Statoil, along with its partners, has finalized a 19-month exploration drilling program offshore Newfoundland. The purpose of the drilling program was to increase the robustness of the Bay du Nord project and to test new areas of the Flemish Pass Basin.

Nine wells were drilled safely and efficiently by the Seadrill West Hercules in the Flemish Pass Basin, located approximately 500 kilometers east of St. John’s, Newfoundland and Labrador. The results have improved Statoil’s understanding of the frontier Flemish Pass Basin.

The West Hercules drilling rig. (Photos: Ole Jørgen Bratland)

The drilling program included four exploration wells in close vicinity of the 2013 Bay du Nord discovery, as well as three appraisal wells on the discovery. In addition, two exploration wells were drilled in areas outside the Bay du Nord discovery. The program was conducted in a harsh offshore environment; however, with strong operational and HSE performance, setting several records on drilling speed during the campaign.

The drilling program has resulted in two discoveries of oil at the Bay de Verde and Baccalieu prospects in the Bay du Nord area, both of which add to the resource base for a potential development at the Bay du Nord discovery.

The appraisal and near-field exploration of the Bay du Nord discovery has reduced key reservoir uncertainties and confirmed that the volumes are within the original volume range of the 300 to 600 million barrels of recoverable oil initially estimated by Statoil in 2013, but potentially towards the lower end of the range.

“We are encouraged by the discoveries in the Bay de Verde and Baccalieu wells and the results of the appraisal wells,” said Erling Vågnes, senior vice president, Statoil Exploration, Northern Hemisphere. “Based on the improved understanding of the Flemish Pass Basin petroleum system, we are maturing further prospects that may add volumes to Bay du Nord.”

“The Flemish Pass Basin offshore Newfoundland is a frontier area, where only 17 wells have been drilled in the entire basin – in an area that is 30,000 km2,”said Vågnes. “This drilling campaign has been critical both to maturing the Bay du Nord discovery as well as evolving our knowledge of the greater basin and Newfoundland offshore – which remains a core exploration area for Statoil.”

The drilling program began in November 2014 and was extended by one month to incorporate the drilling of Baccalieu, a well on a license awarded by the C-NLOPB in the 2015 land sale, which Statoil was able to progress from access to well-completion in four months.

Statoil’s assessment of the commercial potential of the Bay du Nord discovery is ongoing. “The recent drilling program has been critical to Statoil’s continued assessment of Bay du Nord, and work is underway to evaluate the results related to proceeding with a potential Statoil-operated development in the Flemish Pass Basin,” said Paul Fulton, president, Statoil Canada.

The North Sea will see a rise in infrastructure deals this year, with private equity funds playing an increasing role in midstream assets, according to business advisory firm Deloitte.

Shaun Reynolds, Director, Transaction Services, Deloitte

Against the backdrop of a low oil price, more oil and gas companies are looking to rationalise their portfolios and divest non-core assets in the UK Continental Shelf (UKCS), the firm said – with private equity and specialist infrastructure funds likely purchasers.

Deloitte’s latest European Infrastructure Investors survey found that pipelines, in particular, have provided a solid and steady return over the last five years. The asset class was highlighted by investors as performing well compared with other infrastructure, including fuel storage, ports and renewables; the internal rate of return on pipelines reached 14% in the period 2013-2016.

Deloitte’s report also found that pipelines will remain a strong focus for infrastructure investors in the future, along with gas and fuel storage.

Shaun Reynolds, Director, Transaction Services, at Deloitte, said: “Historically, big oil and gas operators developed and owned what they needed, transporting their major discoveries through proprietary pipelines and refining it in their own processing plants. That’s largely remained the case, until the last two or three years.

“The ownership model has evolved, driven by the maturity of the basin and the low oil price. Established players are divesting to shore up their balance sheets, and infrastructure is comparatively less complex to value and sell, with a ready market at the right price.

“Private equity firms and specialist energy infrastructure funds are likely buyers – specifically those with a solid grasp of the UKCS. They’ll look to take a number of assets under management, create a portfolio, maximise their potential and then look to divest; most likely to a pension fund aiming for steady returns from a stable asset.”

In 2015, BP sold its stake in the Central Area Transmission System (CATS) to Antin Infrastructure Partners in a £324 million deal. Antin had bought BG Group out of its stake the previous year, giving it near-complete ownership of the asset.

The third party ownership model has been employed successfully in the US shale gas market for years, while oil and gas infrastructure in The Netherlands and Norway is commonly owned by private equity or pension funds.

Shaun added that the changing asset stewardship of North Sea infrastructure could be a positive development for the industry, with 20 billion barrels still recoverable in the basin.

