Leases Awarded for Gulf of Mexico Sale 247

7BOEMLeaseSale OilRigs KevinThe Bureau of Ocean Energy Management (BOEM) completed its required evaluation to ensure the public receives fair market value for tracts leased in Central Gulf of Mexico Oil and Gas Lease Sale 247, held on March 22, 2017. The sale offered 9,118 unleased blocks, covering 48 million acres.

During Sale 247, 28 companies participated in submitting 189 bids on 163 tracts. A total of $274,797,434 was received in high bids covering 913,542.21 acres. Of the tracts receiving bids, 22 were in water depths less than 200 meters and 141 were in water depths greater than 200 meters.

After extensive geological, geophysical, engineering, and economic analysis, BOEM awarded 153 tracts receiving bids and rejected 10 high bids. The 10 rejected high bids totaled $10,848,507 and covered 56,365.79 acres. BOEM has determined that the value of those bids was insufficient to provide the public with fair market value for the tracts and will re-offer these tracts as part of the next lease sale, Sale 249 in August. The highest bid accepted was $24,056,719 submitted by Shell Offshore Inc. for Atwater Valley 64. The tract receiving the greatest number bids was Garden Banks 1006 with five bids.

More information on Sale 247.

Assuring Senegal’s Future in Oil and Gas

8LR Cairn senegalMitigating uncertainty and determined to help Cairn Energy (Capricorn Senegal Limited) to get the assurance they need to succeed in their offshore plans covering 400 square kilometers, Lloyd’s Register begins field development surveys in the Sangomar Offshore and Sangomar Deep Offshore license blocks.

Cairn Energy PLC, one of Europe's leading independent oil and gas exploration and development companies, has chosen Lloyd’s Register (LR) to provide project management and technical assistance in their extensive SNE field development surveys offshore Senegal.

The contract will use LR’s specialist geophysical and geotechnical expertise in a site investigation campaign that will use two vessels to survey and investigate an area of more than 400 square kilometers in the Sangomar Offshore and Sangomar Deep Offshore license blocks. Offshore operations are expected to take place between June and September 2017.

Chris Burnside, Cairn Energy PLC, SNE Exploitation Manager, says: “Cairn and its Joint Venture partners, Woodside Energy and FAR Ltd and Petrosen, the national oil company of Senegal, are determined to ensure a safe, efficient and technically productive field development survey and site investigation campaign and Lloyd’s Register will help us to achieve these objectives.”

The geophysical, shallow geotechnical and environmental site survey will assist the planning and engineering of the facilities needed to develop the field. LR will ensure optimum information on seabed and sub-seabed conditions are provided to enable the safe, secure and efficient design and installation of facilities, identify and investigate the relevant seabed areas and shallow soil zones; and assess the location for the presence of potentially important seabed habitats. Its specialist teams will also cover the geotechnical site investigation to help Cairn develop suitable arrangements for their subsea production system, from drill centers connected via flowlines and umbilicals, to Floating Production, Storage and Offloading facility (FPSO), and provide information relating to an export pipeline route to shore.

Richard Orren, Vice-President of Survey and GeoEngineering at LR, says: “We are delighted that Cairn Energy has decided to continue their association with LR. The award of this contract builds upon and reinforces our long and successful collaboration with Cairn.”

“It’s an exciting project to be involved in and at such a critical time in the industry. It will bring together considerable expertise from our specialist teams across LR and we look forward to playing our part in supporting Cairn and their partners on their field development program in Senegal.”

LR has provided support to Cairn over the past two years for their SNE field development. This includes a metocean study, a regional geo-hazard assessment desk study, a seabed and shallow soils ground model, and a continental shelf regional study for export pipeline routes. The company has also been instrumental in providing Cairn with assistance on evaluating the technical capability of survey contractors and tender responses prior to selection of the contractor for the survey and site investigation campaign.

LR’s Well Engineering team are also supporting Cairn and their partners in the significant multi- well appraisal drilling campaign off Senegal, with the provision of staff and services.

Cairn has been active in Senegal since 2013 and drilled two wells in 2014, discovering oil in both and opening a new hydrocarbon basin on the Atlantic Margin, with the SNE-1 discovery recognized as the largest global oil discovery in 2014. These were the first wells to be drilled offshore Senegal in more than 20 years and the first deep-water wells.

In 2015 the Government of Senegal approved Cairn and its Joint Venture partners’ extensive evaluation plan with Cairn going on to drill four further appraisal and exploration wells in the SNE field in the first half of 2016.

Statoil Starts Production on Gina Krog in the North Sea

At 17.02 CET on 30 June, Statoil started production on the Gina Krog oil and gas field in the North Sea.

9GinaKrogThe Gina Krog platform is tied into Sleipner A. (Photo: Ole Jørgen Bratland/Statoil)

Statoil and the partners invest a total of some NOK 31 billion in the development of the Gina Krog field.

“We are proud to have delivered Gina Krog with a good HSE record and in line with the cost estimate in the plan for development and operation,” says Margareth Øvrum, Statoil’s executive vice president for Technology, Projects and Drilling, thanking suppliers and partners for good collaboration in the project.

More than 600 people have been working on the Gina Krog field since last August preparing the platform for production.

Gina Krog is a global project with substantial Norwegian deliveries. For example, the living quarter has been built at Stord, more than half of the equipment packages come from Norway, and all drilling and well services are performed by Norwegian suppliers.

The Gina Krog platform is tied in to Sleipner A and uses both processing capacity on the platform and existing pipelines for sending the gas to the marked in Europe.

“This illustrates how we can maximize value creation and realize new projects on the NCS by utilizing existing infrastructure,” Øvrum says.

Oil from the field is transported by a floating storage and offloading unit (FSO) which will be located on the field.

