BG Group (LSE: BG.L), a world leader in exploration and LNG announced on December 30, 2014, that its partner Petróleo Brasileiro S.A. (Petrobras), as the operator of block BM-S-11 in the pre-salt Santos Basin, has submitted the Declarations of Commerciality (DoC) to the Brazilian National Agency of Petroleum, Natural Gas and Biofuels (ANP) for three separate oil and gas accumulations in the Iara area, offshore Brazil. As part of the DoC, the consortium has suggested that the new fields be designated Berbigão, Sururu and Atapú West.

The Iara area is located approximately 250 kilometers off the coast of Rio de Janeiro, in water depths of around 2 270 meters. All fields contain good quality oil, of approximately 24 to 30 degrees API.

Iara and Entorno de Iara areas in the Santos Basin, Brazil

The DoC submission follows an exploration and appraisal program which began in 2008 and consisted of acquiring 3D seismic data, drilling seven wells as well as performing an extended well test. The encouraging results from this program continue to reinforce BG Group's view of gross recoverable volumes in the BM-S-11 Iara area. The DoC notification to the ANP includes the operator's estimates of total recoverable volumes of the three accumulations.

These three accumulations extend outside the BM-S-11 Iara concession area and into the Entorno de Iara Transfer of Rights area which is 100% operated by Petrobras and will therefore be subject to unitization agreements. Unitization of the Entorno de Iara area will be required with Berbigão to the north and south, with Sururu to the north and south and with Atapú West to the east.

The regulation requires a development plan to be submitted within 180 days of the DoC. However, because of the need for unitization agreements to be negotiated, the ANP may amend this deadline and allow submission of a unitized area development plan when the unitization agreement is signed.

The initial development of the unitized accumulations is expected to be based on three FPSOs, adding to the 10 production units currently planned for the Lula and Iracema areas. Subject to a complementary campaign for data acquisition, additional production units could be contracted by the consortium.

Ahead of the submission of the Development Plans for ANP, the partners will be working on the deployment and allocation of the initial planned FPSOs as well as negotiating the required unitization agreements.

The total amount of resource that BG Group believes will ultimately be recovered is not expected to be affected.

The DoC is another major milestone in the first phase of development of BG Group's significant interests in the region, marking the start of the production period of the fields.

BG Group has a 25% interest in the BM-S-11 concession, offshore Brazil (Petrobras, operator 65%, Petrogal 10%).

The Bureau of Safety and Environmental Enforcement (BSEE) announced this week that it is soliciting proposals for oil spill response research projects and will be investing up to $6 million to support these projects in 2015. In a Broad Agency Announcement (BAA) released on the federal government's business opportunities website,

www.FedBizOpps.gov, the bureau called for white papers focusing specifically on one of seven topic areas for proposed research covering oil spill response operations on the U.S. Outer Continental Shelf.

The deadline for submitting white papers is February 9th, 2015. Topics should be limited to the following:

Innovative Methods to Remove Surface Oil under Arctic Conditions;

Decanting Recovered Oil at Sea;

Quantifying In-situ Burn Efficiency;

Innovative New Uses of Chemical Herders to Enhance Oil Spill Mitigation Efforts;

Develop an Innovative Dispersant Spray Drift Model;

Determine the Effect of Various Deep-Ocean Conditions on Dispersant Effectiveness; and

Evaluate Dispersant Effectiveness of Subsea Applications in Ocean Brine Pools.

More information on the BAA can be found here or by searching for the BSEE solicitation E15PS00027 on www.fbo.gov.

On January 3rd, 2015, at 8.36 a.m. the Valemon gas and condensate field in the North Sea was brought on stream by Statoil and partners. Recoverable reserves from the field are estimated at 192 million barrels of oil equivalent.

"Valemon is one of several new projects on the Norwegian continental shelf that will help add value, activity and innovation, demonstrating well the long-term perspective that characterizes Statoil's activity on the Norwegian continental shelf," says Arne Sigve Nylund, executive vice president for Development and Production Norway.

Valemon is the second Statoil-operated platform to be put into production in the last nine months and also the first new platform to be operated from Bergen since Kvitebjørn came on stream 10 years ago.

