Amid low oil prices, pressure is growing to find industry wide solutions which can reduce costs. The documentation demanded today for subsea operations is time-consuming, complex and costly to deliver. Now a DNV GL led Joint Industry Project (JIP) involving twenty industry players has made a major step forward in addressing this global industry with the first issue of a Recommended Practice.

Working together the partners have invested considerable time to scope out and agree upon a set of typical subsea production systems (SPS) and functions with common terminology and a required minimum set of documentation between E&P operators and contractors. A first issue of the DNV GL Recommended Practice (RP) establishing industry guidelines and recommendations is now available to JIP partners and will be publicly available later this year. The work has been performed in Norway but has an international focus, not limited to appliance to the Norwegian Continental Shelf (NCS).

“The JIP group has made significant progression in standardizing the vast set of documents for designing, approving, manufacturing, verifying, operating and maintaining subsea equipment. The RP is an important element in DNV GL’s wider drive to streamline the global subsea sector and to increase efficiency, predictability and assure quality,” explains DNV GL JIP project manager, Jarl S. Magnusson. “We are now in dialogue with oil majors in Houston with the aim to build an even broader international network collaborating and capitalizing on the joint work.”

Halvar Larsen, Subsea Manager, Det norske says, “The collaborative approach to solving a common industry challenge through a JIP on neutral ground is the fastest way to develop a common global standard. Alignment between operators, contractors and suppliers and establishing a common understanding of the need for appropriate information have been interesting to witness through this JIP. In addition I see increasing interest from the industry and am really looking forward to using the results from this JIP in our next subsea project.”

Jan Ragnvald Torsvik, lead engineer of Life Cycle Information at Statoil and co-chairman of the project, is now operationalizing the draft RP in Statoil, implementing the RP result from 2014 with Statoil’s technical requirements for Life Cycle Information. This requirement will be adopted for new projects including development of the Johan Sverdrup field. Statoil is one of the first international E&P companies to implement the new standard.

“As a contractor, processing, handling and expediting various types of documents to and from suppliers, clients and third parties represents a significant portion of the man hour costs on typical subsea EPCI projects today,” says Torgils Skaar, engineering department manager at Subsea 7. “Aligning documenting procedures and paperwork will present marked financial savings and provide a higher level of predictability for the production, handling and administration of technical documents and time taken to undertake such tasks.”

The subsea documentation RP is linked to current sources of industry standards and practices and is open for industry review. To request a copy of the publicly available RP later this year, please register here. At a later stage, the RP may be included in industry guidelines, such as NORSOK, and/or as an amendment to relevant ISO standards.

The next phase of the JIP is now to extend the current scope of Subsea Production Systems (SPS) to also include subsea, umbilicals, risers and flowlines (SURF) and to further address documentation requirements between contractors and suppliers. Phase 3 of the JIP will be run in 2016 and will include among other activities to identify an improved and shared solution for governance of information and a finalizedDNV GL RP.

JIP partners:
Aker Subsea AS, Centrica Energi, Det norske oljeselskap ASA, DNV GL, FMC Technologies, GE Oil & Gas, GDF SUEZ E&P Norge AS, Kongsberg Oil & Gas Technologies AS, Lundin Norway AS, Oceaneering, OneSubsea, RWE Dea Norge AS, Statoil Petroleum AS, Subsea7, Subsea Valley and SUNCOR.

Observers: Norwegian Oil and Gas Association, Petroleum Safety Authority Norway

Steel forgings are important building blocks for subsea components and are often tailored to meet end-users’ specific requirements. This results in long delivery times and repeated follow-ups throughout the supply chain. With DNV GL’s new Recommended Practice (RP) ’Steel forgings for subsea applications’ these requirements are now harmonized. The implementation of the RP will enable reduced lead times, enhanced stock keeping, interchangeability of forgings and help to improve and maintain consistent quality.

“Unifying requirements for forgings into an acceptable common specification is an important step in the work we are doing together with the industry to increase subsea standardization,” says Bjørn Søgård, Segment Director Subsea with DNV GL.

