Merakes is the first exploration well drilled by Eni in the East Sepinggan Block, which was assigned to the Company in 2012 following an International Bid Round.

Eni has made an important gas finding in the Merakes exploration prospect, in the East Sepinggan Block, where Eni is operator with a 100% stake. The Block is located in the offshore East Kalimantan (Borneo), 170 kilometers south of the Bontang LNG Plant and 35 kilometers from the offshore Jangkrik field, also operated by Eni.

The finding was made through the Merakes 1 well which was drilled at a water depth of 1,372 meters and reached a total depth of 2,640 meters. The well encountered a significant accumulation of gas in the lower Pliocene clastic sequence. Merakes has crossed a hydrocarbon column of 60 meters in high quality sandstones.

Merakes is the first exploration well drilled by Eni in the East Sepinggan Block, which was assigned to the Company in 2012 following an International Bid Round. Merakes finding potential has been preliminary estimated to be 1,3 Trillion cubic feet (Tcf) of gas in place. The finding has further upside that will be assessed with a delineation campaign.

Claudio Descalzi, Eni's CEO said: "This new success further implements the Company's growth strategy in the Pacific Basin where, in addition to its presence in Indonesia, Australia and China, Eni recently signed new exploration contracts in Vietnam, Myanmar and China. Merakes finding is a significant one as it strengthens our position as operator in Indonesia. Moreover thanks to its proximity to the Jangkrik field, which is currently under development, this new gas finding could supply in the future additional gas volumes to the Bontang LNG plant. This new achievement proves once more the effectiveness of Eni's strategic approach to exploration, which is based on operating with elevated stakes in exploration phase to better valorize exploration success"

Eni has been operating in Indonesia since 2001 and currently has a large portfolio of assets in exploration, production and development which have an increasing importance in contributing to the overall Company's production growth. The company holds working interests in fourteen permits and is operator in ten of them. The exploration activities are located in acreage in the Tarakan and Kutei Basins, offshore Kalimantan, north of Sumatra, West Timor and West Papua. In the Kutei Basin in early 2014 Eni started the development activities of the deep offshore Jangkrik gas field in the Muara Bakau PSC. Eni also holds a participating interest in the development of significant gas reserves located in the Ganal and Rapak PSCs. Production activities are located in the Mahakam River Delta, East Kalimantan through the participated Company VICO Ltd (Eni 50%, BP 50%) operator of the Sanga Sanga PSC that provides an average equity production of 17,000 barrels of oil equivalent per day.

Shell announced on Wednesday a frontier exploration discovery offshore Gabon, West Africa. The well Leopard-1 encountered a substantial gas column with around 200 meters net gas pay in a pre-salt reservoir.

Leopard-1 is located around 145 kilometers off the Gabonese coast, west of Gambia. It was drilled in water 2,110 meters deep to a total vertical depth of 5,063 meters. Shell and partners are planning to undertake an appraisal program to further determine the resource volumes.

"Shell has been exploring in Gabon for over 50 years. This latest deep water discovery is a testament to the innovation of our explorers in pursuing new plays, and application of our global sub-surface expertise," said Andy Brown, Shell Upstream International Director. "We are proud to be sharing this success with CNOOC Limited, our partner in the license."

Leopard-1 was drilled in license BCD10, operated by Shell (75%). Second partner in the venture is CNOOC Limited (25%).

This frontier discovery follows recent deep water exploration successes in the heartlands for Shell Exploration in the Gulf of Mexico and Malaysia.

Statoil (OSE: STL, NYSE: STO) has sold its 15.5% participating interest in the Shah Deniz production sharing agreement, 15.5% share in the South Caucasus Pipeline Company (SCPC), 15.5% share in the SCPC holding company, and 12.4% share in the Azerbaijan Gas Supply Company (AGSC) to the Malaysian oil and gas company PETRONAS. The transaction value is USD 2.25 billion.