Shaun commented: “It’s a positive step for the UKCS. Private equity will provide focussed management of the assets and ensure they are being used to their utmost potential. That can only be a good thing, particularly from a longevity perspective as we seek to make the most of the North Sea.

“Whatever the case, there’s a strong appetite from investors for North Sea infrastructure – but only at the right price. As the oil price continues to take its toll and pressure mounts on balance sheets, more operators will have to look at rationalisation and infrastructure tends to be a logical sale. Deals are brewing in the UKCS – and we’ll see more on the infrastructure front in the short- to medium-term.”

Dynamic Industries, Inc., (Dynamic), a leading fabrication and service provider to the global oil, gas and energy industries, announced the completion of the 500 ton production platform and 300 ton jacket refurbishment, achieved by accelerating delivery dates accomplished by utilizing Dynamic's large inventory of used structures, and in doing so the client realized significant savings in cost and time. The Nene’ field, which is expected to contain 140,000 BOE/d was discovered by ENI in August 2013. Dynamic, who maintains one of the largest inventories of offshore structures in the Gulf of Mexico, was able to reduce the schedule to first oil by as much as 60% by using a production platform and jacket from its inventory.

Jeff Clement, COO of Dynamic Industries, Inc. US Fabrication Division, stated, "In today's low commodity price environment, offshore fields that are challenged from a budget and schedule perspective can benefit greatly from utilizing our large inventory of offshore structures. Our client saw significant savings by utilizing used structures. In addition, the environmental advantages of a closed loop system, where platforms and jackets removed by Dynamic and its partners are refurbished and returned to active use, provides another example of continued commitment to both the environment and reserve replacement."

Optimus Seventh Generation, an Aberdeen headquartered behavioural change consultancy, has successfully completed the first phase of a yearlong project with BP to induct all crew and contractors into its Life Extension Project on the Eastern Trough Area Project (ETAP) in the Central North Sea.

ETAP is one of the largest and most complex developments in the North Sea, comprising nine oil and gas reservoirs, six of which are operated by BP. The ETAP Life Extension Project (ELXP) will help secure the future of the fields until 2030 and beyond.

The initial phase of the project, which commenced in Q3 2015 and was completed in Q4, involved crew members attending Optimus Seventh Generation’s Induction Plus™ workshop before mobilizing on ETAP.

Derek Smith, chief executive at Optimus Seventh Generation

The four hour induction was in collaboration with BP to include its values and project specific information, and was blended with Optimus Seventh Generation’s behavioural and motivational concepts and a commitment from delegates to demonstrate behaviours to deliver safe performance.

The second phase of the project, which commenced in October 2015 and is due for completion in August 2016, involves Optimus Seventh Generation’s behavioural coaches working alongside HSE to deliver Supervising Safety modules to the 148 personnel crossing from the flotel to the asset daily.

Derek Smith, chief executive at Optimus Seventh Generation, said: “The recent contract win strengthens our relationship with BP and we are delighted to be working with the team as they continue to invest in the North Sea with the rejuvenation of ETAP.

“Our Induction Plus™ workshop was delivered at the initial stages of the project and has continued throughout to satisfy the introduction of multiple contractors at different stages - to date this has totalled 1,110 delegates. Following this, our behavioural coaches were deployed and the contract was extended based on the coaches’ support and performance.

“In the current climate it is increasingly important that expenditure on training is focused on vital areas. At Optimus we develop bespoke programs and adapt our focus to ensure our approach is project specific, helping to guarantee optimum outcomes and success.

“Our experienced team is well equipped to deliver on the ground support for industry service companies and operators, and we are committed to ensuring safety is at the forefront of everyone’s mind in this challenging market.”

BP Egypt announced on June 9, another important gas discovery in the Baltim South Development Lease in the East Nile Delta.

The Baltim SW-1 exploration well, drilled in water depth of 25 meters by operator IEOC (Eni), reached a total depth of 3750 meters depth and penetrated approximately 62 meters of net gas pay in high quality Messinian sandstones. The discovery, which is located 12 kilometers from shoreline, is a new accumulation along the same trend of the Nooros field discovered in July 2015 and currently producing 65,000 barrels of oil equivalent per day. Further appraisal activities will be required to underpin the full resource potential of the discovery.

Hesham Mekawi, Regional President of BP North Africa, commented: “We are pleased with the results of the Baltim SW-1 well as it is the third discovery along the Nooros trend and confirms the great potential of the Messinian play and its significant upside in the area. Our plan is to utilize existing infrastructure which will accelerate the development of the discovery, and expedite early production start-up. This announcement is another example of BP’s commitment to unlock resources in order to bring critical gas production to Egypt.”