The standardization of steel forgings was targeted as a high priority initiative in a report issued by the Norwegian Oil and Gas Association in 2014 and also highlighted by the Society of Petroleum Engineers. The RP (DNVGL-RP-0034) has been developed through a joint industry project (JIP) involving 21 companies, representing steel manufacturers, subsea contractors and oil & gas companies. It contains requirements for qualification, manufacturing and testing, and complements existing industry codes for subsea equipment.

“We are pleased that this initiative, which has involved all players in the value chain from Forgemasters, Subsea Suppliers to End Users, has produced a document that captures best practice and now enables the manufacture of forgings in a predictable and consistent way,” says David Llewelyn, Norwegian Oil and Gas Association.

To help support the efficient implementation of DNVGL-RP-0034 and to further strengthen the standardization work and quality processes established in phase one, a second phase of the JIP is now being planned and is still open for industry participants to join.

The following companies has been part of developing the RP in phase one of the JIP: Aker Solutions, Brück, Celsa, Chevron, Det Norske, Dril-Quip, Ellwood Group, Eni, ExxonMobil, FMC, Frisa, GE, Japan Steel Works, Lundin, OneSubsea, Petrobras, Ringmill, Scana Subsea, Shell, Statoil and Total.

Read more and download the Recommended Practice here.

Operator Statoil has together with PL602 partners made a gas discovery in the Roald Rygg prospect in the Norwegian Sea. This is the second Statoil discovery in the Aasta Hansteen area in spring 2015.

“Statoil has completed a targeted two-well exploration program around Aasta Hansteen which aimed to test additional potential in the area and make the Aasta Hansteen project more robust. Both wells, Snefrid Nord and Roald Rygg, have resulted in interesting discoveries, which will now be further evaluated for future tie-in to the Aasta Hansteen infrastructure,” says Irene Rummelhoff, senior vice president exploration Norway in Statoil.

The well 6706/12-3, drilled by the Transocean Spitsbergen rig in the Roald Rygg prospect, proved a 38-metre gas column in the Nise Formation with very good reservoir quality. Statoil estimates the volumes in Roald Rygg to be in the range of 12-44 million barrels of recoverable oil equivalent (o.e.).

Roald Rygg is located less than 7 kilometers west of the Snefrid Nord discovery. The estimated total volumes in the two discoveries correspond to about 25% of the Aasta Hansteen recoverable volumes.

Aasta Hansteen will be the largest SPAR platform in the world and is the biggest ongoing field development project in the Norwegian Sea. It is one of the main projects in Statoil’s portfolio. The plan for development and operations (PDO) was approved by the Norwegian Ministry of Petroleum and Energy in 2013. Production start-up is expected in 2017.

Exploration well 6706/12-3 is situated in PL602 in the Norwegian Sea. Earlier this year, Statoil increased its equity share in PL602 through transactions with Rocksource ASA and Atlantic Petroleum Norge AS.

Subject to government approval, the PL602 partnership will consist of Statoil Petroleum AS (operator, 42.5%), Petoro AS (20%), Centrica Resources (Norge) AS (20%), Wintershall Norge AS (10%) and Atlantic Petroleum Norge AS (7.5%).

Statoil and its partners are evaluating further appraisal activity.

The Maersk Developer drilling rig. (Photo: Jonathan Bachman - AP - Statoil) Statoil announced today that it has made an oil discovery in its Miocene Yeti prospect located in the Gulf of Mexico (GoM).

“The Yeti discovery expands the proven sub-salt Miocene play further south and west of the Big Foot field,” says Jez Averty, Statoil’s senior vice president, exploration for North America. “We are analyzing data to determine the size of the discovery in order to consider future appraisal options.”

The Yeti discovery was made in Walker Ridge (WR) block 160, which is located approximately 15 kilometers (9 miles) south of the Big Foot field, and 11 kilometers (7 miles) from the Cascade field. All of the blocks making up Yeti were accessed by the current owners in recent years.

