Oil & Gas News

2bseeLogoThe Bureau of Safety and Environmental Enforcement is continuing its investigation of the oil release from Shell Offshore Inc.’s Glider Field on May 12. The Glider Field, located approximately 97 miles south of Port Fourchon, LA, includes subsea wells and the field’s production flows to the Brutus Platform.

BSEE Gulf of Mexico Regional Director Lars Herbst formally established an Investigative Panel May 16. The seven-member panel is comprised of BSEE engineers, inspectors, and investigators. The panel will conduct a thorough investigation of the incident in order to identify the causes and any contributing issues that led to the release. The panel will make recommendations in its final report on how to strengthen existing safety and environmental management systems, and identify any reforms to existing regulations that may be needed. The focus of these recommendations is to prevent a similar incident from occurring.

BSEE approved Shell’s plan for recovery of the damaged flowline segment. A BSEE inspector is on board the recovery vessel to observe the recovery operations. All repair plans for the subsea flow lines and production systems will be submitted to BSEE for review.

Production remains shut-in from the two subsea fields that flow to the Brutus platform. BSEE will not approve production restart of these subsea fields until all safety concerns and applicable regulations have been met.

9Airborne Oil and Gas for PR useThe Libra consortium has invited Airborne Oil & Gas to perform a failure mode, effect and criticality assessment (FMECA) for a TCP Riser that could be used at the giant Libra field offshore Brazil. The request followed a successful feasibility study (preliminary version) performed by Airborne Oil and Gas and Wood Group Kenny, that showed a 45% reduction in top tension in a cost effective riser solution, using a hybrid riser design comprising of the conventional flexible pipe (used for the top and bottom riser-sections) and the TCP section inserted at the mid-water depth.

Henk de Boer PhD, Engineering Manager Airborne Oil & Gas: "We are independent in our material choice and select the right material for every application. In this case, we assessed 3 different composite materials in the riser design and optimized it for installation, fatigue, top tension and pipe cost. Interestingly, the most cost effective riser solution turned out to be the technically best performing as well."

The TCP Riser solution (provided for the full riser length) could offer significant benefits in deep water riser applications: first, the lightweight TCP Riser reduces the top tensions up to 50% (as compared with the conventional flexible pipe), reducing the weight loading on the FPSO. Second, the TCP Riser itself is a simple monolithic wall pipe; while still flexible, it is inherently simple in its design leading to a very cost effective solution for deeper waters.

Airborne Oil & Gas is the world's first manufacturer of Thermoplastic Composite Pipe (TCP) to have qualified its design, production and materials in compliance with the new DNV Recommended Practice for Thermoplastic Composite Pipe, DNVGL RP F119. The FMECA will be conducted in accordance to this recommended practice.

Plugging and abandonment (P&A) of offshore wells represents the highest cost within field decommissioning for operating companies and national authorities. DNV GL has now issued a new, globally applicable Recommended Practice (RP), on risk-based abandonment of offshore wells which in combination with optimized project execution and new technology could potentially reduce P&A costs by 30–50%. The framework outlined in the RP provides the possibility for individualized, fit-for purpose well abandonment designs, a contrast to the prescriptive methodology available in the industry today.

11DNVGL Illustartion A4 RightCutRight cut drilling and well illustration. Credit: DNV GL

Well abandonment is driven by economic decisions, when the production of an oil or gas reservoir ceases or is no longer profitable. Authorities require that well operators perform safe and environmentally friendly operations by establishing a permanent barrier to prevent release of hydrocarbons to the surface. Traditional P&A methods are time consuming, costly and have remained unchanged despite technological advances in the industry.

“The costs related to well P&A are enormous. Using current practices, there will be a global fleet of dozens of full-time drilling rigs needed to perform P&A for generations to come. We believe the time has come to tackle this issue head on by assisting regulators and the industry to establish a new methodology for dealing with the decommissioning of wells. By using this method, hazardous wells will get the attention they deserve, and benign wells will avoid excessive rig-time and expenditure. We're looking at potential cost savings of more than USD32bn on the Norwegian Continental Shelf alone, and even more globally,” says Per Jahre-Nilsen, Business Development Leader, Drilling & Well, DNV GL – Oil & Gas.

