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Europe's first LNG process/export terminal Statoil Double Capacity Snohvit LNG Plant
Statoil Barents Sea Wildcat Guovca prospect 2005 April
Snohvit Barge Ready To Go Statoil 6/27/2005
LNG - Snøhvit project March 2002
Troms Barents Sea unitization deal finalized  Aug 09, 2000
Snohvit Development On Hold 3/22/2002
Snøhvit development hinge on LNG commerciality

Melkøya Island, site for the LNG liquefaction plant to serve the Snøhvit, Albatross, and Askeladd fields in the Barents Sea, marks progress in November 2005 with its revised target start-up date of late 2007. Operator Statoil ASA announced in September 2005 that the project was over budget by about NOK 7 billion and that gas production to feed the plant would be 8 months later than planned. Photo by Eiliv Leren, Statoil.
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.
Europe's first LNG process/export terminal 08 2005
Offshore August 2005 ,

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.
Snohvit Barge Ready To Go Statoil 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.
Statoil Barents Sea Wildcat Guovca prospect
Statoil 4/4/2005 URL:

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."
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.

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.

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.
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.
Troms development in the Barents Sea unitization deal finalized
Aug 09, 2000
LONDON—Seven licensee groups involved in the Troms patch development in the Barents Sea today struck a unitization deal that will see redistribution of interests in the three-field licence off northern Norway. According to Troms? operator Statoil AS, the agreement, which encompasses the Snovit, Askeladden, and Albatross gas-condensate discoveries, will give the Norwegian oil company a 34.29% share in the complex, as well as the state's direct financial interest of 30%. 
Under the redistribution, the development licensees will hold the following interests: TotalFinaElf SA, 18.4%; Norsk Hydro AS, 10%; Amerada Hess International Ltd., 3.25%; RWE-DEA AG, 2.61%; and Svenska Petroleum Exploration AB, 1.24%.
The unitization deal also built in new voting rules "to secure efficient planning and decision-making," said Statoil. 
Statoil's Kai Bjarne Lima said the unitization would provide licensees with "a common goal for future work" in developing the first of these fields, Snohvit, where current thinking revolves around a subsea production concept with gas-condensate transported to the Melkoya treatment and liquefaction facility onshore near Hammerfest. 
A final plan for development and operation of Snovit is scheduled for submission to the Norwegian authorities next summer. 

Proven gas reserves on the Troms patch stand at 320 billion cu m.