Oil & Gas News

Protea is well known for delivering high quality handling equipment including cranes, winches and launch and recovery systems for the offshore and onshore energy industries.

In addition to cargo handling equipment, Protea has also developed an extensive track record in the supply of personnel lifts for operations in hazardous areas.

12Protea PersonnelLiftsPhoto credit: Protea

“Both onshore and offshore, the safety of personnel when accessing equipment at height is key. We have applied our knowledge of the design, build and supply of safety critical handling equipment to develop a range of personnel lifts that can be tailored for specific applications.” highlighted Protea’s Global Sales Manager, Graham Manning.

Most recently Protea delivered a scissor lift for use on an offshore semi-submersible drilling rig. An electrically powered unit with an integral Hydraulic system to operate the lift and drive system, it can safely lift 2 personnel and their equipment to a height of 13m.

The system has a total lift capacity of 300kg and fully complies with all appropriate offshore design codes and regulations including DNV-OS-E101 Drilling Plant, LA 2.22 Standard for Certification – Lifting Appliances and EN 280:2013 Mobile Elevating Platforms.

In addition, Protea has also developed a range of rig elevators for land and offshore drilling applications. Available with lift capacities up to 200kg, these proven elevators allow the safe transport of workers from ground level up to the rig floor.

“Lifting people as opposed to cargo presents a number of unique challenges. However, with our experienced design team, we have developed a successful range of high quality personnel lift products that tailored to the specific needs of our clients - once again demonstrating our capability to deliver standard products, bespoke design and unique solutions’ commented Tomasz Paskiewicz, Protea CEO.

14APIlogoThe API has called on the administration to maintain and promote U.S. oil and natural gas development through the Bureau of Ocean Energy Management’s (BOEM) 2017-2022 offshore program, API Group Director of Upstream and Industry Operations Erik Milito said in a briefing with journalists on April 26.

“Rising U.S. production has dramatically increased our ability to protect consumers and the U.S. economy from energy shocks even within a low price environment,” said Milito. “Forward-looking energy policy recognizes long lead times needed for offshore energy development. The nation’s long-term energy security can only be ensured with a lasting commitment to expanding offshore oil and natural gas development to new areas.”

In 2010, over 30 percent of the oil and 11 percent of the natural gas produced in the United States was produced in the Gulf of Mexico, according to the U.S. Energy Information Administration (EIA). New projections by the EIA estimate that Gulf of Mexico production will increase to record high levels in 2017. This and other data have informed BOEM’s analysis, recently released as part of the 5 year program’s decision document, and led the agency to state that “there is no reason to exclude any of the proposed program areas in the Proposed Program Options based purely on the price of oil and gas.”

“The five year program is a critical part of our nation’s ability to secure affordable and reliable energy and create jobs for future generations of Americans,” said Milito, ahead of the public hearing held in Washington, D.C., on offshore areas in the program. “Too many promising areas are already excluded from the proposal, taking off the table thousands of potential jobs and billions of dollars in potential government revenue. Knowing that oil and natural gas will be needed for many more decades to come, the Department of the Interior should promote robust development of U.S. offshore energy resources and recognize the Arctic and Gulf of Mexico as core components of the five year program.”

API is the only national trade association representing all facets of the oil and natural gas industry, which supports 9.8 million U.S. jobs and 8 percent of the U.S. economy. API’s more than 650 members include large integrated companies, as well as exploration and production, refining, marketing, pipeline, and marine businesses, and service and supply firms. They provide most of the nation’s energy and are backed by a growing grassroots movement of more than 30 million Americans.

By Reid Porter, API

8Statoil huldra 468Hereema Marine Contractors Nederland SE will remove the platform and transport it to shore, while AF Offshore Decom AS has been awarded the contract for disposal and recycling of the platform.

Photo credit:  Statoil

The Huldra field is a Statoil- operated gas and condensate field on the Norwegian Continental Shelf, North East of Bergen. The field came on stream in November 2001 and on plateau the field produced 10, 3 MSm3/day.  

