Responding to the industry's need for more guidance on procedures related to liquefied natural gas (LNG) bunkering, the US Coast Guard (USCG) has published two new Policy Letters on LNG Bunkering, Personnel Training and Waterfront Facilities. With regard to simultaneous operations (SIMOPS) USCG points to DNV GL's Recommended Practice for "Development and Operation of LNG Bunkering Facilities" for guidance.

Since US ports do not have LNG liquefaction and storage facilities yet, ships will have to rely on small-scale bunkering for the time being. This practice harbors certain risks that had not been addressed by US legislation until now, but are covered in DNV GL's Recommended Practice RP-0006: 2014-01 on the Development and Operation of LNG bunkering. In 2013, DNV GL developed the Recommended Practice to help facilitate the development of an international LNG infrastructure while waiting for the final release of the ISO 18683 workgroup document on systems and installations for supply of LNG as fuel to ships. It was released on 15 January 2015 and builds on DNV GL's RP.

USCG's LNG Expert Ken Smith, General Engineer at the Office of Vessels' and Facilities' Operating Standards, recently said: "DNV GL is already doing everything the USCG could hope for and more, and we recognize and appreciate the vast experience and in-depth expertise that DNV GL has when it comes to LNG as fuel, both here in the US and internationally. The recommended practices and standards that you issue and the work you have done in other technical committees are helping to shape our policies and regulations in this area."

"The early phases are essential when performing risk assessment in the context of LNG bunkering," Tony Teo, Technology and Business Director North America, explains. "They set the boundaries for risk acceptance, define the scope and lead either into a scenario-based or to a full quantitative risk assessment." Simultaneous operations like loading/unloading of cargo or passenger movements at the terminal during bunkering operations require special attention. Says Teo: "We recommend carrying out a full quantitative risk assessment with the aim to demonstrate that overall safety targets are met, evaluate and select safeguards and risk reducing measures and eventually confirm or develop safety zones. A quantitative or probabilistic risk assessment as against the consequence risk method is based on our 30 years data bank refined from the UK Health and Safety Executive."

Most of the LNG-fuelled ships and a large number of LNG tankers sailing the oceans today are built to DNV GL's classification rules. Further information on LNG safety as well as DNV GL's full Recommended Practice for Development and Operation of LNG bunkering facilities can be found on the DNV GL website: www.dnvgl.com/maritime/lng/lng-safety.html

VAALCO Energy, Inc. (NYSE: EGY) has announced that on March 2, 2015, the Company spudded the post-salt Kindele-1 well, its first exploration well on Block 5 offshore Angola. As previously announced, VAALCO contracted the Transocean "Celtic Sea" semi-submersible rig to drill the Kindele-1 well to a planned total depth of 2,250 meters in a water depth of approximately 100 meters.

Steve Guidry, Chairman and CEO, commented, "We are very pleased to announce this major step forward for our operations offshore Angola. After nearly nine years of continued commitment to our Block 5 license, we are embarking on an important phase in our efforts to explore for hydrocarbons from a second West African country. We continue to believe that Block 5 is within an area with potential in both post- and pre-salt formations including the syn-rift and sag play."

As previously announced in October 2014, VAALCO, together with its working interest partner, Sonangol P&P, entered into the Subsequent Exploration Phase ("SEP") on Block 5. Under the SEP, VAALCO and Sonangol P&P have committed to drill a total of four exploration wells during the exploration extension period, which expires in November 2017. The four-well obligation includes the original two-well commitment under the primary exploration period that carries over to the SEP period.

The Kindele-1 well will test a fault block adjacent to the Mubafo discovery which tested oil from the Mucanzo sand section within the Pinda group formations. The Kindele-1 will be drilled to a depth of 1,800 meters to evaluate the Mucanzo sand section. The well will then be deepened to the salt to an estimated depth of 2,250 meters for geologic and geophysical correlation. The well is expected to take approximately six weeks to drill to total depth.

Additionally, the Company is nearing finalization of the seismic processing in the outboard portion of Block 5. The seismic processing is being performed to image pre-salt structures as potential targets for future exploration wells on Block 5.

While many of us were putting Christmas trees up in our homes in December, BG Group was working with Petrobras to install the first Wet Christmas Tree (WCT) by using a vessel and cables, as opposed to rig, in the JV pre-salt Santos area, offshore Brazil.

