NORTH SEA GAS: DEVELOPMENT OPTIONS

• Document Type: CREST
• Collection: General CIA Records
• Document Number (FOIA) /ESDN (CREST): CIA-RDP83B00851R000200040005-6
• Release Decision: RIPPUB
• Original Classification: S
• Document Page Count: 17
• Document Creation Date: December 19, 2016
• Document Release Date: February 20, 2007
• Sequence Number: 5
• Publication Date: September 1, 1982
• Content Type: REPORT

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Directorate of Secret
Intelligence
North Sea Gas:
Development Options
Secret
GI 82-10178
September 1982
Copy ? 409
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Directorate of Secret
Intelligence
North Sea Gas:
Development Options
This assessment was prepared b
Office of Global Issues. Comments and queries are
welcome and may be directed to the Chief Energy
Issues Branch, OGI,
Secret
GI 82-10178
September 1982
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North Sea Gas:
Development Options
D
Key Judgments Exploratory drilling during the last several years has revealed huge gas
Information available reserves in the North Sea-particularly in the Norwegian sector-which
as of 25 August 1982 could provide sizable additional gas supplies to the European continent.
was used in this report.
Given long leadtimes, technical problems, and political constraints, howev-
er, these supplies are unlikely to come on stream before the early 1990s.
Continental gas import requirements are expected to increase by about 1.2-
1.3 million barrels per day of oil equivalent in the 1990s as demand grows
and production from older fields declines. Under favorable circumstances,
North Sea and Dutch gas could meet about 80 percent of these require-
ments and forestall further increases in purchases from the Soviet Union.
Multinational cooperation will be critical in bringing sizable new volumes
of North Sea gas to the Continent by the early 1990s. Projects to boost
North Sea gas exports will require enormous capital investments-$15-20
billion may be required to develop Norway's Troll gasfield alone-and will
have to compete with other North Sea oil and gas projects for a share of
the approximately $100 billion to be spent during the next decade. Interest
rate subsidies similar to those offered for the construction of the Soviet
pipeline could substantially speed development of North Sea gas reserves;
an interest rate subsidy of about 2 percentage points could cut 15 percent
from total investment costs.
Cooperative agreements to transport gas to the marketplace will be equally
important. A gas swap agreement, for example, would involve increased
Norwegian gas deliveries to the United Kingdom in exchange for delivery
of equal volumes of British gas to the European continent. This could save
$1-2 billion in facilities investments and shorten leadtimes by two to three
years. Similarly, Dutch participation in a coordinated gas marketing
strategy could vastly simplify Norway's efforts to increase future gas sales.
Although the commercial advantages of such arrangements are sizable,
numerous political obstacles must still be overcome, including Norwegian
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GI 82-10178
September 1982
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reluctance to become overly dependent on hydrocarbon development.
Other critical factors determining the timing and size of new North Sea
projects include:
? Tax policies. The current UK tax regime is a serious deterrent to the de-
velopment of small fields. Norway's petroleum taxes are also high, and
development has been slowed further by short drilling seasons and
generally cautious government policies.
? Market prospects. An unprecedented decline in West European gas
consumption during the last two years has clouded the outlook for the fu-
ture size of the European gas market. Present uncertainties could cause
North Sea producers to hesitate before launching new projects, especially
in view of the possibility of being undercut by cheaper Soviet gas.
? Revenue needs of producing countries. If the budget crisis in the
Netherlands worsens, pressures to increase gas sales will increase.
Similarly, Norway may be inclined to speed gas development because of
lowered expectations of future oil revenues
Without subsidies, the price of Norwegian gas is likely to be about 15
percent higher than the price of Soviet gas. Hence, the market share for
North Sea gas could be constrained by limited European willingness to pay
a premium for long-term security of supply.