The gas and condensate production was closed down 3. September 2014. Previously the jack up rig West Epsilon has been awarded the contract for plugging the six wells at Huldra during 2016. On behalf of the partners Statoil has now awarded two new contracts for removal, transportation, disposal and recycling of the Huldra platform.

• The Engineering, Preparation and Removal (EPR) contract has been awarded to Heerema Marine Contractors Nederland SE.

• The contract for disposal and recycling of the platform has been awarded to AF Offshore Decom AS, a subsidiary of AF Gruppen ASA.

The total weight of the platform is approximately 10.000 tons, distributed over a 5, 000 ton topside and a 5, 000 ton steel jacket. It is expected that more than 95 percent of the platform will be recycled.

The plan is to remove the Huldra platform during 2019 with the subsequent disposal and recycling work taking place at AF Offshore Decom’s environmental base in Vats, Norway within the first half of 2020.

The platform is being removed according to the Ospar convention, stating that oil installations no longer being used as a main rule shall be removed.

18BSEElogoSecretary of the Interior Sally Jewell and Director of the Bureau of Safety and Environmental Enforcement Brian Salerno have announced final well control regulations to reduce the risk of an offshore oil or gas blowout that could result in the loss of life, serious injuries or substantial harm to the environment. The regulations represent one of the most significant safety and environmental protection reforms the Interior Department has undertaken since Deepwater Horizon, and builds upon a number of reforms instituted over the last six years to strengthen and modernize offshore energy standards and oversight.

- Final Well Control Rule

- Final Well Control RIA

- Reforms Since Deepwater Horizon

- Well Control Final Rule Fact Sheet

On April 18, 2016, Goliat was the first oil field to come on stream in the Barents Sea. The field applies several ground-breaking technologies, which will also benefit the industry in future developments. The Goliat project development execution has contributed to substantial ripple effects, positively impacting the supplier industry in all of Norway, and Northern Norway in particular. Goliat operations will deliver considerable income both to the state and the partnership in the years to come.

1 1Goliat EniPhoto credit: © Eni Norge

“This is a proud moment for everyone in Eni Norge. It is the culmination of years of hard work by many dedicated people. We are now entering into a new phase as operator on the Norwegian continental shelf. The start-up of production from Goliat is an important milestone in Eni’s growth strategy”, says Andreas Wulff, External Communication Manager.

Production at Goliat started safely in the evening of March 12, 2016, and was followed by a rapid production ramp-up of all wells. Full re-injection of associated gas into the reservoir has started and re-injection of produced water in order to minimize environmental impact will soon commence.

Eni, operating through its subsidiary Eni Norge AS, has been present in Norway since 1965. The company has interests in exploration licenses and producing fields such as Ekofisk, Norne, Åsgard, Heidrun, Kristin, Mikkel and Urd, with a total production in 2015 of 106,000 boed. With Goliat, eni Norge production will grow above 160,000 boed net to Eni.

1 2Eni Goliat Illustration Overview visco Large 001Eni Goliat illustration overview. Credit: © Eni Norge.

Specially built for the Barents Sea
The Goliat field is located 88 km north west of Hammerfest. Goliat is the world's largest and most sophisticated circular, floating, production, storage and offloading (FPSO ) unit. The platform is fully winterized and is specially designed for operations in the Barents Sea. It is powered from shore through a subsea electrical cable, which, at the time of construction, was the longest of its kind ever made. Power from shore reduces CO₂ emissions from Goliat by up to 50 per cent. This equals the emissions from 50 000 cars annually.

The platform has a production capacity of 100,000 barrels of oil per day and storage capacity of 950.000 barrels. Its estimated recoverable reserves are ca 180 million barrels of oil. Field life is currently estimated to 20 years, with significant upside already identified.

Ripple effects
The Goliat development project has led to major ripple effects in Northern Norway. Recent research shows that goods and services worth around 1,3 billion NOK have been supplied by regional suppliers, creating ca 450 jobs. Further positive impacts have been seen in areas such as education, R&D, culture and the travel industry. Major additional ripple effects resulting from Goliat operations and maintenance are expected in the future.
 
