Statoil Double Capacity
Snohvit LNG Plant
Interfax Information Services, B.V. 9/14/2005
Statoil plans to double planned capacity at a liquefied gas plant at
the Snohvit field by 2012, Henrik Carlsen, the Norwegian oil and gas
company's senior vice president, said at the RAO/CIS OFFSHORE 2005
conference.
At around the same time, he said, Russia would bring the Prirazlomnoye
field on stream and the first LNG sourced at the Shtokman field would
be delivered to the United States.
Statoil plans to start developing the Snohvit field, which is on its
Barents Sea shelf, in October 2006. It will launch an LNG plant to
process the gas in December 2006.
Statoil has submitted proposals on its participation in the Shtokman
project to Gazprom and will seek a 25% interest in the project,
offering Gazprom 10% of the Snohvit project. Statoil is also thinking
about letting Gazprom use the Statoil Cove Point regasification
terminal in the United States.
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Europe's
first LNG process/export terminal 08 2005
Offshore August 2005 , wwwoffshore-mag.com
Statoil's Snohvit field development in the Barents Sea will feature
Europe's first LNG process/export terminal. Dragados Offshore
assembled this facility on a steel barge measuring 154 m long, 54 m
wide and 9 m deep, and is currently undergoing installation at Melkoya
Island off northern Norway. The sole purpose of the barge,
following transportation to the island, is to serve as the foundation
for the LNG process plant.
At the end of June 2005 the barge and topsides left the Dragados
Offshore fabrication yard in Puerto Real, southwest Spain for their
5,000-km voyage to the island.
Due to the extreme weather conditions in northern Norway, Statoil's
rationale was to outsource as much of the construction as possible well
away from the island. From Dragados Offshore’s point of view, the
main challenge has been the constraints imposed by the steel barge's
dimensions. This limited space and access for personnel involved
in topsides assembly and of pipework, insulation, electrical, and
instrumentation systems. Also, the structural steel was not
designed to support a conventional modular construction program.
In this regard, the operation proved to be much more complex than a
standard offshore module assembly performed on open land at the yard.
The 10,000-ton barge, Izar in Ferrol built, arrived at the yard early
last September. To meet the scheduled delivery date of late June
2005, Dragados Offshore implemented a three-pronged strategy:
· Expedite and facilitate access to the barge,
once it was in position alongside the quay
· Plan in detail the working sequence
· Take as much assembly work as possible away
from the barge.
To simplify access to the barge for the construction team, materials,
and lifting gear, the first step was to ground the barge and level its
deck to the same height as the quay. To this end, the team placed
gravel on the seabed beneath the barge, and then ballasted the barge.
This solution, however, only addressed access from the quayside.
To ensure unfettered access from all sides, the construction tean
inserted a temporary work platform between one end of the barge and the
quay, and brought in an auxiliary barge along the side of Snohvit’s
process barge that was open to the sea. The team grounded the auxiliary
barge on a gravel bed to match the height of the process barge's deck.
Much of the Snohvit plant could not be put together in modules, but
Dragados Offshore undertook detail design of the construction
process. This led to the LNG terminal being subdivided into
smaller, pancake-type structural sections that could be assembled
easily on the barge - i.e., a stick-build approach - following
pre-fabrication in the company's workshops.
Dragados still had to plan the fabrication sequences to ensure
installation at the right time, according to the area and location:
Despite the apparent rigidity of this approach, the company achieved
the necessary flexibility by apportioning sections of the plant to
different parts of the yard. The basic idea was to shift
resources around where possible to avoid potential bottlenecks during
fabrication and erection.
The third main aim was to withdraw as much assembly work as possible
from the barge. With a peak labor force of 2,300 working on the
barge's confined space simultaneously, there was as risk of
productivity losses due to interference among the various engineering
tasks. This, in turn, could have presented a major safety risk.
Having the pancake structures assembled, painted, and fireproofed in
the workshops eased the congestion, as did completion of pipework
painting and cleaning prior to erection on the barge.
Additionally, the construction team mounted the maximum amount possible
of equipment, piping, and cable trays on the structural sections on
land at the quayside, close to the erection area. They also
outfitted main equipment items such as distillation columns in a
horizontal position in the same area with all internals, piping,
insulation, and electrical trace heating systems, prior to installation
on the barge.
To secure transfer from the quayside of the process plant's primary and
heavier elements, Dragados employed what it says is the world's second
largest land-based crane, with a lifting capacity for this project of
1,400 tons.
Once the team completed assembly work in mid-June, various other tasks
were necessary to prepare the plant for its voyage north. First,
they had to de-ballast the barge for de-grounding from the gravel base,
and then tow it to a harbor 500 m away for inspection of the underwater
hull. This maneuver was completed on June 21. The
plant/barge was then towed to a location 2-km from the yard in the Bay
of Cadiz, where Dockwise's transportation vessel Blue Marlin was
already submerged, ready to take onboard the Snohvit plant following a
float-on operation.