Yeti was drilled with the Maersk Developer drilling rig, a sixth generation semi-submersible. Statoil reports that its drilling efficiency with Yeti was among the best of any well drilled in Walker Ridge, achieving a rate of approximately 123 meters (400 feet) per day. The rig has moved on and is currently drilling Statoil’s Thorvald prospect in the Mississippi Canyon block 814.

Statoil is the operator (50%) of Yeti, and its partners are Anadarko (37.5%) and Samson (12.5%).

Ovivo Inc. ("Ovivo") has been awarded a large contract to design and supply containerized modular fresh water makers for an offshore oil and gas production platform located in the North Pacific Ocean. The contract value is over $9 million Canadian and includes a custom designed production plant, using reverse osmosis membrane process. The equipment is scheduled for delivery in 2016.

The contract includes Ovivo's fresh water maker, through its heritage brand Caird & Rayner Clark. The units will produce potable water and turbine wash water directly from raw seawater at a temperature often below zero degrees Celsius. Life support systems, such as the fresh water maker, are necessary on offshore platform since it is difficult for supply boats to bring water to the platform in winter.

"This high specification engineering contract demonstrates that Ovivo possesses the technologies and equipment to meet the highest and most rigorous international requirements," said Marc Barbeau, President and Chief Executive Officer. "We booked large orders recently in the energy market thanks to our global platform which allows us to support our clients wherever their projects are located across the globe," added Mr. Barbeau.

GMC LTD has just completed the Basic Design of a self-installing Buoyant Tower for the Prinos Field Development for Energean Oil and Gas (Athens, Greece).

The design brief was twofold to find a way to extend the life and utility of the existing Prinos infrastructure, and to find a cost effective and flexible solution for the green field expansion of the existing Prinos facility.

The existing wellhead platforms (Prinos Alpha) was reanalyzed, and strengthened to accommodate drilling using the Energean newly acquired and commissioned Energean Force (formerly Glen Esk) tender assist drilling rig. The focus was on finding an efficient solution to extending the utility of the existing infrastructure. GMC delivered a design for the retrofit of the existing platform that was both efficient and leveraged the local supply chain and workforce to deliver the platform modifications.

For the greenfield solution, GMC developed a full field plan to connect the greenfield facilities to the existing offshore processing facility (Prinos Delta), including j-tube and riser retrofits.

The greatest contribution to the efficiency of the whole development project was a reconfigured and redesigned GMC Buoyant Tower which has been engineered to accommodate the unique challenges of the field location. Away from any oil and gas centers, the challenge was to develop an offshore facility design that could be fabricated locally and self-installed. The key benefit of the design was that it could be installed without the use of heavy lift vessels, and using only locally available marine assets.

Mathios Rigas, CEO, Energean explained: “GMC has proven to be a true partner in helping us develop solutions that meet Energeans’ unique challenges. GMC’s unique approach to addressing technical and commercial constraints has helped in driving this project forward.”

Dr Steve Moore, Technical Director, Energean, added: “GMC has been an integral part in developing and shaping our contracting and execution strategy on this project. They (GMC) have delivered a Basic Design which gives us confidence that the execution phase of the project will proceed according to schedule and plan.”

While Vibor Paravic, General Manager GMC explained: ”GMC has succeeded in leveraging our 20+ years of experience in working on technically challenging projects to deliver a bespoke solution for both the brownfield and the greenfield challenges faced by Energean. We look forward to the next phases of the project. “

Total E & P Angola has awarded the marine warranty services (MWS) contract for their flagship Kaombo project. Angola is a country of strategic importance for Total and Kaombo will secure the sustainable growth of Total E & P Angola’s offshore resources.

Delivered by DNV GL’s Noble Denton Marine Assurance service area, the MWS activities will focus upon the review of the design documentation and the execution of critical marine operations. The MWS team will support Kaombo project teams in assuring the project transportation and installations are conducted to recognized guidelines, standards and client internal requirements. The project sees the installation of the largest single award Subsea, Umbilical, Risers and Flowlines (SURF) contract ever to be placed. The extensive ultra deepwater development plan comprises the installation of 300 km of flowlines and 20 manifolds to connect 59 wells to the 2 VLCCs converted into turret moored Floating Production Storage and Offloading (FPSO) vessels.

