Statoil and co-venturer Exxon Mobil have announced that the Giligiliani-1 exploration well hasresulted in a new natural gas discovery offshore Tanzania.

The discovery of an additional 1.2 trillion cubic feet (tcf*) of natural gas in place in the Giligiliani-1 well brings the total of in-place volumes up to approximately 21 tcf in block 2.

The Giligiliani-1 discovery is located along the western side of block 2 at a 2,500-metre water depth. The new gas discovery was made in Upper Cretaceous sandstones.

"This discovery has proven the gas play extends into the western part of block 2, which opens additional prospects. Our success rate in Tanzania has been high and opening up a new area will be key to continuing our successful multi-well programme," said Nick Maden, senior vice president for Statoil's exploration activities in the Western Hemisphere.

The rig Discoverer Americas will now drill the Kungamanga prospect located in the central part of block 2.

The Giligiliani-1 discovery is the venture's seventh discovery in block 2. It is preceded by the five high-impact gas discoveries Zafarani-1, Lavani-1, Tangawizi-1, Mronge-1 and Piri-1, and a discovery in Lavani-2.

Statoil operates the licence on block 2 on behalf of Tanzania Petroleum Development Corporation (TPDC) and has a 65% working interest. ExxonMobil Exploration and Production Tanzania Limited holds the remaining 35%. Statoil has been in Tanzania since 2007, when it was awarded the operatorship for block 2.
(*1 Tcf =180 million barrels of oil equivalent)

Petrofac's Offshore Projects & Operations business unit has been awarded two major reimbursable contracts in the UKCS and the Middle East.
In the Central North Sea, Petrofac has been selected to provide engineering and construction support worth up to $120m for Chevron's three operated assets – the Captain, Alba, and Erskine platforms.

Alba Northern Platform (photograph courtesy of Chevron North Sea Limited)

The contract - awarded under a competitive tender - is for up to three years, plus two one year options. Petrofac will create more than 70 onshore and offshore positions in order to execute and deliver the services.

Walter Thain, Senior Vice President Europe, said: "We're delighted to have been selected to support Chevron North Sea Limited with our operationally focused scalable engineering delivery model.
"We share with Chevron an absolute commitment to safe and cost-effective delivery, ultimately enhancing value."

Petrofac has also been awarded a major contract in Iraq to provide general construction management services to BP Iraq NV (BP) on the Rumaila field near Basra in the south of the country.

Petrofac will provide management and personnel to manage brownfield modifications to assist BP – and its partners in the Rumaila Operations Organization, China National Petroleum Company and South Oil Company – in executing its strategy to rapidly and safely increase production from what is one of the world's largest fields.

The contract, which runs for three years, with an option for further extension of two years, has a potential value of up to $500 million.
Petrofac will provide the overall management and co-ordination of multiple construction projects, including construction management and supervision of work undertaken by third party contractors on the field, 32 km from the Kuwaiti border.

Mani Rajapathy, Senior Vice President, MENA/CIS, said: "The award builds on an established track record for Petrofac in Iraq, in particular at Rumaila, dating back to 2011. We look forward to sharing in the continued success of the regeneration of Rumaila."

The discovery well 7319/12-1, drilled by the drilling rig Transocean Spitsbergen, proved a 15-meter gas column in the well path. Statoil estimates the volumes in Pingvin to be in the range of 30-120 million barrels of recoverable oil equivalent. The discovery is currently assessed as non-commercial.

Pingvin is the first well drilled in PL713 – a large frontier area northwest of Johan Castberg awarded in the 22nd concession round. For a discovery in this area to be commercially viable it needs to be an oil accumulation of a significant size. A gas discovery does not have commercial value at present. 

"On the positive side, it is encouraging that the first well drilled in this unexplored area has proven hydrocarbons in sandstones. This indicates that we have both a reservoir and a working hydrocarbon system in the area, and creates a good basis for further subsurface work in the licence," says Dan Tuppen, vice president exploration Barents Sea and Norwegian Sea.

Pingvin is a good example of efficient exploration performance.

"The partnership drilled Pingvin just 15 months after the acreage award. The chosen well location allowed us to clarify the hydrocarbon volume in the structure with one very efficiently executed exploration well," says Tuppen.