Emergency preparedness
Goliat brings new technologies and standards for oil spill preparedness on the Norwegian Continental Shelf. For the first time in Norway, the local fishing fleet is a permanent part of the oil spill preparedness organization.

Oil production has started under budget and ahead of schedule at the Julia oil field in the Gulf of Mexico, Exxon Mobil Corporation (NYSE:XOM) announced on April 19. The first production well is now online and a second well will start production in the coming weeks.

The Julia development is located approximately 265 miles southwest of New Orleans in water depths of more than 7,000 feet. The initial development phase uses subsea tie-backs to the Chevron-operated Jack/St. Malo production facility, reducing the need for additional infrastructure and enhancing capital efficiency. Technology has also played a key role in the Julia development including the use of subsea pumps that have one of the deepest applications and highest design pressures in the industry to date.

“Successful deepwater developments like Julia, located more than 30,000 feet below the ocean’s surface, benefit from ExxonMobil’s disciplined project execution capabilities and commitment to developing quality resources using advanced technology,” said Neil W. Duffin, president of ExxonMobil Development Company.

1MaerskVikingThe Maersk Viking drillship is currently drilling a third well, which is expected to come online in early 2017. Credit: Maersk

Production results will assist in the evaluation of additional wells included in the initial development phase, which has a design capacity of 34,000 barrels per day of oil.

“This initial production will provide ExxonMobil with insight into the potential future development of the reservoir,” said Duffin.

Discovered in 2007, the Julia field comprises five leases in the ultra-deepwater Walker Ridge area of the Gulf of Mexico. ExxonMobil, the operator, and Statoil Gulf of Mexico LLC each hold a 50 percent interest in the Julia unit. Over the past decade, ExxonMobil has drilled 187 deepwater wells worldwide in water ranging from 2,100 feet to 8,700 feet.

ExxonMobil is on track to start up 10 new Upstream projects in 2016 and 2017, adding 450,000 oil-equivalent barrels per day of working-interest production capacity. The company is enhancing resource value through production optimization, technology application and cost management.

Statoil together with operator Repsol Sinopec and partner Petrobras has completed the Gavea A1 well in the ultra-deep pre-salt block BM-C-33 in the Campos basin in Brazil.

The well encountered a hydrocarbon column of 175 meters in a good-quality reservoir of silicified carbonates of the Macabu formation.

The well reached a total depth (TD) of 6,230 meters and was successfully tested producing around 16 million standard cubic feet (scf) of gas and 4,000 barrels per day of oil (32/64” choke).

11Statoil brazil 468

Map image courtesy: Statoil

This is the fourth appraisal well in the license, which comprises the Seat, Gavea and Pão de Açucar (PdA) discoveries. In 2013-2015 the consortium drilled and tested the Seat-2, PdA-A1 and PdA-A2 appraisal wells.

With Gavea A1 the consortium has finalized the appraisal activities in BM-C-33 and will now evaluate the sub-surface data and assess lean and cost-effective development concepts.

Repsol Sinopec Brasil (35%) is operator of BM-C-33 with Statoil (35%) and Petrobras (30%) as partners.

As announced in December 2015, Statoil will take over operatorship of the license. This is expected to happen in the third quarter of 2016, subject to the approval from Brazilian authorities (ANP).

1CSA Seanic copySeanic Ocean Systems Inc. (Seanic) and CSA Ocean Sciences Inc. (CSA) are responding to challenges faced by the oil industry to address increasing regulations and environmental stewardship concerns. This strategic partnership merges technology and environmental expertise with the goal of improving oil spill response equipment and services. Innovative solutions developed by Seanic and CSA will provide much-needed support to the oil industry, which is under increasing pressure to maximize efficiency while minimizing risk and environmental impact.

Both companies already support the oil spill response needs of the energy industry, providing a range of specialized equipment and services, from engineered solutions to oceanographic sensors and from testing and maintenance to developing dispersant monitoring plans. Forging this partnership integrates the skills and experience of each company, resulting in better service to both industry and the environment.