The DNV GL MWS team is regularly engaged in providing marine consultancy and assurance services to all major operators in West Africa. Stephen Norman, Senior Business Development Manager for the UK and Sub Saharan Africa says “we have a proven track record with Total in Angola having previously worked on the CLOV, GirRI and Dalia projects and we are grateful to be recognized once again to support the delivery of a truly mega project.”

He adds “the work will be coordinated and managed by DNV GL’s London office who have recently completed the successful installation of the CLOV development. They will be supported with local attendances from regional DNV GL offices in Luanda, Singapore, Houston, Jakarta and Dubai.”

Sergio Garcia, Sub Saharan Africa Regional Manager says “Our Angolan team will be headed by a local MWS consultant who will drive engagement and training to support the Kaombo project using competent Angolan nationals who will be trained to support the development of MWS in the region. This will deliver long term benefits to the country and build upon DNV GL’s competence within Angola supporting clients with a more proactive delivery of local MWS”.

The Kaombo project is a development at Block 32, located about 150 km offshore Angola. It includes six fields, Gindungo, Gengibre, Caril, Canela, Louro and Mostarda which will be tied back to two converted FPSOs. The water depth in the development area extends from 1400m (Gindungo) to 1950m (Louro).

After thorough environmental analysis and substantial opportunity for public input, the Department of the Interior has issued a Record of Decision affirming Chukchi Sea OCS Oil and Gas Lease Sale 193 and the remaining oil and gas leases issued in 2008 as a result of the sale.

"The Arctic is an important component of the Administration's national energy strategy, and we remain committed to taking a thoughtful and balanced approach to oil and gas leasing and exploration offshore Alaska," said Interior Secretary Sally Jewell. "This unique, sensitive and often challenging environment requires effective oversight to ensure all activities are conducted safely and responsibly."

Upon issuance of the Record of Decision, BOEM may begin formal review of a company's exploration plan for the Chukchi Sea, which includes public engagement and additional environmental analyses. BOEM, BSEE and other Federal agencies will need to review and approve activities before any exploration activity can occur.

The original Environmental Impact Statement (EIS) for Lease Sale 193 was published in 2007 but subsequent legal challenges and Federal court decisions remanded the lease sale back to the Bureau of Ocean Energy Management (BOEM) for further analysis. The most recent court decision, from the U.S. Court of Appeals for the Ninth Circuit, specifically addressed BOEM's estimates of production levels from OCS oil fields that might be discovered in the Chukchi Sea.

In response to the court remand, BOEM conducted additional analysis using the best available data to estimate the highest amount of production that could reasonably result from Lease Sale 193 and incorporated that information into a Supplemental EIS (SEIS) that was published in February 2015. The Department issued today's decision after studying the information compiled in the SEIS and analyzing all comments received.

"Working closely with our partner agencies at the Federal, state and local levels, our analysts brought to bear the best science available to produce a careful and robust analysis," said Janice Schneider, Department of the Interior Assistant Secretary for Land and Minerals Management, who signed the Record of Decision.

Upon the Ninth Circuit court remand in January 2014, the Bureau of Safety and Environmental Enforcement suspended all leases issued via Lease Sale 193. With today's decision these suspensions are lifted.

"I am very grateful for the work that BOEM professionals put into this extensive analysis, and for the input we received from our stakeholders throughout the entire process," said BOEM Director Abigail Ross Hopper.

In February, the Interior Department released proposed regulations to ensure that future exploratory drilling activities on the U.S. Arctic Outer Continental Shelf (OCS) are done safely and responsibly, subject to strong and proven operational standards. Using a combination of performance-based and prescriptive standards, the proposed regulations codify and further develop current Arctic-specific operational standards that seek to ensure that operators take the necessary steps to plan through all phases of offshore exploration in the Arctic, including mobilization, drilling, maritime transport and emergency response, and conduct safe drilling operations while in theater.