The Valemon platform will be Statoil's first platform remotely controlled from shore, turning into a "normally unmanned platform" when the drilling on the field is completed in 2017.

Condensate from Valemon will be piped to Kvitebjørn for processing, and from there to Mongstad, whereas the gas will be sent to Heimdal for processing, and then transported to the market.

Heimdal, which was scheduled to be shut down in 2014, will thus get extended life as a gas hub in this part of the North Sea thanks to Valemon.

"By using the existing facilities at Kvitebjørn and Heimdal, as well as the existing pipelines, we have also reduced the costs of developing the Valemon field," says Nylund.

The Valemon topside was built in South Korea. The topsides EPC contract (engineering, procurement and construction) is a first for Statoil in Asia. The platform also has a high Norwegian content, 80 of the 120 mechanical equipment packages being delivered by Norwegian suppliers.

"The South Korean yard and a competitive Norwegian supply industry have together with a competent project organization ensured project start-up on schedule, with excellent HSE results," says Margareth Øvrum, executive vice president for Technology, Projects and Drilling.

Facts:
– Partners: Statoil Petroleum A/S (operator) 53.77 percent, Petoro AS 30 percent, Centrica Resources 13 percent, A/S Norske Shell 3.23 percent.

– When all wells have been drilled the investments in the Valemon field development project will total about NOK 22.6 billion. The platform will then have 10 production wells.

– Valemon is a high-pressure, high-temperature field.

– The steel jacket and living quarters are built at two yards in the Netherlands, the topsides in South Korea, and 80 of the 120 mechanical equipment packages on board come from Norway.

– The platform has 40 cabins, but during normal operations there will be some 17 people on board. In the longer term the platform will normally be unmanned.

Deep Down, Inc. (OTCQX: DPDW) ("Deep Down"), an oilfield services company specializing in complex deepwater and ultra-deepwater oil production distribution system support services announced it has received a large order for flying leads and ancillary equipment directly from one of the supermajor operators. The flying leads will be delivered and deployed in the Gulf of Mexico by the first quarter of 2016.

Ron Smith, Chief Executive Officer of Deep Down, Inc. stated, "We are pleased to receive this award on such a critical project and will continue to provide the best quality and service to our customers."

The first new-build semi-submersible drilling rig incorporating Wood Group Mustang Norway's (WGMN's) GG5000 floating hull design has been delivered to COSL Drilling Europe (CDE). The COSLProspector was designed to operate in water depths up to 1,500 metres (5,000 feet) and drill wells up to 7,600 metres (25,000 feet). The unit is planned for use on the Norwegian Continental Shelf (NCS).

WGMN was responsible for the basic design and participated in the detailed design of the semi-submersible hull and main marine systems. The 50,000 man-hour project was engineered to Norwegian Petroleum Directorate (NPD) standards.

"The delivery of the rig as designed is the result of a highly successful collaboration among WGMN, CDE and Yantai CIMC Raffles Shipyard," explained Otto Søberg, president of WGMN. "We worked closely with CDE to ensure the design of the rig would meet its needs and objectives and with the shipyard to deliver the rig as planned, thereby avoiding costly construction modifications common to the industry."

Prior to designing the COSLProspector, WGMN performed the modification design and engineering for three CDE drilling rigs: COSLPioneer, COSLInnovator and COSLPromoter.
"The success of the COSLProspector project is due to hard work from all parties involved. COSL, the yard and WGMN worked closely together, resulting in a rig that I know will do an excellent job for COSL and our clients," said Jørgen Arnesen, CEO of CDE.

WGMN is currently providing engineering services for another semi-submersible to CDE's parent company, China Oilfield Services Limited (COSL). COSL chose WGMN's A5000 semi-submersible drilling rig design for its new-build HYSY982 rig, which is planned for operation in the South China Sea. WGMN's scope is the result of another successful basic design project and includes detailed design work for the hull, marine systems and the integration of the drilling equipment package.

Greater Baton Rouge Business Report
Daily Report Staff

As crude oil prices continue to plummet, some oil companies are talking about scaling back operations and job cuts. But in the Gulf of Mexico, USA Today reports, business is booming.