The surrounding area was dredged to create a water depth of 20 m for
this task (the natural depth was around 17 m). On June 27, the
transportation vessel returned to the harbor for seafastening of the
LNG plant ahead of its voyage northwards, which started three days
later.
Transportation of the barge on another vessel avoids stresses on the
plants steel structure, which might occur following long-distance
towing by tugs. Using a dedicated transportation vessel also
shortens the duration of the voyage and simplifies maneuvering,
decreasing the risk element. The route takes the LNG plant around
western France and through the English Channel. The journey had
to be undertaken in the summer months, as tidal movements in the
Barents Sea are more favorable at this time of year for final
docking-in operations.
On arrival, the float-off operation should be a reverse of the initial
loading procedure. First the seafastening will be cut, followed
by ballasting down of the vessel until the Snohvit barge/plant floats
freely in the water. Tugs and winches will then take it to its
final location in a dock specially excavated in the island. Once
in position, a thick layer of concrete will cover the barge deck.
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Snohvit Barge
Ready To Go Statoil 6/27/2005
6/27/2005
The barge-mounted production plant for Statoil's Snøhvit project
in the Barents Sea was ready to be shipped north from the fabrication
yard in southern Spain on June 27th. It has been placed on the Blue
Marlin heavy-lift vessel in preparation for starting its voyage later
this week to the Melkøya site outside Hammerfest in northern
Norway. The 33,000-tonne unit represents the heart of Statoil's first
and Europe's only export facility for liquefied natural gas (LNG).
"This represents an important milestone for the Snøhvit project
and for the group," says Egil Gjesteland, who has headed the
development. "Getting the process plant north, so that we can continue
our work at the Hammerfest LNG site on Melkøya, means a lot for
us in the project team. "As the first development project in the
Barents Sea, Snøhvit is important for Statoil's future
commercial development."
The process plant has been constructed as an integrated unit on a barge
with a deck area of 154 by 54 meters – considerably larger than an
international football pitch. Assembled at the Dragados Offshore yard
in Cádiz, this structure cast off its moorings and moved from
the quay to be lifted onto the world's largest heavy-lift carrier. It
will be secured for the sea voyage before Blue Marlin leaves Spain. The
trip to Hammerfest is expected to take just under 14 days.
After its arrival at Melkøya, the huge installation will be
moved into a pre-excavated dock as soon as wind and weather conditions
permit. The plant is due to export a total of 5.7 billion cubic meters
of LNG annually to the USA and Europe from the autumn of 2006.
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Statoil Barents Sea
Wildcat Guovca prospect
Statoil 4/4/2005 URL: http://www.rigzone.com/news/article.asp?a_id=21520
A wildcat in the Guovca prospect operated by Statoil in the Barents Sea
was spudded on April 2nd from the Eirik Raude semisub.
Statoil had planned to drill the Uranus exploration well in the Barents
Sea before Guovca, but had to re-prioritize the drilling program as
handover of the rig from Hydro was delayed.
Work on drilling and completing the well is expected to take 20-30 days.
Once Guovca is completed, Eirik Raude will move to the Norwegian Sea
for a well on Statoil's Tulipan prospect in block 6302/6. The rig is
then due to return to the Barents Sea during the autumn to drill the
Uranus wildcat.
"We've adopted a number of measures to ensure safety and protect the
environment while drilling this well," explains Ørjan Birkeland,
Statoil's Barents Sea exploration manager. "These include detailed
planning and training of personnel in cooperation with the rig
contractor and other suppliers."
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LNG - Snøhvit project
In March 2002, the Norwegian parliament approved Statoil's
plans to
develop the $5 billion Snøhvit project. If it is completed,
Snøhvit
will be the largest sub-sea liquefied natural
gas
(LNG) project in the world, as well as the most northerly, as it is
located
in the Barents Sea. In November 2002, Statoil bought El
Paso’s LNG capacity rights at the import terminal Cove Point, Maryland.
Statoil
now has 20-year access to one-third of the terminal’s capacity.
In September 2003, Statoil concluded its
first LNG
contract with Tractebel to deliver annually 35.3 Bcf over three years.
The deal started on Oct. 1, 2003. After Fall
2006,
Statoil plans to begin supplying LNG from Snøhvit – 250 Mmcf/d
until
2023. Statoil’s first LNG delivery arrived on September 2 from
Repsol-YPF
(Trinidad). Alongside Statoil, BP and Royal Dutch/Shell have leased
capacity
at Cove Point. |
Snohvit
Development On Hold
Statoil 3/22/2002
Statoil has been informed that the position
between the
Norwegian government and the Efta Surveillance Authority (ESA) on the
Snohvit development in the Barents Sea
remains
unclarified.