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Projected Expenditures for North Sea Oil and Gas Development
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North Sea Gas:
Development Option
European Gas Needs
An unexpected decline in West European natural gas
consumption in recent years has reshaped the strate-
gies of players in the European gas market. North Sea
producers, seeing gas demand and prices of competing
fuels rising more slowly than previously expected, are
no aking more
cautious appraisals of the profitability of expensive
gas development projects. European gas buyers have
political decisions necessary to bring about this com-
bination of events would require a reversal of existing
policies and a sharp acceleration of North Sea devel-
opment.)
For the 1990s, however, we project that West Europe-
an countries will have to line up new supplies of 1.2- 25X
1.3 million b/doe. North Sea gas could sup 1 the
bulk of this increment. with Norway alone 25
sharply reduced purchases of Dutch gas, stepped back
from participation in Nigeria's Bonny liquefied natu-
ral gas (LNG) project, and trimmed proposed imports
of Soviet gas from Siberia. Uncertainties about the
future may lead decisionmakers on both sides to stall
new commitments for development of North Sea gas.
Because of long leadtimes in developing these proj-
ects, doing so would strengthen Soviet leverage to
increase gas sales in the 1990s.
We expect the falloff in West European gas consump-
tion to end this year and demand to revive as econom-
ic recovery begins.' We estimate that demand for gas
in Western Europe will increase from 3.6 million
barrels per day of oil equivalent (b/doe) in 1980 to
about 4.1 million b/doe in 1990 and to 4.5-5.0 million
b/doe by the year 2000. Provided some new deliveries
of Soviet gas begin by the late 1980s, most West
European countries expect to meet projected demand
through 1990 from domestic production and imports
they have already lined up.
In the 1980s European gas buyers expect sizable new
supplies to come from Algeria and the Soviet Union,
while deliveries of North Sea gas will increase only
slightly under current plans. If the West Europeans
were to forgo increases in Soviet gas deliveries be-
cause of sanctions or unforeseen political events, they
technically could still balance supply and demand
through the decade. However, the economic and
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additional to 00 b/doe. Dutch gas
exports can also play a role in filling Western Eu-
rope's natural gas requirements but will do so only if
current policies change. By supplying additional gas
in the late 1980s and early 1990s-before additional
Norwegian gas becomes available-the Dutch might
enable some countries, notably Belgium, to avoid
purchasing Soviet gas.
Political Factors
Political decisions made in Oslo, The Hague, and
other European capitals during the next year or two
will heavily influence the pace of European gas
development. In our view, if differences in petroleum
taxation and pricing policies among Norway, the
United Kingdom, and the Netherlands can be recon-
ciled, cooperative agreements for gas development
could be achieved that would yield sizable economic
and security benefits for Europe. Budget pressures on
the governments of these countries will probably
increase the incentives for them to reach agreement.
The Netherlands's large gas production capacity is
the key to European security of supply both now and
in the future. Dutch gas policy has long been torn
between keeping Groningen gas as a reserve for future
domestic use and increasing gas sales to finance new
social programs. Since 1980 the official Hague policy
has been aimed at restricting gas production and
conserving reserves by:
? Linking prices more closely to those of competing
fuels, such as residual fuel oil, to promote gas
conservation.
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During the past 10 years, petroleum revenues have
come to play a central role in government budgets of
the Netherlands, the United Kingdom, and Norway.
Recently, those governments have discovered that the
influx of petroleum revenues can be a mixed blessing;
government incomes have proved vulnerable to the
volatile fluctuations of energy prices.
In the Netherlands, government earnings from gas
sales accounted for 17 percent of total revenues in
1981. Moreover, total public-sector expenditures
amounted to two-thirds of national income. The
sharp drop in gas sales in recent years has disrupted
budget plans and pushed government deficits to rec-
ord levels. This year's deficit, which is projected to
exceed $7 billion, should increase pressures for a
reevaluation of gas sales policies.
The United Kingdom, with the highest petroleum
taxes in the North Sea, claimed about half of the $24
billion earned from oil and gas production in 1981.