“Seanic’s Remote Systems Technology combined with CSA’s experience in Environmental Sciences will allow us to approach oil spill response, particularly the application and monitoring of dispersants, in a unique and innovative manner,” stated Kevin Peterson, President of CSA Ocean Sciences Inc. “As environmental regulations evolve, water depths increase, and locations become more remote, cost-effective solutions based on solid science and technology become more important than ever.”

Seanic brings expertise in ROV tooling, engineered solutions, and the maintenance and improvement of oil spill equipment. Their corporate headquarters in Katy, Texas offers state-of-the-art facilities for manufacturing, testing, storage, and maintenance of equipment, including stabilized yard space, a tool pool, storage warehouse, and a 500,000-gallon in-ground wet test tank. Overseas facilities in Scotland, Norway, Australia, and Singapore support international operations.

CSA brings 46 years of specialized experience in marine environmental consulting, serving the energy industry worldwide through offices in the United States, the Eastern Mediterranean, Qatar, Trinidad, Singapore, and Australia. CSA’s expertise in coastal, marine, and deep ocean surveys, sampling, monitoring, assessment, and mitigation is built on the integration of science, operations, and an understanding of environmental data collection, management, and analysis within geospatial domains.

3WoodGroupNewLogoWood Group has recently won four subsea contracts with Statoil on the Norwegian continental shelf (NCS). The latest award is a study to deliver subsea field concept engineering for the Snorre expansion project.

This project will focus on cost efficient enhanced recovery from the Snorre reservoir, with tieback to the existing Snorre A tension leg platform and gas import from Gullfaks A. There are also options for front end engineering design (FEED), detailed design and fabrication on this contract award.

On the Oseberg field development Wood Group Kenny has been awarded detailed design for two pipelines with corresponding spools and an umbilical, which will form part of the tieback from the future unmanned wellhead (UWP) platform to the Oseberg field centre.

Wood Group Kenny also provided FEED support on the Utgard field development to support engineering on the pipeline system that will tieback the planned subsea template to the Sleipner T platform and performed lifetime extension studies to the pipeline system in the Gullfaks field.

Bob MacDonald, CEO of Wood Group Kenny said: “Norway remains a key market for Wood Group Kenny and winning this work with Statoil underlines our position there. Our independent solutions strengthen the appeal of Wood Group Kenny to clients in this challenging environment and we are focused on improved efficiency. The four latest contracts awards cover the whole project lifecycle in pipeline engineering from concept, FEED, detailed design and life time extension, utilizing our broad expertise in this area.”

Trond Grytten, operations director of Wood Group Kenny in Norway added: “Winning these four Statoil contracts is testament to our hard work and adaptability; underlining Wood Group Kenny’s capacity and capability to take on larger subsea projects in the Norwegian Continental Shelf. We look forward to continuing our good relationship with Statoil and working with them to bring the cost down for these important projects.”

Statoil has set tough targets to reduce costs in their project portfolio. During the last decade subsea costs have increased significantly and the industry needs to move from tailor-made solutions to more industry standards.

At the Barents Sea Conference in Hammerfest, Norway, a new subsea concept developed by Statoil was presented by Margareth Øvrum, executive vice president for technology, projects and drilling in Statoil.

The new subsea solution is called Cap-X.

2StatoilnewsubseaconceptImage courtesy: Statoil

"Once again we aim to drive subsea technology development on the Norwegian continental shelf together with our industry partners. The potential for increased efficiency and reduced costs can make this the next standard within subsea templates," says Margareth Øvrum. "With Cap-X, Statoil is one step closer to a “plug and play” solution on the seabed."

Cap-X is a combination of existing and new technology. It is ¼ the size of today’s subsea templates and enables more operations from vessel instead of rig.

The technology increases the efficiency of horizontal drilling in shallow reservoirs. The main structure of the technology can be produced in shorter time by a larger number of suppliers, with potential for local production.

The development of Cap X was initiated in 2013 to increase commerciality of potential resources in the Barents Sea.

“We as explorers need to find resources that can be developed at a lower cost and with lower emissions. Cap-X can potentially have a significant impact on developing the resources in the Barents Sea and in other areas with shallow reservoirs”, says Jez Averty, senior vice president for the exploration Norway and UK cluster in Statoil.