BP holds a 50% stake in the Baltim South Development lease, and Eni, through its subsidiary IEOC, holds 50%. The well was drilled by Petrobel, a joint venture between IEOC and the state partner Egyptian General Petroleum Corporation (EGPC).

• BP has a long and successful track record in Egypt stretching back over 50 years with investments of approximately $30 billion, making BP one of the largest foreign investors in the country. In Egypt, BP’s business is primarily in oil and gas exploration and production. BP is working to meet Egypt’s domestic market growth by actively exploring in the Nile Delta and investing to add production from existing discoveries.

• To date, BP Egypt, in collaboration with the Gulf of Suez Petroleum Company (GUPCO), BP’s joint venture (JV) Company with the Egyptian General Petroleum Company (EGPC), has produced almost 40% of Egypt’s entire oil production, and currently produces almost 10% of Egypt’s annual oil and condensate.

• In addition, through joint ventures with EGPC/EGAS and IEOC (ENI) the Pharaonic Petroleum Company (PhPC) and Petrobel BP currently produces close to 30% of Egypt's total gas.

• The West Nile Delta (WND) Project is a strategic project for BP. BP is the operator of the project. The West Nile Delta project, involves the development of 5 trillion cubic feet of gas resources and 55 million barrels of condensates. Production from WND is expected to be around 1.2 billion cubic feet a day (bcf/d), equivalent to about 30% of Egypt’s current gas production. All the produced gas will be fed into the country’s national gas grid. Production is expected to start in 2017.

• BP has made a series of discoveries in Egypt in recent years including Taurt North, Seth South and Salmon and Rahamat, Satis, Hodoa, Notus, Salamat and Atoll.

• BP is a 33 per cent shareholder of a natural gas liquids (NGL) plant extracting LPG and propane, United Gas Derivatives Company (UGDC) in partnership with ENI/IEOC and GASCO (the Egyptian midstream gas distribution company).

• BP is also present in the downstream sector through Natural Gas Vehicles Company (NGVC, BP 40 per cent) which was established in September 1995 as the first company in Africa and the Middle East to commercialize natural gas as an alternative fuel for vehicles.

Engineers and analysts from the Bureau of Safety and Environmental Enforcement's (BSEE) Gulf of Mexico and Alaska Regions recently evaluated Spill Response Operations Training and Equipment Verification exercises conducted by the Tennessee Gas Pipeline Company and its oil spill removal contractor at the Port of Morgan City, La. These exercises are required periodically to test spill response team training and resource availability, as part of each operator’s Oil Spill Response Plan.

Photo courtesy: BSEE

The exercises were held in mid-May on board two responder vessels of Clean Gulf Associates, which was contracted by Tennessee Gas Pipeline. During the spill response exercise, BSEE staff evaluated Clean Gulf’s Spill Response team and their training of a group of responders seeking team member certification. Along with the spill response training evaluation, BSEE simultaneously conducted an equipment verification of Clean Gulf’s oil spill resources. Both vessels maneuvered offshore and deployed specialized equipment to simulate a spill response. The responders also tested the effectiveness of their oil boom apparatus, skimmers, motorized components and vessel performance. Staff from BSEE's Oil Spill Preparedness Division and Tennessee Gas Pipeline boarded each vessel and assessed response actions.

Spill Response Operations Training and Equipment Verification exercises are part BSEE's many efforts to make sure that offshore operators will be ready to effectively manage a real spill, should one occur.

Chet Morrison Contractors announces a new tool for cleaning drilling and production risers that is safer, faster and more cost-effective than current methods. MUDBUG is an air-actuated, self-propelled device that uses oscillating brushes to clean debris build-up inside risers, moving through the length of the riser and back out again.

“MUDBUG is a giant leap forward in deepwater riser cleaning,” said John DeBlieux, vice president of Deepwater Riser Services for Chet Morrison Contractors. “It’s not only more cost-effective and safer, it’s also better for the environment and customer’s bottom line.”

Unlike other methods, MUDBUG does not require high-pressure water to remove the rust, scale and drilling mud that builds up in drilling and production risers. Instead, MUDBUG uses only 120-psi air to operate, thus eliminating the problem of water disposal and risk associated with high-pressure washing.

MUDBUG can be operated by a two- or three-man crew instead of the usual five-man team required to clean a riser. Because the device is portable, it can easily be transported via plane or helicopter to any remote location either onshore or offshore. Its small job box (two feet by four feet) takes up very little space, making it ideal for rigs or other offshore operations. When operational, MUDBUG is approximately three feet long and 19 inches in diameter.