Although petroleum revenues were less than had been
projected, they accounted for about 9 percent of
government revenues. The marginal tax rate for oil
producers in the British sector of the North Sea
exceeds 90 percent; the average tax rate is 85 percent.
Oil company officials claim that these taxes have
deterred development of numerous small oil and gas
fields in Britain's offshore waters.
Norway's central government earned $4.9 billion
from taxes on oil and gas production in 1981-
roughly 27 percent of total revenues. Norway's aver-
age tax rates are slightly less than British taxes.
Declining oil prices, increased development costs (tax
deductible), and lowered production forecasts have
combined to reduce sharply Oslo's projected petro-
leum tax revenues. In May 1981, the Labor govern-
ment forecast petroleum tax earnings of about $28
billion for the 1982-85 period. The estimate has since
been revised downward three times, and now stands
at about $10 billion. Less-than-expected oil revenues,
coupled with a growing public appetite for petroleum
earnings, may give the current government more
leverage to accelerate gas development.
? Phasing out gas for power generation and other
nonpremium uses.
? Meeting present export contracts but allowing no
new export sales.
? Promoting coal gasification and conversions of pow-
er plants to coall
Under current contracts, foreign customers of
Gasunie-the state gas company-may purchase
from 580,000 to 1.1 million b/doe of gas annually.
Because the Dutch allow customers to take less than
the maximum amounts contracted, Gasunie has borne
the brunt of the recent drop in European gas con-
sumption
Dutch gas sales dropped by 6 percent in 1980 and by
another 8 percent in 1981. Total gas sales in first-
quarter 1982 were 9 percent below levels a year
earlier. The sharp drop in gas sales has increased
government deficits and prompted a reexamination of
Dutch gas policies
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Norway has traditionally held a "go-slow" attitude
toward petroleum development and has moderated the
pace of activities with a number of restrictive policies.
The new conservative government has recently re-
laxed some of these policies but is still concerned that
rapid development would have negative effects on the
Norwegian economy. In addition, Oslo recently indi-
cated its sensitivity to outside pressures to accelerate
development. Norwegian Energy Minister Hvedding
told the press that he resented "arm twisting" by the
United States to have Norway deliver more gas to
market in the 1980s than it considers feasible
Nonetheless, Norwegian Government officials are op-
timistic about gas exports in the 1990s. Oslo has
already taken some measures to facilitate develop-
ment by:
? Announcing a willingness to adopt a less hawkish
attitude in future gas price negotiations.
? Relaxing some restrictions on the length of the
drilling season and allowing foreign companies to
operate concessions north of the 62nd parallel.
? Declaring that the 660,000-b/doe-production ceil-
ing for oil and gas could be reconsidered.
? Expressing a desire to keep the Norwegian conti-
nental shelf fully open for international competition
and to limit the role of the state oil companies
The United Kingdom will probably not be a net
exporter of natural gas in the foreseeable future but
could be instrumental in a gas swap with Norway.
Consequently, development of British gasfields in the
Table 1 Number of wells
North Sea Drilling Activity a
Total
60
43
58
76
101
United Kingdom 32
19
26
32
49
Norway
9
8
16
21
20
Netherlands
10
10
15
13
24
Denmark
0
0
1
2
2
Ireland
8
5
0
6
2
southern part of the North Sea could affect the timing
of new gas deliveries to the Continent. Oil companies
have not launched any major field development proj-
ects in the United Kingdom in the last two years
because they claim taxes are too high, but exploratory
drilling has, nonetheless, remained at high levels
(table 1). London's decision to end the monopsonistic
purchasing power previously granted to the British
Gas Corporation will probably raise gas prices for new
roiects in the UK sector and encourage development.