Exploration well 7319/12-1 is located in PL713 about 65 kilometers northwest of the Johan Castberg discovery. Statoil is operator with an interest of 40%. The partners are RN Nordic Oil AS (20%), North Energy ASA (20%) and Edison International Norway Branch (20%).

For further details on the results of exploration well 7319/12-1, please see the press release issued by the Norwegian Petroleum Directorate (NPD).

Leading oil and gas experts are lined up to present at the 20th SPE ICoTA European Well Intervention Conference which will, once again, bring industry professionals together to discuss current trends and new technologies within well intervention and completion.

Taking place on 12/13 November at Aberdeen Exhibition and Conference Centre, the annual conference is hosted by the Society of Petroleum Engineers (SPE) Aberdeen Section and the Intervention and Coiled Tubing Association (ICoTA) European Chapter. The conference will feature over twenty presentations from a variety of major oil and gas operators, including BP, Shell, ConocoPhillips and Statoil and specialists from the coiled tubing sector, including AnTech.

An extensive range of topics will be covered over the course of the two day conference, including the world's first deepwater propellant perforation for a depleted carbonate subsea gas well. Oil & Gas UK will also present the conference with the findings of the 4th Well Intervention Excellence Network.

Michael Taggart, Chairman of the conference committee, is looking forward to welcoming delegates to the event: "Sharing skills, knowledge and experience for the benefit of the oil and gas industry is high on the agenda for both SPE and ICoTA. We are therefore delighted that this conference has come to be regarded as Europe's premier forum for exchange and discussion of the latest developments in well intervention and completion techniques.

"Now in its 20th year, the conference has matured into an influential event where well intervention professionals attend to share knowledge, learn and do business. By imparting our knowledge and experiences from the North Sea and beyond, we can push the boundaries of well intervention and ensure a healthy oil and gas industry for the future."

A pre-conference short course on 11 November entitled, 'An introduction to well intervention', is aimed at those who have an interest in the topic but are new to the subject or are looking for a refresher and will appeal to those looking to gain a basic understanding of well intervention operations.

Eni's CEO, Claudio Descalzi, signed today with Petrovietnam's President and CEO, Do Van Hau, two Production Sharing Contracts (PSCs) for the exploration of blocks 116 and 124, located off the coast of Vietnam.

Block 116 covers an area of about 5,000 sqkm in the Song Hong basin, in waters with a depth ranging from 10 to 120 meters. The PSC block, wholly owned by Eni, provides for an exploration period of seven years divided into 3 phases.

Block 124 covers an area of 6,000 sqkm in the Phu Khanhbasin, in waters that have a depth ranging from 50 to 2,600 meters. The PSC provides for an exploration period of seven years divided into 2 phases. This block is held by Eni, which is the operator with a 60% stake, and by Santos Vietnam with a 40% stake.

Claudio Descalzi also met Hoang Trung Hai, Deputy Prime Minister with responsibility for Trade, Industry, Construction and Transport, and provided him with an update of the activities and projects that the Company is developing in the Country

"The participation in these two new high-potential blocks will consolidate our presence in the area and support our growth in the Pacific basin. The proximity of these blocks to those which we already operate will enable us to exploit at best the logistical and operational synergies, with considerable savings in terms of time and costs" said Eni's CEO.

These new agreements confirm Eni's interest to continue and consolidate its presence in Vietnam, where the company returned in 2012 and already operates four offshore exploration blocks.

2H Offshore, an Acteon company, has been appointed by Weatherford Secure Drilling® services to manage the design and delivery of the riser equipment for its Managed Pressure Drilling (MPD) system.

The project award follows a successful feasibility study carried out by 2H Offshore, which outlined multiple integrated concepts for the system. 2H's scope of work now includes the development and delivery of MPD riser stack equipment for the next two generations of Weatherford's MPD systems for offshore applications.

Despite the success that has been achieved using MPD offshore to date, there are still some challenges with the ability of offshore, particularly deepwater, rigs to accommodate MPD technologies. Weatherford is developing a fully integrated MPD solution that can be easily incorporated into nearly any deepwater drilling vessel, improving the adaptability and implementation for deepwater MPD systems.