13dnvgllogo largeIn a period of cost constraint and increasingly complex oil & gas production, finding solutions that increase efficiency and production has never been more important. To address the industry’s need for smart solutions that reduce complexity, DNV GL is funding 43 new joint industry projects in 2016 in addition to launching a new Step Change innovation program to help customers leverage opportunities from digitalization.

Both initiatives are based on closed interaction and collaboration with industry partners. Key focus areas for DNV GL in 2016 will be to address challenges on standardization, operations (OPEX services), safety, environment, regulations and performance.

“DNV GL led JIPs aim to provide insights into future trends and technologies. Many of the projects result in new industry standards and practices that support innovation and flexibility in design while managing costs and maintain safety levels,” says Rolf Benjamin Johansen, Technology Manager, DNV GL – Oil & Gas.

The value of standardization is recognized by the industry with 61% of senior oil & gas professionals agreeing that operators will increasingly push to standardize their delivery globally1. The most common strategy for maintaining innovation with lower budgets is to increase collaboration with other industry players (45%) and nearly one in three (30%) plans greater involvement in joint industry projects in the year ahead.

DNV GL’s new Step Change innovation program is focused on digitalization. Only one in five oil and gas companies see themselves as highly digitalized today. However, close to half of senior oil & gas professionals (45%) already see solid or high potential for big data and analytics to transform the operating efficiency of the industry in 2016. DNV GL’s program involves the end-users, e.g. oil companies, drilling contractors and suppliers, in the innovation process. The first pilot projects have already created significant value for these end-users from using new forms of data analytics in combination with domain knowledge and technical insight.

“Step change is exactly what it says – a paradigm shift in how we drive innovation to quickly test out data smart solutions and new business models with strong customer involvement at an early stage. In the current price environment, innovation is even more critical. It can both help the industry to reduce complexity short term by standardizing parts and processes and enable new technological developments long-term that will drive efficiencies. At DNV GL, we are continuing to invest 5% of our revenue in R&D because it enables us to provide long-term foresight for our customers,” says Kjell Eriksson, Regional Manager Norway, DNV GL - Oil & Gas.

Currently in the initial phase, DNV GL welcomes industry players to join the JIP projects or contact us if they are interested to be involved in our Step Change program.

5Aker statoil njordAker Solutions' maintenance, modifications and operations (MMO) business in Norway will as a subcontractor of Kværner provide engineering services for upgrading the semi-submersible platform at the Statoil-operated Njord A oilfield. 

Statoil-operated Njord A oilfield. Photo: Øyvind Nesvåg / Statoil.

The company signed a subcontractor agreement with Kværner, which was awarded the framework agreement for the Njord Future project by Statoil. Aker Solutions' initial delivery will be front end engineering design (FEED) work. The contract with Kværner also includes engineering work in the engineering, procurement and construction (EPC) phase of the project should the operator decide to proceed with this, as well as an option for prefabrication work.

"We look forward to working with Kværner to find the most robust and cost-effective solutions for Statoil on this project, which draws on our experience in complex modifications," said Per Harald Kongelf, head of Aker Solutions' Norwegian operations.

The MMO unit in Bergen will execute the FEED work with support from Aker Solutions' engineering business in Oslo, working as an integrated team with Kværner. The work will start immediately and at its peak involve 120 employees of Aker Solutions.

Aker Solutions has previously delivered concept and feasibility studies on upgrading Njord to Statoil.

12Trelleborgs new Floatover Forecast1As offshore topsides become heavier and more oil reserves are identified in harder to reach locations, innovative solutions are key to effective oil & gas extraction. As a result, floatover installations are experiencing an upturn, rather than traditional heavy crane lifting. JP Chia, Engineering Manager and floatover specialist for Trelleborg’s engineered products operation, will be on stand at OTC Houston to discuss this trend, share market insights and answer any questions.

An active, global industry expert since the technology was introduced in the early 2000s, Chia has compiled his first hand experiences in a new whitepaper, The Floatover Forecast. He recounts lessons learned, changes in technologies and materials, as well as trials and errors that have contributed to developments in the field.