Whoever is warning that slumping crude prices will curb oil production hasn't told the tenants of the bustling Port Fourchon on Louisiana's coast. There, cranes line two enormous slips, expanding capacity and building more facilities. Louisiana-based Bollinger Shipyards is constructing four massive dry docks able to serve 300-plus-foot vessels. Workers drive pilings into the ground for what will be the expanded site of Schlumberger, an oil-and-gas technology supplier.

Photo: Edmund D Fountain, for USA TODAY

All this activity soon will cater to huge floating facilities in the deepest waters of the Gulf of Mexico as they drill for and produce crude and other products.

"It's an unprecedented time," Port Director Chett Chiasson says. "This is the busiest it's ever been."

Even as crude's rampant price plunge rattles the industry—as of this morning the price per barrel still was hovering around the $50 mark—the Gulf of Mexico is on the brink of an unprecedented oil boom. Nearly five years after the Deepwater Horizon disaster briefly paralyzed gulf drilling, analysts predict deepwater oil production is headed into one of the biggest growth spurts in history.

Production is likely to reach a peak of 1.5 million barrels of crude a day by 2016, surpassing the previous record set in 2009.

In 2015, production will jump 21% from 2014 levels and grow even more in 2016—adding to America's already bulging oil production, says Imran Khan, a deepwater Gulf of Mexico analyst at energy consultants Wood Mackenzie.

Meanwhile, the number of permits for deepwater drilling increased from 14 in 2010 and 274 in 2011 to 603 in 2014, according to the Bureau of Safety and Environmental Enforcement, which oversees the drilling. Read the full story.

Total has completed the flare out of the Ofon field on Oil Mining Lease (OML) 102 offshore Nigeria. The associated gas of the Ofon field is now being compressed, evacuated to shore and monetized via Nigeria LNG.

"The flare-out of the Ofon field illustrates our commitment to developing oil and gas resources around our existing hubs in Nigeria. This important milestone of the Phase 2 of the Ofon project was achieved in a context of high levels of local content," commented Guy Maurice, Senior Vice President Africa at Total Exploration & Production. "The flare-out on Ofon is also significant for Total's environmental targets, representing a 10% reduction in the Group's E&P flaring. This achievement is a clear demonstration of Total's commitment to the Global Gas Flaring Reduction Partnership promoted by the World Bank."

The Ofon field is located 65 kilometers from Nigerian shores in water depths of 40 meters. The field initially commenced production in 1997 and is currently producing about 25,000 barrels of oil equivalent per day (boe/d). This flare-out milestone will allow for the gradual increase of production towards the 90,000 boe/d production target through monetization of around 100 million cubic feet of gas per day, followed later in 2015 by the drilling of additional wells. The execution of the project also involved significant local content, including the first living quarters platform to be fabricated in Nigeria.

Total E&P Nigeria operates OML 102 with a 40% interest, alongside the Nigerian National Petroleum Corporation (60%).

Total Exploration & Production in Nigeria

In 2012, Total celebrated fifty years of its presence in Nigeria. The Group's production in Nigeria was 261,000 boe/d in 2013.

Deep offshore developments are one of Total's main growth avenues in Nigeria, where the Group operates the Akpo field in OML 130 and launched the development of the Egina field in the same lease in 2013.

Offshore production also comes from OMLs 99, 100 and 102, which are operated by the Group as part of a joint-venture with NNPC. The main fields in these leases are Amenam-Kpono, Edikan and Ofon.

Total's onshore production comes from OML 58, which it also operates as part of its joint-venture with NNPC. A project is underway to increase the lease's natural gas and condensate production capacity to supply the domestic market.

In addition, Total has significant equity production in Nigeria from its interests in non-operated ventures, particularly the SPDC-operated joint venture (10%) and the Bonga field (12.5%). Total also has a 15% interest in Nigeria LNG, which operates six LNG liquefaction trains on Bonny Island with a capacity of 21.9 million metric tons per year.

