Barents Sea headed for more development

Statoil and Gazprom held talks in April at the Hammerfest LNG plant that is under construction on Melkøya island in northern Norway.

This facility, which will liquefy natural gas from Statoil’s Snøhvit field, the first discovery to be developed in the Norwegian sector of the Barents Sea, ranks as Europe’s first LNG facility.

Statoil recently signed a letter of intent with Aker Stord to extend the installation contract for additional work and completion of the LNG process barge that will be placed on the island. The contract has been extended from the end of 2005 to the summer of 2006.

This work will take place in Norway. Aker Stord, part of Norway’s Aker Kværner engineering group, won the contract in September 2003 to install and hook up the mechanical units on the barge.

The barge is due to be shipped from Cadiz on a heavy-lift vessel late this month for installation in the dock at Melkøya at the end of July.

Statoil is still planning to start LNG deliveries from Hammerfest next fall.

To that end, theSolitaire laybarge started laying a 143-km pipeline from the western side of Melkøya in April. The main pipeline will carry the wellstream from the Snøhvit field to the Hammerfest LNG plant on Melkøya.

Statoil and Gazprom have met to address prospects for Gazprom participation in the Snøhvit LNG project and opportunities for using Statoil regasification capacity in North America.

The two companies also signed a memorandum of understanding last September to study possible development solutions for the Shtokmanovskoye gas and condensate field in the Russian sector of the Barents Sea.

The April meeting in Melkøya addressed work done under a former agreement. The work includes joint studies on prospective projects for Shtokmanovskoye, building an LNG plant, and deliveries of LNG to the US.

At the end of April, Statoil was the first international company to submit proposals for developing Shtokmanovskoye, along with a draft agreement that could bring the project closer.

Americas

Exploration offshore Nova Scotia could get a boost from a more flexible approach to licensing rules. The province has proposed allowing exploration license holders to consolidate exploration commitments from their own and other licenses.

Energy Minister Cecil Clarke says the consolidation provisions will encourage drilling.

“We’re more interested in collecting royalties from successful wells than collecting penalties from expired licenses. And making sure that companies have the flexibility to adapt their exploration licenses to changing conditions will help make sure that wells are drilled,” Clarke says.

Under the licensing rules, companies have to pay a penalty if they do not meet the work commitments they made when bidding on exploration leases.

Encouraging companies to bring forward consolidation proposals is a positive step for the province. Consolidating commitments allows companies to focus their commitments in lease areas that have the best chances for success. Once caveat is that consolidation proposals must be accompanied by firm commitments to drill.

“This is one of a number of changes the department is making to achieve our objective of encouraging more offshore exploration,” Clarke says.

Pemex believes there are reserves of about 54 Bbbl of crude equivalent in and around the Gulf of Mexico. About 25 Bbbl are in deepwater (beyond 500 m water depth).

The company is investing $10 billion/yr in exploration and production, but is still falling short of the technology needed for deepwater production. Pemex officials have been lobbying for more foreign investment that will make technology available for deepwater production. In the meantime, the country is struggling to increase domestic production and to decrease imports.

Unless Mexico opens the door wide to foreign investors, most of the 25 Bbbl in deepwater reserves are likely to remain in the ground.

Central Asia

The contractors involved in exploration drilling on the Tub-Karagan offshore block in Kazakhstan’s sector of the Caspian Sea held a pre-start meeting in Aktau, Kazakhstan, in April. Contractor company managers met with Lukoil Overseas and KazMunaiTeniz, 50/50 owners of operator, Tub-Karagan Operating Co. BV, to discuss drilling commitments.

TheAstra jackup rig spudded the first exploration well in 7 m water depth in early May. All drilling activity will be carried out on a zero-discharge basis, with all industrial waste recycled.

Well results will allow the operator to assess the geological profile, determine if there are hydrocarbon deposits, and evaluate commercial productivity.

The 1,300-sq-km Tub-Karagan block has estimated in-place reserves of 324 million tons of oil. Peak production is estimated to be 7 million tons/yr with cumulative production reaching 110 million tons of oil.

