Offshore facility operators can now consider an alternative and more cost-effective means to transfer personnel to and from their facilities, which is safe, efficient and regulatory compliant.

Statoil, Eni Norge, Lundin Norway, OMV and GDF SUEZ will collaborate on solving operational tasks tied to exploration in the Barents Sea.

The project, called BaSEC, Barents Sea Exploration Collaboration, will initially last for three years. The project will cover the Barents Sea, but with a special focus on the areas included in the 23rd licensing round.

The Barents Sea Exploration Collaboration will initially last for three years. (Photo: Ole Jørgen Bratland)

"We are taking operational responsibility seriously and have connected leading companies with operations in the Barents Sea to work together to find good and robust solutions for the tasks we see ahead, especially considering the new areas that have been opened in the Barents Sea south-east," says Statoil's Irene Rummelhoff, senior vice president for exploration in Norway. The project, which was initiated by Statoil and Eni Norge, will be led by Statoil in the first phase, but all the companies participate in the steering group and contribute to the working groups, and the work will start immediately.

"Our goal is to increase coordination and develop cost-effective solutions for exploration in the Barents Sea in both the short and medium term. We will collaborate with authorities, industry organizations and other relevant institutions to deliver on this. We aim to be effective and address the concrete actions that need to be taken and share relevant solutions and data with both the authorities and the rest of the industry. It is in our common interest to have robust exploration activity in the Barents Sea," says Rummelhoff.

The companies aim to find common solutions for operations in the Barents Sea, and through that contribute to high level of safety and emergency response. This will happen through sharing of data, cost-effective solutions, more collaboration and increased coordination.

The following working groups will be established:

• MetOcean and ice

• Environment and oil spill response

• Logistics and emergency preparedness

• Mobile drilling units

• Health and working environment

The criteria for participation is to either have made discoveries in the Barents Sea and/or have two or more operated licenses north of 73° N. The project will evaluate adding more participants after the awards in the 23rd licensing round.

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. “

Recently, LoneStar Energy Fabrication (LSEF) completed work on the $5.1 billion Big Foot drilling platform that is now ready to begin drilling in the Gulf of Mexico. This was the largest project in LSEF’s history, and the company was the primary fabricator of the 4,600HP modular drilling rig. The extended tension-leg platform (ETLP) is the industry’s largest and will operate in the Bigfoot oil and gas field, 225 miles south of New Orleans at a depth of 5,200 feet.

The project took LSEF two years to complete and tapped into the company’s 100 years of combined experience in the fabrication and rig up of offshore rigs, helidecks, modular living quarters and offshore buildings for the oil and gas industry.

“Big Foot is now onsite being moored and should begin drilling soon,” stated Lone Star Energy Fabrication’s President, Brian Shanklin. “This was an amazing project that aligned extremely well with our fabrication, rig up and commissioning capabilities. We had to compete against other, larger, more experienced and better known fabricators to win the Big Foot contract, but our proven ability to deliver high quality work, on time and within or under budget helped us win the job.”

Gargantuan does not begin to describe the size of the Big Foot project. The platform cost approximately $5.1 billion, will house 200 workers, and has the capacity to produce 75,000 barrels of oil and 25 million cubic feet of gas per day. Standing more than 40 stories above the Gulf of Mexico and weighing in at more than 8,200 tons, it will operate in 5,200 feet of water. At that depth pressures exceed 2,325 pounds per square inch.

Big Foot was not the first large offshore project for LSEF. The company also served as the primary fabricator for the $5 billion Olympus project that required more than 650,000 man-hours to complete. Olympus is now in operation 130 miles south of New Orleans and is known as the Mars B TLP DVA rig.

Located on 40 acres in the Cedar Crossing Industrial Park, just 20 miles south of Houston near the Houston Ship Channel, LSEF is perfectly located to work on jobs like Big Foot. With direct access to the Houston Ship Channel, as well as rail and air transportation, the company can tackle onshore and offshore as well as international projects of any size.

“We specialize in modular units that encompass rigs, living quarters and helidecks. As an example, the average sleeping quarters we build accommodates 100+ workers with sleeping, shower and galley facilities,” explains Shanklin. “When a job is completed it can easily be lifted by cranes and loaded onto barges to move into the Gulf or shipped out via rail or truck.”

The company has more than 100,000 square feet under roof and is a certified facility that complies with the most rigorous standards in the industry that includes: ISO 9001, API Q1, ABS (American), BV (French), DNV (Norwegian), SOLAS (British and USCG (American).