Statoil and several other oil companies and nations joined together and have committed , for the first time, to end the practice of routine gas flaring at oil production sites by 2030.

CEO Eldar Sætre represented Statoil at the signing at the World Bank in Washington together with Norwegian foreign minister Børge Brende.

“Meeting the target of zero routine flaring by 2030 is a highly important contribution our industry can make towards mitigating climate change,” Sætre said in his speech in Washington today. “In our operations in Norway we do not carry out any routine flaring. This leading performance was made possible by a government determined to avoid waste and maximize value from its natural resources,” Sætre continued.

In 1971 Norway banned routine flaring. Coupled with a price on carbon equivalent of USD 65/ton CO2 today, these measures provided the necessary incentives for both the government and the industry to invest in production and export of gas. But globally every year, around 140 billion cubic meters of associated natural gas is wastefully burned or “flared” at thousands of oil fields.

This results in more than 300 million tons of CO2 being emitted to the atmosphere - equivalent to emissions from approximately 77 million cars.

Together with Statoil and Norway, eight other oil companies and eight other countries have endorsed the initiative recognizing that routine gas flaring is unsustainable from a resource management and environmental perspective.

They have all agreed to cooperate to eliminate ongoing routine flaring as soon as possible and no later than 2030.

“Lessons still to be learned on fifth anniversary of Macondo”

The International Well Control Forum (IWCF) has initiated a pilot scheme to trial new behavioral training aimed at reducing problem areas in well control safety relating to human factors.

Crew Resource Management (CRM) has been designed to improve non-technical skills and encourage a change in attitude to raise awareness of human factors in well operations.

The CRM course aims to create a unique environment in which wells personnel can practice dealing with simulated well control situations in an interactive way. Participants are given tools that improve the sharing of information in teams and optimize decision making skills. Teams also get more skilled in working together as a group and supervisors enhance their operational leadership abilities.

Several IWCF accredited training centers are running the pilot scheme, BP America in Houston, Maersk Training in Denmark, Shell and The Well Academy in the Netherlands.

Jan Willem Flamma, Director of Training Development at The Well Academy said: “Initially, participants have been sceptical as they feel they have completed IWCF courses to a high level many times before. However, after working on their first scenario in the simulator they soon change their mind and see the value of CRM training. We have received nothing but positive feedback and participants have told us it’s the best well control course they have done.

“CRM training and scenario based well control training has been carried out in the industry for some time but now five years after Macondo the industry is still struggling to implement the learnings.”

By taking part in the IWCF pilot we are confident CRM training will be promoted and convince operators, drilling contractors and service providers that it is the right thing to do.”

The course is focused on the individual worker in a team setting as ‘portable team skills’ are needed for whatever crew they find themselves in. The emphasis is on the candidates taking responsibility and during the course they are educated to identify the signs and indicators that reflect a decline in their own and others use of interpersonal skills. It will also enable them to identify when their behavior or their actions may be interfering with effective team working.

IWCF is the independent organization that sets global training standards for well control.

David Price, CEO of IWCF said: “While we know that improvements in technology and management systems have reduced safety incidents, a culture shift in behavior and attitude is still needed. Following the Macondo incident, investigations revealed that processes where people could question, challenge or take action were not always followed. On the fifth anniversary of Macondo it is important that these lessons are not forgotten. We believe that by changing behaviors and making individuals feel empowered to act, CRM training is an important step to ensuring the welfare of everyone on an installation.”

Founded by the oil and gas operators in 1992, IWCF administers well control training, assessment and certification programs and is committed to creating a step-change in well control knowledge. Since then, IWCF has certified over 160,000 people in almost every continent through more than 220 accredited training centers.

IWCF is investing in new facilities at its headquarters in Montrose, UK to improve training for well control assessors and instructors who address drilling operations and well intervention activities. The organization is also introducing new levels to well control training including a new level 1 introductory online course, which will be available free to anyone with an interest in the industry.