Weatherford and 2H Offshore are working to ensure that the systems meet the new regulations currently being adopted by Det Norske Veritas (DNV) Drill Class N and the American Bureau of Shipping (ABS) CDS Certification.

"Weatherford has recognized that 2H is a leader in system integration and delivery management. This along with our expertise with riser systems has led them to partner with us to meet the demands of their customers and of the industry," said Mark Nolet, project manager at 2H Offshore. "The 2H team in Houston is extremely excited about assisting Weatherford Secure Drilling Services in developing its next generation of managed pressure drilling."

The next generation of Weatherford's MPD system is expected to be delivered in 2015.

First orders for Semco Maritime Rig Projects at Invergordon, UK: Orders for equipment and upgrading of two Prospector Drilling jack-up rigs and Norwegian operated semisubmersible rig Songa Dee.

At the beginning of the year Semco Maritime entered into a strategic partnership with the Port of Cromarty Firth to establish a center for rig upgrades at Invergordon in UK. The first solid orders have now been awarded: In the course of the next months, Semco Maritime will complete various scopes of work on two Prospector Drilling jack-up rigs and the semisubmersible rig Songa Dee.

Two Prospector Drilling rigs
Rig operator Prospector Drilling has chosen Semco Maritime to complete final installations at Prospector 5, a new state-of-the-art jack-up drilling rig. Prospector 5 will see follow-up installation of client supplied equipment for the rig's first assignment. Moreover, minor installation work is to be performed on another Prospector Drilling rig, Prospector 1.

Songa Dee (photo)
The 112 by 80 meters wide Norwegian operated semisubmersible rig Songa Dee is now moored at the Invergordon facilities deep water quay Queens Dock, with various electrical, structural, mechanical and pipe-work scopes to be performed over the next 60 days.

Frank Hall, General Manager Semco Maritime UK:

"Songa Dee is a good example of the type of large rigs that Semco Maritime is able to handle at the deep water facilities at Invergordon. The three orders bode well for our ambition to be the preferred leading provider of rig upgrades in the North Sea region."

As well as Songa Dee, the two Prospector Drilling rigs have arrived at Invergordon, and the Semco Maritime crew of approximately 60 rig upgrade specialists has commenced the work simultaneously at all three rigs.

Center for rig upgrades
The promising start for the newly established Semco Maritime rig yard facility is, not least, a result of a successful and seamless cooperation with the Port of Cromarty Firth.

Bob Buskie, Chief Executive of the Port of Cromarty Firth:

"We are pleased to support Semco Maritime's activities in Invergordon. The Port of Cromarty Firth is transforming, expanding and investing in facilities at Invergordon, particularly within logistics and agency services as well as new warehousing facilities, office buildings and expansion of laydown and storage areas."

For more than 40 years, the Invergordon area in Northern Scotland has delivered engineering work and support for the North Sea's energy sector. With its strategically important location and its position as Scotland's deepest harbor, the port has handled more than 650 rigs through the years.

The Bureau of Safety and Environmental Enforcement (BSEE) published an Advanced Notice of Proposed Rulemaking today in the Federal Register Reading Room soliciting public comments on improving the safety of helideck and aviation fuel operations on fixed offshore facilities. This notice is the most recent step in BSEE's continued efforts to strengthen safety on the Outer Continental Shelf (OCS).

"We know that transportation accidents account for the majority of fatalities on the OCS, and that helicopter-related accidents are a significant concern" said BSEE Director Brian Salerno. "We are looking at our regulations to ensure that the aviation related areas over which we have jurisdiction have the benefit of rigorous safety standards."

Specifically, BSEE is seeking comments on whether to incorporate in its regulations certain industry and international standards for the design, construction and maintenance of offshore helidecks, as well as standards for aviation fuel quality, storage and handling. The bureau is also soliciting information on past accidents or other incidents involving helidecks, helicopters or aviation fuel on or near fixed OCS facilities.

