeen.
9Interview with representative of the Scottish Fishing Vessel
Owners' Association.
53
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DEBRIS
Certainly the most emotional fishing/offshore oil issue in
the North Sea is the debris problem. The commercial fishermen
have encountered debris in areas of abandoned drill sites, along
pipelines, and in those areas of the North Sea that see heavy
service boat operation between shore-based service bases and off-
shore operations. The debris they have encountered during trawl-
ing ranges from refuse, such as oil drums and scrap metal, to
lengths of steel cable, steel superstructure, pipe turnings, and
heavy equipment which is cheaper to dump overboard than repair.
The debris issue is closely tied to the access question.
One Norwegian study cites a one-third decrease in available fish-
ing areas in the North Sea due to debris during the period from
1966 to 1971.96 Heavy pressure from the fishing industry and
recent ocean dumping legislation have reduced, but by no means
eliminated, the problem.
With respect to pipelines, there are three types of debris
that cause problems for the fishermen: (1) the exposed boulders
and heaps of heavy clay caused by trenching activities; (2) the
piles of crushed stone sometimes used by the oil companies to
cover pipelines that become exposed or are never covered natural-
ly; and (3) the debris and refuse tossed overboard by pipeline
contractors during construction.
Both Norway and the U.K. have established compensation
funds through which fishermen can recoup some or all of the cost
of replacing gear damaged by debris that cannot be identified as
belonging to a specific company. In the U.K., the UKOOA estab-
lished a compensation fund administered by the fishing associa-
tions with an initial balance of roughly $60,000. To date, ap-
proximately $120,000 has been paid out. The majority of the
claims have been by small operators, and have averaged $800 per
claim. For the most part, neither damage to vessels themselves,
nor lost catches of fishing time are covered by compensation,
although a $1500 per incident maximum "hardship" payment can be
added. The oil industry sees damage to vessels as an issue for
the insurance companies, and has so far refused to consider lost
time as an item suitable for compensation.^7
In Norway, debris damage claims are made to the government,
The state pays in any case where it is probable that gear damage
or loss is oil-related. Having paid the claim, government offi-
96
Interview with representatives of the Ministry of Petroleum
and Energy.
97
Interview with representative of the Scottish Fishing Vessel
Owners' Association.
54
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cials then track the cause of damage to the company involved,
where possible/ and require repayment. The total paid to date
is nearly $2 million. Again, though, compensation covers only
damaged or lost gear.98
Fortunately, officials in the newly-established Ministry of
Petroleum and Energy are particularly concerned about the extent
of the debris problem and debris-related claims, and will soon
propose to the Norwegian Parliament that fishermen not only be
compensated for lost gear, but also for lost fishing time and
loss of access to fishing ground, whether de jure or de
facto. 99
The Norwegian government, through the Oil Directorate, has
also been responsible for the most comprehensive debris survey
and cleanup program to date. Although diving certificates re-
quired at the completion of pipeline construction or drilling
activities indicated no significant debris in Norwegian waters,
the government recorded some 2,000 complaints from fishermen and
finally conducted an underwater study of its own and detected
substantial debris, particularly along pipeline routes and major
supply routes.1°° Consequently, the Petroleum Directorate or-
dered Norpipe and Phillips to resurvey the marine portions of the
Ekofisk to Emden gas pipeline and the Ekofisk to Teesside oil
pipeline and to identify and retrieve all debris located along
the route. Phillips and Norpipe contracted with Fred Olsen
Oceanics A/S for both visual inspection and retrieval, employing
the support vessel M/S Bergholm and the submersible vessel Pis-
ces 10. Work on the Emden gas line lasted from July 26 to Octo-
ber 7, 1977, and work on the Teesside oil line lasted from Octo-
ber 7 to December 11, when it was postponed due to bad weather.