"Statoil has created significant value by participating in the development of this asset over the years and we are pleased to announce this deal with PETRONAS. The divestment optimises our portfolio and strengthens our financial flexibility to prioritise industrial development and high-value growth," says Lars Christian Bacher, executive vice president for Development and Production International in Statoil.

In recent years Statoil has strengthened its resource base and industrial opportunity set. To prioritise high potential future developments, Statoil has realised substantial value from transactions on the Norwegian continental shelf and internationally.

This portfolio optimisation continues to increase financial strength and flexibility to deliver on our strategy for high-value growth. Statoil's 2014 second quarter production from the Shah Deniz field was 38,000 barrels of oil equivalent per day.

Following the divestment, Bacher says, "We remain committed to our business in Azerbaijan, which continues to play an important role in Statoil's international portfolio."

The effective date is 1 January 2014. The transaction is expected to be closed early 2015, subject to approval from the relevant authorities.

Shah Deniz
The Shah Deniz field was discovered in 1999. It is located on the deep water shelf of the Caspian Sea, 70 kilometres south-east of Baku, in water depths ranging from 50 to 500 metres. Shah Deniz Stage 1 began operations in 2006. The Shah Deniz partners are currently producing approximately 26 million cubic meters of gas and 53,000 barrels of condensate per day, approximately equivalent to 225,000 barrels of oil equivalent per day.

The Shah Deniz field is operated by BP (28.8%) and the other partners are TPAO (19%), SOCAR (16.7%), Lukoil (10%), Nico (10%).

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."

VAALCO Energy, Inc. (NYSE: EGY) has announced that the Company has entered into the Subsequent Exploration Phase ("SEP") on Block 5 offshore Angola together with its working interest partner, Sonangol P&P, as provided for in the Production Sharing Agreement signed in 2006 with the Republic of Angola.

The SEP extends the exploration license for an additional three year period such that the new expiry date for exploration activities is November 30, 2017. The SEP requires the Company and its partner to acquire a 3D seismic program covering six hundred square kilometers and to drill two additional exploration wells. The seismic obligation has been satisfied with a seismic program already completed covering 1,058 square kilometers over the outboard portion of the block.

By entering the SEP, the Company is now required to drill a total of four exploration wells during the exploration extension period. The four well obligation includes the two well commitment under the primary exploration period that carries over to the SEP period. A ten million dollar assessment (five million dollars net to VAALCO) applies to each of the four commitment exploration wells, if any, that remain undrilled at the end of the exploration period in 2017.

As previously announced, the Company has contracted for the Transocean "Celtic Sea" semi-submersible rig to drill the first exploration well, the post-salt, Kindele-1 well. The Kindele well is targeting the Mucanzo sand (Pinda group) with a planned total depth of 2,250 meters in a water depth of 101 meters. Gross unrisked recoverable resources are estimated to be between 20-49 million barrels. The rig is currently estimated to be on location in mid-December 2014.
The decision to enter the SEP was made in part to remove uncertainty that the primary term of the exploration license would be extended by the Republic of Angola before the November 30, 2014 expiration date.

Steve Guidry, Chairman and CEO, commented, "We believe entering into the SEP is a sound strategy for the Company. Although the SEP comes with additional commitments, we believe this is a coveted block with potential in the deep syn-rift and sag play. The SEP allows VAALCO and its partner to properly assess the results of the current seismic reprocessing that is being merged with previously licensed seismic data through pre-stack depth migration. This will help us determine the best opportunities in the pre-salt horizons. The action we took to enter into the SEP removes the uncertainty of an exploration license extension and allows us to focus on our exploration activities on the block."

Operator Statoil has together with PL169 partners proved new oil resources in the D-structure in the vicinity of the Grane field in the North Sea.

The Grane platform in the North Sea. (Photo: Harald Pettersen)

Well 25/8-18 S, drilled by the rig Transocean Leader, proved an oil column of 25 meters in the Heimdal Formation. The estimated volume of the discovery is in the range of 30-80 million barrels of recoverable oil.