BSEE is responsible for the regulation of offshore facilities engaged in oil and gas operations, including the safety of helidecks and aviation fuel storage and handling on fixed offshore facilities. This notice begins the process of addressing any additional safety issues through new regulations.

The Advanced Notice of Proposed Rulemaking can be viewed hereThe public is invited to submit comments starting tomorrow. Comments can be submitted by any of the following methods:

Federal eRulemaking Portal: http://www.regulations.gov. In the entry titled Enter Keyword or ID, enter BSEE-2014-0001, then click search.

Mail or hand-carry comments to the Department of the Interior; Bureau of Safety and Environmental Enforcement; Attention: Regulations Development Branch; 381 Elden Street, HE3313; Herndon, Virginia 20170-4817

Shell has started oil production from the Gumusut-Kakap floating platform off the coast of Malaysia, the latest in a series of Shell deep-water projects.
The Gumusut-Kakap field is located in waters up to 1,200 meters (3,900 feet) deep. The platform is expected to reach an annual peak oil production of around 135,000 barrels a day, once fully ramped up. With oil production now under way, work on the gas injection facilities is continuing with an expected start-up during 2015.

"We are delighted to have reached this milestone with our partners," said Andrew Brown, Shell Upstream International Director, "Gumusut-Kakap is our first deep-water development in Malaysia, and uses the best of Shell's global technology and capabilities in deep water. The field is one of a series of substantial deep-water start-ups this year, driving returns and growth for shareholders."

This floating platform is the latest addition to Shell's strong portfolio of major deep-water projects. Assembling the vast structure, whose four decks total nearly 40,000 square meters, involved the world's heaviest onshore lift. The project uses Shell Smart Fields® technology to carefully control production from the undersea wells to achieve greater efficiency. Oil is transported to the Sabah Oil and Gas Terminal onshore at Kimanis, Malaysia via a 200 km-long pipeline.

The project has allowed Shell to share deep-water expertise with Malaysian energy companies, assisting in the Malaysian government's goal to create an offshore industry hub. The platform was built in Malaysia by Malaysian Marine and Heavy Engineering Sdn Bhd (MMHE).

Shell Malaysia Chairman Iain Lo said: "Shell is pleased to be able to play an active role in developing the nation's deep-water resources and deep-water service industry. Deep-water resources are critical to Malaysia's long-term energy security. The Gumusut-Kakap field is expected to contribute up to 25% of the country's oil production."

Gumusut-Kakap is the latest of more than 20 major deep-water projects that Shell has delivered around the globe. Shell began production from the Mars B development in the Gulf of Mexico through the Olympus platform in February this year. In August it announced the start of oil production from the first well at the Bonga North West deep-water development off the Nigerian coast. In September, Shell announced the start of production from the Cardamom development, the latest deep-water breakthrough in the Gulf of Mexico which is a high-value addition to the Shell's pioneering Auger tension-leg platform.
The Gumusut-Kakap project is a joint venture between Shell (33%, operator), ConocoPhillips Sabah (33%), PETRONAS Carigali (20%), Murphy Sabah Oil (14%).

• The Gumusut-Kakap platform was 100 % built by Malaysian Marine and Heavy Engineering Sdn Bhd (MMHE) in Johor, Malaysia, and is MMHE's largest ever structure.
• Around 5,000 local employees were directly involved in building the platform.
• It provides permanent living quarters for 140 crew members in four main modules, plus 11 technical buildings.
• Viewed from above, it covers an area of around 1.5 soccer fields.
• It was built using 676 kilometers of stainless steel tubes – enough to run the distance from the northern to southern tips of Peninsular Malaysia.

The construction team achieved the world's largest and heaviest onshore lift when the 23,000-ton "topsides" comprising four decks, including living quarters and technical buildings were lifted onto the hull in April 2012.

Claxton, an Acteon company, has released an infographic guide to well abandonment costs in the North Sea. Released on the eve of the Oil and Gas UK Offshore Decommissioning Conference, held annually in St Andrews, Scotland, to discuss decommissioning in the region, the infographic highlights the costs operators are facing as they plan future campaigns. Abandonment cost reduction is an area where Claxton helps operators in the North Sea and beyond, via a proven suite of rigless technology.