A WCT is a device installed at the wellhead comprising a series of remotely operated valves to safely control the flow of fluids (oil, water and gas) from the reservoirs to the surface.

The WCT was installed in the well 7-SPH-2-SPS, in the Sapinhoá field, Santos Basin, at water depth of 2,130 metres.

"BG Group has strongly supported the development and implementation of this new technology in Santos field deepwater", said Shaun Hancock, VP Well Engineering in Brazil, "by providing technical studies and supporting the contracting of a second vessel, which is expected to start operations in mid-2016."

Substantial time savings

Andre Pinheiro, Principal Completion Engineer at BG Brasil. "It took less than two and a half days to install the first Wet Christmas Tree; including navigation time, the total time per well is around four and a half days, compared to 15 days using a Drillship Rig. This generates an approximate saving of $8 million per well using this new technique," he added.

The installation of the WCT and Production Base (BAP) on wire from the same vessel started in Brazil back in 2009 at the Petobras-owned field in the Espirito Santo Basin, said Shaun. "Due to deeper water challenges in our pre-salt fields, it has taken a few years to develop this technology for Santos environment."

"By the end of 2016, Petrobras expects most of Santos basin subsea Christmas trees and production adapter bases to be installed by cable," confirmed Shaun.

In the UK and North Sea alone, around 475 installations will eventually have to be decommissioned and the associated costs for the rest of this decade are expected to average at £1.3billion per year .

Accounting for a potential 40-50% of the cost of decommissioning an asset, well abandonment is an increasingly costly and complex activity to consider. Preparations must start early and in the North Sea, that time is already upon us.

This topic will be a key focus for the Society of Petroleum Engineers (SPE) on Tuesday, 21 April, as the Aberdeen Section hosts the 5th European Well Abandonment Seminar.

A number of major operators, service companies and industry bodies are set to highlight new and existing abandonment techniques and case studies, including Decom North Sea, GE Oil & Gas, Hess and Shell UK.

Ross Lowdon, chairman of SPE Aberdeen, said: "The number of decommissioning projects estimated for the future is the reason behind the rapid growth of the well abandonment sector, and this will only continue to increase.

"The North Sea is home to many leaders in modern well abandonment techniques and this forum is a hugely effective way for the industry to come together, sharing best practice and new technologies. In order to maximise efficiency whilst importantly keeping costs to a minimum and safety as priority, we must learn from the innovations of others."

This seminar will be of interest to anyone involved in, or planning for well abandonment across the drilling, completions, project, well integrity, environmental and commercial personnel disciplines.

Mr Lowdon continued: "I would urge anyone who is, or is likely to become involved in decommissioning to attend this event. We have an excellent programme of speakers who will cover some of the well abandonment industry's most pressing issues, which I am confident will stimulate conversation and collaboration."

New for this year is the pre-conference training day, 'An Overview on Well Abandonment'. This course will be presented by technical experts from Baker Hughes and Helix Well Ops and is a must-attend for anyone looking for an introduction or refresher on this specialist subject.

The pre-conference training day will take place on Monday, 20 April with the full seminar and exhibition following on Tuesday, 21 April. Both events will be hosted at the Aberdeen Exhibition and Conference Centre.

For seminar bookings, exhibition space and sponsorship opportunities, please visit www.spe-uk.org/aberdeen

Statoil was the apparent high bidder on 14 leases in the Central Lease Sale.

Statoil announced today that it successfully bid on 14 leases in the U.S. Department of the Interior's central region Gulf of Mexico lease sale 235, which occurred in New Orleans, LA.

"The acreage high bid today, completes our ownership of the Monument prospect, brings additional prospects in to our portfolio and strengthens our position in prioritised areas of the US Gulf of Mexico," says Jez Averty, Statoil's senior vice president, exploration for North America.

Statoil's winning bids are subject to review and final approval by the authorities.

Claxton Engineering Services, an Acteon company, has been awarded a contract with Statoil to supply conductor and internal centralizers to a minimum of 14 wells on the Gina Krog development, offshore Norway. The contract was finalized in Dec. 2014, and first delivery is scheduled for March 2015. Claxton is responsible for the design, fabrication, testing and installation of the units.

Vegard Dale, business development manager, Claxton, said, "Winning this order reinforces our position as the premier supplier of centralizers in the North Sea and underlines our capacity to understand new challenges and devise solutions."