London is
considering making some changes in tax policies to
stimulate development. Together, these moves could
encourage development of the smaller gasfields and
complement efforts to arrange a gas swap by increas-
ing the amount of gas available for transport to the
Continent from nearby southern gasfields
Key North Sea Projects 25X1
Gas projects already under way in the North Sea will
link several new fields to the Continent in the 1980s,
but only modest increases in gas deliveries are expect-
ed. Norway currently exports almost 300,000 b/doe
of gas to continental Europe via a pipeline from the
Ekofisk field to Emden, West Germany, and about
280,000 b/doe to the United Kingdom via the Frigg
pipeline (see map). Norway's Statpipe system, which
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North Sea: Natural Gas Systems
Greenland
(Denmark) (
o Major natural gasfield
Major natural gas pipelines
Existing
? ? ? ? ? Planned
-- Under consideration
0 400
Kilometers
Norwegian
Statfjord0.0 Norway I
"- "dal;X.rSto v` j I
Steipner . t , ..
:I r
Ekofisk6l /" I t.1,/
North\\ _Gorm 'Denmark a
Kingdom r d \t ~.., ~r
Neth_ West East
Z Germany f Germany Baanaar,,aprasantatianis
not o.ea my authoritative.
will connect Statfjord, Heimdal, and other fields to
the Ekofisk-Emden pipeline, is expected to be com-
pleted by 1986 but will do little more than compen-
sate for declines in gas production from Ekofisk. To
increase gas supplies in the 1990s, major development
projects are under consideration for Sleipner, Troll,
far-northern Tr ms region
I and the
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Sleipner Field. The Sleipner field is the most promis-
ing field to link to the United Kingdom in exchange
for British gas deliveries to the Continent. Statoil has
decided on a policy of rapid depletion of the field-
forgoing possible gas recycling for recovery of conden-
sates-and foresees gas production startup by 1990. A
swap for UK gas would allow substantial savings of
time and money in delivering 170,000 to 250,000
b/doe of gas to Europe
Troll Field.
eliveries of gas from the field
cou ach 500,000 to 670,000 b/doe by the mid-
1990s if sufficient demand materializes. Given water
depths of 340 to 350 meters and the shallow, broad
reservoir, technical challenges of field development
will be enormous.
Linking Troll tote existing rigg pipe ine to te
United Kingdom might allow deliveries of up to
450,000 b/doe to begin in the early 1990s. Otherwise,
construction of a new trunkline to Europe will delay
startup until the mid-1990s.
transportation costly, both Norwegian and Swedish
officials are optimistic about the eventual construc-
tion of a pipeline through Sweden that could deliver
Other Fields. Another area for potential development
is the Tromsa area off the northern coast of Norway.
Although the remoteness of the area would make gas
up to 250,000 b/doe in the 1990s
other small fields, Dutch Government officials expect
the share of non-Groningen production to increase,
stretching the lifetime of Groningen reserves.
Financial Requirements 25X1
North Sea oil and gas development projects during
the next decade could require investments of more
than $100 billion (1982 dollars) on top of the $85
billion already invested (table 2). Commitments to
projects already under way in the Norwegian sector
will entail expenditures of about $5 billion annually
through the mid-1980s, including $3-4 billion in
capital investments and $1-2 billion in exploration and
operational expenses. Norwegian banks and other
credit institutions are allowed to lend only a total of
about $500 million annually to finance petroleum
activities. The Bank of England has estimated that
more than $6 billion must be spent annually in the
UK sector in order to keep pace with growing demand
for gas during the next decade. Additional invest-
ments in the Netherlands and Denmark could push
total North Sea investments to more than $10 billion
annually. 25X1
Most development projects for the late 1980s are still
under review, including major gas development proj-
ects. A decision to bring gas production from Sleipner
on stream by the 1990s could require investment of
more than $7 billion in the late 1980s and early
1990s. Development of Troll gas reserves could cost as
much as $15-20 billion during the 1980s and 1990s.
Development of other, smaller fields in both the
British and the Norwegian sectors, linked to existing
or proposed pipelines, can provide additional gas.