The DNVGL-RP-E103 'Risk based abandonment of offshore wells' is based on case studies performed by DNV GL in projects dating back to 2011. A thorough process is defined where the key stages in the risk-based methodology are assessing the well barrier failure modes, well flow potential, valued ecosystem and safety components, dispersion modeling and impact analysis. These steps allow for a consistent method to be applied when assessing risk of the offshore well abandonment designs. The RP methodology provides assurance that selected well abandonment designs are robust, environmentally friendly and economically advantageous.

“DNV GL helps the industry to understand and manage the risks of their operations. Risk-based approaches are widely used in all other offshore disciplines, ensuring appropriate long-term environmental protection and also representing the most efficient method to ensure safety. It is time to apply these principles to P&A.” says Elisabeth Tørstad, CEO of DNV GL - Oil & Gas.

The main obstruction to change in this sector has been today’s prescriptive approach to the regulations, which represents a conservative interpretation of past experience and outdated technologies. Practice also differs from country to country. The new RP uses well-known and accepted risk-based approach methodology in which both environmental and safety risk aspects are key factors. Through the development of the RP, DNV GL worked with international oil and gas operators to establish an initial set of risk acceptance criteria and cross-checked these using case studies. The criteria and methodology have been further strengthened through dialogue with regulators and industry players.

3akersolutions abbAker Solutions and ABB agreed to build on their combined strengths in subsea, power and automation technologies to develop solutions that will improve oil and gas production for the global energy industry.

The cooperation will integrate Aker Solutions' pioneering subsea capabilities and ABB's subsea power and automation system expertise to bring customers more effective, reliable and flexible oil and gas production solutions. It will enhance how production equipment on the seafloor is powered and controlled by applications on shore or platforms, lowering costs and enabling economically viable production at fields far offshore from existing infrastructure.

"This partnership builds on a relationship with ABB that already has a proven track record of developing groundbreaking subsea technology," said Alan Brunnen, head of Aker Solutions' subsea business. "Together we will now further hone our focus on developing technologies for greater and more sustainable hydrocarbon recovery and help customers reduce costs by making existing subsea solutions more effective."

"Power and automation are crucial to improving the effectiveness of compression, boosting and other solutions for increasing oil and gas recovery from subsea fields," said Peter Terwiesch, president of ABB's process automation division. "This collaboration is part of our Next Level Strategy to engage in value-adding partnerships and will bring together the expertise and technology needed to help better serve customers and strengthen our subsea power and automation solutions."

The cooperation is an outcome of several years of joint work that includes landmark developments such as the 2015 delivery of the world's first subsea compression system for the Statoil-operated Åsgard field offshore Norway. Initial focus areas will include developing better subsea compression systems at lower costs and in less time.

The collaboration will target opportunities globally, building on the companies' presence in major oil and gas markets to meet customer needs worldwide. It will be headquartered in Oslo, Norway.

Forum Energy Technologies Inc. has successfully delivered a number of its largest subsea Pig Launchers and Receivers (PLRs) and laydown heads to a project in North Africa.

The nine PLRs have been deployed as part of a development of nine subsea wells, which vary from four to 24 inches in size, with water depths ranging from 300 to 800 meters.

Manufactured at Forum’s Moffat subsea engineering business in Northumberland, UK, the custom-designed units will be used in the completion of flooding, cleaning, gauging, strength test, intelligent pigging and dewatering activities.

3Forum 1Forum Energy Technologies has delivered several of its largest PLRs and laydown heads to a North African project. Photo courtesy: Forum Energy Technologies

John Thompson, operations director at Moffat, said: “Despite the market conditions, there has been a strong and continued demand for the capabilities and expertise held in our Moffat facility. We are engineering innovative products that are benefitting clients around the globe, and this latest contract is testimony to that.