Gina Krog was initially a small-size gas discovery made in 1974. In 2007 and 2008 oil was struck, which shows the importance of near-field exploration.

“We believe it is possible to maintain high levels of activity on the NCS up to, and beyond 2030. We have a very good infrastructure which we will leverage to add value for Statoil and society for a long time to come,” says Statoil’s executive vice president for Development and Production, Arne Sigve Nylund, adding:

“The field will be operated from Statoil’s Stavanger offices, whereas the helicopter and base services will be run from Sola and Dusavika.“

Gina Krog will create jobs both onshore and offshore for 15-20 years. In addition, Gina Krog will help extend the productive life and maintain jobs at Sleipner A and Kårstø.

Falcon 9 Rocket Booster Returns to Port Canaveral

10Falcon 9 Rocket BoosterOn Thursday, June 29, 2017, Port Canaveral welcomed back a SpaceX Falcon 9 rocket booster after its successful June 23 launch and landing aboard the drone ship Of Course I Still Love You. This was the most challenging launch for the 229-foot-tall rocket to date. The first stage rocket soared to an altitude of 44 miles before successfully separating from an 8,150-pound BulgariaSat 1 satellite.

Once the Falcon 9 first stage rocket booster has been offloaded from the drone ship, it will make the short transit to SpaceX’s new rocket refurbishment facility some 700 yards away. SpaceX is planning to launch its third Falcon 9 rocket in less than 10 days, scheduled for Sunday evening, July 2nd.

ABOUT PORT CANAVERAL

Led by the elected five-member Canaveral Port Authority Board of Commissioners and Port Director and CEO, Captain John Murray, Port Canaveral is one of the world's most dynamic and exciting ports. A world-class gateway for cruises, cargo, recreation and logistics, as well as a gateway to new frontiers, including space, Port Canaveral hosts more than 4 million revenue cruise passengers through its state-of-the-art terminals and 5.5 million of tons of cargo annually, including bulk, break-bulk, project, and containerized. The Port is strategically located to service all Florida markets, as well as the Southeastern United States. In addition to world class cruise facilities and diverse cargo operations, Port Canaveral offers more recreational opportunities than all other Florida deep-water seaports combined, including public parks, free public boat ramps, marinas, an entertainment district, and the seven-story interactive exhibit and event venue Exploration Tower. For more information or to download high resolution versions of the photos, visit the Port Canaveral website.

M2 Subsea Awarded Internationally Recognized DNV-GL Certifications

11 1M2Subsea11 2M2Subsea dnvM2 Subsea, the global independent provider of ROV services, has been awarded a raft of industry certifications from DNV-GL for its management system standards, just seven months after starting up.

The Aberdeen-headquartered company received two of the internationally recognized ISO certifications for its quality management systems, both to the latest 2015 standards. The ISO 9001: 2015 promotes the adoption of a process approach and underpins M2 Subsea’s commitment to consistency, continual improvement and customer satisfaction. The accreditation was awarded following an independent assessment of M2 Subsea’s quality management.

The ISO 14001: 2015, which is aligned with the 9001: 2015, sets the requirements for environmental management systems. The accreditation covers business areas including operations, leadership, planning and support to ensure the company meets all environmental objectives as part of its daily operations.

Mike Arnold, chief executive officer of M2 Subsea, commented: “We are thrilled to have achieved a number of DNV-GL accredited certifications, only seven months after M2 Subsea was launched. The certificates are a huge testament to the quality of work our teams have already provided and our continued efforts for improvement.”

M2 Subsea also received the OHSAS 18001: 2007 certificate which is an internationally recognized standard for Occupational Health and Safety (OH&S) management systems. The certification supports businesses in implementing the policies, procedures and controls required to achieve the best possible working conditions and workplace health and safety.

Mr. Arnold continued: “Safety and environment is one of our core values and is always at the forefront of our operations. We achieve this through management, training, processes and a passion to deliver. To be able to assure our clients with an official accreditation is fantastic news for M2 Subsea.”

A New Way to Fight Piracy on the Open Sea

12state of piracy 2016 logo bannerThe economic cost of maritime piracy is on the rise once again as Somali pirates resume attacks on ships and resorting to old tactics of ransoming crew for money. The State of Maritime Policy Report 2016, released last month by Oceans Beyond Piracy (OBP), states the economic cost of piracy caused by groups out of Somalia increased to $1.7 billion in 2016, from $1.3 billion in 2015.

Piracy had been on a steep decline since 2010 due to increased security efforts and precautions taken aboard ships. However, in the past few years, per the OBP report, there has been decreased vigilance by the shipping community such as hiring smaller private security teams and taking less security measures aboard ships. In 2017, only halfway through the year, there have already been two hijackings including a tanker and a commercial ship. Read the full report from OBP.

A solution to the rise in piracy is not just to increase the number of security personnel aboard ships, but to also outfit the ship with surveillance technology which will allow them to take the precautions necessary to avoid a conflict. Electro Optical Industries’ line of 360-degree panoramic view infrared thermal cameras, Spynel, are able to detect and track targets that could present a threat to a ship and its crew. They act as optical radars but can pick up targets that radar could not detect, such as small wooden and rigid inflatable boats up to the horizon. The Spynel cameras can successfully operate at sea state level 5/6 (rough to very rough sea) thanks to an autonomous gyro-stabilized platform and in addition to mechanical stabilization, Spynels come with a sea-specific image processing stabilization algorithm. Spynel are currently deployed on ships and at ports around the world to combat against theft, piracy, terrorism and espionage.