Heimdal, block 34/ 10, and other Norwegian gasfields
will be developed and linked to the Statpipe system
which will connect Statfjord to the Continent via the
existing pipeline from Ekofisk, West Germany. In the
Dutch sector, Mobil's P-6
field to come on stream in 1984, producing about
10,000 b/doe. With the production from this and
All of these projects will have to vie for investment
funds against other development projects. Given the
long leadtimes before production can begin, high
interest rates can easily deter development. For a
project financed over a 15-year period, an interest
rate subsidy of less than 2 percent can reduce by 15
percent the overall costs of a project that is entirely
debt financed. Hence, favorable financing terms for
gas projects could substantially boost incentives for
development.
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Table 2
Projected Expenditures for North Sea
Oil and Gas Development
26 to 29
Norway
14.4
Frigg
0.8
Statpipe system
3.5
I to 2
Statfjord
3.4
2 to 7
Sleiper
0.5
7 to 8
Troll
-
15 to 20
Tromsa
-
0 to 7
6.2 5 to 10
10 to 11 30 to 35
Denmark, West Germany, 2 to 3 5 to 7
Netherlands
a Total is less than the sum of the maximum investments for
individual projects because it is unlikely that all the projects would
be undertaken during the period.
Outlook
While North Sea gas exports could technically be
expanded by more than 900,000 b/doe by the mid-
1990s, the market share for this gas will be limited by
the high cost, even if subsidies are offered. If Europe-
an gas buyers are serious about diversifying gas
supplies and limiting dependence on Soviet gas, they
may be willing to buy more than 700,000 b/doe of
Norwegian gas-enough to support development of
Sleipner and Troll but not enough to warrant simulta-
neous development of Tromsa resources. The profit-
ability of the Tromsa and Troll projects depends on
high volume deliveries. Completing both projects at
the same time would provide a larger increment of
high-cost gas than Europe could absorb. Moreover, we
believe that Oslo will act to spread development
activity as evenly as possible over the next decade in
order to minimize potential adverse effects on the
Norwegian economy.
Both French and West German utilities have ex-
pressed an interest in securing additional Norwegian
gas and have indicated a willingness to pay a small
premium for these supplies. The volume they would
be willing to purchase, however, will depend in large
part on the growth in gas demand. With much of the
incremental demand expected to come from the indus-
trial sector, gas prices will have to be competitive with
coal and residual fuel oil prices to guarantee addition-
al sales
Given the economic uncertainties confronting produc-
ers, European cooperation in guaranteeing reduced
interest rates for development projects or arranging a
gas swap to minimize transportation costs could be
critical to full-scale North Sea gas development. The
long-term benefits of such cooperation would be sub-
stantially enhanced diversity and security of gas
supplies.)
In the absence of such European cooperation, Nor-
way's gas development might still proceed apace, if
the Norwegians were to moderate their price demands
and accept a lower return on their gas than they
receive on existing contracts. Such a move, however,
would be a reversal of Oslo's previous objectives. In
any case, if the Dutch can be persuaded to extend gas
export contracts in the late 1980s and early 1990s,
they will effectively hold a share of the European gas
market until new supplies of Norwegian gas come on
stream. Otherwise, because of the timing of the new
projects, the market for Norway's gas might be
preempted by increased sales of gas from other
sources, especially the Soviet Union
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Appendix A
The Troll Gasfield Project
Norway's Troll gas-
field contains recoverable gas reserves of 1.4-2.0
trillion cubic meters-roughly the size of the Nether-
lands's Groningen field. The Troll structure-which
covers nearly 700 square kilometers-is located in
blocks 31/2, 31/3, 31/5, and 31/6, of which only
31/2 has been drilled by the operator, Royal Dutch
Shell. The three undrilled blocks are likely to contain
up to 75 percent of Troll's reserves. Norway's new
conservative government has recently appointed Stat-
oil, a Norwegian state oil company, as operator in the
exploration phase for blocks 31/3 and 31/5. Norsk
Hydro, another Norwegian company, will be the
operator in the exploration phase of block 31/6.