JP Chia, says: “Supported by statistics from a current research paper, our whitepaper details just how far the offshore industry has come in three decades of floatover developments, and how much further they can advance as oil companies utilize the technology in far-off locations. Visitors can get their copy of the whitepaper from our stand, number 5541 (hall A).”

As oil and gas exploration continues to develop year-on-year, and technology becomes more sophisticated, the effectiveness of extraction will improve. However, as floatover installations become more popular, it is vital that the industry applies the right thinking to ensure that projects are implemented safely and efficiently from beginning to end.

Chia continues: “Our whitepaper will help owners, operators, EPC contractors and consultants to confidently keep up to speed with the world of floatover installations.”

Available to view on stand, Trelleborg’s leg mating units consist of steel structures incorporating engineered elastomeric pads. They make a floatover transition possible by damping the forces created as the topside’s load is transferred to the jacket. The elastomeric pads are designed to take up the static and dynamic forces of the topside structure, as well as the horizontal forces due to open sea motions during the float-over mating operation. The assembled LMU can be installed either on the topsides or jacket.

Pick up your copy of ‘The Floatover Forecast’ from stand 5541 (hall A) at OTC Houston. For additional information about Trelleborg’s engineered products operation, click here.

Fabrication of the billion dollar topsides destined for the Maersk Oil operated USD 4.5 billion UK North Sea megaproject, Culzean has begun. The steel-cutting ceremony for the first of the three topsides modules took place at the Sembcorp Marine Offshore Platforms (SMOP - formerly known as SMOE) Admiralty Yard in Singapore on April 7th.

Culzean is the largest hydrocarbon discovery in the UK North Sea for over a decade. The field is approximately 145 miles east of Aberdeen and is expected to produce between 60,000 - 90,000 boepd at plateau production, producing for at least 13 years. The project was sanctioned in August 2015. Maersk Oil’s coventurers in Culzean are JX Nippon Exploration & Production (UK) Limited (34.01%) and BP (Britoil) (16%).

5Maersk Culzean singapore for websiteJakob Thomasen, CEO of Maersk Oil, igniting the flames for the steel-cutting ceremony. This is the first sheet of steel cut for the Culzean megaproject. Credit: Maersk Oil

“Starting the fabrication of the topsides is an important milestone. When the field begins to produce in 2019, Culzean will become a key contributor to Maersk Oil’s ambition to become a Top 5 operator in the North Sea in the 2020s, and provide around 5% of UK gas demand at peak production. Maersk Oil and coventurers’ investment will also support employment in both the UK and Asian supply chains,” said Maersk Oil Chief Executive Jakob Thomasen, speaking at the ceremony in Singapore.

“Our focus for the next three years is working with our partners and suppliers to deliver the project from fabrication right through to commissioning safely, on time and within budget,” says Thomasen.

The contract with SMOP, worth over USD 1 billion including long lead items, was awarded in September 2015. The contract includes the building of the Central Processing Facility plus two connecting bridges, Wellhead Platform and Utilities & Living Quarters Platform Topsides for the Culzean Field Development.

The platforms will be built with enhanced digital and monitoring capability.

“We will be harnessing technology to develop a 21st century facility with the ability to remotely monitor critical equipment 24 hours a day, and enable offshore colleagues to access real time data and immediate technical evaluation and onshore support. The technology will minimize time spent on plant and enhance safety and efficiency. Maersk Oil estimates this digital toolkit can save more than USD 10m annually,” says Martin Urquhart, Culzean Project Director.

17AkerSolutionsAker Solutions secured an agreement to provide maintenance and other services for subsea facilities at Petrobras-operated oil and gas fields offshore Brazil.

The contract is for a fixed term of three years valued at BRL 435 million net of taxes (NOK 1 billion) and may be extended by another three years. It covers maintenance, storage, supply of parts and technical assistance for all subsea equipment delivered by Aker Solutions to Petrobras in Brazil.

"Brazil is a key global offshore market," said Luis Araujo, chief executive officer of Aker Solutions. "We have a nearly four-decade presence in the country and are committed to finding solutions to help Petrobras develop its petroleum resources in the most efficient and sustainable manner possible."