“The scope of work for the project, which included the full design, manufacture and testing of the PLRs, underlines the fully integrated system we can offer from concept through to delivery.”

In addition to their size and weight, Forum’s PLRs have other additional capabilities compared with conventional systems because they are also equipped with a remotely operated vehicle (ROV) readable subsea flow meter, a ROV operable choke valve for discharge throttling to control the pigging velocity. Forum also developed and manufactured a landing interface from the PLR’s to the pipeline end terminator (PLET) with a horizontal driverless connection system.

AnTech Ltd, provider of specialist products and services for the upstream oil and gas industry, has responded to industry demand, with the launch of three new products within its best-in-class Wellhead Outlet range.

The Type-C Wellhead Outlet, which was designed and developed by the company for use in hazardous environments, has been on the market since 2013 and has achieved great success due to its safe and simple installation, created in compliance with API 6A, ATEX and NACE standards. In response to the product’s success and customer feedback, AnTech has launched two further outlets, namely: Types CB and CC. Each adaptation has been carefully designed to suit various working environments including pressure, ranging from 10,000 - 15,000psi, temperatures from -60°C to +160°C, whilst meeting ever-tightening budget constraints.

16Antech Type FC WellheadType FC Wellhead Outlet

The Type CB and CC Wellhead Outlets provide solutions to the demands of high technical specifications and the rippling effect of the low oil price. Driven by strong customer feedback from key clients, the company has designed, tested and manufactured both variations to AnTech’s customary high standards. Both options meet API 6A and NACE certification and have been designed for applications in North America, Africa and Europe.

With the increasing demands for more data and distributed measurements, there has been a growth in the use of fibre optic cables for permanent monitoring. These solutions are only as good as the connections at surface and AnTech’s Type FC outlet has been designed specifically to meet this demand whilst maintaining the highest safety standards at a cost effective price.

In order to meet a lower price point, AnTech has reviewed its current material costs and utilised new manufacturing processes including 3D printing. As a result, the new Type FC outlet incorporates a 3D printed smart system for handling and storing up to four fibres. The unit is suitable for operating in some of the world’s most stringent wellsite environments, as it is certified to both API 6A and NACE, additionally it can hold pressures of up to 10,000 psi.

AnTech sales manager, Tim Mitchell said: “AnTech continues to lead the way for innovative design and customer service when it comes to wellhead outlets for permanent monitoring. We’ve worked hard to develop a range of electrical and fibre outlets in order to meet the needs of varying environments around the world, focusing on certification and, of course, a cost effective price point. We’ve listened to our customers’ requirements and as a result have developed market-driven solutions which now create a larger range of products.”

Commenting on the cost effective options, AnTech managing director, Toni Miszewski said: “We have realised that we not only need to meet today’s demands but also look towards the future. With the current low oil price, customers are demanding our high certified products but at a lower price point. After considerable research and development, we are pleased to announce three new lower cost options, which result in a wider choice within our product lines. This will help our customers to provide safe solutions to their clients without breaking the bank.”

Founded in 1992, AnTech operates globally across two divisions and provides products and services to the upstream oil and gas industry. On the Products side of the business, AnTech offers patented and innovative products in the areas of permanent monitoring, data acquisition, coiled tubing and downhole tools. In addition, AnTech provides a Directional Coiled Tubing Drilling (DCTD) Service with a suite of proprietary bottom hole assembly tools, trained teams and operational facilities in Saudi Arabia and Houston, USA.

12Sonardyne SensorView Ichthys4Software that enables acoustic data to be streamed in real-time from subsea structures as they are installed has helped to reduce non-production time (NPT) for independent oil and gas producer, INPEX, and its survey contractor, Neptune Geomatics, during construction of the Ichthys gas field, offshore Western Australia.