While these two Norwegian companies are expanding
their capabilities to handle major development proj-
ects, they still must rely on major international oil
Both fixed and floating platform concepts are being
evaluated and, given the water depth of more than
300 meters and the shallow, broad reservoir, subsea
production techniques are certain to play a significant
role in development. Feasibility studies are under way
to evaluate:
? The Condeep T300 concrete platform (Norwegian
contractors).
A tension leg platform (VO Offshore).
A steel tripod platform (Heerema).
A multiwell subsea production template (Kvaerner
Engineering and Can Ocean).
Alternative riser configurations-the conduit that
delivers oil or gas from the wellhead to the surface
(Kongsberg Engineering).
Offshore gas, oil, and NGL (natural gas liquids
treatment facilities (S. H. Landes)
companies for technical expertise in many areas
ecause new technologies must be employed, it is
produced. I a preliminary proposal
In addition to the gas reserve
the Troll structure contains oil reserves
of up to 2 billion barrels. Since the oil lies in a
relatively thin layer below the gas reservoir, however,
it is not yet clear that the oil can be economically
difficult to estimate development costs before detailed
feasibility studies are completed. The Condeep plat-
form is a gravity-based platform with three concrete
legs joined below th waterline and a single leg
su ortin the deck
for developing Troll oil indicated unit costs of $35,000 I platform produced
I each pat
peak daily barrel of capacity and a maximum real
billion cubic meters (bcm) Z per year over a 15-year
rate of return of 6 to 8 percent. Since the completion
production costs alone (exclusive of transporta-
of the study, however, drilling results indicate that the period,
tion costs and a real return on the resource) would be
oil layer in the western part of the field is thicker than
$3.40 to $4.25 per million BTU:
had been expected-as much as 30 meters in some
areas-and might be commercially producible. Far-
ther to the east, the oil layer varies in thickness from 0 Annual operating cost $140 million
$330 million
to 10 meters and probably is not recoverable. A Interest on investment
(15 percent)
decision to produce the oil could delay the startup of
natural gas production by several years, since recov- Depreciation (15 years) $140 million
ery of the oil will probably precede gas production ~Total $610 million
Annual volume produced 4-5 bcm
Field Development 25X1
Shell is moving smoothly toward a development plan
for block. 31/2 and expects to make a formal declara-
tion of commerciality for the field by late 1983. It has
already awarded contracts to six companies for feasi-
Unit cost 0.12 to 0.15
($ per cubic meter)
3.40 to 4.25
($ per million BTU)
bility studies on the main development alternatives, One billion cubic meters per year is approximately 16,700 b/doe.
some of which are thus far untried in the North Sea.
O
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Notably, interest costs play a large role. A 1-percent
interest rate subsidy would lower unit costs by 35 to
45 cents per million BTU.
31/2
31/3
Shell
Statoil
0 8
kilometers
North
Sea
31/6
31/5
Norsk ydro
Statoil
-u-Fault line
- Block boundary
Q Gas reservoir
A Gas well
0. Gas show
31/9
Pipeline Alternatives
Scenario A. The quickest way of initiating gas deliver-
ies from Troll would entail linking the field to the
existing Frigg pipeline to the United Kingdom. In
return, comparable amounts of UK gas would be
delivered to the Continent via a new pipeline in the
southern sector of the North Sea a
link to the existing Frigg line would allow deliveries to
begin in the early 1990s and would probably cost less
than $500 million. The contract between Norway and
the United Kingdom specifies that production from
Frigg will drop to nearly zero by 1992, leaving spare
pipeline capacity of about 20 bcm per year. Moreover,
with additional compressors the capacity of the Frigg
line could be expanded to 27 bcm per year.