An optional software module enables the display AIS (Automatic Identification System) data from boats in the thermal panoramic video. The automatic thermal detections and the AIS data can be fused to generate alarms only for instance objects without AIS transmitter, like a pirate. (Requires an AIS receiver)

About the Company: Electro-Optical Industries is a world leader in electro optics and infrared test equipment, thermographic cameras for process control monitoring and infrared wide area surveillance systems. Founded in 1964, Electro-Optical Industries has products in over 80 different countries with a customer list of over 10,000, including some of the best-known companies worldwide.

Trelleborg Wins Contract for Johan Sverdrup Oil Field

13Trelleborglogo copyTrelleborg’s engineered products operation announces it has been awarded a contract for the supply of elastomeric bearings to Statoil’s Johan Sverdrup oil field, Norway's largest offshore development in the past three decades.

Located on the Utsira Height in the North Sea, 160 kilometers west of Stavanger, the Johan Sverdup oil field will be operated by electrical power generated onshore, significantly reducing offshore emissions of climate gases. Daily production during the project’s first phase is estimated at 440,000 barrels per day, while peak production is estimated to reach 660,000 barrels daily - 25% of all Norwegian petroleum production.

The riser platform – the largest of the four platforms comprising the project’s field center – will be the first of the Johan Sverdrup topside to be installed in 2018. Trelleborg will manufacture and deliver 96 custom designed, sliding elastomeric bearings for use across the 23,000 ton platform’s six support points that will be in direct contact with the heavy transport vessel that will deliver the topside, which is being manufactured in South Korea, to the field.

JP Chia, Engineering Manager for Trelleborg’s engineered products operation, says: “The Johan Sverdrup oil field is one of the largest ongoing projects in the North Sea. Therefore, it is vital that the finest quality bearings were used to successfully secure each of the platform’s support points. We design and manufacture all of our elastomeric bearings specifically for their application, to ensure that they always perform exactly as required. We are very proud to have been selected to supply a project that will be of major importance to Norway for decades to come.”

Trelleborg’s elastomeric bearings are steel plate laminated and installed between the hull of the facility and its modules. They accommodate axial, shear and rotational movement to keep the modules safe from impact, damage and deformation. Similarly, they prevent the concentration of excessive strains and stresses around the mounting points of the modules and the hull caused by adverse sea and weather conditions.

All of Trelleborg’s bearings are tested to the highest of standards. Trelleborg’s engineering team check the design for specified loads and deformations and the fatigue performance by means of crack growth analysis calculations. After production they are a 100% individually tested at the company’s laboratory for full-scale research and development. The press used for the tests is the largest in the world of its type, with a load capacity of 18,300 metric tons and weighing in at 600 tons.

For more information about Trelleborg’s engineered products operation, or any of its products and solutions, please visit the Trelleborg Engineered Products website.

BPTT Awards Add Energy with Angelin Maintenance Build Contract

14AddEnergyAdd Energy, an international energy consultancy provider, has been awarded a maintenance build contract with BP Trinidad and Tobago LLC for work on the Angelin gas field, a development located 60 km offshore Trinidad and Tobago’s east coast.

The contract will see Add Energy carry out the development of a full asset maintenance build and will include the delivery of an asset register and functional hierarchy build, equipment criticality assignment, development of maintenance strategies for critical and non-critical equipment, job plans and procedures, critical sparing and BoMs development.

The 8-month project will be led by Add Energy’s Technical Manager, Julio Monsalve and will cover 6500 equipment tags.

As part of this win, Add Energy have recruited 4 new personnel in Houston to support the project delivery.

Peter Adam, Executive Vice President, Add Energy, commented: “As we continue to work closely with BP and expand our presence in delivering projects in the Trinidad and Tobago region, we are delighted to have been selected for this project with BPTT Angelin.”

“We believe that Add Energy’s customer-focused approach, in combination with project execution expertise and lessons learnt from previous maintenance builds, will enhance this project and support the operator in getting best value for money and will continue to optimize maintenance expenditure for BPTT.”

Hydrex Mobdock Reduces Singapore Sterntube Spill

It is estimated that damaged ship sterntubes are leaking some 57 million tonnes of lubricating oil in to the oceans every year, but by replacing these seals when the damage is first discovered, Hydrex in-situ repairs not only help towards reducing the environmental impact but can also save shipowners time and money.

15sterntube repairs low resUsing its flexible mobdock technology, damaged aft sterntube seals can be quickly replaced underwater during a vessel’s port-stay, negating the need for costly drydocking. Even complicated sterntube configurations and liners can be repaired this way.

Photo credit: Hydrex

“Environmental considerations are frequently demanding that damaged sterntube seals are repaired as they happen and in the shortest possible time frame,” said Hydrex Production Executive Dave Bleyenberg. “Every Hydrex office is equipped with the mobdock technology and sophisticated equipment that can be deployed at a moment’s notice to effect repairs in any location around the world.”

A recent sterntube seal replacement Hydrex engineers completed in Singapore underscores the commercial and environmental benefits of using the in-situ repair method.

When a 138m long LNG tanker began leaking oil from a damaged sterntube seal during the vessel’s port of call, an expedient repair was required to avert any delay to its schedule and prevent further pollution.

“Such incidents not only result in off-hire costs and charges, but also pollution related fines,” said Bleyenberg.

Hydrex’s local mobdock team was deployed while the company’s technical department in Antwerp, Belgium, put forward a detailed repair plan which, once approved, allowed the mobdock team to make all necessary vessel preparations. Within a matter of days, diver/technicians were on-site carrying out the seal replacement work.

Working in concert with the original equipment manufacturer, the Hydrex team removed and replaced three damaged seals with new ones. The entire operation was carried out underwater, without the need to drydock the vessel and without disruption to the vessel’s schedule.

“From the start to finish, the project took just a few days, preventing any further oil leaks and keeping the vessel operational without incurring significant costs,” said Bleyenberg.