Noble Energy, Inc. (NYSE: NBL) has announced that it has acquired a 75 percent interest and operatorship of the PL001 License in the North Falkland Basin from Argos Resources Limited. The PL001 License covers an area of nearly 285,000 gross acres and is located to the northwest of the PL032 License, which includes the Sea Lion oil discovery. Edison International SpA has obtained the remaining 25 percent interest in the PL001 License.

Noble Energy and Edison will provide to Argos a 5 percent royalty override from all hydrocarbon development on the license. Noble Energy has identified the Rhea prospect as its initial target on the PL001 License. Rhea is a Cretaceous-aged stratigraphic trap prospect with multiple reservoir targets and total estimated gross mean unrisked resources in excess of 250 million barrels of oil. Water depth at the anticipated drilling location is approximately 1,550 feet, and the target total well depth is 8,760 feet. Rhea is anticipated to commence drilling in the third quarter of 2015 with Noble Energy's second slot on the 2015 Falkland Islands drilling campaign.

The Company's initial operated Falkland Islands prospect, Humpback, is now expected to commence drilling by early May 2015. Humpback, located in the South Falkland Basin, is the first of multiple stacked fan prospects clustered together in the Fitzroy sub-basin. Humpback has estimated gross mean unrisked resources of more than 250 million barrels of oil, with the cluster of prospects in the sub-basin totaling over one billion barrels of oil. The Humpback well, located in a water depth of approximately 4,170 feet, is targeted to be drilled to a total depth of 17,550 feet. Noble Energy's interest in the South Falkland Basin is 35 percent.

Susan M. Cunningham, Noble Energy's Executive VP of Exploration and New Ventures, stated, "The Rhea prospect diversifies our prospect inventory and upgrades our chance of overall success, without changing our total capital program for the year. This opportunity is in a proven petroleum system and is a strong complement to the vast number of remaining prospects on our acreage. Our Falkland Islands program, combined with our exploration well in Cameroon, give us the potential to discover substantial new resources through exploration this year."

Early Wednesday morning the dehydration and pumping area caught fire in the Permanent Abkatun platform in the Bay of Campeche.

Pemex's Emergency Response Plan was immediately put in action and approximately 300 workers were evacuated and transferred to other platforms in the area. Four people were killed and 45 workers were injured in the fire, two of them in serious condition.

One of the persons dead was a contractor for the Mexican oil service company Cotemar.

Eight firefighting boats were battling and controlling the emergency.

▪ U.S. could miss out on widely acknowledged economic and environmental benefits associated with LNG exports

▪ Bureaucracy is stalling legislation and issuance of export permits U.S. role as world’s leading energy producer is at stake

The United States is at risk of losing economic opportunity and the ability to solidify its role as a global leader in energy production unless the government moves to approve liquefied natural gas (LNG) exports, Rob Franklin, president of ExxonMobil Gas & Power Marketing Company, said on Monday.

“If policymakers don’t revisit and redress some significant legal and regulatory problems…then the U.S. could be left behind during one of the great, historic developments in global energy and trade,” Franklin said in a speech at the Johns Hopkins School of Advanced International Studies in Washington D.C.

The U.S. has long embraced open and free markets. Free trade benefits Americans in the form of more choices, higher wages, and better jobs. Franklin said that the export of LNG should be treated no differently from other exports such as agricultural goods, automobiles and computer products.

”LNG exports can provide the spur to further increase America’s natural gas production, providing all the attendant benefits that would generate,” he said.

ExxonMobil has embarked on a $10 billion project to convert the LNG regasification terminal at Golden Pass, Texas, into an LNG export terminal. In support of this effort, an application to export to non-Free Trade Agreement countries was submitted to federal officials more than two years ago, but no decision has been made. Permit applications for some two dozen other projects are also in the same state of bureaucratic limbo.

“If we are serious about having a U.S. LNG industry and capturing the tremendous opportunities in front of us then we need to ensure that the case of LNG exports does not become just another casualty of bureaucracy,” Franklin said.