Work was completed during the 1978 work season.101
A list of potential debris items, or targets, was prepared
from sidescan sonar recordings taken along a 100 meter wide strip
centered on the pipeline, and compared with submersible sightings
and earlier sonar readings. The targets were then classified as
98Interview with official of the Norwegian Ministry of the
Environment.
"interview with officials of the Ministry of Petroleum and
Energy.
10QEnterview with officials of the Norwegian Petroleum Directorate,
Interview with Norpipe officials.
55
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either rubbish, which was judged to be of no danger to trawl
nets, divers, or the pipe itself, or debris of obvious potential
harm. Debris targets were generally large wires or hawsers,
steel pulley blocks, large plates or pipes, anchors, heavy
equipment, rails, concrete-filled drums, wire loops, or pipe
bevel turnings. The submersible vessel photographed both types
of objects and if the target was identified as debris, it was
either lifted to the surface or marked for future recovery.102
NERBC has a detailed report, in rough draft form, of the
types of targets identified. The information is generic in na-
ture and is likely to have comparability in any OCS operation
area. During the 1977 season, the cost to Phillips and Norpipe
of resurvey and retrieval activities approached $4 million.103
Since the project was completed, Norpipe has recommended
that_a standard debris clause be included in offshore contract
specifications to prevent debris dumping during construction
work. These specifications are quoted below:
"During the work, Contractor shall not dispose
of any material into the sea or air, which can
be of danger to or interfere with other marine
activity or life. The sea floor, sea, or air
shall not be contaminated.
As soon as the work is completed, the seabed
shall, if practical, be brought back to original
condition and Contractor shall clear the premises
of debris, waste material, and equipment remaining
from the work. Nothing shall be left which can
interfere with fishing, marine, or other activity.
All material belonging to Company shall be loaded
for storage or to a location as directed by the
Company Representative.
Contractor shall be responsible for the recovery
of any debris it dumps and shall bear the cost of
such recovery operations.104
Norpipe, Debris Survey Scope of Work, 1978, pp.2-11.
Interview with Norpipe officials.
104
Norpipe, Debris Clause.
56
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APPENDIX
The following is an annotated bibliography of reports
gathered from the sources interviewed while preparing this
document. Each entry contains a bibliographic citation and a
brief description of the information contained in each docu-
ment. Entries are organized by country/ and then by organiza-
tion providing the information.
ENGLAND
BRITISH GAS CORPORATION
The following are documents prepared by British Gas
Corporation:
A Guide to Noise and Its Assessment, 1974. 10pp.
Methods of measuring noise with footnote on compressor stations.
A Guide to Noise Legislation/ 1974. 9pp.
Historical background and implications of noise legislation on
gas industry.
Environmental Impact Analysis in the British Gas Industry;
Parts I and II.Prepared for the Symposium on the Gas
Industry and Environment, Minsk/ USSR, June 1977.
General considerations and practical application of environmental
impact analysis to gas industry facilities.
Gas Plants and People. Prepared for Symposium of the
Institute of Gas Engineers, November. 1976. 25pp.
Environmental implications of gas pipeline and facility construc-
tion and operation.
Onshore Development of the Frigg Gasfield/ July 1974.24pp.
Description of St. Fergus terminal, including plans3 requirements3
pipeline route map and pictures.
Onshore Requirements for Oil and Gas Reception. Prepared
for Offshore Oil - Onshore Industry Conference, Liverpool,
November 1974. 31pp.
Comprehensive look at onshore requirements for offshore oil and gas
receiving terminals.
57
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Pollution Control; A Summary of the Control of Pollution
Act of 1974, December 1977. 12pp.
Interpretation of the 1974 Act for use by the gas -industry.
To See or Not To See, undated. 15pp.
Description of facility design considerations to minimize visual
impacts.
Additional information provided by British Gas:
Institution of Gas Engineers. Recommendations on Trans-
mission and Distribution Practice: Steel pipelines for
high pressure gas transmission, Editions 1 and 2,19777
141 pp.