Conductor centralizers form the interface between the platform jacket and well conductor, assuring vital integrity over the working life of the conductor. Having supplied a range of conductor and structural centralizers to major operators since 1992, Claxton has become the leading North Sea supplier, supplying and installing more than 5000 conductor guide centralizers.

Working out of bases in the UK, Norway, Singapore and Dubai, Claxton has provided engineering across the life of field for three decades with a focus on drilling risers, offshore decommissioning and subsea structures.
-Ends-

At OTC 2015, Parker will unveil new solutions for building tubing systems capable of meeting the immense challenges posed by higher pressures and corrosion mechanisms as oil and gas exploration and production moves into deeper offshore environments. The new technology will evolve the well-known ranges of small-bore tube fittings and valves from the Instrumentation Products Division of Parker Hannifin – a global leader in motion and control technologies.

Engineers constructing tubing systems for high pressure hydraulics, chemical injection systems and other higher-pressure topside and subsea offshore applications will be presented with new tube connection technology that provides easy-to-apply solutions for pressures up to 15,000 or 20,000 PSI.

At pressures of 15,000 PSI and more, tubing failures can pose an enormous threat to asset integrity. Ensuring asset integrity is a critical element of the new tube connection designs. Parker's engineering spans the spectrum of potential failure modes - from guarding against mechanical failures to combating corrosion mechanisms. The new connection technology is supported by Parker's heritage of materials expertise, which provides users with the highest-possible materials quality and the widest choice of corrosion resistant alloys to meet corrosion threats. Although metallurgy know-how is becoming quite common on the project teams run by operators and their engineering, procurement and construction contractors, Parker almost certainly has the broadest and deepest understanding of metallurgy in this market today - and will also help users with both expert advice and education.

With annual sales exceeding $13 billion in fiscal year 2014, Parker Hannifin is the world's leading diversified manufacturer of motion and control technologies and systems. Strong competitive advantages, a clear strategy and goals, consistent execution and performance, and many opportunities for growth, have allowed the company to consistently deliver strong shareholder returns. Parker has increased its annual dividends paid to shareholders for 58 consecutive fiscal years, among the top five longest-running dividend-increase records in the S&P 500 index.

Statoil, on behalf of the Johan Sverdrup partnership, will sign a contract with Aibel for the construction of the deck for the drilling platform on the field. The contract is worth in excess of NOK 8 billion.

The contract includes engineering work, procurement and construction (EPC) of the drilling platform deck. Engineering design will be undertaken at Aibel's office in Asker outside Oslo

The platform deck will be built at the Aibel's yard in Thailand and Haugesund, and at Nymo's yard in Grimstad.

Assembly and mechanical completion of the deck will be carried out at the Aibel's yard in Haugesund with delivery in 2018. Installation on the field is planned for the same year.

"The Johan Sverdrup field is one of the biggest discoveries on the Norwegian continental shelf that will, for its entire lifetime, be a pillar for Norwegian industry and value creation for the Norwegian society. On behalf of the partnership we are looking forward to a close cooperation with Aibel in order to ensure a safe and efficient delivery of this project," says Statoil's Arne Sigve Nylund, executive vice president of Development & Production Norway.

"Targeted efforts have been made to reduce cost and ensure a cost-efficient delivery and execution. We are therefore pleased to see that Norwegian suppliers have regained their competitiveness. The drilling platform is one of four platforms in the planned field centre and it is a complex and challenging project in itself. In order to succeed we are dependent on competent suppliers at all stages, and Aibel has been awarded this contract in a very competitive market," says Margareth Øvrum, executive vice president for Technology, Projects & Drilling Statoil.

Investment costs for full field development are estimated to be in the region of NOK 170-220 billion (2015 value) with recoverable resources of between 1.7 and 3.0 billion barrels oil equivalent.

Johan Sverdrup's first phase development involves four installations including an accommodation a drilling, a riser and process platform, as well as three seabed templates for water injection. The platforms will be connected by walkways.
The ambition is a recovery of 70%. At plateau production the field will account for roughly 40% of the total oil production on the Norwegian continental shelf. Start-up is planned for late 2019.

The Johan Sverdrup partnership consists of Statoil, Lundin Norway, Petoro, Det norske oljeselskap and Maersk Oil. The partnership has recommended Statoil as operator for all the field's phases.
The award of this contract is subject to approval of the Plan for Development and Operation in 2015 by the Norwegian Parliament.