"We are pleased with having proved new oil resources in the Grane area," says May-Liss Hauknes, Statoil vice president for exploration in the North Sea. "Near-field exploration is an important part of Statoil's exploration portfolio on the Norwegian continental shelf. It provides high-value barrels that are important for extending the production life of existing installations."

The D-structure is located on the Utsira High, just seven kilometers north of the Grane field and in the immediate proximity of the Grane F oil discovery made by Statoil in 2013. The D-structure was originally penetrated in 1992 by well 25/8-4, which encountered just one metre of oil corresponding to about six million barrels.

"Well 25/8-18 S appraised the D-structure and proved substantial additional oil volumes in an excellent sandstone reservoir. This is a result of a recent re-evaluation of the area done by the partnership. New seismic and improved subsurface mapping have given us new confidence in the D-structure and allowed to mature it towards a drilling decision," says Hauknes.

"Tie in to the nearby Grane field is one of the development solutions that will be evaluated for the discovery," according to Gro Aksnes, Statoil vice president for area development in Operations West.

Exploration well 25/8-18 S is located in PL169 in the North Sea. Statoil is operator with an interest of 57%. The partners are Petoro AS (30%) and ExxonMobil Exploration & Production Norway AS (13%).

For further details on the results of exploration well 25/8-18 S, please see the press release issued by the Norwegian Petroleum Directorate >>

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."

GDF SUEZ E&P UK Ltd and BP today announced a new exploration discovery in the UK Central North Sea. The discovery, which spans GDF SUEZ operated block 30/1f (license P1588) and BP operated block 30/1c (license P363) was flow tested at a maximum rate of 5,350 barrels of oil equivalent per day. The discovery, referred to as 'Marconi' by GDF SUEZ and 'Vorlich' by BP, is located in the Central North Sea.

Left: Location map of Marconi/Vorlich CNS discovery

Ruud Zoon, Managing Director of GDF SUEZ E&P UK Ltd said: "This is an encouraging exploration discovery in a part of the Central North Sea that needs additional volumes of hydrocarbons to open up development options for several stranded discoveries. The discovery is our third successful well this year and demonstrates a continuing commitment by GDF SUEZ to an active exploration and appraisal drilling program on the UK Continental Shelf."

Trevor Garlick, Regional President of BP North Sea said: "As BP marks its 50th year in the North Sea and as the industry looks to maximize economic recovery from the basin, increasing exploration activity and finding new ways to collaborate will be critical to realizing remaining potential. This discovery is a great example of both."

The well was drilled by GDF SUEZ E&P UK Ltd as operator, with the Transocean Galaxy II jack-up rig under a joint well agreement between the two license groups.

Business and Energy Minister Matthew Hancock said: "We are determined to have set the right fiscal and regulatory regimes to make sure we can get the maximum possible economic extraction of oil and gas from the North Sea."

Transocean Galaxy II drill rig

"This discovery shows exactly what can be achieved in the North Sea if companies work together to maximize the considerable potential of remaining oil and gas reserves."

Exploration well 30/1f-13AZ encountered hydrocarbons in a Palaeocene sandstone reservoir in block 30/1c (license P363 operated by BP) and a subsequent side-track into block 30/1f (license P1588 operated by GDF SUEZ E&P UK Ltd) confirmed the westerly extension of the discovery.

Equity interests in the P1588 license are operator GDF SUEZ E&P UK Ltd (50.00%) and partners RWE DEA UK SNS Limited (27.78%) and Maersk Oil North Sea Limited (22.22%).
Equity interests in the P363 license are operator BP Operating Company Ltd (50.00%) and partner Total E&P UK Ltd (50.00%).

GDF SUEZ E&P activities in the UK
GDF SUEZ, through its subsidiary GDF SUEZ E&P UK Ltd is an increasingly significant player in oil and gas exploration and production in the UK Continental Shelf. Since entering the region in 1997, the company has built up a substantial portfolio of assets in the Central and Southern North Sea, and West of Shetland, comprising more than 50 licenses, 20 as operator*. The company entered the UK onshore market in October 2013 when it agreed to acquire a 25% share in 13 licenses located in Cheshire and the East Midlands from Dart Energy, which is operator of the licenses.