This emerges from a letter sent by the ESA. partners in the
Statoil-operated project
will now
seek a clarification of the tax position for Snohvit from the Norwegian
authorities.
They must have a final clarification by 15
April
at the
latest to continue the development.
Those partners who have sold their gas to
Spain's Iberdrola
and El Paso Global LNG Company in the USA have until March 22nd to
give final confirmation of the contracts.
Agreements
have also been reached with shipping companies to build three special
carriers for liquefied natural gas.
These
agreements have
the
same deadline for final confirmation.
Failure to clarify the framework terms means
that these
partners can not give final confirmation to the buyers and shipping
companies within the deadline.
Statoil is working for a
postponement of the
deadlines
for the confirmation of the sales and shipping contracts. The
partnership
will also continue project
preparations in
accordance
with
current plans. Work at Melkoya, outside Hammerfest, will not be
initiated
and new commitments will not be made
until the
frame
conditions
with the authorities have been clarified.
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Snøhvit development prospects hinge on LNG commerciality
Gas discoveries in the Snøhvitarea of the Barents Sea-currently
only marginal economically-could become commercially viable if
sufficient
LNG markets materialize within the next 6 years, according to a new
report
by Edinburgh analysts Wood Mackenzie.
Financial feasibility of the Snøhvitproject also will
depend
on the Norwegian government's provision of full tax advantages to
the
operators, WoodMac concluded, and on the operators' broad employment of
the most recent advances in LNG technology.
Snøhvitis located in Norway's Hammerfest basin, in the
southern
Barents Sea.
Three fields-Snøhvit, Askeladd, and Albatross-make up
the Snøhvitarea. The remoteness of the area makes exploration,
production,
and transportation costly. Because the distance from existing gas
export infrastructure is so great, the Snøhvit partners are
planning
a multiple-phase LNG program with dual, phased pipelines from the
fields to a proposed single-train, onshore LNG plant in Norway.
Statoil would operate facilities for its partners,
currently TotalFinaElf
SA, Norsk Hydro AS, Amerada Hess International Ltd., RWE-DEA AG,
Svenska Petroleum Exploration AB, and Norway State DFI (see
table).
The operators expect to begin production in 2006.
Statoil and other leaseholders in the Norwegian sector have
drilled
56 wells in the area to date and, although they have discovered
no
commercial oil reserves, they have found a substantial core recoverable
resource of about 6.5 tcf of gas and 170 million bbl of
condensate
in the fields.
Operators plan to begin an expanded exploration-appraisal
program this
summer and expect to drill another nine wells over the coming 2
years.
Capital costs for the project are estimated at 26 billion
kroner (2000
value), with total annual operating costs of 500 million kroner,
including a carbon dioxide tax levied on at least part of the project.
Snøhvit facilities
Current development plans for the Snøhvit LNG project will
require
construction of a single-train LNG terminal on the small island
of
Melkøya near Hammerfest. If a second train were built, WoodMac
observed,
it would increase output and improve project economics.
Plans call for 18 horizontal wells in the fields-5 in
Snøhvit
5 in Askeladd, and 8 in Albatross-and a 140-km, 27-in. multiphase
pipeline to deliver condensate and natural gas from the fields to the
plant.
Phased development, using the one-train facility, would have
condensate-rich
Snøhvit field production on stream first, followed by
Askeladd
8 years later and Albatross 14 years after initial production begins.
Gas
produced early from Askeladd could be injected into
Snøhvit
wells to enhance liquids production.
The project will probably require compression facilities
in later
phases, both on a floating field platform and onshore, in order
to
boost recovery.
The partners expect production to reach 4.5-5.6 billion cu m/year
(435-542 MMcfd) of natural gas and about 20,000 b/d of
condensate.
The field gas contains 4-7% CO2, which would require removal at the
plant.
Statoil will most probably reinject the CO2 into an offshore
aquifer,
WoodMac noted, which would require a smaller-diameter pipeline-probably
6-8-in.-and one or more injection
wells.
After removing CO2 and reserving sufficient gas for the production and
liquefaction processes, owners could produce 5.5-6.9 million
tonnes/year
of LNG for sale. Regasification would then free 387-485 MMcfd of
natural
gas deliverables. At this production rate, the three fields would
have a life expectancy of about 40 years.
Area history, development
Exploration drilling began in the Norwegian sector of the Barents
Sea in 1980, with several substantial gas-condensate discoveries
made in the central part of the sea in the Snøhvit area. Core
gas
reserves in the fields are contained in Middle-Lower Jurassic
sandstone
structures in 300-340 m of water.