Total deploys an assertive policy to create in-country value in Nigeria - the Group is helping Nigerian contractors to build deep offshore expertise, especially in the Niger Delta, a region that is home to more than half of Total's Nigerian employees and most of its operations in the country. Local content accounted for 60% and 90% respectively for Usan and the onshore OML 58 projects, and is likely to reach 75% for the deep offshore Egina development.

Leading international oil and gas service company, ASCO, has secured a new contract for the provision of supply base services in Sandnessjøen, Norway by Statoil, commencing in July 2015.

The ten-year contract, with a value of between US$22 million and US$25 million (NOK 100 – 130 million), is for supply base services in support of Statoil's drilling and operational activities in the Northern part of the Norwegian Sea from Sandnessjøen, including the Norne, Urd and Aasta Hansteen fields.

The contract scope of supply includes the provision of warehouse management, terminal handling, oil country tubular goods (OCTG) handling, as well as management of Statoil and BP's joint subsea base in Sandnessjøen. In addition, the six-year contract has two further two-year options.

Runar Hatletvedt, Managing Director for ASCO Norge said: "This is a significant win for ASCO Norge that highlights the strength of our expertise as well as our proven track record in oilfield support services in the region. We look forward to working with Statoil in Sandnessjøen."

ASCO also manages a supply base in Mtwara, Tanzania, on behalf of Statoil, BG, Petrobras and Ophir.

McDermott International, Inc. (NYSE: MDR) ("McDermott") has completed the installation of a 3,086-ton central processing platform ("CPP") topside using the tight-slot float-over method in the Kepodang gas field, Muriah Working Area, offshore Indonesia for PC Muriah Ltd, a wholly-owned subsidiary of PETRONAS. This brings the installation of all structures for the Kepodang project to a close.

McDermott commenced operations on this fast-track project, one month after the contract was awarded, in January 2013.

"The overall success of this project was made possible by the smart engineering of the float-over sequence to position the CPP topside next to an existing wellhead module already installed on the jacket at the installation site," said Hugh Cuthbertson, Vice President and General Manager, Asia Pacific. "Our global team of in-house engineering experts, high performance fabrication at our Batam, Indonesia yard and our strong supplier relationships in Indonesia were our key differentiators. We are also proud to be recognized by PETRONAS as "Best Contractor HSE Performer 2013" for our exemplary project safety record."

The project scope included procurement, construction, installation and commissioning of the CPP topside and jacket, a wellhead module, a wellhead platform and jacket, 1.7-mile-long 10-inch diameter infield flowline, and installation of remote control facilities at an onshore receiving facility. The total weight of overall facilities is close to 11,000 tons.

The Kepodang field is located approximately 112 miles northeast of Semarang, Central Java, in water depths of up to 230 feet, and is expected to supply gas to the Tambak Lorok power plant in Semarang, Central Java.

Chevron Corporation (NYSE: CVX) has announced a significant oil discovery at the Anchor prospect in the deepwater U.S. Gulf of Mexico. Anchor is Chevron's second discovery in the deepwater Gulf in less than a year.

"The Anchor discovery, along with the previously announced Guadalupe discovery, are significant finds for us in the deepwater Gulf of Mexico. We had one of our best years with the drill bit in 2014, reporting more than 30 discoveries worldwide and adding an estimated one billion barrels of new resources to our holdings," said Jay Johnson, senior vice president, Upstream, Chevron Corporation.

The Green Canyon Block 807 Well No. 2 encountered oil pay in multiple Lower Tertiary Wilcox Sands. The well, which was spudded in August 2014, is located approximately 140 miles (225 km) off the coast of Louisiana in 5,183 feet (1,580 m) of water and was drilled to a depth of 33,749 feet (10,287 m). Appraisal drilling will begin in 2015.

"Chevron's leading position in the Gulf, where we are expecting further growth in the near-term from recent project startups at Jack/St. Malo and Tubular Bells, is further underpinned by this discovery," said Jeff Shellebarger, president, Chevron North America Exploration and Production Company. "We currently have five deepwater drillships operating in the Gulf, two of which are focused on exploration activities."

Chevron subsidiary Chevron U.S.A. Inc. is the operator, with a 55 percent working interest in the Anchor prospect. Anchor co-owners are Cobalt International Energy, Inc. (20 percent), Samson Offshore Anchor, LLC (12.5 percent); and Venari Resources LLC (12.5 percent).