GDF SUEZ E&P UK is the operator of the Cygnus development, one of the most significant undeveloped gas fields in the North Sea and employs more than 300 staff and contractors in offices in London and Aberdeen. Cygnus is located in the Southern North Sea, 150 kilometers off the coast of Lincolnshire. It has gross 2P (proved and probable) reserves of approximately 18 billion cubic meters. First gas is targeted for late 2015.

*As awarded by DECC

• Lewek Constellation, together with Lewek Express, have successfully executed a full field installation for the VAALCO Etame Extension Project offshore Gabon           

• Total scope included installation of rigid and flexible pipelines along with the transportation and installation of two production platforms

• Contract value US$120 million, as previously announced on 7 August 2013

EMAS AMC, the subsea services division of EMAS, a leading global offshore contractor and provider of integrated offshore solutions to the oil and gas (O&G) industry, has announced that it has recently completed a US$120 million project for VAALCO Gabon (Etame) Inc. offshore Gabon in West Africa using the new build Lewek Constellation on her inaugural installation project.

The work scope included the transportation and installation of two jackets, topsides, flare booms and living quarters for the Etame and Southeast Etame / North Tchibala ("SEENT") platforms along with the installation of a new living quarters and a gas lift package onto the FPSO Nautipa.

Earlier this year EMAS AMC also successfully installed rigid pipelines and flexibles using the Lewek Express and performed 60 days of saturation diving to complete the subsea tie-ins using two dive support vessels on VAALCO's Etame and SEENT Fields offshore Gabon.

"We are delighted to have successfully completed this workscope for VAALCO, adding to EMAS AMC's established track record of delivering successful projects safely, efficiently and on time," said Mr Lionel Lee, Ezra's Group CEO and Managing Director.

"I would like to extend my gratitude to VAALCO for offering us this inaugural opportunity for the Lewek Constellation to showcase her heavy lift capabilities, as well as allowing us to display our subsea engineering expertise with the transportation and installation of pipelines. This was an important first project for the Lewek Constellation, and I am pleased to observe that the vessel and the project team displayed excellence in execution."

Mr Craig Devenney, VAALCO Energy, Inc. Construction Manager, said, "The EMAS AMC project team worked extremely well with the VAALCO team on a very significant part of our Etame Marin expansion project - the installation of the two new production platforms on our offshore Gabon permit. The Lewek Constellation, their impressive new build vessel, performed the heavy lifts of the platform, jackets and decks supported by the Lewek Express and associated dive support vessels for the pipe lay and subsea tie-in portions of the project. The successful work by EMAS AMC sets the stage for VAALCO to commence the drilling of production wells from the new platforms beginning in the fourth quarter of 2014. We look forward to an opportunity to work with the EMAS AMC project team again."

The Lewek Constellation is now headed to the Netherlands for the installation of her multi-lay tower and ancillary equipment for pipe lay activities, after which she will proceed to the Gulf of Mexico to begin work for Noble Energy in the first quarter of 2015.

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.

The Bureau of Ocean Energy Management (BOEM) has announced that it will prepare an Environmental Impact Statement (EIS) in support of a potential oil and gas lease sale in Cook Inlet, off Alaska's south central coast. 
The Notice of Intent to Prepare an EIS, which will be published in the Federal Register on Oct. 23, 2014, will open a public comment period extending through Monday, Dec. 8, 2014. During this time, BOEM will hold public scoping meetings and accept comments through www.regulations.gov. The Notice is available here.

The EIS analysis will focus on the potential effects of leasing, exploration, development and production of oil and natural gas in the proposed lease sale area, which BOEM identified in November 2013. That Area Identification reflected BOEM's approach of using scientific information and stakeholder feedback to proactively determine, in advance of the potential lease sale, which specific areas within a planning area offer the greatest resource potential and industry interest while reducing potential conflicts with environmental and subsistence considerations.