EnQuest Confirms First Oil from Kraken

EnQuest confirms that first oil from the Kraken development was delivered on 23 June 2017. During the initial ramp-up period, the 13 wells that have been drilled and completed to date, comprising 7 producers and 6 injectors, are being brought online in a phased manner, to maximize long term productivity and value.

1KrakenFPSOKraken FPSO. Photo credit: EnQuest

EnQuest CEO, Amjad Bseisu said:
“EnQuest is delighted to confirm that first oil has been achieved on the Kraken development, delivered on schedule and under budget. Drill centers 1 and 2 are fully complete and work continues on drill centers 3; as a result, further production capacity will come online into 2018 as these further wells are put onstream.

Kraken is a transformational project, made possible by EnQuest’s differential capabilities; the right mix of integrated technical capabilities, high levels of efficiency and cost discipline. With production from Kraken, EnQuest is moving from a period of heavy capital investment, to a focus on cash generation and deleveraging the balance sheet.

A further update and additional analysis will be provided with EnQuest’s 2017 half year results.”

EnQuest’s Head of Major Projects, Richard Hall said:
“The achievement of producing first oil from Kraken on schedule and considerably under budget is a great testament to the capabilities of EnQuest. I am extremely proud of the EnQuest Kraken team for their dedication, vison and sheer hard work and thank them for this exceptional performance. Our approach of rigorous planning, simplification of specifications and clarity in execution methodology has enabled us successfully to deliver this highly complex project.”

UK Business and Energy Secretary Greg Clark said:
“This is a landmark project for EnQuest and the UK oil and gas sector as one of the largest new oil fields to come on-stream in the North Sea in a decade. This has been made possible through significant UK government support to encourage investments of this type in the North Sea, supporting thousands of highly-skilled jobs. We’ll continue to build on this support for the oil and gas sector as it looks to seize the significant opportunities that lie ahead.”

UK Oil & Gas Authority Chief Executive, Dr Andy Samuel said:
“As one of the most significant oil field projects in the UK Continental Shelf, successful production from Kraken is positive news for the whole basin. It has the potential to open up additional heavy oil opportunities in the Northern North Sea, with other developments in the pipeline. It’s particularly pleasing to see a project delivered under budget, having clearly benefitted from a strong partnership between operator and key service providers.”

THE KRAKEN DEVELOPMENT: Facts and figures

  • Kraken is a large heavy oil accumulation in the UK North Sea, located in the East Shetland basin, to the west of the North Viking Graben, approximately 125 km east of the Shetland Islands
  • The field contains c.128 MMboe of gross 2P reserves, making it one of the largest new oil fields to come onstream in the North Sea since Buzzard
  • Gross peak oil production expected to be approximately 50,000 barrels of oil per day
  • The gross capital costs of the development are currently estimated to be approximately $2.5 billion, down from $3.2 billion at the time the project was sanctioned; good planning and project execution including good progress on drilling and on the execution of the subsea program were key factors in the capex savings. Drilling and formation evaluation have shown excellent correlation with pre-sanction subsurface expectations
  • EnQuest has an interest of 70.5% in Kraken, with its partner in the development Cairn Energy PLC having the balancing 29.5%
  • Kraken is EnQuest’s seventh operated production hub

Johan Castberg Field Expected to Come on Stream in 2022

The overall operational support to Johan Castberg will have considerable spinoffs in North Norway.

Statoil has, on behalf of the license partners, decided that the Johan Castberg operation will be supported by a supply and helicopter base in Hammerfest and an operations organization in Harstad. Recruitment of offshore personnel from Finnmark county is also prioritized.

2JohanCastbergImage credit: Statoil

Expected to come on stream in 2022, the field will be operating for 30 years. We will invest around NOK 1.15 billion per year in operation of the field, amounting to around 1700 man-years nationally, of which around 500 will be performed in North Norway. These are both the direct and indirect spinoffs (Agenda Kaupang).

Johan Castberg is one of the largest projects in Statoil’s portfolio yet to be developed. It will be an important contribution in further developing the northern petroleum activity.

A final investment decision regarding Johan Castberg is to be made towards the end of 2017.

Location of operational functions

“This has been a comprehensive process. We have studied several alternatives, and decided that Hammerfest and Harstad separately will be the best industrial solution for Johan Castberg,” says Knut Gjertsen, project director for Johan Castberg.

The Hammerfest supply base will have an employment effect of around 30-45 man-years, and the helicopter base around 12-15 man-years. Hammerfest has already established bases and has long experience from such services, providing the most qualified and cost-effective solution. Supporting the offshore organization and further developing the field during production, the Harstad operations organization is expected to have an employment effect of 40-45 man-years. Statoil has developed a strong specialist environment in the city based on 40 years of experience from operation in the north. Johan Castberg will benefit particularly from co-locating with the Norne and Aasta Hansteen organizations, which have some similar elements in their development concepts.

“To ensure a long-term development of petroleum-related specialist jobs in Finnmark, Statoil will, in collaboration with other operating companies, suppliers and local authorities before the plan for development and operation is submitted to the authorities, look at possible initiatives to upgrade the general petroleum competence level in Hammerfest and Finnmark. In the longer term this will lead to more local recruitment to the industry, and Finnmark may strengthen its position in the technology-driven development of the Barents Sea,” says Siri Espedal Kindem, senior vice president for the operations north cluster in Statoil.

Offshore staff based in Finnmark

Offshore we will need a staff of 90-100 people distributed on three shifts. “We will seek to recruit as many as possible from Finnmark to the offshore organization. We have therefore contacted the county administration and schools to launch an initiative to ensure good recruitment to the studies that will meet our offshore competence requirements,” says Kindem.