Supplied by subsea technology company Sonardyne Asia Pte. Ltd in Singapore, the SensorView software allowed data gathered by an acoustic transponder mounted on Tubing Head Spools (THS), to be transmitted at high speed to rig personnel monitoring the installation operations. The parameters measured by the transponder’s on-board sensors included heading, depth, sound velocity and inclination, and meant that delays previously incurred while aligning each THS to drilling templates, could be substantially reduced.

Located 220 kilometers off the coast, Ichthys represents the largest discovery of hydrocarbon liquids in Australia in over 40 years. It covers an area of around 800 square kilometers in water averaging depths of around 250 meters and is estimated to contain more than 12 trillion cubic feet of gas and 500 million barrels of condensate.

The field will be developed using a semi-submersible central processing facility, the largest of its kind anywhere in the world, and an FPSO connected by 890 kilometers of gas export pipeline to an onshore processing and storage facility at Bladin Point near Darwin.

As part of a 40 month contract, INPEX contracted Neptune to provide rig positioning and survey services during the drilling and completions phase of the project, work that is being undertaken by the Jack Bates and Ensco 5006 mobile drilling units.

At each of the five drill centers, Neptune installed a seabed array of Sonardyne Compatt 6 Long BaseLine (LBL) acoustic transponders to accurately position the spud locations and monitor the installation of the Drilling Guide Bases (DGBs) as they were lowered from the surface. Structure-mounted Compatt 6s fitted with high resolution inclinometers and depth sensors were used to verify final DGB positions and inclinations following cementing of the conductor in the top hole section.

While trying to align each THS with the DGBs once they arrived at depth, operational delays leading to rig non-productive time were incurred. To avoid such delays, INPEX requested that Neptune gather real-time positioning and heading information on each spool as it was being maneuvered.

The requirement was met using SensorView, Sonardyne’s dedicated sensor monitoring software application. It can be used in parallel with 6G acoustic positioning systems such as Fusion, or as a standalone solution for cost-effective remote monitoring and subsea data harvesting projects.

At Ichthys, SensorView was mobilized on one of the rigs and interfaced with a Dunker 6 transceiver which was deployed over the vessel’s side. Subsea, a Sonardyne GyroCompatt 6 was temporarily mounted on each THS and attached using a customized bracket designed to allow an ROV to recover the unit after each THS was installed. GyroCompatt 6 combines the features of a Lodestar Attitude and Heading Reference System (AHRS) with a Compatt 6 transponder in one unit to provide high update rate wireless attitude, heading, heave, surge, sway, pressure, sound velocity and acoustic positioning of any subsea object.

Commenting on the successful deployment of SensorView, Pat Fournier, Operations Manager for Neptune’s Geomatics service line said, “During Neptune’s recent Ichthys drilling and completions campaign, SensorView delivered us THS heading update rates of approximately one every three seconds. This was sufficient for our surveyors to fully understand the dynamic motion of the structures and thereby reduce the time needed to land them in the correct location.” He added, “We were impressed with the ease with which we could configure SensorView to work with our LBL acoustic hardware and view the data streams we needed to see.”

For more information on Sonardyne’s SensorView software click here.

McDermott International (NYSE:MDR) has successfully completed the installation scope associated with the Otis development in the Gulf of Mexico on behalf of LLOG Exploration Offshore. McDermott’s Lay Vessel North Ocean 105 (LV 105) completed the deepwater subsea tieback from the Otis well in Mississippi Canyon 79 to the Delta House Floating Production System in water depths ranging from 3,861 feet to 4,420 feet.

4McDermott NO105 BannerNorth Ocean 105 - Fast-transit, dynamically positioned vessel with an advanced Reel-lay system capable of rigid and flexible pipelay in up to 10,000 feet of water. Photo courtesy: McDermott

The scope of work consisted of project management, engineering, and installation of 70,000 feet of insulated rigid flowline and insulated steel catenary riser as well as a control umbilical, PLEM jumper and associated flying leads. The flowline and riser were fabricated at McDermott’s new spoolbase and marine facility in Gulfport, Mississippi. All engineering and project management functions were completed in McDermott’s Americas, Europe and Africa headquarters in Houston.