Global LNG demand is expected to triple between 2010 and 2040. To put this into perspective, it means that the amount of incremental gas needed to meet global demand by 2025 will be almost double the size of the entire U.S. gas market today. Most of the new demand for LNG will come from existing and emerging markets in the Asia Pacific as well as the Middle East.

Franklin noted that the February 2015 report by the President’s Council of Economic Advisors concludes that LNG exports would increase U.S. GDP, create jobs, promote cleaner energy worldwide, while maintaining the competitive cost advantage for U.S. manufacturers. He also cited various other studies, which have generally reached the same conclusion that allowing LNG exports would benefit the American economy, and the greater the level of exports, the greater the benefit.

From an environmental perspective natural gas is the cleanest burning conventional fuel. When used for power generation it emits up to 60 percent less greenhouse emissions than coal – which have helped return emissions levels in the U.S. to where they were in the 1990s, despite the fact that the U.S. economy is six times larger now than it was then. The export of LNG will help manage emissions and the risk of global climate change.

In response to the findings of investigations into the Deepwater Horizon tragedy, and following a thorough evaluation of recommendations from industry groups, equipment manufacturers, federal agencies, academia and environmental organizations, Secretary of the Interior Sally Jewell announced on Monday, proposed regulations to better protect human lives and the environment from oil spills. The measures include more stringent design requirements and operational procedures for critical well control equipment used in offshore oil and gas operations.

“Both industry and government have taken important strides to better protect human lives and the environment from oil spills, and these proposed measures are designed to further build on critical lessons learned from the Deepwater Horizon tragedy and to ensure that offshore operations are safe,” said Secretary Jewell, who recently discussed the Administration’s energy reform agenda in remarks at the Center for Strategic and International Studies. “This rule builds on enhanced industry standards for blowout preventers to comprehensively address well design, well control and overall drilling safety.”

The proposed rule, which will be open for public comments, addresses the range of systems and equipment related to well control operations. The measures are designed to improve equipment reliability, building upon enhanced industry standards for blowout preventers and blowout prevention technologies. The rule also includes reforms in well design, well control, casing, cementing, real-time well monitoring and subsea containment.

The well control measures would implement multiple recommendations from various investigations and reports of the Deepwater Horizon tragedy, including the Bureau of Ocean Energy Management, Regulation and Enforcement/U.S. Coast Guard Joint Investigation-Forensic Equipment Analysis (September 2011); National Academy of Engineering (May 2012); National Oil Spill Commission (January 2011); Ocean Energy Safety Advisory Committee; Government Accountability Office and others. Interior’s Bureau of Safety and Environmental Enforcement (BSEE) thoroughly analyzed the results of the investigations, including nearly 370 specific recommendations, and conducted extensive outreach to derive further enhancements from stakeholder input, academia, and industry best practices, standards and specifications.

The blowout preventer, an essential piece of safety equipment used in offshore drilling operations, was a point of failure in the Deepwater Horizon event, but several other barriers failed as well. The cascade of multiple failures resulted in the loss of well control, an explosion, fire and subsequent months-long spill. In connection with this rulemaking, BSEE worked with a wide array of stakeholders to comprehensively address well control measures and equipment.

“We worked to collect the best ideas on the prevention of well control incidents and blowouts to develop this proposed rule – including knowledge and skillsets from industry and equipment managers,” said Assistant Secretary for Land and Minerals Management Janice Schneider. “This rule proposes both prescriptive and performance-based standards that are based on this extensive engagement and analysis.”

In May 2012, BSEE’s offshore energy safety forum brought together federal policy makers, industry, academia, and others to discuss additional steps the Bureau and the industry could take to continue to improve the reliability and safety of blowout preventers. Following the forum, BSEE received significant input and specific recommendations from industry groups, operators, equipment manufacturers, and environmental organizations.

“In addition to more stringent design requirements, the proposed rule requires improved controls of all repair and maintenance activities through the lifecycle of the blowout preventer and other well control equipment,” said BSEE Director Brian Salerno. “It would provide verification of the performance of equipment designs through third party verification, enhanced oversight of operations through real-time monitoring viewed onshore, and require operators to, during operations, utilize recognized engineering best standards that reduce risk.”