Statoil Petroleum AS and Gassco AS have awarded the 2015 annual pipeline inspection contract to Fugro. The contract covers inspection of defined sections of subsea pipelines between Norway and continental Europe: Europipe 1, Europipe 2, Franpipe, Zeepipe and Norpipe. Inspection of pipeline sections for production fields in Norwegian waters is also included in the scope of work.

Fugro will utilize its Echo Surveyor Hugin 1000 autonomous underwater vehicle (AUV) equipped with EM2040 multibeam echosounder and EdgeTech Full Spectrum 120 & 410 kHz side scan sonar. The AUV will be deployed from Fugro's multi-purpose survey vessel Geo Prospector.

The inspection survey is scheduled to commence in May 2015 and the confirmed workscope has an estimated duration of 30 days.

Following the sanction of the Peregrino phase 2 project in December, Statoil together with its partner Sinochem submitted the Plan of Development (PoD) to the National Agency of Petroleum, Natural Gas and Biofuels (ANP) in Rio de Janeiro on 30 January.

The project entails a new well head platform and drilling rig (Platform C) and adds approximately 250 million barrels in recoverable resources to Peregrino field. The project entails investments of approximately USD 3,5 billion.

"Over its lifetime the project will generate several positive effects for Statoil's supply chain and substantial tax incomes for Brazil. Peregrino Phase II will strengthen our position in the country and reinforce our long-term commitment for the development of Brazil", says Pål Eitrheim, senior vice president and Brazil country manager.

Phase II solution, with Platform C in the foreground.

The submission of the PoD to the Brazilian authorities is an important milestone. The Peregrino Phase 2 will enable the extension of the economic life of the Peregrino field in Campos Basin, Offshore Brazil.

Brazil is a core area for Statoil and Phase 2 is an important and strategic element in Statoil's ambition to continue to build a strong position in the country. The Peregrino field has a good track record, with more than 90 million barrels produced since first oil, in April 2011.

Based on the current plan, Peregrino Phase II is expected to start production towards the end of the decade, but Statoil will make adjustments to the schedule should that be necessary. The project team will look into further savings through simplification, standardization and a tailor made execution strategy thus improving return over investment.

Project concept
The current solution consists of a wellhead platform with a drilling unit (WHP-C) tied-back to the existing FPSO Peregrino. The facilities contains standalone power generation and will export power to WHP-A.

Phase II will enhance production from the Peregrino field by increasing the number of production wells from a new area (Peregrino Southwest), which today is not reachable by the existent platforms A and B. A total of 21 wells – 15 oil producers and 6 water injectors – are planned to be drilled as part of the Phase II development.

All the production and injection wells in the Phase II development are planned to be drilled from one new drilling center, WHP-C installed in 120 m water depth.

With platform C, the company will increase well potential and be able to continue producing in Peregrino field for a longer period of time.

The expected recoverable resources from the Phase II development within the concession period (until end of 2040) are 250 million barrels.

McDermott Middle East, Inc. (NYSE:MDR) ("McDermott") announced on Monday that it has been awarded initial work for a significant power supply system replacement contract by Saudi Aramco for the Marjan field, offshore Saudi Arabia. Work is expected to be executed through the fourth quarter of 2016 and will be included in McDermott's first quarter 2015 backlog.

McDermott has successfully executed several offshore electrification projects for Saudi Aramco such as the one pictured. (Photo: Business Wire)

The overall brownfield project comprises integrated engineering, procurement, construction, installation ("EPCI") and replacement of the decks of two existing tie-in platforms, as well as the removal and salvage of existing gas turbine generators, and the installation of two new 115kV subsea power and communication cables. The initial scope of work awarded today, comprises the engineering, procurement, fabrication and load-out of the platforms and cable.

"McDermott's continuing relationship with Saudi Aramco and our commitment to the Kingdom of Saudi Arabia is reflected in this project award, as well as our ability to provide integrated services and an efficient technical solution within an active production field," said Tom Mackie, Vice President, Middle East. "We approach facility modifications with safety and our client's production in mind, using the latest technology, a full suite of design disciplines and proprietary McDermott processes to minimize operational interruption."