“This marks an important milestone for the McDermott organization as the first project executed in its Gulfport Spoolbase and the first installation of a steel catenary riser by the LV 105,” said Scott Munro, McDermott Vice President for Americas, Europe and Africa. “The execution of the Otis project has positioned McDermott for success on our other 2016 reel lay projects, including Anadarko Caesar Tonga Phase II. This project demonstrates our commitment to adding value to the subsea tieback market and is the foundation for McDermott to establish itself as the reel lay contractor of choice for our customers in the Gulf of Mexico.”

6AmecFWlogoAmec Foster Wheeler announces the award of a project management consultancy contract by consultancy company NIRAS to support the next stages in the development of a Kenya Ports Authority project for the offshore relocation and expansion of the Kipevu Oil Terminal (KOT) in Mombasa, Kenya.

Amec Foster Wheeler’s scope of work is to provide technical support and expertise to NIRAS for the development of an engineering, procurement and construction tender package and the evaluation of tenders. Amec Foster Wheeler previously supported NIRAS with the preliminary design stage for KOT.

Kipevu Oil Terminal (KOT) in Mombasa, Kenya, will be relocated to a site adjacent to Mombasa port berth 16 and 17 and overlooking the naval base in Mtongwe.

KOT presently handles more than 90% of the country’s imports as well as transit products for Uganda, northern Tanzania, Rwanda, Burundi, Eastern DRC and South Sudan.

Refined petroleum products are offloaded at KOT and transferred to the Kipevu Oil Storage Facility in the coastal town.

In a concerted drive to find smart solutions to safely reduce complexities and cost in the North American oil and gas industry, DNV GL is leading seven new joint industry projects (JIP) from the region in 2016. The initiatives will support overall efficiency efforts in the pipelines, wells and subsea, umbilicals, risers, and flowlines (SURF) sectors.

Key focus areas for DNV GL in 2016 will be centered around solving challenges around standardization, operations (OPEX services), safety, environment, regulations and performance.

“Our collaborative projects are pivotal in strengthening the industry throughout the Americas and helping it move forward and out of the difficulties we are currently facing,” said Peter Bjerager, Executive vice president, Oil & Gas – DNV GL Region Americas. “As an independent third party we are uniquely positioned to provide a neutral ground for collaboration.”

4DNV FRONTPAGE LAPTOPImage credit: DNV GL

DNV GL is inviting industry players to take part in the following JIPs:
- Extended application of corrosion resistant alloys
- Guidance for qualifying materials in compliance with API 17TR8 HPHT design guidelines for subsea equipment
- Increased consistency for sour service testing and assessment
- Sour HPHT fatigue testing for clad subsea components
- Prediction of internal flow induced vibration of complex subsea pipework
- Jumper VIV instrumentation and field measurements - expanding ongoing JIP
- Safe assessment of embedded flaws in sour pipelines

According to a recent research report published by DNV GL1, one-third of North American respondents are concerned that they do not have a strategy in place to maintain innovation in a declined market. However, 31% see greater involvement in JIPs as a priority over the next 12 months, while four in ten want to increase collaboration with other industry players (40%).

The report also found that six out of ten (60%) respondents agreed that operators will increasingly push to standardize their approach globally- up from 42% in 2015. Only 9% expect an increase in spending in R&D and innovation, a figure that has been cut by more than half in two years, from 20% in 2014.

“Like the global oil and gas industry, companies in North America are braced for an extended period of lower oil prices, which is leading to continued pressure on cost management. However, it is encouraging that there is still enthusiasm to work together and drive greater standardization and reduce inefficiencies. The success of our collaborative approach has seen the introduction of new industry standards and practices which help advance innovation and reduce complexity,” continued Peter Bjerager.

In total, 43 DNV GL-led JIPs have been initiated globally this year, in addition to the launch of a new Step Change innovation program to help customers leverage opportunities from digitalization.

DNV GL’s ‘Technology Outlook 2025’ report predicts and showcases technology trends across a number of industries. For oil and gas, key developments include digitalization, connectivity, automation and remote operation.