The “MUDBUG” name was inspired by the crawfish, which pushes back mud and debris to make its home. It has been successfully tested and used in the offshore environment by major drilling contractors. The device comes with an extra motor and all brushes, and is available exclusively through Chet Morrison Contractors in the United States, Gulf of Mexico, Caribbean and Trinidad. For more information, visit www.mudbugrisercleaner.com.

by CGG

Despite depressed oil prices, the Gabonese 11th deepwater licensing round has generated considerable interest from both International Oil Companies (IOC’s) and newcomers alike, encouraged by the success of exploration in the conjugate margin offshore Brazil, as well as recent pre-salt discoveries such as Ruche, Tortue, Diaman and Leopard in nearby Gabonese waters. CGG has worked directly with the Direction Generale des Hydrocarbures of Gabon (DGH) to acquire and process over 25,000 km2 of new 3D BroadSeis™ multi-client seismic data over available and licensed blocks in the South Basin to enable evaluation of this prospective area. A fast-track pre-stack time-migrated dataset for this survey is available now, along with sample pre-stack depth reverse time-migrated (RTM) data in one area. The final RTM for the whole of the survey area will be available this summer.

Map showing available license blocks and coverage of new broadband 25,000-km2 multi-client survey and additional data being acquired in blocks F14 and F15. Credit: CGG

The objective of the survey is to image potential prospective structures at base salt level without compromising the shallower post-salt image quality. The data do not disappoint. Even a preliminary ultra-fast-track dataset produced onboard was described as “way beyond expectations” by a major oil company interpreter. On the full fast-track dataset, more detail below the salt is being revealed than has ever been seen before, revolutionizing the understanding of the geology of the area. Early seismic imaging results indicate the presence of thick syn-rift and sag sequences below the salt, which are the key intervals of a pre-salt petroleum system and indicate many exciting prospects, some of which continue beyond the borders of the survey so that their full extent cannot be gauged.

This survey is being processed using the latest high-end imaging technology to produce the clearest images. The fast-track PSTM volume shows clear uplift over the existing data, while the fast-track PSDM shows the full benefits of advanced velocity modeling and depth-migrated modern broadband 3D seismic data. The uplift in subsalt imaging that will be achieved in the final dataset is dramatic; the RTM fully depth-migrated example line (which can be seen in the lightbox on the CGG booth #1250) shows clearly defined tilted fault blocks and horst features as well as the highly complex nature of the thrusted and distorted salt and sediment overburden.

Multi-layer tomography (TomoML) and full waveform inversion (FWI) are being used to create the final velocity model, with RTM being used in the velocity model building iterations. The high-quality, low-frequency data acquired using the BroadSeis solution is particularly beneficial for FWI as the low frequencies prevent cycle-skipping. The imaging improvement from the FWI velocity model can be seen both in the shallower section, where pull-up/push-down image distortions are precisely corrected, and in the deeper salt bodies, where salt flanks and subsalt reflectors show improved focus and continuity due to better overburden description. A booth theater presentation describing details of the imaging of this dataset is being given daily on our booth #1250, and these were also presented by Andrew Ratcliffe in the technical sessions on Tuesday (Tu SRS2 07).

Although this dataset delivers unprecedented images of the subsurface in this area, additional data are being acquired to improve the imaging still further in the most complex geology to the southeast of the survey. Tailored multi-vessel survey design is enabling longer offsets, up to 14 km in the same orientation as the original data, to be acquired over block F14. In block F15, adjacent to the Congo border, a second orthogonal azimuth of the full range of offsets, including those up to 14 km, is being acquired. Longer offsets and dual azimuths are expected to improve the sub-salt illumination and provide even greater clarity of the most challenging structures. In order to acquire these long offsets an additional source vessel is being deployed. Synchronized source technology and blended acquisition are being used to enable the shot interval to be less than the record length, so that source density, and therefore fold of coverage, can be maintained.

All the survey data form the centerpiece of an integrated geoscience project which will include interpretation of the gravity data acquired with the seismic to analyze the deep structure of the basin, analysis of the key wells in the area, full seismic interpretation in the depth domain with integration of satellite seep data to identify potential natural hydrocarbon escape conduits and production of paleogeographic, reservoir distribution and source rock maturity maps of key stratigraphic intervals, among other products. Integrated studies are becoming increasingly popular as they provide a single validated source for information and each individual part is improved by understanding the requirements of the larger project. Large multi-client surveys also provide a cost-effective means of acquiring high-quality 3D seismic data which allows oil companies to reduce their exploration risk in both mature and frontier areas and helps to reduce the time required from licensing award to drilling wells. 