Major spinoffs during the development

Johan Castberg development costs have been calculated at close to NOK 50 billion. The national employment during the development phase has been estimated at almost 47,000 man-years, of which close to 1800 will be in North Norway.

Statoil, together with the other operators of oil fields in the Barents Sea, are investigating the possibilities to find possible economic solutions for an oil terminal at Veidnes.

The decisions are based on an analysis made by Agenda Kaupang. You may read the report below. (in Norwegian only)

The full impact assessment report will be posted on Statoil.com at the end of the week.

GE Oil & Gas and Eni East (EEA) Africa Sign Long-Term Partnership

3 1GEOilgaslogo3 2EnilogoGE Oil & Gas (NYSE: GE) has signed a long-term agreement to collaborate with Eni East Africa (EEA), on the offshore Mozambique developments it operates. The move underlines GE Oil & Gas’s commitment to expand its global footprint while supporting local investment in Africa, and re-affirms its leadership in large bore technology and cutting-edge subsea equipment and services.

Since 2014, teams from GE Oil & Gas and EEA have been co-developing efficient, cost-effective technical solutions to ensure operational reliability and equipment availability to avoid loss of revenue through unplanned downtime. This was achieved through six-months of front end engineering and design (FEED) work, leveraging GE’s in-house engineering capabilities and portfolio of standardized products.

The agreement comprises a multi-year contract to supply subsea production systems, ancillary equipment and services. It covers the Coral South FLNG project and is the first phase of EEA’s strategically-important development plans for the Rovuma basin Area 4 gas resources. The agreement also covers Area 4 future potential upstream projects. It includes a separate five-year aftermarket services contract for Life of Field of the subsea infrastructure, plus one five-year option and five three-year extensions.

GE Oil & Gas has secured orders for the Coral South FLNG from EEA for the supply of seven xmas trees, three 2-slot manifolds with integrated distribution units, MB rigid jumpers, seven subsea wellheads with spare components, a complete topside control system to be installed on the FLNG facility, and associated Services equipment and support including IWOCS and Landing Strings, tools, spares and technical assistance for installation, commissioning and start-up.

Underlining GE’s ongoing commitment to localization and investment in Mozambique and the SSA region, 20 local graduate engineers have been employed in the last three years to support GE Oil & Gas customer operations. They attended technical training at the Mozal Training Center in Maputo where they received intense, in-class/laboratory-based instruction on engineering fundamentals and courses in Florence, as well as performing on-the-job training in Brazil, Korea and Colombia to gain hands-on experience with subsea and liquefied natural gas products and equipment.

“Coral South FLNG is the first major subsea development in East Africa and provides GE Oil & Gas with the opportunity to affirm our leadership in large bore technology and our standardized portfolio of subsea equipment and services for deep water projects,” said Neil Saunders, President and CEO of Subsea Systems & Drilling, GE Oil & Gas. “As the only subsea production systems supplier in-country and in East Africa, it provides tremendous opportunities to grow our operations in the region and it further underlines our commitment to drive productivity and cost-efficiency improvements for global projects by building long-term relationships with industry players in place of more outdated transactional approaches.”

Ado Oseragbaje, President and CEO of Sub-Saharan Africa, GE Oil & Gas, added: “With the award of this project in Mozambique following the recent OCTP Project in Ghana – with first oil delivered ahead of schedule and in record time-to-market – GE reaffirms its subsea leadership in Africa, operating in all the major oil basins and with all international and National Oil Companies. GE is committed to building capacity in Africa and with the Mozambique project, like we have already demonstrated in Nigeria, Angola and Ghana, we will continue to invest in the years to come, developing a local highly-skilled and motivated workforce.”

The Coral South FLNG project, the first phase of EEA’s wider plan of development for the Rovuma basin Area 4, will see the installation of an FLNG facility with a capacity of around 3.4 MTPA, fed by six subsea wells and expected to produce up to 5 TCF of gas, with an anticipated start-up in mid-2022. The first ever deep water project to start producing gas in Mozambique, it will provide significant local economic benefits through job creation and support the region’s future energy needs.

EEA is the operator of Area 4, and holds 70% of the Area 4 Concession. Eni (71.43%) and CNPC (28.57%) are shareholders of EEA.

SBM Offshore Awarded Contracts for ExxonMobil Liza FPSO

4SBMO CL transparent background OriginalSBM Offshore announces that ExxonMobil has formally confirmed the award of contracts for the next phase of the Liza project in Guyana. Under these contracts, SBM Offshore will construct, install, lease and operate a floating production, storage and offloading vessel (FPSO). This follows completion of front-end engineering studies and the final investment decision on the project by ExxonMobil.

The Liza field is located in the Stabroek block, which covers almost 27,000 square kilometers, circa 200 kilometers offshore Guyana. Esso Exploration and Production Guyana Limited is the operator and holds a 45 percent interest in the Stabroek block. Hess Guyana Exploration Ltd. holds a 30 percent interest, and CNOOC Nexen Petroleum Guyana Limited holds a 25 percent interest.

The FPSO is designed to produce up to 120,000 barrels of oil per day, will have associated gas treatment capacity of circa 170 million cubic feet per day and water injection capacity of circa 200,000 barrels per day. The converted VLCC FPSO will be spread moored in water depth of 1525 meters and will be able to store 1.6 million barrels of crude oil.

SBM Offshore CEO Bruno Chabas commented:

“We are proud that ExxonMobil awarded SBM Offshore the contracts for the Liza FPSO. The Liza Field offshore Guyana is one of the industry’s largest oil discoveries of the past decade. We look forward to cooperating closely with our client and partners to make this project a success. This award underlines SBM Offshore’s continued focus on building on our experience, our long term relationships and FPSO-led strategic vision.”