Today’s announcement is another step in the most ambitious reform agenda in the Department’s history to strengthen, update and modernize offshore energy regulations. Interior has made sweeping reforms for safe and responsible development, overhauling federal oversight by restructuring to provide independent regulatory agencies that have clear missions and are better-resourced to carry out their work, while keeping pace with a rapidly evolving industry. In the wake of the Deepwater Horizon blowout, explosion, and oil spill, BSEE strengthened preparedness and planning regulations applicable to oil and gas companies operating offshore, and raised the bar through new requirements for well design, production systems, blowout prevention, and well control equipment.

The Outer Continental Shelf is a critical component of our nation’s energy portfolio, accounting for more than 16 percent of the Nation’s oil production and about five percent of domestic natural gas production – bringing in revenues of over $7.4 billion dollars to the U.S. Treasury in 2014. There are more floating deepwater drilling rigs working in the Gulf of Mexico today than prior to the Deepwater Horizon spill, and drilling activity is expected to steadily increase over the coming year.

The public may submit comments on the proposed regulations during the 60-day comment period that begins April 15, 2015, when the proposed rule is published in the Federal Register. Comments may be submitted via regulations.gov, the federal government's official rulemaking portal. The proposed regulations are available here.

Subsea 7 S.A. (Oslo Børs: SUBC) has been awarded a contract worth approximately USD$200 million with a duration of approximately two years. The contract is for the installation of flexible lines for Petrobras' projects using Subsea 7's construction and flex-lay vessel Seven Seas, on a day-rate basis. The vessel has been operating for Petrobras under a similar day-rate contract since 2013 and will commence the new contract in direct continuation to the current one.

The Seven Seas is a vessel capable of operating in water depths up to 3,000 meters and is equipped with an advanced flexible pipe-lay system with top tension capacity of 430 tons. The contract work scope will be similar to that of other Subsea 7 Pipelay Support Vessels (PLSVs) operating under day- rate contracts in Brazil, providing engineering and installation services for client-supplied flowlines, umbilicals and subsea equipment.

Subsea 7's Senior Vice President for Brazil, Victor Bomfim, said: "This new contract for Seven Seas maintains our solid presence in the market for PLSVs in Brazil. We are proud to provide continuous service to Petrobras as it develops its complex oil and gas fields offshore Brazil."

Statoil announces that the Mdalasini-1 exploration well has resulted in a new natural gas discovery offshore Tanzania

The discovery of an additional 1.0-1.8 trillion cubic feet (tcf*) of natural gas in place in the Mdalasini-1 well, brings the total of in-place volumes up to approximately 22 tcf in Block 2.

The Mdalasini-1 discovery is located at a 2,296-metre water depth at the southernmost edge of the block. The new gas discovery has been made in Tertiary and Cretaceous sandstones.

"The Mdalasini-1 discovery marks the completion of the first phase of an efficient and successful multi-well exploration program offshore Tanzania," says Nick Maden, senior vice president for Statoil's exploration activities in the Western Hemisphere.

"Since the start of the program in February 2012, we have drilled 13 wells and made eight discoveries, including Mdalasini-1. We still see prospectivity in the area, but after appraising the Tangawizi-1 high-impact discovery, which was made in March 2013, there will be a pause in the drilling to evaluate the next steps and to mature new prospects," adds Maden.

Statoil has drilled the Mdalasini-1 well with a 100% working interest. Previously Statoil and co-venturer ExxonMobil have made seven discoveries in Block 2, including the five high-impact gas discoveries Zafarani-1, Lavani-1, Tangawizi-1, Mronge-1 and Piri-1, as well as the discoveries in Lavani-2 and Gilligiliani-1.

Statoil operates the license 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%. TPDC has the right to a 10% working interest in case of a development phase. Statoil has been in Tanzania since 2007, when it was awarded the operatorship for Block 2.

(*1 Tcf =180 million barrels of oil equivalent)