Aker Solutions is in April opening a new subsea manufacturing center in Curitiba, doubling its local production capacity. The company is also upgrading its subsea services unit in Rio das Ostras to better meet customer demand.

The contract will be managed at the base in Rio das Ostras in Rio de Janeiro, at a local content rate of 87 percent. This builds on a commitment to develop partnerships with national suppliers.

"We are pleased to be able to continue providing top-notch services and technologies to support Petrobras' production and growth plans in the pre-salt deepwater fields," said Maria Peralta, head of Aker Solutions in Brazil.

The agreement is similar to one signed in 2011 for maintenance of equipment and other offshore services. Currently, Aker Solutions' subsea lifecycle services unit has about 360 employees in Brazil, of which 150 are part of the technical team working offshore. The company has about 1,300 employees in the country.

The contract is booked as part of Aker Solutions' first-quarter order intake.

New subsea technologies and systems must be qualified before use to build confidence that they will function as intended. However, current subsea technology qualification (TQ) processes can be inefficient, time consuming and variations in methodology impede industry players from leveraging on each other’s results. Now DNV GL is calling for a standardized system qualification approach and joint industry effort to drive faster take-up of new technology and value creation in subsea.

A new position paper ‘Subsea system qualification: Towards a standardized approach’ by DNV GL’s Strategic Research & Innovation unit aims to answer two questions: How can confidence in new subsea systems be demonstrated in a faster and more efficient way? How can already qualified technologies be re-qualified in an effective manner for reuse in similar systems or under slightly different operating conditions?

6DNV FRONTPAGE PRINTSubsea illustration Credit: DNV GL

The position paper proposes a joint industry effort in three steps to enable more effective technology development and implementation in the field: 1) Establish common industry principles, and consolidate a common framework for system qualification founded on existing industry procedures; 2) Develop a methodology to standardize system qualification for common use across the upstream oil and gas industry and 3) Pilot and demonstrate the developed methodology and roll-out a Recommended Practice.

“The subsea industry needs to overcome key challenges such as cost reductions, enabling increased recovery, and complex field developments. At the same time, the future trend still points towards more complex systems which require integrating process, power, and control systems subsea. Assuring safety and reliability on a system level is critical when interfaces become more complex and system integration failures are harder to identify,” says Tore Myhrvold, researcher and lead author of the paper, DNV GL.

“Developing a standardized approach to subsea technology qualification will enable companies to leverage on each other’s qualification efforts and results, reduce the overall development time and ultimately enable faster innovation in the subsea sector,” continues Myhrvold.

Previous experience has shown that focus on qualification in the early phases of development reduces risk of failures in late phase testing. Failures and errors in tests that are run in later development stages, such as factory acceptance tests (FAT) and system integration tests (SIT), are expensive to fix since they may result in costly rework and re-iteration of the design process. DNV GL’s position paper recommends increasing the qualification efforts in the early phases of development to enable faster and more effective development and implementation of novel subsea technology systems.

The position paper also proposes that numerical or analytical methods (models) could prove to be cost effective and safe alternatives to current expensive physical testing or be used in conjunction with existing methods. These alternative methods can explore the effects from parameter variations and how different sub-systems or single components affect the entire system performance. By using non-intrusive numerical modelling tools to establish a common modelling platform, a wide variety of validated models can be used in the system qualification to virtually test system operational ranges and failures.

“The Norwegian Petroleum Directorate (NPD) reports that subsea tie-back represents the most relevant solution for 68 out of 88 discoveries on the Norwegian continental shelf. To sanction many of these projects, fast and cost effective technology development is vital,” says Elisabeth Tørstad, CEO of DNV GL – Oil & Gas.

“Our efforts to drive standardization in the subsea sector aim to reduce cost, lead times and to increase confidence in new technologies to enable faster innovation. Our collaboration with the industry on subsea documentation and subsea forging for example have resulted in guidance that is being implemented in projects and now delivering benefits for operators,” adds Tørstad.

To download the position paper visit www.dnvgl.com/download-subsea-position-paper.

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