A replay of a press conference hosted by DNV GL at OTC is available by clicking here. The press conference showcased collaborative DNV GL-led projects including the results of the WIN WIN JIP which assessed the technical and commercial feasibility of using floating wind turbines to power water injection systems offshore.

Download a complimentary copy of A New Reality: the outlook for the oil and gas industry in 2016.

Download DNV GL’s ‘Technology Outlook 2025’ report and videos

19lord corporation logoLORD Corporation has announced that its subsea wellbore sensors have demonstrated Subsea Instrumentation Interface Standardization (SIIS) compliance.

LORD Corporation’s Stellar Technology subsea wellbore pressure/temperature transducers passed the initial interface testing at a recent interoperability event, demonstrating compliance with the new SIIS requirements. Subsea control module (SCM) manufacturers that participated in the event were Aker Solutions, FMC, GE, OneSubsea and Proserv. Having passed each interoperability test, LORD Corporation’s wellbore sensing technology was validated to successfully interface with these SCM manufacturers.

SIIS, a joint industry project designed to achieve improvements in subsea reliability, is the new subsea instrumentation interface standard. It will soon be required by all SCM as well as oil and gas exploration and production companies. The aim is to standardize the interface between subsea sensors and the subsea control system. SIIS members consist of control systems suppliers, sensor suppliers and operators who work together defining the standards for subsea instrumentation interfaces.

According to Andy Winzenz, Commercial Director, Sensing, LORD Corporation, the company continues to expand and unify its sensing offerings and this is a major milestone.

“Demonstrating this compliance status validates our wellbore sensor communication interface with the major subsea control system manufacturers,” said Winzenz.

Subsea processes and technology present a space-saving solution for offshore facilities around the world and can help reduce the complexity of operations. For example, by utilizing subsea separation, the amount of production transferred from the seafloor to the surface of the water can be reduced. It also helps cut down on moving unwanted components to the facility on the water’s surface, just to direct them back to the seafloor for re-injection.

Typical subsea processes include subsea water removal and re-injection or disposal, single- or multi-phase boosting of well fluids, sand and solid separation, gas/liquid separation and boosting, as well as gas treatment and compression. In addition to the work flow benefits of subsea operations, sensors and transmitters can also help increase field recovery. They also make it easier to gain access to challenging oil fields, reducing additional spending for topside equipment.

More information about the SIIS certification can be found here and additional details on LORD Corporation’s subsea pressure transducers can be found here.

International oilfield services company, Expro, has successfully completed a plug and abandonment (P&A) project in the Gulf of Mexico (GoM) for Apache.

Expro recently expanded its business capabilities to offer fully integrated well abandonment services including; late-life reservoir management, permanent reservoir abandonment and post abandonment monitoring.

5expro apache may 3Photo credit: Expro

The Apache work comprised the pre-abandonment and plugging of wells in the ultra deepwater Atwater Valley and Mississippi Canyon areas.

Commencing in March 2016, Expro utilised its well intervention services to provide the first phase of abandonment of the wells. This involved plugging, cutting and perforating using slickline and electric-line cased hole applications to gain access to the wells and allow circulation.

Kevin Illingworth, Global Well Abandonment Manager, comments:
“Our experienced teams provide integrated products and services, underpinned by the subsurface expertise within our Expro Group Integrated Services (EGIS) product line. This includes well integrity management, well testing, subsea and wireless well solutions, for temporary and permanent well abandonment.

“Expro is uniquely placed to understand the challenges that come with the re-entry and abandonment of an aging well population. We were delighted to demonstrate this on the project with Apache, and continue our global relationship with them.”

Expro has worked with Apache for over 10 years, primarily in the North Sea, supplying subsea, well testing, intervention and sampling services, and well integrity software.

Mark Enget, Vice President - North America, adds:
“We have a proven track record for service quality and innovation in the North American market partnering with major operators Kevin Illingworth, Global Well Abandonment Manager, comments: on well testing, intervention and subsea projects.