While commercial oil discoveries have been elusive,
Snøhvit
field does contain about 500 million bbl of oil within a thin zone
at
the base of the reservoir. A rapid breakthrough of gas and water during
the production test spelled the end of oil production attempts,
as
recovery was consequently deemed noncommercial.
Because of technology limitations during early exploration and
development, discoveries were not encouraging, and drilling
ceased
in 1994. However, in an attempt to stimulate continued exploration,
Norwegian
authorities revised licensing terms in 1996. The revisions
enabled
group applications, the award of greater equity shares, elimination of
drilling commitments for some awards, and the expansion of
blocks.
Licensing activity continued in 1997 as the Barents Sea Project.
Norsk Hydro, which has had success producing oil from thin oil
zones
in West Troll, investigated new oil production options for
Snøhvit
but shelved them in 1999. The picture for oil does not remain totally
bleak,
however. Recent advances in technology may soon improve
commercial
prospects for the fields, and exploration plans for the next 2 years
could
well result in discoveries of oil deposits in more-favorable
production
environments. The Norwegian Petroleum Directorate is eager to maximize
recovery of oil reserves in the Barents and will encourage
further
investigation of methods to accomplish that goal, notes WoodMac.
The huge Barents Sea region, vastly underexplored compared
with the
North Sea, contains several distinct geological provinces that
hold
the potential for major hydrocarbon discoveries.
|
To date, almost all finds have been located in the Hammerfest basin.
Four wells are scheduled for 2000: Norsk Hydro plans to drill one in
Area
A, in the western part of the sea (Fig. 1); Agip SPA will drill two, on
PL229 and PL201, southeast and southwest of Snøhvit; and Statoil
will drill the fourth farther east on PL202 in the Nordkapp
basin.
The company will target Lower Jurassic-Triassic plays in this salt
basin,
which is dominated by diapir traps. |
 Establishment
of sufficient LNG markets by 2006 is critical to the economic
feasibility
of the Snøhvit development scheme, the WoodMac report
emphasized.
Discussions for an earlier LNG gas sales agreement with the Italian
electric
utility ENEL broke down in 1993, and the owners then shelved that
project.
Operator Statoil and six partners (see table) are reportedly
interested
in attracting additional strategic partners such as gas utilities
and other upstream buyers. Gaz de France has expressed an interest in
the
project in the past. Snøhvit partner TotalFinaElf, itself
one of the largest global LNG players, is likely to take a leading role
in the venture and could provide a primary market base, according
to WoodMac.
The Mediterranean region and US East Coast, viewed as
prospective market
areas having the most significant demand growth potential, will
be
principal target markets for Snøhvit LNG. The high cost of LNG
transportation
gives the Norwegian location a delivery advantage over other
supply
sources in competing for US and European LNG markets.
Additional growth markets are concentrated in Turkey and in Atlantic
markets such as Brazil, Spain, Portugal, and the US. WoodMac
notes
that Snøhvit is not designed to compete with Norwegian pipeline
gas sales, but will, instead, complement them.
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Taxes
Total tax liability will have a key impact on the financial viability
of the project.
The WoodMac report notes that Norway employs a separate tax base
for onshore and offshore facilities: onshore rates, which cover
standard
industrial activities, include a 28% "corporation tax," while
offshore
upstream oil and gas activities are subject to an additional "special
tax"
at a rate of 50%. Norwegian authorities
currently
favor taxing the entire project, including all LNG terminal facilities,
at the higher offshore tax rates. WoodMac reasons, however, that
local support for the venture will likely result in political pressure
to grant favorable tax status to the project and that two-thirds
of costs of the onshore LNG plant will probably be subject only to the
more favorable onshore taxation.
Tax
advantages would significantly enhance the project's economics. In its
feasibility assessment, WoodMac speculates that half of the total
operating expenditures will likely fall under the preferable onshore
taxation,
and half will be taxed at the higher offshore rates.
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Economics
The onshore-offshore designation can affect rate of return on
investment,
which is often decisive for the advancement of marginal projects
such as this. Norwegian authorities could restrict the rate of return
to
a pretax level of 7% by designating the onshore facilities as
"infrastructure,"
which would be a tradeoff for taxing them as onshore
facilities.
Financing is expected to be relatively easy, given Norway's low
political
risk. The ability to offset interest payments against the high
marginal
tax rate also could turn out to be a bonus for participants when
seeking
financing. WoodMac's assessment of economics models a break-even
LNG price scenario of $2.60/Mcf.
Other variables can affect this project's profitability, positively
or negatively-cost increases or decreases, higher or lower
production,
and fluctuations in the exchange rate-between the time of project
initiation
and on-stream deliveries. Any or all of these could affect the
economics
of this undertaking in the future, but the WoodMac study concludes that
the project, at this phase of planning at least, is marginal. |