A cross-industry project led by DNV GL to halt the boom in subsea documentation shows that implementing a standardized approach can significantly reduce engineering hours. The two-year collaboration led by DNV GL has concluded in a publicly available Recommended Practice which can reduce the amount of subsea documentation and enable documentation reuse in a typical subsea field development project.

Image courtesy: DNV GL

DNVGL-RP-O101 ‘Technical documentation for subsea projects’ details a required minimum set of documentation transferred between E&P companies, operators and contractors for the construction, procurement and operation of a field. The outcome will reduce the volume and variety of documentation exchanged between the parties in a project, thereby making project execution more cost effective.

According to a contractor in the JIP, subsea documentation increased by a factor of four between 2012 and 2015. Previously, a contractor in a typical subsea project would deliver around 10,000 documents, with each one averaging three revisions, resulting in up to 30,000 transactions between two actors. Today, projects can deliver 40,000 documents, with three revisions resulting in 120,000 transactions. Handling time has also doubled per revision. A big project may require a contractor to have 25 people just on document control.

“We like solid documentation in DNV GL, but this massive explosion in paper hasn't tangibly improved performance, safety or environmental impact – it’s just escalated costs without adding value,” says Bente Helén Leinum, Project Manager, DNV GL – Oil & Gas.

“A benchmarking exercise by one JIP participant showed that adoption of the RP could deliver a 42% potential reduction in engineering hours. The savings come from reduced reviews by reusing documents, having more standardized documents and avoiding unnecessary reviews of non-critical documents. Another supplier estimates that the potential cut in documentation can be as high as 75-80% through increased use of standardized documents,” continues Leinum.

Jan Ragnvald Torsvik, lead engineer of Life Cycle Information at Statoil and co-chairman of the project, comments: “All JIP partners have invested considerable time and the outcome is a fantastic achievement that will dramatically cut waste in the handling of technical information in projects. We have already learned that this standard’s approach in utilizing package-specific requirements has a positive impact on standardization and efficiency. We are already seeing the benefits of implementing a draft version of the RP in Statoil’s Johan Sverdrup project last year,” he continues.

“The RP encourages more reuse of subsea documentation and will deliver more predictability throughout the value chain. It provides clear expectations for all parties involved, and duplications, misunderstandings and unnecessary work can be avoided,” says Tommy Lien, Senior LCI Process Coordinator, Aker Solutions.

JIP partners were Aker Solutions, Brightport, Centrica Energi, DEA Norge, Det norske oljeselskap, DNV GL, ENI Norge, GCE Subsea, FMC Technologies, GDF SUEZ E&P Norge, Kongsberg Oil & Gas Technologies, Lundin Norway, Oceaneering, OneSubsea, Statoil, Subsea 7, Subsea Valley and SUNCOR Energy Norge.

Observers: The Norwegian Oil and Gas Association and Petroleum Safety Authority (PSA) Norway.

Swiber Holdings Limited (“Swiber” and together with its subsidiaries, the “Group”), a leading global offshore construction services provider to the oil and gas industry, has secured three new contracts for projects with a total value of US$215 million in the Middle East and Southeast Asia regions.

Said Mr. Darren Yeo, Deputy Group CEO of Swiber, “Despite the ongoing oil market volatility and challenging conditions in the offshore oil and gas industry, Swiber continues to demonstrate our ability to successfully secure new projects. In fact, one of these new projects represents an important breakthrough for Swiber into the lucrative Middle East market.”

Swiber was awarded an EPCI (“Engineering, Procurement, Construction and Installation”) contract from a European oil major to perform pipeline replacement work in Qatar, marking the Group’s first offshore construction project in the Middle East. The Group has commenced the engineering phase of this project which is scheduled for completion in the third quarter of 2017.

“This job is for a repeat customer with whom we have worked closely on numerous projects across the globe. It is a testament of our proven experience and execution capabilities that the customer is once again entrusting Swiber with this project in Qatar,” said Mr. Yeo.

Swiber recently also won new contracts for a further two projects in Myanmar and Vietnam, which solidifies its market position in Southeast As.

The Group is participating in a consortium that will carry out EPCI of two wellhead platforms, associated pipelines and tie-ins for a project off the coast of Myanmar for a major Southeast Asian oil and gas company. This project commences immediately and is expected to be completed by the first quarter of 2018. The customer has options to award an additional two wellhead platforms.