Engineering is expected to be carried out by McDermott's specialist teams in Dubai, U.A.E.; Al Khobar, Saudi Arabia; and Chennai, India, and the two new electrical decks are scheduled to be fabricated at the Dubai-based fabrication facility

Aker Solutions delivered the key subsea component for the system being developed by Marine Well Containment Company to limit environmental risks from oil and gas production in the U.S. Gulf of Mexico.

The Subsea Containment Assembly, or SCA, is designed to contain a well-control incident by connecting and creating a seal to prevent oil leaks. It can also be used in a cap-and-flow plan to direct fluid to vessels on the surface. The technology works under pressures as high as 15,000 psi.

The equipment was delivered to Marine Well Containment Company's team in Ingleside, Texas. It weighs 170 tons and consists of a stack of adapters and connectors assembled on a steel base. Aker Solutions developed the technology over three years, involving designers and engineers at the company's hub in Houston.

"This has been a collaborative effort involving ten oil companies and is a great example of how the offshore industry can pull together," said Alan Brunnen, head of Aker Solutions' subsea business. "Aker Solutions is pleased to have contributed its unique knowledge and experience in high-pressure subsea technology."

BP Egypt has announced another important gas discovery in the North Damietta Offshore Concession in the East Nile Delta. The "Atoll-1" deepwater exploration well, currently being drilled using the 6th generation semi-submersible rig "Maersk Discoverer," has reached 6,400 meters depth and penetrated approximately 50 meters of gas pay in high quality Oligocene sandstones. Expected to be the deepest well ever drilled in Egypt, the Atoll well still has another 1 kilometer to drill to test the same reservoir section found to be gas bearing in BP's significant 2013 Salamat discovery, 15 kilometers to the south.

Maersk Discoverer

Bob Dudley, BP Group Chief Executive, commented: "Success in Atoll further increases our confidence in the quality of the Nile Delta as a world class gas basin. This is the second significant discovery in the license after Salamat. The estimated potential in the concession exceeds 5 trillion cubic feet (tcf) and we now have a positive starting point for the next possible major project in Egypt after BP's West Nile Delta project."

Commenting on the discovery, Hesham Mekawi, BP North Africa Regional President said: "The Atoll discovery is a great outcome for our second well in this core exploration program in the East Nile Delta. It demonstrates BP's continuous efforts to help in meeting Egypt's energy demands by exploring the potential in the offshore Nile Delta. We are proud of our commitment to unlock Egypt's exploration potential that requires large investments to utilize using the latest drilling and seismic technologies."

Atoll-1 was drilled in 923m water depth around 80km north of Damietta city, 15km north of Salamat and only 45 km to the north west of Temsah offshore facilities. BP has 100% equity in the discovery.

BP has a long and successful track record in Egypt stretching back 50 years with investment
exceeding $25 billion, making BP one of the largest foreign investors in the country. In Egypt,
BP's business is primarily in oil and gas exploration and production.

To date, BP Egypt, in collaboration with the Gulf of Suez Petroleum Company (GUPCO),

BP's joint venture (JV) Company with the Egyptian General Petroleum Company (EGPC), has produced almost 40% of Egypt's entire oil production, and currently produces almost 10% of Egypt's annual oil and condensate production.

In addition, through BP's JVs with EGPC/EGAS and IEOC (ENI), the Pharaonic Petroleum Company (PhPC) and Petrobel currently produce close to 30% of Egypt's total gas production.

BP is working to meet Egypt's domestic market growth by actively exploring in the Nile Delta and investing to add production from existing discoveries.

The West Nile Delta (WND) Major Project is a strategic project for BP and its partner and is also critical to Egypt as it will provide more than one billion cubic feet per day (25% of Egypt's current production) of gas.

BP is a 33% shareholder of an NGL plant extracting LPG and propane, United Gas Derivatives Company (UGDC) in partnership with ENI/IEOC and GASCO (the Egyptian midstream gas distribution company).

BP is also present in the downstream sector through Natural Gas Vehicles Company (NGVC, BP 40%) which was established in September 1995 as the first company in Africa and the Middle East to commercialize natural gas as an alternative fuel for vehicles.

McDermott International, Inc. (NYSE:MDR) ("McDermott") announced on Monday that it has been awarded a large project for a new jacket, temporary deck and replacement umbilical by Qatar Petroleum for the North Field Alpha gas development, offshore Qatar. Work is expected to be executed through the second quarter of 2016 and will be included in McDermott's first quarter 2015 backlog.