Mediterranean

Qatar Petroleum, Exxon Mobil Corp., and Edison recently reached milestone agreements for the Isola di Porto Levante LNG terminal, which will be built offshore the coast of Italy in the North Adriatic Sea.

The terminal, scheduled for startup by year-end 2007, will have a regasification capacity of 8 bcm/yr. The facility will be a key component in providing dependable supplies of natural gas to the Italian energy sector.

Isola di Porto Levante terminal owners have secured all the primary authorizations for construction and operation from the Italian government and European Union Commission.

Aker Kværner won the contract to develop the gravity-based structure, LNG storage tanks, and off-loading and regasification facilities. Snamprogetti, an ENI affiliate, will be the contractor for the pipeline associated with the project.

The terminal will be 15 km from the Veneto coast in 30 m of water. Aker Kværner will construct the concrete GBS onshore and tow it to the site, where it will create an artificial island. Aker will also position the LNG storage tanks, which ExxonMobil will design using its proprietary modular tank technology, inside the GBS. The terminal will be equipped with a berthing/mooring system for product unloading, designed to accommodate ships delivering up to 152,000 cu m of LNG. Two ships per week will make deliveries.

QP and Exxon are making a number of upstream investments associated with the project. These include a wellhead platform with an expected seven wells, pipelines, a 4.7 million tons/yr LNG train at Ras Laffan City, and five conventional LNG tankers to supply the new LNG terminal.

Asia-Pacific

Canada’s Talisman (Vietnam 15-2/01) Ltd. and PetroVietnam Exploration and Production Co. signed a petroleum contract for block 15-2/01 offshore Vietnam.

According to Talisman, block 15-2/01 is in the center of the most prolific oil producing region of Vietnam and offers significant exploration opportunities, which, if economic, can be developed quickly.

The 700,000-acre block is 20 km offshore southern Vietnam in 25-50 m of water in the Cuu Long basin adjacent to a number of significant producing oil fields.

The consortium’s commitment on block 15-2/01 includes conducting a 3D seismic survey and a two-well exploratory drilling program during the initial three-year exploration phase.

A joint operating company will conduct operations on the block, with key staff provided by both members.

Talisman has a 60% interest in block 15-2/01, with PetroVietnam holding the remaining 40%.

Technip recently signed a contract with DNV to class the Kikeh truss spar, the first to be installed outside the Gulf of Mexico.

In addition to the spar, there will also be an FPSO on the field, fluid transfer lines between the FPSO and the spar, subsea production systems, and pipelines.

“This project is important for bringing DNV knowledge and experience into the Floating Production System (FPS) market. This is our best opportunity to show how DNV can perform and, hopefully, lay the foundation for future work with Technip and other FPS vendors,” says Craig Colby, a DNV regional manager.

Kikeh is the first deepwater production project offshore Malaysia. Murphy Oil operates the field with Petronas as partner.

ONGC reported three oil and gas finds, one in shallow water on the west coast and two in the deepwater Krishna-Godavari basin on the east coast.

The shallow-water discovery is 60 km south-southwest of the Mumbai High field in a pre-NELP block where ONGC is 100% operator. The company spudded the well in late October 2004, identifying multiple oil and gas bearing sands in the Panna formation and opening a new exploration opportunity. ONGC believes the field covers at least 25 sq km.

The two east coast gas strikes are part of the Sagar Samriddhi deepwater exploration campaign. Well VA-2 in block KG-OS-DW-IV flowed 326,545 cu m of gas per day through 24/64-in choke. This prospect will be integrated to the up-scaled exploitation plan of the G-1 and GS-15 structures where ONGC is developing India’s first digital oil field in the KG basin.

ONGC’sSagar Vijay drillship found gas in another pre-NELP block. Well G4-4, targeted the channel levee complex, where wire-line testing confirmed the presence of gas. ONGC could integrate G4-4 to the fast-track development plan for the G4 and GS-29 prospects.