The third contract involves the provision of transport and installation services for a full field development project in the waters off Vietnam. The Group has recently started work on this job, which is targeted for completion in the third quarter of this year.

“While Southeast Asia has seen a slowdown in offshore oil and gas activities over the past couple of years, it remains an important market for Swiber as our projects in this region contributed US$117.1 million or 14.1% of the Group’s revenue in 2015. Our project wins in Myanmar and Vietnam will solidify the Group’s established market presence in the region,” said Mr Yeo.

These latest contracts have lifted Swiber’s order book to around US$1.2 billion. The contracts are expected to contribute to the Group’s financial performance in the current financial year ending December 31,2016. The US$100 million EPIC contract awarded to Swiber in February 2016 has been re-tendered by the customer due to changes in the project work scope and schedule. Swiber will soon be submitting its bid for this project.

“As an established provider of EPCI services for shallow water oil and gas field development, Swiber remains in a good position to weather the current industry downturn. We continue to see opportunities in our target markets and are actively working on new tenders to grow our pipeline of projects,” Mr. Yeo said.

The Group is presently bidding for projects with a combined value of US$3.4 billion, made up of US$1.65 billion for Africa/Europe, US$750 million for Latin America, US$550 million for Southeast Asia and South Asia and US$450 million for the Middle East.

On 6 June 2016, Swiber also fully redeemed its Series 16 S$130 million Fixed Rate Notes.

Materia Inc., a leader in the development and manufacture of catalysts and advanced polymers, is pioneering the next generation of oil and gas solutions with Proxima® thermoset resins.

Proxima resins provide reliable, practical and economical solutions that solve major technology challenges in subsea thermal insulation, subsea buoyancy and downhole tools. Proxima resins are extremely easy to process due to their inherently low viscosity and controlled cure profile. The resulting durable products are ideal for use in extreme environments. Compared with commonly used polymers, Proxima thermosets withstand the most extreme hot/wet conditions and provide excellent performance.

Proxima HTI resins for high temperature subsea thermal insulation provide an effective thermal barrier between high temperature flowlines and seawater. Proxima polymers maintain structural integrity in operating environments at water depths greater than 10,000 ft., and this advanced insulation technology can be rapidly and safely applied in the factory or the field. Earlier this year, Materia was selected by Shell Offshore, Inc., a wholly-owned subsidiary of Royal Dutch Shell plc, to supply pipeline insulation materials for the Appomattox development in the deepwater Gulf of Mexico.

Brian Conley, senior Proxima product development manager, said, “Materia’s subsea thermal insulation products offer full system integrity for high temperature deepwater environments. The use of Proxima HTI polymers results in lower risk and better reliability for insulation of high temperature subsea flowlines, field joints and equipment relative to the alternative engineered solutions.”

Proxima STR thermosets are designed for use in syntactic foams in subsea buoyancy applications. These lightweight materials withstand the severe hydrostatic pressures of deepwater and ultra-deepwater environments while providing substantially improved buoyant support to critical subsea components. Ed Lehman, Proxima product development manager, said, “Proxima STR resins offer reliable manufacturing, state-of-the-art properties and improved long-term performance, delivering benefits throughout the value chain.”

Daryl Allen, Proxima product development manager, said, “Proxima HPR casting resins offer thermal stability and toughness with fast and easy polycrystalline diamond compact (PDC) or tricone drillability for many downhole applications. When long fiber composite performance is required, Proxima ACR infusion resins offer exceptional performance with fiberglass and carbon fiber. These bring improved thermal stability, corrosion resistance and reliability when compared to standard composite materials. Both the HPR and ACR systems provide superior materials that solve today’s downhole challenges.”

Materia supports its customers with application engineering services provided from its state-of-the-art prototyping and polymer testing facility in Pasadena, CA.

In the Arendal Yard in Gothenburg, Sweden, Apply Emtunga is building the offshore accommodation modules to the oil rig projects Martin Linge and ETAP. As the living quarters are to be the safest place on a rig Apply Emtunga puts a lot of effort into creating maximum safety. One way to ensure safety is to use Roxtec cable and pipe transits.

The nine-floor high living quarters of Martin Linge (photo) are delivered as a complete integrated accommodation module from Gothenburg. It has three A60 fire rated divisions and an H60 fire rated bulkhead as partition towards the production and processing areas. The complex contains offices and meeting areas as well as cabins equipped with TV, Internet and bathroom. There are also facilities such as a little hospital, a kitchen, a dining room and two TV rooms as well as a music room and a gym.