“This contract builds on the long-standing relationship between Expro and Apache, and I’m delighted that we’re providing successful plug and abandonment expertise in the GoM.”

P&A is just one of the four new capabilities developed by Expro in response to current market conditions and being launched at the Offshore Technology Conference (OTC) in Houston from 2-5 May 2016.

Sparrows Group has been awarded a 20-month inspection services contract to cover Stena Drilling’s global fleet of drilling vessels.

The agreement will see Sparrows Group deliver LOLER lifting gear surveys, potential dropped objects surveys, cargo carrying unit (CCU) and non-destructive testing (NDT) inspections as well as rig specific maintenance.

Sparrows Group had previously held a similar contract with Stena for an eight-year period.

7Sparrow stena forthStena Forth. Photo courtesy: Stena Drilling

Stewart Mitchell, chief executive officer of Sparrows Group, said: “Over the years we have developed a strong relationship with Stena and we are delighted to now be working with them again. It is encouraging to see that they are committed to ensuring safety and integrity across their global fleet.

“Our experienced inspection team has a reputation for delivering quality, cost effective services to our customers. I have no doubt their professionalism and track record for reliability has contributed to us regaining this contract. In today’s low oil price environment it is more important than ever to ensure inspection and maintenance is carried out effectively to avoid costly emergency repairs.”

This latest contract with Stena Drilling comes shortly after Sparrows Group announced it had secured a five-year contract in the North Sea with Statoil. In March, the firm revealed it was to deliver cranes and maintenance services at the prestigious Mariner development.

Established originally in 1946, the Sparrows Group moved into the oil and gas market in 1975 and has more than 40 years’ experience working offshore. They are one of the most well-known and trusted names in the oil and gas industry. The company provides engineered products and services, primarily to the offshore sector, specializing in lifting and handling, cable and pipe lay, and fluid power solutions.

Statoil ASA (OSE: STL, NYSE: STO) has entered into an agreement with Lundin Petroleum AB (Lundin Petroleum) to divest its entire 15 percent interest in the Edvard Grieg field for an increased shareholding in Lundin Petroleum.

The transaction also includes divestment of a 9 percent interest in the Edvard Grieg Oil pipeline and a 6 percent interest in the Utsira High Gas pipeline, and in addition payment of a cash consideration of USD 68 million to Lundin Petroleum.

6Statoil EdvardGrieg2The Edward Grieg platform. Photo courtesy: Lundin Petroleum

Following completion of the transaction Statoil will own approximately 68.4 million shares of Lundin Petroleum, corresponding to 20.1 percent of the shares and votes. The effective date of the divestments of these assets is 1 January 2016.

The transaction was initiated by Lundin Petroleum. The two companies will continue to operate independently, and act as separate entities in all licenses on the NCS. Statoil remains supportive of Lundin Petroleum’s management, its Board of Directors and strategy.

Statoil will through this transaction further strengthen its indirect exposure to core field development projects and growth assets on NCS. This includes the Statoil operated Johan Sverdrup field, a world class project with a break-even of less than USD 30 per barrel for phase 1

“The increased shareholding in Lundin Petroleum will be an important long term industrial investment for Statoil. The transaction also underlines our long term interest and commitment to the future of the NCS,” says Hans Jakob Hegge, Executive Vice President and CFO of Statoil ASA.

In consideration for the acquisition of the assets, Lundin Petroleum has agreed to issue to Statoil 27,580,806 shares in Lundin Petroleum based upon an agreed average share price of SEK 138 per share and a SEK/USD exchange rate of 8.09. In addition Lundin Petroleum will transfer 2,000,000 treasury shares and issue an additional 1,735,309 shares to Statoil in exchange for a cash consideration based on the market value of the shares (ten day volume weighted average closing share price prior to and including the date of signing).

As a consequence of the transaction Statoil will equity account its stake in Lundin Petroleum, resulting in an increase in Statoil’s reserves and production. Statoil has no plan to further increase its shareholding in Lundin Petroleum.