Description of design* planning* construction and materials
standards for high pressure gas pipelines.
Ministry of the Environment. Planning Permission: A
Guide for Industry, 1978. 30pp.
Guide to the British development permits process.
Photos - variety of black and white and color photos of
terminals, compression stations, landfall con-
struction and restoration.
OCCIDENTAL INTERNATIONAL OIL COMPANY
The following documents were prepared and provided by
Occidental:
Occidental North Sea Consortium Information Sheet, June
1978. 16pp. ~~~
Update on Occidental-related offshore and onshore activities.
The Flotta Story; Development of an Oil Handling
Terminal, July 1978. 24pp."
Description of how Flotta was chosen and built. Includes maps.
The Search for North Sea Oil, 1977. 25pp.
Outline of history, process* facilities and people involved in
offshore exploration and development. Includes photos.
58
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SHELL/ESSO GROUP
The following were provided by the Shell/Esso Group:
Broussard, D. L., et al. "FLAGS Gasline - Design for
Seabed Safety and Stability". In European Offshore Pe-
troleum Conference and Exhibition, London, October 1978.
Technical Report on FLAGS gasline routing and results of trenching
experiments.
Dept. of Energy (U.K.). Landfall Construction Permit
Conditions, issued to Shell/Esso, April 1976. 2pp.
Conditions guiding Brent gasline landfall construction at
St. Fergus3 Scotland*
Shell/Esso Group. FLAGS Gasline; Seabed Safety and
Stability, presentation to Dept. of Energy, October
1977. unnumbered.
Summary of results of trenching experiments and routing decisions.
Includes map of route alternatives resulting from discussions with
fishing industry representatives.
Sample report - prepared by Dr. William Ritchie (under
contract to Shell/Esso Group).
Results of periodic survey of restoration success at St. Fergus
landfall.
BRITISH PETROLEUM COMPANY, LIMITED
BP provided the following report:
Larminie, F. G. "The Onshore Handling of Oil". In
Petroleum and the Continental Shelf of Northwest Europe.
edited by H. A. Cole;John Wiley& Sons, New York,
1975. 2:39-47.
Description of main components of land pipeline systems, including
pipelines, gas separation units3 storage and loading terminals.
DEPARTMENT OF ENERGY (U. K.) - H. M. PIPELINES INSPECTOR
The Inspector's office prepared and provided the fol-
lowing document:
Application for a Submarine Pipeline Works Authorization
(Draft), August 19/v. app.
59
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Sample of "guidance notes1' produced by DOE (U.K.) to aid industry
in complying with the Petroleum and Submarine Pipelines Act of
1975.
SCOTLAND
TOTAL OIL MARINE
The following documents were prepared and provided by
Total:
Frigg; Gas from the North Sea, 1978. unnumbered.
Review of Frigg Gasfield development. Printed for formal
opening of St. Fergus terminal.
Total Information - Number 71, 1977. unnumbered.
Review of entire Frigg operation.
Photo - aerial of St. Fergus terminal.
SCOTTISH DEVELOPMENT DEPARTMENT
All the following documents were prepared and provided
by the Department:
"Land and Industry - Offshore and Onshore Physical Con-
straints for Pipeline Landfalls." Oil and Gas Forward
Planning Discussion Paper No. 302, October 1975. 17pp.
Examination of physical constraints at various potential pipe-
line landfall sites.
National Planning Guideline Series, 1977. unnumbered.
Guidelines for planners considering large industrial sites and
rural land use issues.
North Sea Information Sheet, Nov. 1977. 13pp. and
North Sea Information Sheet, March 1978. 16pp.
Quarterly summaries of OCS-related developments. Includes maps.
Physical Criteria for Evaluating Pipeline Landfalls.
1978. ip~:
List of criteria for determining physical suitability of alternative
landfall sites.
60
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Planning Advice Note No. 13 - Planning and Geology,
Dec. 1975. 14pp.