Certificates showing reliability

“We use Roxtec Sleev-it fire penetration seals for all plastic pipes with drinking water and hot water. The reason for choosing Roxtec is that it was the only supplier that could present the required fire protection certificates. Everything in this project must have a minimum lifetime of 30 years,” says piping engineer Mattias Öhrn at Apply Emtunga.

The living quarters of Martin Linge will under normal conditions house 75 people, but can if necessary house up to 124 people. The building will in total weigh approximately 2,000 tons when it is ready to be shipped on a barge to the platform off the coast of Norway.

Simplicity and efficiency

The living quarters for the ETAP project are, on the other hand, delivered as several smaller units directly to the rig off the coast of Scotland for final installation into an integrated unit on the platform. In this project, the fire rated plastic pipe penetration seals used are the Roxtec RS PPS/S. Ulf Efraimsson of pipe installation contractor Assemblin, is very satisfied with the Roxtec contribution: “It is easy to work with Roxtec sealing solutions and they work perfectly.”

With the continuous search for new gas supplies, companies like Gazflot often find themselves in harsh geographical conditions trying to unlock the next reserve of natural gas. Such explorations require robust and reliable equipment to work under some of the most difficult conditions imaginable. As such, there is a need for genuine partnerships with companies that understand what it takes and are well-positioned to deliver technologies that support more efficient exploration activities.

GE’s Marine Solutions (NYSE: GE) was recently awarded a service contract by CIMC Raffles to provide the first dry-dock services on two of Gazflot’s semi sub drilling vessels—Northern Lights and Polar Star. During the dry-docking, GE’s Marine Solutions will thoroughly test its scope of supply and will replace and upgrade parts where necessary.

Semi subsea drilling vessel Polar Star: Photo courtesy: Gazflot

With years of experience in carrying out similar activities, historical data from these vessels and an understanding of how systems interact with each other, GE’s Marine Solutions is ideally placed as a one-stop solution to carry out the dry-docking of these vessels. This dry-docking will enable Gazflot to continue operating its vessels at optimum levels.

“GE will not only carry out the required maintenance activities on the two vessels, but will also be assisting with the supervision of the activities throughout dry-docking. We are impressed by GE’s technical and operational finesse and look forward to working with them in the long-term,” said Mr. Yongqiang Shao, deputy general manager, CIMC Raffles.

Commenting on the contract, Andrey Nikireev, deputy head of power supply department, Gazflot, said, “We have been very happy with GE, and its technology is running flawlessly on board our vessels. GE’s deep understanding of these technologies makes them an ideal partner for this dry-docking, and with GE’s engineers carrying out the maintenance activities, we are confident that our vessels are in a safe pair of hands.”

The two vessels were equipped with GE technologies including dynamic positioning, automation, drilling drives, MV 7000 propulsion drives, Power Management System, Vessel Management System and Thruster Assisted Mooring System. These technologies have been reliably at work on Gazflot’s ice class vessels, which are capable of drilling up to 10,000 feet in the adverse conditions in Northern Russia. Through the current contract, GE’s team of on-site engineers will ensure the longevity of installed systems while working with the yard to supervise the dry-docking activities.

“We have had a long-standing relationship with Gazflot and are happy to further our partnership through this deal. With our reliable technologies on board their vessels, GE is at the heart of Gazflot’s exploration activities. Our thorough maintenance services and assurance of providing technical support for these vessels will ensure uninterrupted operations for Gazflot in the years to come,” said Tim Schweikert, president & CEO, GE’s Marine Solutions.

After the dry-docking, GE will continue to provide remote technical support for the Northern Lights and Polar Star semi sub drilling vessels.

Aker Solutions has won a contract to deliver its longest-ever umbilicals system at the Zohr offshore gas field in the Egyptian part of the Mediterranean Sea.

Photo courtesy: Aker Solutions

The agreement with Petrobel in Egypt is worth more than NOK 1 billion and will be booked in the second quarter. It stipulates the delivery of 180 kilometers of steel tube umbilicals that will connect the Zohr subsea development to an offshore control platform. Petrobel, a joint venture between The Egyptian General Petroleum Corporation (EGPC) and Eni, is responsible for the development and operations at Zohr.

"Aker Solutions is building on its previous experience offshore Egypt to now deliver its largest-ever umbilicals project," said Luis Araujo, chief executive officer of Aker Solutions. "We are very pleased to support Petrobel and Egypt on this important development."

The work will be led by Aker Solutions' subsea division in Oslo and manufacturing will start immediately at the umbilicals plant in Moss, Norway.

The company has invested substantially in the Moss facility over the past years. The plant has more than 20 years of experience in making the most advanced and complex umbilical systems, which are used to transport data, power and liquids between oil and gas installations on the seafloor and facilities onshore or on platforms.