Claxton has significant experience in platform well abandonment and conductor recovery, having completed the world's first rigless platform well abandonment in 2003. More recently, Claxton carried out the first rigless recovery of a stuck BHA for Maersk on the Tyra East field. More than 280 conductor cutting and recovery projects have been carried out using Claxton's equipment and offshore crews, and the company has worked with Acteon sister company, OIS, to deliver pioneering multi-operator campaigns with the SWAT™ suspended well abandonment tool.

Jamie Hall, marketing communications manager, Claxton, said, "Our infographic, created from Oil and Gas UK's recent review of the North Sea market, highlights the scale of the challenge facing operators. Claxton has a long standing track record of reducing costs associated with platform well abandonment, which Oil and Gas UK estimates at around £4.8 million per well.

"We are also delighted to be sponsoring the annual Offshore Decommissioning conference dinner at the Fairmount Hotel in St Andrews. It is rewarding to be involved in such a significant event for the decommissioning industry, and our commercial team will be on hand during the event to talk to operators about how we can help to reduce their abandonment costs."

The new compressor in operation on the Kvitebjørn field in the North Sea from 17 September will increase production there by 220 million barrels of oil equivalent and extend the field's lifetime with eight years.

The compressor will help boost recovery rate and accelerate production on the Kvitebjørn field. (Photos: Harald Pettersen)

The new compressor contributes to an increase in the recovery rate at the Kvitebjørn field from 55% to 70%. "These are very profitable barrels, which make a considerable contribution to wealth creation on the Norwegian continental shelf.

Increased production and extended lifetime for the field also provides increased ripple effects across the entire value chain," says Kjetil Hove, senior vice president for operations in Development and Production Norway in Statoil.

Valuable modules
The compressor project is making a substantial contribution to the increased recovery of gas resources from the field, which has increased its reserves by 50% since the plan for development and operation was submitted in 2000.

The extra barrels from the compressor are equivalent to a medium-sized, separately developed field.

"Many people don't realize that these relatively small modules are able to contribute as much or more value as new fields and that they cost much less to develop because the platform is already in place," explains Statoil brownfield projects senior vice president Terese Kvinge.

The reason why the new compressor is being installed on a field that has been in production for some years is that pressure in the reservoir has gradually fallen as the oil and gas has been produced. By lowering the pressure on the platform, more can be produced.

The compressor module was built by Bergen Group Rosenberg (now Rosenberg Worley Parson Group) in Stavanger. The 1000-ton module was lifted into position during the summer of 2013.

This is the first phase of pre-compression on Kvitebjørn, but space has been left in the new module for a potential second pre-compression phase as well.

Kvitebjørn value chain
Rich gas and condensate (light oil) from Kvitebjørn are piped to Kollsnes near Bergen and Mongstad further north respectively.
After processing at Kollsnes, the dry gas is piped to continental Europe. The separated NGL is transported by pipeline to the Vestprosess plant at Mongstad for fractionation into propane, butanes and naphtha.

Condensate travels through the Kvitebjørn Oil Pipeline, which ties into the Troll Oil Pipeline II to Mongstad.

Eni has made a new oil discovery in Block 15/06, in the Ochigufu exploration prospect, in deep water offshore Angola. Oghigufu is the 10th commercial oil discovery made in Block 15/06. The new discovery is estimated to contain 300 million barrels of oil in place.

Ochigufu 1 NFW well, which has led to the discovery, will be brought into production in record time. The well is located at approximately 150 kilometers off the coast and 9.8 kilometers from the Ngoma FPSO (West Hub) and the closeness to Ngoma FPSO allows the increase of the resource base of the West Hub project, currently underway. The well was drilled by the Ocean Rig Poseidon Drilling Unit in a water depth of 1,337 meters and reached a total depth of 4,470 meters.

Ochigufu 1 NFW was directionally drilled in order to reach the targets in optimal position and proved a net oil pay of 47 meters, (34° API) contained in the Lower Miocene and Oligocene sandstones with very good petrophysical properties. The data acquired in Ochigufu 1 well indicate a production capacity equal to more than 5,000 barrels of oil per day.