Africa

Wood Group subsidiaries Woodhill Frontier and J P Kenny won a contract from Energy Africa for final concept selection and front-end engineering and design for the proposed Kudu field development offshore Namibia.

The companies are considering two main concepts. One is a direct subsea to beach development, an option that poses significant technical challenges for the 180-km distance to shore.

The other concept is a floating production facility that would process the gas offshore. The FPF option would minimize the facilities and cost of the onshore gas terminal.

Discovered in 1974, Kudu lies in 170 m water depth and is now being considered for development due to improvements in market conditions.

Phase one of Kudu is due onstream in 2009 at an initial rate of 130 MMcf/d, which will supply an 800-MW power plant at Oranjemund in Namibia. NamPower developed the plant to supply both the expanding Namibian and South African markets.

In early May, Nigerian National Petroleum Corp. authorized Total to begin developing the deepwater Akpo field on oil mining license (OML) 130.

The field development plan calls for 22 producing wells, 20 water injection wells, and two gas injection wells tied back to an FPSO with storage capacity of 2 MMbbl.

Total Upstream Nigeria Ltd. awarded a consortium made up of Technip, as leader, and Hyundai Heavy Industries, a contract for engineering, procurement, supply, construction, and offshore commissioning of the FPSO.

Technip’s engineering center in Paris will be in charge of the overall project management and will performed the engineering phase.

Hyundai Heavy Industries will execute the FPSO hull and topsides construction and integration. Engineering and some of the fabrication will take place in Nigeria.

TheAkpo FPSO hull will have deck space to accommodate more than 17 topsides modules. The FPSO will be anchored in 1,325 m of water and will produce 225,000 boe/d. It will include two processing trains to separate gas and water.

Discovered in 2000, the Akpo gas and condensate field is 200 km offshore Port Harcourt in water depths ranging from 1,100 to 1,700 m.

Akpo will come onstream in late 2008 and is expected to quickly reach peak production of 225,000 boe/d. Condensate will be exported via a buoy 2 km from the FPSO, while the gas will be piped 150 km to the Amenam/Kpono platforms, from which it will be sent to the Bonny Island liquefaction plant.

Europe

Statoil’s most recent Barents Sea well came up dry. Though the Guovca prospect yielded no commercial hydrocarbons, it did provide data that confirms there is reservoir quality sandstone in the area. Guovca is the second of four exploration wells to be drilled in the Barents Sea this year.

After drilling Guovca, Ocean Rig’sEirik Raude moved to the Norwegian Sea to drill on Statoil’s Tulipan prospect, but will return to the Barents Sea to drill a wildcat on the Uranus prospect this fall.

“Even though no oil or gas was proven on Guovca, we still have great expectations for the Barents Sea, and we firmly believe in the potential for new discoveries in the north,” says Tim Dodson, Statoil’s senior vice president for exploration on the Norwegian continental shelf.

“We will review our experiences from Guovca and the Hydro-operated Obelix well, which was drilled earlier this year and take that knowledge with us in our further work in the Barents Sea.”

In the Norwegian Sea, Statoil completed its first production well on the Kristin platform. According to the company, the well is ready to flow gas and condensate.

Challenging reservoir properties required new solutions be devised for cost-effectively controlling and producing the field. According to Statoil, reservoir pressure is 911 bar, and the temperature is 170° C, making Kristin the first field in the world with subsea-completed wells and systems able to handle such extreme conditions.

Carrying out the completion put newly developed equipment to work. Norway’s Kværner Oilfield Products designed the downhole equipment and put it through an extensive technological qualification program prior to deployment on the field.

“We now know that we have downhole equipment, which can be installed and which is able to produce the gas and condensate in this field,” says Eileen Buan, operations vice president at Statoil.

Buan hails this first producer, with a deviation of 75° from the vertical, as a project milestone.

When Kristin is on plateau, it will yield gas and condensate worth NOK 35 million per day. Production will begin the first of October.