Although this alternative would probably allow a
lower delivered cost for gas, it has some drawbacks for
the Norwegians:
? An agreement for the gas swap would have to be
reached with both UK and continental buyers,
weakening competition between them for Norwe-
gian gas.
? Deliveries would be constrained by the capacity of
the Frigg system and the volume of gas the British
are willing to swap.
In the mid-to-late 1990s, spare capacity should be-
come available in the Statpipe system, which will be
linked to the West German gas grid. At that time, gas
from Troll could be delivered to Europe via a link to
Statpipe. The Statpipe system has a total planned
capacity of 17 bcm and could be expanded to deliver
about 20 bcm with additional compressors
Scenario B. Norway could build a new gas trunkline
capable of delivering 30-40 bcm directly to the Conti-
nent. While this alternative would free the Norwe-
gians from the constraints mentioned in scenario A,
we estimate that it would probably entail capital costs
of more than $3 billion and could take two to three
years longer than building a link to the Frigg system.
The new trunkline would be more than 1,200 kilome-
ters long and would re uire more than 800,000 metric
tons of steel.
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Appendix B
Triangular Gas Deal
Using the United Kingdom as a conduit for delivering
Norwegian gas to the Continent could save both time
and money compared to the alternative of building a
major new trunkline. Norwegian gas delivered to
Scotland could be swapped with UK gas in the
southern basin, providing at least 10-15 bcm annually.
0
In the near term, Norway's Sleipner field-with
reserves in excess of 280 million cubic meters-is the
most logical field to link to the United Kingdom.
Exploratory assessment of the field is nearly complete,
and a development decision will be made in the next
one to two years. Moreover, the gas has a high
concentration of carbon dioxide-6 to 9 percent-and
will probably require a separate distribution system.
Because several small fields in the UK sector have a
similar problem with carbon dioxide content, a link to
the United Kingdom would be a logical step
According to government estimates, proved gas re-
serves in the southern sector of the UK offshore
waters are 370 bcm.
Sleipner Gasfield
15/6 16/4
reserves are actually much higher and that substantial
additional reserves remain to be proved. The southern depletion of the field, ruling out gas recycling for
sector provides the ideal link to Western Europe enhanced condensate recovery. Statoil has estimated
because of its proximity to the Continent. British tax the capital costs of field development at $5-6 billion
policy is an important consideration in estimating the and has indicated that gas deliveries might begin by
future availability of gas from the United Kingdom. If 1990. Including operating and transportion expenses,
tax policies that currently discriminate against devel- the cost of producing and delivering the gas (presum-
opment of relatively small fields were to be modified, ably via pipeline to the United Kingdom) is estimated
the profitability of developing the numerous small at about $3.50 per million BTU. The Norwegians are
gasfields in the southern basin could improvel lexpected to demand a price comparable to that re-
Field Development and Pipelines
Because the reserves of the Sleipner complex are
distributed among seven reservoirs, five platforms
would probably be required to exploit the field fully.
The field is in about 650 meters of water, and
technologies previously tested in North Sea waters
will largely be employed there. Statoil, operator for
the field, has recently decided on a policy of rapid
BTU.
A major Dutch oil company has estimated a cost of
$500 million for constructing a pipeline from Sleipner
to the United Kingdom. By contrast, construction of a
separate pipeline from Sleipner to the European conti-
nent would cost $2-3 billion.
+-~ Fault line
-Block boundary
Q Gas reservoir
0 Potential, gas
reservoir
C Oil show
Gas well
Gas show
Dry hole
Approved For Release 2007/02/20: CIA-RDP83B00851 R000200040005-6
 Approved For Release 2007/02/20: CIA-RDP83B00851 R000200040005-6
Approved For Release 2007/02/20: CIA-RDP83B00851 R000200040005-6
 Approved For Release 2007/02/20: CIA-RDP83B00851 R000200040005-6
Secret
Secret
Approved For Release 2007/02/20: CIA-RDP83B00851 R000200040005-6