Discussion of geologic considerations in planning.
Planning Advice Note No. 17 - High Pressure Methane Gas
Pipelines, June 1977.7pp.
Legal and technical requirements and planning considerations for
local authorities on land pipelines.
GRAMPIAN REGIONAL COUNCIL
The Council's Department of Physical Planning prepared
and provided the following documents:
Contingency Plan for Petrochemical Industries, July 1978
105 pp.
Siting strategies for petrochemical plants.
Pipelines, May 1978. 3pp.
Legal and engineering requirements for pipeline rights-of-way.
Onshore Pipeline Corridor Feasibility Report, July 1976.
8 pp.
Discussion of the implications of the corridor concept.
THE SCOTTISH COUNCIL
The Scottish Council - Development and Industry prepared
the following report:
United Kingdom Oil & Gas - Situation Review, February,
1978, 28pp."~~
Overview of the state of North Sea oil and gas development as of
December, 1977.
UNIVERSITY OF ABERDEEN
Three departments within the University were contacted
and provided the following information:
Department of Geography - Project Appraisal for Development
Control Research Unit (PADC).
Environmental Impacts of Selected Linear Developments
(DRAFT).PADC 17F,undated.43pp.
Preliminary look at environmental impacts of developments like
pipelines.
61
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Past and Current Work (of PADC), undated. 9pp.
Prospectus on work in environmental impact assessment. Includes
publications list.
Planning Information Sheet: Gas Terminals. PADC 12D (iv),
undated.18pp.
Review of gas terminal characteristics., requirements and impacts.
Planning Information Sheet: Oil Refineries. PADC 12D
(ii), undated. 10pp.
Characteristics* requirements3 and impacts of oil refineries.
Research on Impact Analysis and Environmental Planning,
undated.9pp.
Outline of future research programs in environmental assessment.
Department of Political Economy - Institute for the Study of
Sparsely Populated Areas.
Department of Political Economy. Loss of Access to Fish-
ing Grounds Due to Oil and Gas Installations in the North
Sea.Commissioned by the British Fishing Federation and
Scottish Fisherman's Federation, 1978. 152pp.
Detailed study on effects of platforms and pipelines on access to
commercial fishing grounds.
Department of Zoology.
Sullom Voe Environmental Advisory Group. Oil Terminal at
Sullom Voe Environmental Impact Assessment, May 1976.
133pp. ~~~ ~
Report of interdisciplinary group assessing construction impacts
from Sullom Voe oil terminal.
Text of Presentation to Nature Conservancy Council
July 1978.
Outlines how the Shetland Oil Terminal Environmental Advisory
Group (SOTEAG) - designed to monitor the terminal's operation -
works. Includes list of members and monitoring projects.
NORWAY
U. S. EMBASSY
The Embassy provided the following documents:
Bergen Bank. Petroleum Activities in Norway, June 1978.
38 pp.
62
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Introduction to petroleum related activity in Norway including
structure of state controlled development companies.
Economic Trends Report - Norway, June 1978. 9pp.
Brief examination of current Norwegian economic problems,, some
related to oil-related development/investment issues.
MINISTRY OF PETROLEUM AND ENERGY (formerly Industry and Crafts)
The Ministry prepared the following basic documents
regarding Norwegian offshore oil development:
Factsheet: The Norwegian Continental Shelf, April 1978.
22 pp.
Status report on Norwegian OCS activities.
Legislation Concerning the Norwegian Continental Shelf,
October 1977. 273 pp.
Compilation of all Norwegian laws governing OCS activities,
The following are Parliamentary Reports which the Ministry
prepared for the government on various aspects of Norwegian OCS
development:
No. 33 - Annual Report of Statoil for 1976-1977 and
Statoil Development Plan for 1978,1977-78 .42pp.
No. 92 - Landing of Petroleum from Valhall and Hod Fields,
1976-77.22pp.
No. 91 - Petroleum Exploration North of 62 N, 1975-76.