Canyon Awarded Trenching Contract for Hornsea Offshore Windfarm

Canyon Offshore Limited, a leading trenching solutions provider based in Aberdeen, has been awarded a contract by Siem Offshore Contractors for the provision of trenching services on DONG Energy’s Hornsea Offshore Wind Farm Project One. In November 2016, and building further upon the recent establishment of its UK office in Aberdeen Scotland, Siem Offshore Contractors was awarded a contract for the installation of the inner-array grid cable system for the Hornsea Offshore Wind Farm Project One by DONG Energy Wind Power A/S.

5Hornsea Zone with UK Map full Size copyImage credit: Dong Energy

Canyon Offshore’s award will require the trenching of approximately 140km of inner-array grid cables on the wind farm which will have been laid onto the seabed by Siem Offshore Contractors. In order to provide the optimum trenching solution to bury the inner-array grid cables, Canyon Offshore Limited will use both jetting and cutting methodology with its Jet Trencher, T1200 and its hard ground trencher, i-Trencher. Both systems, together with two work class remotely operated vehicles, will be deployed from a single support vessel, the chartered Grand Canyon I, with operations commencing Q4 2018. Management of the operations will be provided from Canyon Offshore Limited’s Aberdeen base.

Canyon Offshore Limited’s Director for Commercial & Sales, Euan Roberts, said, “We have built up an enviable track record in providing successful trenching solutions to the offshore wind-farm market in recent years in the North Sea, successfully burying hundreds of kilometres of inner-array grid cables. This has complemented our traditional oil and gas trenching market and extended our brand into the renewables industry.”

Siem Offshore Contractor’s Project Manager for the Hornsea One wind farm, Johann Stulemeyer, said: “In Canyon Offshore we will not only have a UK partner to complement our growing local presence, but also a technical leader in their field whose trenching solution will neatly complement our Siem Duo cable lay solution. We look forward to working together.” Duncan Clark, Hornsea Project One Director said: “The UK leads the world in offshore wind and the industry continues to grow. This is great news not only for our low carbon electricity needs but also for the many skilled suppliers and contractors that are becoming part of this booming supply chain. We are delighted that Siem Offshore Contractors have chosen to work with another UK based company, as a strong and competitive UK supply chain providing the specialist capabilities needed to serve this growing industry will ultimately help to reduce the cost of electricity.”

DNV GL’s Global Network of Verification Experts to Support Major New Contract with Maersk Oil

DNV GL has won a major contract to provide independent verification services for the Maersk Oil redevelopment of the Tyra Field, offshore Denmark.

The Tyra field in the Danish North Sea has been at the center of Denmark’s national energy infrastructure since 1984, providing 90% of the country’s gas production.

6Tyra fieldTyra field. Credit: Maersk Oil

The contract will be coordinated by DNV GL in Denmark, with teams of experts from multiple DNV GL offices supporting the construction in fabrication yards across the world over the next five years.

DNV GL’s contract scope includes independent verification and support services and ultimately the certification of all greenfield activities. This work will take place during the engineering, procurement, construction, installation, hook-up and commissioning phases for two new jackets and eight topsides. These consist of one central processing facility, one accommodation platform, four wellhead modules and two riser modules.

DNV GL’ s independent third-party verification will help Maersk Oil to ensure transparent package status and the real-time reporting of equipment-salient points, provide technical assurance and enable Maersk Oil to manage project risks.

Liv Hovem, Senior Vice President, DNV GL – Oil & Gas, says: “We're very proud to have won the verification contract for the Tyra redevelopment and look forward to furthering our collaborative relationship with Maersk Oil. Maersk Oil’s Tyra project is extremely complex, involves a wide range of technical disciplines and requires global support. Drawing on our global and local presence, we will utilize our worldwide network of technical experts to provide on-demand support. This will result in both cost-efficient and best practices.”

Having worked with Maersk Oil on successes such as Halfdan Phase 4, Tyra Southeast B and Culzean, we're pleased to further our business relationship. New digital technologies and DNV GL’s project delivery models will be key in delivering another success to Maersk Oil,” adds Liv Hovem.

Major parts of the work included in the contract will only be executed given that Maersk Oil takes final investment decision on the Tyra redevelopment project.

John Crane Asset Management Solutions Signs Three-Year North Sea Contract

John Crane Asset Management Solutions has secured a three-year £3million contract to provide condition based maintenance services with a major operator in the UK North Sea.

The work covers rotating equipment across 12 assets and infrastructure sites and includes deployment of a specialist engineer to the operator’s UK offices to support reliability improvement.

The agreement, which follows a competitive re-tender, extends the contract which John Crane Asset Management Solutions has held for the past eight years.

7JCAMS contractJohn Crane Asset Management Solutions will provide condition based maintenance services to a major operator in the UK North Sea.

In October 2015, John Crane announced it had acquired XPD8 Solutions, an Aberdeen independent asset management business. All employees from both firms who were based in Aberdeen have now transferred to one site, which includes offices and workshops, at Centurion Court on North Esplanade West.

The latest contract, which is for an initial three years plus two one-year options, will enable the strengthened John Crane Asset Management Solutions team to use their expertise to fully meet the customer needs and further increase asset performance.

Rod Mackenzie, UK Reliability Engineering Manager at John Crane Asset Management Solutions, said: “We will be supporting the client in transitioning from a mostly time-based maintenance program to a condition based maintenance and reliability centered program. This approach allows full ownership of each plant, with all data captured and used to ensure assets are working efficiently with any issues identified before they reach the stage of a breakdown.

“Key factors in securing the contract included our existing close business relationship and track record of success with the client, along with the experience in taking a holistic approach to maintenance.”

The contract involves John Crane Asset Management Solutions engineers mentoring their onshore and offshore compatriots with the client. This will include data collection training to minimize costs associated with sending specialists offshore.