The umbilicals system will be delivered by mid-April 2017.

BP has started up a major water injection project at its Thunder Horse platform, extending the production life of one of the biggest deepwater fields in the U.S. Gulf of Mexico.

Photo credit: BP

The project, which reflects BP’s strategy of continued investment in its existing deepwater Gulf of Mexico production hubs, will boost recovery of oil and natural gas from one of the Thunder Horse field’s three main reservoirs.

Over the past three years, BP refurbished the platform’s existing topsides and subsea equipment while also drilling two water-injection wells at the site. From those wells, water will be injected into the reservoir to increase pressure and enhance production. The improvements are expected to allow the Thunder Horse facility to recover an additional 65 million barrels of oil equivalent over time.

The project is the second of five major upstream projects BP expects to bring online in 2016. It is part of BP’s plan to add approximately 800,000 barrels of oil equivalent per day of new production globally from projects starting up between 2015 and 2020.

“This project will help BP sustain high levels of oil production in the deepwater Gulf of Mexico for years to come,” said Richard Morrison, regional president of BP’s Gulf of Mexico business. “And it’s another example of BP taking advantage of targeted and cost-effective opportunities within our existing portfolio.”

The Thunder Horse platform, which sits in more than 6,000 feet of water and began production in June 2008, has the capacity to handle 250,000 barrels of oil and 200 million cubic feet per day of natural gas. The facility continued to operate while work on the water injection project was underway.

In the deepwater Gulf of Mexico, BP operates four large production platforms - Thunder Horse, Atlantis, Mad Dog and Na Kika - and holds interests in four non-operated hubs - Mars, Mars B, Ursa and Great White.

BP has two other major projects underway in the deepwater Gulf of Mexico. The Thunder Horse South Expansion project will add a new subsea drill center roughly two miles from the Thunder Horse platform. In addition, BP continues to design the Mad Dog Phase 2 project, which will develop resources in the central area of the Mad Dog field through a subsea development tied back to a new floating production hub consisting of up to 24 wells from four drill centers.

About BP

Over the past 10 years, BP has invested more than $90 billion in the U.S. - more than any other energy company. BP is a leading producer of oil and gas and produces enough energy annually to light nearly the entire country for a year. Employing about 16,000 people across the country, BP supports more than 170,000 additional jobs through all of its business activities. 

DNV GL has been awarded a contract by COSCO Shipping Company Limited (COSCO SHIPPING) of China for the installation engineering services for the BorWin gamma high voltage direct current (HVDC) converter platform.

The Dutch-German transmission system operator TenneT is developing the offshore AC/DC converter platform BorWin gamma as part of the grid connection project BorWin3. The project will provide an essential renewable offshore resource to meet increasing energy demands in Germany, as part of the German Energiewende (Energy Transition) program.

Artist's impression of the BorWin gamma HVDC platform © Petrofac

A consortium of Siemens and Petrofac has been contracted by TenneT to design, build and install BorWin gamma. COSCO SHIPPING was awarded the transportation and installation contract by Petrofac and has chosen DNV GL's Noble Denton marine services as partner to fulfill the dynamic positioning (DP) float-over job.

Pioneering technology

DNV GL’s Noble Denton marine services pioneered and developed DP float-over, a heavy module installation method using a dynamic positioning vessel, together with COSCO.

"DNV GL has jointly completed 10 installations successfully around the world with COSCO,” explains Andy Wang, project director of DNV GL - Oil & Gas Greater China. “Our experts have a solid track record in DP float-over that won the confidence of Petrofac and Siemens," he continues.

“Our investment in innovative solutions and leading technology for heavy offshore module transportation and installation has given us a long-standing reputation that led us to win this contract. We sincerely look forward to working with COSCO and the consortium partners on this important project,” says Arthur Stoddart, regional manager of DNV GL - Oil & Gas Region Greater China, Korea & Japan.

BorWin gamma: facts and figures

This project will create a few new entries to DNV GL's record book. Weighing in at a massive 18,000 metric tons, BorWin gamma will be one of the heaviest HVDC platform ever installed; moreover, it will be the first DP float-over operation in the North Sea and Europe.

The installation is expected to commence in the summer of 2018. Once completed, it will transmit approximately 900 MW of wind power, which is roughly equal to the annual electricity consumption of 1 million German households.

Scheduled to go online in 2019, the BorWin gamma platform will be installed nearly 130km off the German coast in the North Sea, at a water depth of approximately 40m. The 900 MW DC transmission will be through 320 kV cable of 160 km length.