The area identified last November for the proposed Cook Inlet sale is closer to existing infrastructure, avoids nearly the entire area designated as critical habitat for the beluga whale and the northern sea otter, completely avoids the critical habitat for the Stellar sea lion and the North Pacific right whale, and reduces effects on national parks, preserves and wildlife refuges. It also excludes much of the subsistence-use area for the Native villages of Nanwalek and Port Graham that were identified during the last lease sale process in the area.

"We look forward to receiving thoughtful, substantial input on this EIS," said Dr. Walter Cruickshank, BOEM Acting Director. "In particular, we need to hear from residents of the communities along Cook Inlet on how the proposed leasing area is currently being used and what specific areas need extra attention. To address these issues, we will use rigorous science together with traditional knowledge and input we receive from the The Notice of Intent to Prepare an EIS is an early step in the leasing process."

The Notice does not indicate a final decision to hold a lease sale has been made. Rather, information gathered via the scoping process will help BOEM prepare the EIS, which in turn will inform a final decision on whether to hold the sale.

SCHEDULE FOR SCOPING MEETINGS
Date/Time Location
Nov. 12, 7pm Seldovia (Tribal Conference Center)
Nov. 13, noon Nanwalek (Tribal Community Center)
Nov. 13, 7pm Homer (Bidarka Inn)
Nov. 14, 7pm Soldotna (Kenai Peninsula College) 
Nov. 24, 7pm Anchorage (Loussac Library)

Currently, there are no active leases nor oil/gas exploration or development facilities in the Cook Inlet federal waters. The Department of the Interior's 2012-2017 Outer Continental Shelf Oil & Gas Leasing Program proposes one potential Cook Inlet Oil and Gas lease sale.

SBM Offshore announces it has signed a Production Handling Agreement (PHA) with Noble Energy to produce the Big Bend and Dantzler fields to the Thunder Hawk DeepDraft™ Semi (photo) located in 6,060 feet of water in the Gulf of Mexico (GoM).

Production fees associated with produced volumes are estimated to lead up to projected revenue of US$400 million to be delivered over the ten year primary contract period. First oil from Big Bend and Dantzler are expected in late 2015 and first quarter 2016 respectively. At these levels both fields will utilize a maximum of 85% of total daily asset capacity, and brownfield construction to upgrade the facility will be handled by Noble Energy.

The Big Bend field is 18 miles from the Thunder Hawk platform in 7,200 feet of water in Mississippi Canyon Block 698. Noble Energy operates a 54% working interest in Big Bend alongside W&T Energy VI, LLC with 20%, (a wholly owned subsidiary of W&T Offshore Inc.), Red Willow Offshore, LLC with 15.4% and Houston Energy Deepwater Ventures V, LLC with 10.6%.

The Dantzler field is 7 miles from the Thunder Hawk platform in 6,580 feet of water in Mississippi Canyon Block 782. Noble Energy operates Dantzler with a 45% working interest. Additional interest owners are entities managed by Ridgewood Energy Corporation (including ILX Holdings II LLC, a portfolio company of Riverstone Holdings, LLC) with 35% and W&T Energy VI with 20%. Big Bend and Dantzler will be developed via a dual pipe-in-pipe loop system.

The Thunder Hawk DeepDraft™ Semi, installed in July 2009, was developed as a Steel Catenary Riser (SCR) friendly floater solution. The deck and hull can be integrated quayside avoiding costly offshore lifting and system commissioning operations.

SBM CEO Bruno Chabas noted: "SBM Offshore is pleased that the Thunder Hawk platform allowed for a cost effective development solution for Noble Energy and its partners. The deepwater semi solution offers numerous advantages for subsea developments including reduced development capital, lower operating costs and an accelerated development schedule. This confirms the strategic value of the platform for deepwater Gulf of Mexico production, and we are excited to be offering valuable solutions in supporting the development of the Big Bend and Dantzler fields."

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."