Discussing the integration of XPD8 Solutions staff into John Crane Asset Management Solutions, John Morrison, Managing Director at John Crane Asset Management Solutions, said: “A lot of hard work has gone into integrating what were separate teams into one business stream. This joined up approach links the rapid response and nimble attitude XPD8 was recognized for with the experience and knowledge of John Crane’s staff and worldwide sales and service footprint.”

John Crane Asset Management Solutions is a trading name of XPD8 Solutions Limited, which is part of John Crane, itself a division of the global technology company Smiths Group Plc.

BP Celebrates 40 years of Production at Prudhoe Bay

8 1PrudhoeBay copy8 2bp logo copy 3The BP-operated Prudhoe Bay oil field in Alaska has reached 40 years of production, a milestone highlighting its historic contribution to US energy security and ongoing role as a key economic engine for the region and nation.

Since the giant oil field on Alaska’s North Slope began production, it has generated more than 12.5 billion barrels of oil - far exceeding initial projections - making it the most productive US oil field of all time.

“Forty years is extraordinary for a field that was supposed to have a 30-year life,” said BP Upstream chief executive Bernard Looney. “With continued innovation and investment, the expertise of our people and an unwavering commitment to safe and reliable operations, we firmly believe that the story of Prudhoe Bay is far from over.”

Prudhoe Bay oil production started on June 20, 1977, and began flowing 800 miles down what was then a newly constructed Trans Alaska Pipeline System (TAPS) to Valdez, where it was loaded onto tankers to supply markets on the US West Coast.

The original estimated recovery for Prudhoe Bay was 9.6 billion barrels. However, an additional 3 billion barrels so far have been unlocked through innovations in oilfield technology. Indeed, the field has been a proving ground for advanced drilling techniques, including multi-lateral and coiled tubing, now employed by oilfields across the globe. It also has been a global hub for testing and deploying emerging enhanced oil recovery technologies that BP pioneered and that are now integral to Prudhoe Bay operations and other parts of BP’s portfolio.

Today, while production has fallen from historic peaks due to natural decline, Prudhoe Bay remains the third-largest oil field in the US by proved reserves, behind the Eagle Ford Shale and Spraberry fields in Texas, and a major source of domestic oil production, with current output at approximately 281,800 barrels of oil equivalent per day. In addition, Prudhoe Bay continues to support more than 16,000 Alaska jobs and supplies 55 percent of all Alaska oil production. And over the last four decades, the State of Alaska has earned $141 billion in revenues from North Slope production and development.

“The field has repeatedly defied the odds and remains a major contributor to US energy security and to the state’s economy,” said Janet Weiss, president of BP’s Alaska region. “Today, we celebrate this extraordinary history, and look forward to working with the State of Alaska to ensure that Prudhoe Bay has an equally bright future. Prudhoe Bay is operated by BP in Alaska. The working interest owners include: BP, 26 percent; ConocoPhillips, 36 percent; ExxonMobil, 36 percent; Chevron, 1 percent.

  • Prudhoe Bay was discovered in 1968 by Richfield (ARCO) and Humble Oil (ExxonMobil), and confirmed by BP in 1969.
  • Trans Alaska Pipeline System (TAPS) ownership includes: BP, 49 percent; ConocoPhillips, 29 percent; ExxonMobil, 21 percent, and Unocal, 1 percent.
  • In 2016, Alaska oil production through TAPS increased for the first time in a decade, rising two percent to 517,868 barrels of oil a day.

DOF Subsea Inks Transmediterranean Pipeline Survey Contract

9DOF Geosund full size 2 copyDOF Subsea, a leading provider of integrated subsea services, has recently inked a new contract in the Mediterranean with Transmediterranean Pipeline Company Limited (“TMPC”) to undertake the pipeline inspection on the TMPC’s Pipeline System in Q3, 2017.

The scope involves inspection of 5 submarine pipelines between Sicily and Tunisia and during the scope, DOF Subsea will survey over 750 km of pipeline.

DOF Subsea will deploy the high specification survey vessel, MV Geosund to complete the inspection work scope and pipeline intervention.

DOF Subsea successfully completed a similar scope for TMPC in 2014.

Managing Director, Robert Gillespie said “We are delighted to win this work with TMPC. We have a good relationship with the company, having successfully completed this inspection scope for them in the past, and we are looking forward to delivering on this scope again later this year.

DOF Subsea has an extensive track record in Survey and IMR; combined with our high-specification fleet of owned vessels and skilled ROV and Survey teams, we are able to offer fully integrated solutions for our clients’ projects”.

M-Tech Offshore’s DP-2 Cable Laying Vessel, CLV SIA

10CLV SIAM-Tech Offshore A/S, is a Danish joint venture company equally owned by NT Offshore A/S and Maritech International LTD, owning and operating the CLV SIA, an efficient handy-sized DP-2 cable laying vessel, which is configured for worldwide inter-array and subsea power cable installations and maintenance, with additional facilities on-board to accommodate for installation of smaller subsea cables, including fibre-optics.

The CLV SIA flies the Danish flag, is a fully SOLAS classed vessel, equipped with efficient cable lay spread, 3 turn-table cable tanks, deck winches, A-frame & cranes and accommodates SIMEC's work-class trenching ROV "Seagma", suitable for inspection, survey and burial operations on up to 3m trenching depth, on maximum operating water depth of 1000m.

Additional modular deck spreads are also available for support operations such as pre-lay grapnel runs and route clearances. The 500m2 vessel's deck has been strengthened for LARS, making it an ideal ROV support platform, whist the on-board survey electronic spread, moon-pool and side mounted equipment can be utilised for cable route survey operations.