In addition to being one of the largest fabrication and rig up yards in the Houston area, it is also one of the top 10 located on the Gulf Coast. The Cedar Crossing complex provides Lone Star unlimited growth potential with 15,000 acres of raw land surrounding the existing facility.

Shanklin has a unique, but very valuable, background. “I started out working as a roughneck on an offshore platform rig. That gives me a unique perspective that very few people who build rigs have. I grew up in the business. I understand what the front line workers have to do on their jobs and how they live on these platforms,” says Shanklin. “You can’t get that perspective from a university or from talking to an engineer or reading about it. When you have lived on a platform a couple hundred miles from shore, like I have, you understand how important safety and quality construction really is,” he emphasizes.

LSFE has completed large projects in the past, has others underway and still more in the pipeline. The company just completed work on one 3,000 HP platform rig for a large Mexican oil company, and a second is being completed, tested and commissioned. Work is also underway on two 120-man living quarter projects along with work for other major oilfield service providers. LSEF was also a prime contractor on the Olympus project, completed in 2012 which was also one of the largest ETLP projects in the Gulf of Mexico.

While the recent drop in oil prices has had a major impact on shale drilling and related services, it has had a minimal impact on LSEF, because large oil and gas companies, LSEF’s primary customers, have had major project budgets in place for years, and most will be completed with the anticipation of higher oil prices in the future. Deepwater drilling and production are long term, multi-billion dollar projects that take several years to complete and are not impacted by short-term fluctuations in oil prices. Some experts even predict resurgence in Gulf oil drilling and LSEF is well positioned to benefit from future projects.

“We also do work for other companies around the world and the combination of offshore, land-based, and international work helps to stabilize our project load and ensures work continues to come in,” explains Shanklin.

Shanklin actually sees the downturn in the oil industry as an opportunity to attract high quality employees. “We are only as good as the people who work here,” he explains. “Most of our team has been built through referrals from existing employees. With the recent downturn, a lot of smaller fabrication companies have been forced to lay off highly qualified employees and our existing team members notify us when they identify a potential employee and we pick from the best available. We have built an excellent team with a broad range of certified skills that helps us continue to win contracts.”

LSEF has big plans for the future. “I believe we have established that we can deliver extremely large high quality projects, on time and within budget, and that is our foundation to grow the company,” Shanklin explains. “I believe the key to our future is to build upon our high quality, cost control culture, and focus on maintaining our safety record. Safety is paramount in this industry. You have to protect your people if you want to become an industry leader. We have made good inroads into international markets and I see LoneStar growing its international business significantly in the coming years,” he concludes.

Many developments are taking place these days in the Arabian Sea countries with agreements signed or discussed on various oil and gas projects creating major investment options.

Oman and Iran are in discussions regarding an underwater gas pipeline deal; Russia and Pakistan recently finalized a $2 billion LNG pipeline deal; India is in discussions with Iran for oil deals for E&P projects as well as exports; a block with proven gas reserves in the Mannar Basin in Sri Lanka just became available; while China obtained 40-year management rights in Pakistan’s Gwadar port opening up a route for transporting Middle East oil through a 3,000km long land route.

These examples highlight the various investment opportunities of the Arabian Sea region, where many more exist and are open to international interest. The Arabian Sea Region Oil & Gas Summit, will gather the international and national oil and gas industry to discuss and address the options both on countrywide and regional level.

The Summit will be held on 26th-27th May in the 5* InterContinental Hotel Muscat, Oman with the official support and endorsement of the Minister of Oil & Gas of the Sultanate of Oman focusing on the oil and gas business in Oman, India, Iran, Pakistan, Somalia, Yemen and Sri Lanka.

General Managers, Chairmen, Presidents and Executive Directors from the regional oil players and VP Business Development as well as Country Managers and Heads of Exploration from international oil majors have already confirmed their presence in the speaker line-up.

The Petroleum Federation of India, the Middle East Association and the International Gas Association – CEDIGAZ act as supporters of the Summit. Solarlite, the company that provides environmentally friendly solution to operators of mature fields, is a gold sponsor of the Summit.

More information about the Summit can be found on www.arabianseasummit.com and about the organizers, IRN, at www.irn-international.com.

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.

Intertek, a leading quality solutions provider to industries worldwide, is launching a new set of oil and gas decommissioning services to help manage costs and asset inventory.

The company showcased the new services, which focus on the circular economy approach, at Decom North Sea’s lunch and learn yesterday.