128 pp.
No. 90 - The Development and Landing of Petroleum from
Statfjord Field and a Gas Trunk Line, 1975-76.46 pp.
No. 77 - Landing of Gas from the Frigg Area, 1973-74.
37 pp.
No. 51 - Landing of Petroleum from the Ekofisk Area,
1972-73.68 pp.~~
The following Parliamentary Propositions were also
provided:
No. 72 - Announcement and allocation of blocks on the
continental shelf, and drilling for petroleum under the
direction of the state, 1977-78.15 pp.
63
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No. 114 - Exercise of Statoil's option to participate in
the development of a deposit in the Statfjord Field,
1974-75.16 pp.
NORWEGIAN PETROLEUM DIRECTORATE (NPD)
The Directorate provided a complete Publications List of
all NPD publications and maps - in English.
The Directorate also prepared and provided the following
English translations of Norwegian offshore guidelines and
regulations:
Guidelines for the inspection of primary and secondary
structures of production and shipment installations and
underwater pipeline systems, 1978. 17 pp.
Provisional Regulations relating to worker protection and
working environment, etc., in connection with exploration
of submarine petroleum resources, 1971T15 pp.
Regulations for cranes on production installations/ 1977.
20 pp.
Regulations for drilling for petroleum in Norwegian
internal waters, territorial waters, and on the Contin-
ental SheTF:2nd Edition, 1977.37 pp.
Regulation for Production and Auxiliary Systems on
Production Installations, etc./ 1978. 37 pp.
Regulations for production/ etc./ of submarine petroleum
resources, 1977. 34 pp.
Regulations for the structural design of fixed structures
on the Norwegian Continental Shelf, 1977.78 pp.
The following documents were provided - in Norwegian
only:
General Guidelines for Inspection and Clearing of
Abandoned Drillsites/ December 1977.2 pp.
Oljedirectoratet/ arsberetning 1977/ 1977. 81 pp.
Annual report for 1977 s includes map.
Trenching and Burial of Pipelines on the Norwegian PCS,
March 1978.15 pp.
Regulations, trenching techniques, burial methods and seafloor
conditions on the Norwegian Shelf.
64
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PET NORSKE VERITAS (DNV)
The following technical documents were prepared by Det
Norske Veritas:
Analysis and Management of a Pipeline Safety Information
System, December 1977.8 pp.
Summary of University of Oklahoma analysis of gas pipeline system
safety.
Det Norske Veritas, February 1978. 20 pp.
Prospectus on company activities including involvement in
Norwegian OCS oil and gas activities.
Det Norske Veritas Annual Report 1977, February 1978.40pp.
Detailed information on scope of company activities.
Method for Performing Risk Assessment of Submarine
Pipelines, March 1978.7 pp."~~
Brief description of DNV's methods for assessing risks to pipelines.
Research and Development in Det Norske Veritas, May 1978.
12 pp.
Outline of DNV research in progress.
Rules for the Design/ Construction and Inspection of Sub-
marine Pipelines and Pipeline Risers, 1976.73 pp.
Detailed rules for safety regulation of marine pipelines.
Safety; Life, Environment, Property, April 1978. 16 pp.
Prospectus on Risk and Reliability Analyses.
Statistical Evaluation of Failures to Cross Country Oil
Pipelines in Western Europe, March 1978.6 pp.
Information on incidence and causes of pipeline failures from
1966 - 1976.
Veritas, February 1978. 91: 12 and 28.
Veritas, November 1977. 90: 27-30.
quarterly journal describing various Det Norske Veritas activities.
65
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DNV also provided 3 DNV single sheets and a Norwegian
journal containing additional offshore pipeline related
information:
Loose sheets:
DNV-1: Factors affecting pipeline dimensions
DNV-2: Flow chart in offshore pipelaying
DNV-3: Description of pipeline failure events in
Gulf of Mexico.