Claudio Descalzi , Eni's CEO said: "This important discovery , which will be brought into production in record time, adds even more value to Block 15/06. Like the recent discoveries in Congo and Gabon, this new find exemplifies the results we can achieve by applying leading edge technologies to exploration, and substantiates the decision to refocus Eni on key oil and gas competences".

Studies are underway in order to evaluate an early tie-in to the Ngoma FPSO, already in location in the West Hub and designed to handle 100,000 barrels of oil production per day.

Eni is operator of the Block 15/06 with a 35% stake. The other partners of the Joint Venture committed to the block are Sonangol P&P (30% stake), SSI Fifteen Limited (25% stake), Falcon Oil Holding Angola SA (5% stake) and Statoil Angola Block 15/06 (5% stake).

Angola is a key Country in the strategy of organic growth of Eni, which has been present in the Country since 1980 with a daily production in 2013 of about 90,000 barrels of oil equivalent per day. In Block 15/06 the two oil development projects West hub and East Hub have already been sanctioned. The production start up of the West Hub project, through FPSO Ngoma, is expected by the end of 2014. In Angola, Eni is also operator of Block 35, located in the deepwater Kwanza Basin.

Cairn together with its joint venture partners is pleased to announce that the FAN-1 exploration well, offshore Senegal, has discovered oil.

The well, located in 1,427 meters (m) water depth and approximately 100 kilometers offshore in the Sangomar Deep block, has reached a Target Depth (TD) of 4,927 m and was targeting multiple stacked deepwater fans.

Preliminary analysis indicates:

• 29m of net oil bearing reservoir in Cretaceous sandstones

• No water contact was encountered in a gross oil bearing interval of more than
500m

• Distinct oils types ranging from 28° API up to 41° API indicated so far from
number of oil samples recovered to surface

• Initial gross STOIIP estimates for the FAN-1 well range from P90, 250 mmbbls,
P50, 950 mmbbls to P10, 2,500 mmbbls and are broadly in line with pre-drill
STOIIP estimates

As stated prior to the commencement of operations there are no plans for immediate well testing. Further evaluation will now be required to calibrate the well with the existing 3D seismic in order to determine future plans and optimal follow up locations to determine the extent of the discovered resource.
Once operations are completed on the FAN-1 well, the rig will move to complete the second well, SNE-1 where the top hole has been drilled pending re-entry.

This Shelf Edge Prospect targeting a dual objective in 1,100m water depth is in the Sangomar Deep block.

The FAN-1 well was drilled using the semi-submersible drilling unit "Cajun Express". It is the third well in Cairn's North West Africa program and first in Senegal.

Cairn has a 40% Working Interest (WI) in three blocks offshore Senegal (Sangomar Deep, Sangomar Offshore and Rusifique) ConocoPhillips has 35% WI, FAR Ltd 15% WI and Petrosen, the national oil company of Senegal 10% WI. The three blocks cover 7,490 km2.

Simon Thomson CEO Cairn Energy PLC said;
"The oil discovered in the FAN-1 prospect is an important event for Senegal and the Joint Venture.

We have encountered a very substantial oil bearing interval which may have significant potential as a standalone discovery. Furthermore, this result materially upgrades the prospectivity of the block with a proven petroleum system and a number of deep fan and shelf prospects established.

Work is already underway with the Joint Venture partners to determine follow up activity which is targeted for 2015 onwards.

Cairn looks forward to working with the Government of Senegal and our partners to realize the full potential from this large acreage position off the West coast of Senegal."

Bechtel has been selected by Louisiana LNG Energy, LLC to provide front-end engineering and design for a new midscale liquefaction facility and export terminal in Louisiana, south of New Orleans on the Mississippi River. The design will center on a modular approach, which shortens the construction schedule and accommodates future expansion.

"Bechtel brings world-class expertise in the engineering, design, and construction of LNG liquefaction projects coupled with leadership in modularization and Gulf Coast self-perform work," said Jim Lindsay, chief executive officer of Louisiana LNG Energy.

"This is an exciting project that will harness the region's energy potential," said Jack Futcher, president of Bechtel's Oil, Gas & Chemicals business unit. "We will apply our extensive project delivery experience to provide Louisiana LNG Energy the most efficient design for fast-track construction of the facility. We look forward to working with them."

