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.

Type 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.

Software 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.

North 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.”

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.

Photo 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.

Eni Goliat illustration overview. Credit: © Eni Norge.

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.

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.”

Image 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

LORD 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.

Photo 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.

“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.

“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.

Wood 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 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.

The 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.

Shah 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.

FPSO 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.”

Image 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.”

As 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.

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.

Right 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.

Aker 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.

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.

Photo 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.

The 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