Norwegian Maritime Research, 1978. 6(1).
NORPIPE
Norpipe provided the following information:
Loken, P. A., "Ekofisk-Emden". Norsk Oljerevy, March 1977.
4 pp.
Reprint of magazine article describing -tike Ekofisk to Emden
pipeline. (In Norwegian)
Massey, P. S., "Ekofisk-Teesside line to operate
continuously." Oil and Gas Journal, February 1975.
p. 85-89.
Description of Ekofisk to Teesside natural gas pipeline.
Norpipe; Annual Report and Accounts 1977. 28 pp.
Detailed information on scope of company activities.
Norpipe Brochure and Factsheet, undated.
Brief description of Norpipe offshore activities.
Shaub, D. P., "Line from Ekofisk to Emden nearly
completed." Oil and Gas Journal, January 1976. p.78-86*
Description of final stages of construction of Ekofisk to Emden
pipeline.
MISCELLANEOUS PERIODICALS AND ARTICLES
Daniels, M. and J.C. Swank, "Northern North Sea Pipelines -
The Brent System." Offshore Technology Conference. 1976
Preprint #2601: 803-817:
Noroil, July 1978. 6(7).
Northern Offshore, June 1978. 7(6).
66
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Scandanavian Oil-Gas Magazine, 1978. 6(5/6).
Walker, D.B.L., "A Technical Review of the Forties Field
Submarine Pipeline." Offshore Technology Conference, 1976
Preprint #2603: 816-826.
67
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
i. REPORT NO.
EPA-600/7-80-023
3. RECIPIENT'S ACCESSION NO.
4. TITLE AMD SUBTITLE
NORTH SEA PIPELINES: A SURVEY OF TECHNOLOGY,
REGULATION AND USE CONFLICTS IN OIL AND GAS PIPELINE
OPERATION
5. REPORT DATE
February 1980 issuing date_
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
William E. Nothdurft
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Nev England River Basins Commission
53 State Street
Boston, Massachusetts 02109
10. PROGRAM ELEMENT NO,
INE 826
11. CONTRACT/GRANT NO.
IAG No. T8-D-X0063
12. SPONSORING AGENCY NAME AND ADDRESS
Industrial Environmental Research Laboratory
Office of Research and Development
U.S. Environmental Protection Agency
Cincinnati, Ohio 45268
13. TYPE OF REPORT AND PERIOD COVERED
Final 8/78 - 12/78
14. SPONSORING AGENCY CODE
EPA/600/12
15. SUPPLEMENTARY NOTES
This project was undertaken to provide information on North Sea offshore pipelines
and the processes used in route selection decision-making. It is designed to be
used by persons involved in offshore oil and gas pipeline planning, including
pipeline corridors and landfalls. The bulk of the information for the report comes
from interviews with industry, government and private individuals associated with
pipeline decision-making in Norway, England and Scotland. Supplemental information
is derived from written sources.
A brief overview of offshore activity in both the United Kingdom and Norwegian
sectors of the North Sea is presented, with special emphasis on the transportation
systems established or proposed for the major commercial fields. The report then
focuses on the specific issues arising from the installation and operation of each
of these transportation systems. These issues include: regulations affecting
pipeline placement, criteria for route selection, pipeline trenching and burial
and conflicts with the fishing industry in the North Sea. '
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS |c. COSATt Field/Group
Pipelines
Oils
Natural Gas
Continental Shelves
North Sea Pipelines
Route Selection Criteria
Trenching & Burial
Fishing Industry Conflic
:s
18. DISTRIBUTION STATEMENT
RELEASE TO PUBLIC
19. SECURITY CLASS (This Report)
UNCLASSIFIED
21. NO. OF PAGES
78
20. SECURITY CLASS (Thispage)
UNCLASSIFIED
22. PRICE
EPA Form 2220-1 (9-73)
68
ft U.S. GOVERNMENT PRINTING OFFICE: 1960-657-146/5575
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