McDermott International, Inc. (NYSE:MDR) ("McDermott") announces that it has been awarded a contract to install the offshore jacket, deck and piles for the Ayatsil-A drilling platform for PEMEX Exploracion y Produccion ("PEMEX") in the Bay of Campeche Ayatsil field. The value of the award is included in McDermott's fourth quarter backlog.

Ayatsil-A jacket loaded onboard the Intermac 600 transportation and launch barge, ready for installation. (Photo: Business Wire)

"The Ayatsil-A installation award from PEMEX is a direct result of the substantial local capabilities and operations of McDermott in Mexico, and our demonstrated track record of safe and reliable platform installations for PEMEX in the Bay of Campeche," said Dominic Savarino, Vice President and General Manager, Americas. "Our unique ability to mobilize our versatile marine resources including the heavy-lift vessel, Derrick Barge 50, capable of lifting surface loads up to 4,400 tons, and the Intermac 600 transportation and launch barge was a critical component of the successful award for this fast-track installation project."

The Intermac 600 will launch the 8,400-ton jacket and the heavy-lift Derrick Barge 50 will complete the installation of the jacket, a 3,400-ton deck and other platform components in waters 400 feet deep. The total weight of the facility is approximately 15,800 tons.

The Ayatsil field is the largest discovery for PEMEX to date and is expected to boost production for the country by 150,000 barrels of oil per day. This contract award follows the successful delivery of the Ayatsil-B eight-leg jacket and deck by McDermott in July of 2014.

Increase needed to keep pace with inflation, preserve deterrent effect

As part of the Obama Administration's ongoing efforts to ensure the safe and responsible production of domestic offshore energy resources, the Bureau of Ocean Energy Management (BOEM) has administratively increased the limit of liability for oil-spill related damages from $75 million to approximately $134 million for offshore oil and gas facilities. This is consistent with recommendations to increase the liability cap from the National Commission on the BP Deepwater Horizon Oil Spill and other studies and represents the maximum increase allowable under the Oil Pollution Act of 1990.

"BOEM is taking an important step to better preserve the "polluter pays" principle of the Oil Pollution Act and further promote safe and environmentally responsible operations," said Acting Director Walter Cruickshank. "This is the first administrative adjustment since the Oil Pollution Act was enacted in 1990 and is needed to keep pace with inflation, which has increased 78 percent since then."

The administrative adjustment to the Oil Pollution Act of 1990 liability cap for offshore facilities is based on the significant increase in the Consumer Price Index (CPI) that has occurred since 1990. The liability cap is set by statute and may only be adjusted to address significant increases in the CPI. The increase to $134 million represents the maximum increase that may be implemented absent new legislation.

The increase applies to facilities handling oil and gas in federal and state waters seaward of the coastline. The liability cap applies to damages that result from oil spills, but does not apply to other liabilities such as oil spill removal costs, which remain unlimited. The rule also contains a mechanism to regularly update the limit of liability cap in the future to reflect changes in inflation over time based on the CPI.

The change to BOEM's regulations was proposed in February and the bureau fully considered all stakeholder comments before enacting this rule that will go into effect in January 2015.

ASL Environmental Sciences has a contract for a 3-year metocean-ice study program in Cook Inlet, Alaska for the proposed Alaska LNG Project terminal site. This turnkey metocean program includes program management, a PSO (protected species observer), vessel, HSE lead, data processing and analysis, and engineering inputs.

Photo :ASL trawl resistant LowPro5x7™ IceProfiler™/ADCP mooring

During the summer and fall of 2014 ASL deployed 3 Ice Profiler™/ADCP moorings close to Nikiski, Alaska on the Kenai Peninsula. Each mooring consisted of an Ice Profiler, ADCP, CT, and OBS Turbidity and was mounted in ASL's own designed bottom frame or a taut-line mooring. An additional 8 ADCP moorings have been deployed through the northern Cook Inlet June through October 2014. Sediment transport and sand waves will be studied in this highly dynamic area (6 knot currents). In later October the 8 moorings were replaced with 4 custom-built heavy duty frames each containing an Ice Profiler, ADCP, CT and OBS (see Figure 1). ASL will return to the sites biannually to download data and service the moorings.