Raymond Pirie, Vice President of Exploration and Production said: “We have many years experience of asset inventory and asset integrity planning so bringing all our experience together in a complete solution for managing decommissioning is a natural progression for the business.

“Circular economy provides great opportunities for decommissioning, when planned correctly it can create greater cost control as well as ensuring that redundant materials are removed and used in the most effective way possible. Asset inventory is a key component of this, knowing what is on the asset will determine what can be done with each piece. This in turn has implications for timing, cleaning, cutting and removal options so early identification of the inventory is crucial to understand the reuse opportunities.”

With over 30 years experience in environmental consultancy services, Intertek will complete and manage the applications and permits associated with decommissioning projects for regulators and stakeholders. They will also utilize the expertise of their labs in waste analysis to provide waste characterization and ensure that pipelines are safe to prepare for removal. Once equipment has been decommissioned and repurposed, Intertek can then recertify it to ensure it is ready to reuse – the final step in the circular economy approach.

To assist with managing inventory and data for each asset, Intertek are using its GeoAIMS (Geographical Asset and Information Management System). GeoAIMS is a web-based application which allows users to interact, query and retrieve data from the database without needing GIS software. Using GeoAIMS for decommissioning projects means real-time updates of hazardous materials can be taken as and when they are located and identified. It will also allow the type and quantities of hazardous and residual materials to be logged and tagged to their exact location.

Mr. Pirie continued: “As well as the services to manage the decommissioning work, we can also provide training and manage the change for the people involved. The offshore environment is different for an asset in the decommissioning stage to one in production and we can help people to recognize that and develop the right culture.

“By offering our clients a full life-cycle approach to decommissioning, the client can have one dedicated point of contact and our knowledge of their project ensures that all the phases run effectively together.”

Fugro has set a new seafloor drill water depth record of 2,923 meters (9,589 feet) while completing a combined sampling and piezocone penetration testing (PCPT) borehole to 62 meters (203 feet) below the seafloor. Achieved using its ‘Seafloor Drill I,’ the single deployment in the Walker Ridge area of the Gulf of Mexico exceeded the previous water depth mark for seabed-based drilling technology.

Fugro’s seafloor drill recently set a new water depth record in the Gulf of Mexico.

Andrew Cooper, the Fugro Project Manager, was onboard the vessel for the record-breaking dive in early April 2015 and was pleased with the results. “The project team worked together to deliver a safe and productive operation while obtaining high quality data for our client,” he explained. “‘Seafloor Drill I’ performed as expected in these water depths and we are excited to pioneer the deeper depths demanded by the offshore oil and gas industry.”

Fugro also operates ‘Seafloor Drill II’ which adds coiled tubing PCPT capability and automated handling of drill rods and tools during subsea operations. Both seafloor drills are designed for offshore geotechnical and geohazard investigations.

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▪ 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.

McDermott International, Inc. (NYSE: MDR) announced today that it has received a large contract amendment from Al-Khafji Joint Operations (KJO) for a platform in the Hout field, located 26 miles east of Al-Khafji in the divided zone between Kuwait and the Kingdom of Saudi Arabia.

Work on the brownfield project is expected to be executed through the second quarter of 2017 and is included in McDermott’s first quarter 2015 backlog.

The large contract amendment is an addition to the initial scope for KJO’s Hout project awarded to McDermott in March 2012. The original scope was for an engineering, procurement, construction and installation (EPCI) project for structures including a tripod jacket, deck and flare tower and some 26 miles of 24-inch subsea pipeline. Additionally, McDermott was to carry out modifications to a number of existing platforms in the Hout field through its dedicated brownfield division in Jebel Ali.

“This award is a customer relationship success story,” said Tom Mackie, McDermott’s Vice President, Middle East. “We have always strived to deliver the best production solution to KJO and today’s award demonstrates continued confidence in McDermott’s capabilities.

“McDermott wins on our ability to deliver a differentiated, full scope EPCI solution for brownfield or greenfield projects to enhance the safety, operability and maintainability of our customer’s facilities. These unique capabilities set us apart for the large contract amendment at KJO’s Hout brownfield production facility.”

The scope includes EPCI for one new platform and two bridges with a total weight of approximately 3,300 tons, including significant modifications at the existing complex.

Engineering is expected to be carried out by McDermott’s detailed engineering teams. Structures are scheduled to be fabricated at the Company’s Dubai-based fabrication facility. Vessels from the McDermott global fleet are scheduled to undertake the installation work.

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%).