The new facility will have an initial export capacity of 2 million metric tons per annum of liquefied gas and will use Chart Energy and Chemicals' proprietary liquefaction technology. The export terminal will be positioned to serve large liquefied natural gas (LNG) carriers. Completion of the project is expected in late 2017.

Bechtel is the global leader in the LNG industry. The company is responsible for a third of LNG liquefaction capacity under construction today, including four projects in Australia and the first LNG export facility in the United States.

Global energy company Repsol has selected Deep Sea Mooring (DSM) to provide a range of mooring services for their drilling operations on the Norwegian Continental Shelf.

DSM will be responsible for marine engineering and supplying the mooring equipment. The company will also assist in offshore operations, including both pre-lay and rig move.

Åge Straume, CEO of Deep Sea Mooring said: "Winning this contract further proves that major energy companies appreciate our experience, robust technology and competence in delivering complete mooring systems for the harsh environment of the North Sea."

He added that this was the first time the two companies have worked together: "It's always exciting to showcase our expertise with a new client and we look forward to developing a solid and long-term partnership with Repsol."

The framework agreement is set to commence immediately and last four years including options. Deep Sea Mooring will manage the contract from its headquarters in Bergen.

Statoil ASA (OSE: STL, NYSE: STO) farms down in Aasta Hansteen, Asterix and Polarled andexits two assets on the NCS for a consideration of USD 1.3 billion, including contingent payment.

Illustration: The Aasta Hansteen platform will be the largest SPAR platform in the world. (Illustration: GeoGraphic / Statoil)

Through this transaction Statoil monetizes on the Aasta Hansteen field development project, while retaining the operatorship and a 51 % equity share. In addition Statoil exits the non-core Vega and Gjøa fields. The transaction includes a farm down in four exploration licenses in the Vøring area. The buyer is Wintershall, a Germany-based energy company and a well-established player on the Norwegian Continental Shelf (NCS).

"We realize significant value, created through successful asset development. The transaction increases our flexibility to further strengthen our portfolio," says Arne Sigve Nylund, president for Development and Production Norway in Statoil.

The transaction consists of a cash consideration of USD 1.25 billion and a USD 50 million consideration contingent on Aasta Hansteen milestones. The accounting gain from the transaction is expected to be between USD 0.7-0.9 billion and will be adjusted for activity between the effective date 1 January 2014 and the closing date.

The transaction releases around USD 1.8 billion of capital expenditure for the period from the effective date until end of 2020. Statoil's production from the divested Gjøa and Vega assets in the first half of 2014 is 22.000 barrels of oil equivalent per day. The transaction includes a transfer of operatorship of the sub-sea field Vega. The transaction will not involve transfer of personnel.
"We have a strong portfolio of projects. This transaction focuses our NCS portfolio and further improves our capacity to invest in core areas," says Nylund.

Statoil will invest around 20 USD billion annually in the period 2014-2016. This includes NCS project Gudrun which started up April this year, while Valemon will come on stream towards the end of year. In addition projects like Aasta Hansteen and Gina Krogh are in the execution phase, while Johan Sverdrup and Johan Castberg are under planning. The exploration activity remains high with 50 exploration wells planned globally for 2014.

Statoil and Wintershall have signed an extended agreement to continue cooperating on EOR efforts and exploration. 
The effective date for the transaction is 1 January 2014. Closing is expected around year end 2014, pending government approval.
Strategic portfolio management

In recent years Statoil has undertaken a series of transactions to position Statoil as a well-capitalized, technology focused upstream company. Active portfolio management continues to realize substantial value that is channeled to further strengthening the company's growth potential. Total proceeds of around USD 20 billion have been realized through divestments by Statoil since 2010, including this transaction.

Recent portfolio optimization activity includes divestments internationally as well as on the NCS. Last year Statoil divested their holdings in two West of Shetlands fields, Rosebank and Schiehallion. The same transaction also included shares in Gullfaks and Gudrun.

Lambert Energy Advisory was financial advisor to Statoil on this transaction.