ConocoPhillips (NYSE: COP) has announced first oil production from the Eldfisk II project in the Norwegian North Sea. 

"Eldfisk II joins Ekofisk South as the second major project startup in Norway since late 2013," said Matt Fox, executive vice president, Exploration and Production. "These projects will increase ultimate resource recovery and extend the field life of this premier legacy asset for years to come."

Photo: Ekofisk - North Sea. Credit: ConocoPhillips

Eldfisk II, along with Ekofisk South and other projects offshore Norway, will add approximately 60,000 barrels of oil equivalent per day to the company's production volumes by 2017.

The Eldfisk II project includes plans to drill 40 new production and water injection wells. One of four pre-drilled wells is currently online, with the remaining three anticipated to come on stream this month. Production from the field will ramp up over the next three years as additional wells are brought online.

The Greater Ekofisk Area, located approximately 200 miles (300 km) offshore Stavanger, is comprised of four producing fields: Ekofisk, Eldfisk, Embla and Tor. Crude oil from Greater Ekofisk's producing fields is exported via pipeline to Teesside, England, and natural gas flows via pipeline to Emden, Germany.

ConocoPhillips (35.1%) operates the Greater Ekofisk Area. The other Ekofisk co-venturers are Total (39.9%), Eni (12.4%), Statoil (7.6%) and Petoro (5.0%).

2H Offshore, an Acteon company, has teamed up with oil and gas industry leaders to develop a new design guideline for thermoplastic composite pipes (TCP) to advance the understanding and use of composite materials in the offshore industry. The Joint Industry Project (JIP) began in October and will take a year to complete. 2H teams in London, UK, and Houston, USA, are actively involved in the JIP. The work will build on existing knowledge and guidelines to achieve an industry accepted standard.

Tim Eyles, managing director, 2H, said, "Our involvement in this JIP underlines our commitment to supporting the use of composite materials within the offshore industry. Composite pipes have many advantages. Their good fatigue performance and reduced cross-sectional weight may help to overcome technical challenges in the industry, especially in deeper water and harsh environments. 2H has experience in using composite materials in risers and is committed to using emerging technologies to find the best technical solutions to meet the needs of our clients."

Statoil and its partners have decided to develop the Rutil discovery located in the Gullfaks Rimfaks valley in the North Sea. Providing close to 80 million barrels of oil equivalent, the development will extend the lifetime of the Gullfaks A platform.

The plan for development and operation (PDO) was submitted to the authorities on December 16th.

"We are pleased about the investment decision we have made that will extend the period of profitable production on the Gullfaks A platform. By using existing infrastructure and standardized solutions we are able to create great value for our owners," says Ivar Aasheim, senior vice president for field development on the Norwegian continental shelf (NCS).

"Statoil is currently implementing a major improvement effort to reduce costs and increase profitability to secure longterm activity and value creation on the NCS. The Gullfaks Rimfaks valley is a good example of this work," underlines Aasheim.

Gas and condensate will be transported in existing pipeline for processing in the gas processing facility at Kårstø north of Stavanger. The processed gas is transported to markets on the European continent.

"Production from the Gullfaks Rimfaks valley helps secure jobs and value creation from the Gullfaks field and throughout the whole value chain beyond 2030," says Kjetil Hove, senior vice president for the operations west cluster in Development and Production Norway (DPN).

The investment costs of the Gullfaks Rimfaks valley development are estimated at 4.6 billion 2014 NOK.
The Gullfaks Rimfaks valley development will consist of a standard subsea template with two simple gas production wells, and possibilities of connecting two more wells. The well stream will be connected to the existing pipeline to the Gullfaks A platform.

The Gullfaks Rimfaks valley is one of Statoil's fast track projects, aiming at realising resources quickly and cost-efficiently by for example using existing infrastructure while it is still available.

Production start is scheduled for the first quarter of 2017.

The license partners are Statoil (operator) (51%), Petoro (30%) and OMV (19%).