The transaction is subject to approval in Lundin Petroleum AB’s Extraordinary General Meeting 30 May 2016 and required authority approvals. The transaction has received unanimous support by the Lundin Petroleum Board of Directors, and the Lundin Petroleum family entities have confirmed that they will vote in favor of the transaction at the EGM. Closing of the transaction is expected by end of July 2016.

Saipem and its consortium partners Bos Shelf and Star Gulf have been awarded call-off 007 under the Shah Deniz Stage 2 Master Agreement by BP, on behalf of the Shah Deniz partnership. The total value of the contract is approximately $1.5 billion (Saipem share approximately $1.3 billion), with a duration of five years plus a possible extension for a further five.

1ShahDenizShah Deniz gas field in the Caspian Sea. Photo credit: BP

The Shah Deniz field is located 90 kilometers offshore Azerbaijan, in water depths from 75 meters to 550 meters. The scope of work of the call-off refers to the transport and installation of subsea production systems and subsea structures, laying of fiber optic cables and production umbilicals, laying of 90 kilometers of pipelines, the activation, crewing and operations management of the new-build Subsea Construction Vessel (SCV) Khankendi, the SCV diving support, remotely operated vehicle (ROV) support and marine base management post 2017.

Saipem has been involved in the Shah Deniz Stage 2 project since 2014.

Commenting on the award, Stefano Cao, Saipem CEO, said: “We are delighted to have secured this major award, which enables us to continue and consolidate our 20-year relationship with BP and Socar in Azerbaijan and to put our world-class people and technologies at their disposal for the timely and efficient delivery of Shah Deniz Stage 2. This award also further strengthens Saipem’s key role in the construction of the Southern Gas Corridor where the company has a total of four contracts, in the upstream segment and in gas transportation infrastructure both onshore and offshore.”

BMT Fluid Mechanics (BMT), a subsidiary of BMT Group Ltd, a leading international design, engineering and risk management consultancy, has recently completed a comprehensive Computational Fluid Dynamics (CFD) study for an oil major operating offshore Nigeria.

8 1BMT Oil Major FPSO Gas DispersionFPSO Gas Dispersion. Image credit: BMT

BMT’s scope of work included an assessment of the current loading to which the FPSO hull is subjected to, which has enabled the oil major to ensure its mooring systems are fit for purpose.

Johnathan Green, Manager for BMT Fluid Mechanics’ Numerical Modelling Group explains: “CFD is becoming more commonplace in the oil and gas sector with many customers recognizing it to be an effective tool for solving challenges the industry faces in a less conservative and more efficient manner. In this project, we were able to use CFD to more accurately analyze the hydrodynamic forces caused by current and waves and asses the subsequent effect these forces have on the bilge keels of the vessel which are designed to stop the vessel from rolling.”

8 2BMTImage credit: BMT

Through the creation of a 3D CAD model and representation of the FPSO below the water line, the team of specialists at BMT were able to run a comprehensive experimental and numerical study of the manoeuvring characteristics. This looked at different parameters of current conditions to help build up a picture of how the forces and motions impact the vessel and how it performs.

Johnathan Green continues: “BMT’s extensive experience with shallow water hydrodynamics, manoeuvring simulation, hydrodynamic model testing and Computational Fluid Dynamics (CFD) allowed us to deliver against the customer requirements. The benefit of using CFD in this study is that the customer can use the less conservative loads estimated to help design the mooring systems.

CFD has a number of applications within the oil and gas market. BMT regularly uses CFD for consequence modelling (e.g. hydrocarbon fire & explosion and gas dispersion), flow assurance, and helicopter operations. Whilst the aim of all of our work is to ensure that risks to personnel, asset, and environment are reduced to as low as reasonably practicable (ALARP) and although there may be a focus in today’s current economic climate on reducing capital expenditure, BMT strongly believes that optimising design early on in a project can considerably reduce costs by avoiding conservatism.”

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