The jacket installation calls for highly specialized engineering by McDermott to simulate the expected behavior of the structure during launch to ensure a safe and successful operation. (Photo: Business Wire)

The brownfield contract includes front-end engineering design verification, detailed engineering, procurement, construction, installation ("EPCI") and commissioning of a new six-legged, 15-slot wellhead jacket and temporary drill deck, with a total weight of approximately 5,000 tons. The work also includes the decommissioning, removal, replacement and pre-commissioning of 2.6 miles of composite umbilical and a fiber optic cable, in the Maydan Mahzam field.

"For more than 30 years, McDermott has successfully delivered numerous projects for Qatar Petroleum and its partners in Qatar's North Field, and we are pleased to further build on this relationship, as they focus on enhancing their oil recovery and production capability," said Tom Mackie, Vice President, Middle East. "We believe our ability to provide a fully integrated EPCI solution from one centralized location in Dubai will enable us to be more effective at ensuring certainty of delivery across all stages of the project allowing for more scheduling flexibility, and higher quality and safety, which is critical when working within an actively producing field, to ensure minimal operational interruption."

Detailed engineering, procurement and construction is expected to be carried out by McDermott's specialist teams in Dubai, United Arab Emirates with vessels from the McDermott global fleet scheduled to undertake the installation work in 2016.

Statoil has signed a contract with Allseas for installation of three platform topsides on the Johan Sverdrup field. The vessel will be installing the topsides for the drilling, processing and living quarter platforms.

Allseas will transfer the topsides to Pioneering Spirit (former Pieter Schelte) before they are transported to the Johan Sverdrup field. On the field pioneering spirit will install the topside on the steel jackets.

The drilling platform topsides will be installed in 2018, and the processing and living quarter topsides will follow in 2019.

The vessel has a lifting capacity of 48,000 tons. The heaviest lift will be carried out during installation of the processing platform topside that weighs around 26,000 tons.

After the topsides have been assembled onshore they will be transported offshore for installation. This allows more work related to completion and testing of the topsides to be performed onshore. The number of offshore man-hours will be reduced, which reduces both time and costs.

Constructed in South Korea, "pioneering spirit" is currently being completed in Rotterdam.

This contract award is subject to the Norwegian parliament's approval of the plan for development and operation of the Johan Sverdrup field in 2015.

On 21 February Statoil and its partners started up production from Oseberg Delta 2 in the North Sea. The field's recoverable reserves are estimated at 77 million barrels oil equivalent.

Oseberg Delta 2 is the tenth project in Statoil's fast-track portfolio to be completed.
The field, which is tied back to the Oseberg Field Centre, has been developed using two subsea templates with capacity for a total of eight wells.

The initial phase of the plan initially involves three oil producers and two gas injectors.

"Delta 2 is an important element in extending the lifetime of Oseberg. It provides a good example of how we can make lesser discoveries profitable by using existing infrastructure while it is still available," says Arild Dybvig, vice president for fast-track development projects in Development & Production Norway.

The start-up of the first well is in line with the development plan and takes place 38 months after the discovery became part of the fast-track portfolio.

The total investment is slightly less than NOK 7 billion, well below the estimated investment cost when the project was sanctioned.
"We've delivered yet another high quality, fast-track development according to plan and well within budget," says Torger Rød, senior vice president for subsea projects in Technology, Projects & Drilling.

Oseberg Delta 2 marks a further development on the Delta terrace where oil from two wells on an existing template has been produced since 2008.

"The new development includes gas injection that will give us a substantially greater recovery rate."

"There are also some good opportunities for the further development of the area and an exploration well has already been planned in the southern part of the Delta terrace," says Terje Gunnar Hauge, vice president for operations on Oseberg East.
The plan for development and operation was submitted to the Ministry of Petroleum and Energy on 30 May 2013.
Facts about Oseberg Delta 2
• Decision to commence project development: December 2011
• PDO approved on 10 October 2013
• Location: In North Sea, 14 kilometers south of Oseberg Field Centre
• Volumes: 77 million barrels of oil equivalent (32 mboe oil and 45 mboe gas)
• Depth: Approx. 100 meters, 3,100 meters under seabed
• Estimated lifetime: 20 years
Partners: Statoil (operator) (49.3%), ConocoPhillips (2.4%), Petoro (33.6%) and Total (14.7%)