In addition to cable laying capabilities, the CLV SIA has modern and comfortable accommodation for 50 passengers with crew and can be utilised as a multipurpose support vessel, capable of handling challenging environmental conditions.

Acquisition and subsequent upgrade of the CLV SIA follows the 2016 announcement that Maritech International LTD with NT Offshore A/S had formed the Joint Venture company M-Tech Offshore A/S. Maritech's 25 years of experience in the subsea cable industry, coupled with NT's long-term presence in the North Sea, is now backed by a strategically positioned vessel management office in Esbjerg, Denmark.

Gas Safety Top of the Agenda for Martek Marine on US $3 Billion Offshore Project

Maritime industry technology specialists Martek Marine are setting the bar high when it comes to offshore gas safety. The company has developed a first-of-its-kind gas sampling system for a new moored floating production unit, which forms part of the Jangkrik Complex gas fields development in Indonesia. The system has been developed to dramatically improve offshore crew safety through the use of advanced gas sampling technology.

11Gas Sampling System copyA first of its kind gas sampling system. Photo credit: Martek Marine

The worst offshore disaster in history, the Piper disaster on 6 July 1988, involved a series of gas explosions which destroyed the Piper Alpha oil platform in the North Sea, killing 167 men. According to the latest statistics from the Health and Safety Executive, to this day, a third of all dangerous occurrences occurring offshore relate to gas releases. Explosions, following a gas release are a major offshore hazard due to the catastrophic consequences that tend to result; taking life and impacting the health of workers; pollution of the environment; direct and indirect economic losses, and deterioration of the security of energy supply.

Early warning is key when it comes to the prevention of gas explosions. Failure to avoid ignition of released hydrocarbons is best achieved through the installation and functioning of gas detectors in appropriately defined hazardous areas. The offshore accident report ‘Lessons from Past Accident Analysis’ from the European Commission, advises that a vital step in controlling major offshore hazards is the installation of, ‘state-of-the-art gas detectors in appropriate locations, extending to hazardous areas where necessary.’

It’s not then surprising that gas safety was at the top of the agenda for the new, highly-regarded and large-scale offshore engineering project in Indonesia. The Jangkrik Project comprises of the development of the Jangkrik and Jangkrik North East gas fields, referred to jointly as the Jangkrik Complex. Approximately 400m deep, the Jangkrik Complex forms part of the deep-water Muara Bakau block in the offshore Kutei Basin, situated 70km from the coast of East Kalimantan.

Following drilling at three exploration wells, Jangkrik 1,2 and 3, a feasibility study completed in July 2011, led to selection of the most appealing concept for development of the area. The chosen approach is based on a subsea development with 10 wells and full treatment facilities on a spread moored floating production unit (FPU). The FPU has an export line to shore at Sapi Landfall.

In 2014, energy company Eni awarded offshore engineering experts Saipem, the engineering, procurement, construction, and installation contract for the new FPU, valued at US$3 billion. The shipping division of Hyundai Heavy Industries (HHI), who currently hold a 15% share of the global shipping market, built the FPU hull in Ulsan, South Korea, whilst further fabrication work for the topsides was carried out by Saipem in Indonesia, with Saipem’s Execution Centre in Jakarta managing the overall project.

Gaining international interest thanks to the rapid development and short production start-up time, the project has a time to market of just three-and-a-half years from the date of the investment decision and production at the Jangkrik Complex gas fields commences in 2017.

The FPU is designed to process 450 MMcf/d (12.7 MMcm/d) of gas and condensates and is a multi-purpose unit. The Jangkrik gas volumes will supply the local domestic market, the Indonesian LNG market as well as the LNG export market providing a significant contribution to the Country’s energy needs and economic development.

In addition to being used for activities relating to the Jangkrik Complex, the FPU will also act as a hub for other sites nearby. All gas will be sent to a liquefaction plant called Bontang LNG following treatment on board and this is achieved thanks to connections to 10, deep-water subsea production wells. The final destination of all condensate from the site is the Senipah Power Plant in East Kalimantan.

Global maritime technology company Martek Marine specified a gas sampling system for the FPU which is the first of its kind. Based on the company’s well reputed MM5001 Gas Sampling System, the bespoke setup comprises of 4 independent systems. The systems are designed for the sequential sampling of hydrocarbon gas, as well as sequential sampling and continuous monitoring of oxygen. The sampling activities are focused on the ballast and condensate tanks in addition to continuous monitoring of supply headers within the FPU.

"The system will play a vital role in ensuring the safety of those onboard, by giving crew the means to effectively monitor gases within enclosed spaces and ensure that levels maintain within safe parameters." Said Martek Marine Project Engineer, Steve Austwick.

The first sampling system is a split system, designed to sequentially sample hydrocarbon (22 Point) in water ballast tanks. Equipped with the latest dual Non-Dispersive Infra-Red (NDIR) sensors, the equipment is faultless when it comes to monitoring increasing levels of methane (CH4).

Being a split system, the pump, solenoids and sensors are housed in the monitoring side of the system installed in a cabinet on deck. Benefiting from an EExe enclosure and EExd internal components the unit is explosion-proof. The human machine interface (HMI) and programmable logic controller (PLC) are housed control side in the cargo control room (CCR). In a conventional gas sampling system, the control and monitoring equipment is mounted in a single cabinet which is installed in a safe area, usually the CCR.

"The important benefit to a split system, is that the need to run sample piping into the CCR is avoided." Said Austwick.

The second system supplied is a 6-point system used for sequential sampling of oxygen in condensate tanks. In addition to benefitting from the design features of the sequential hydrocarbon gas sampling system, the addition of advanced paramagnetic sensors enables levels of oxygen to be monitored in the inert gas blanket of condensate tanks.

Paramagnetic sensor technology provides unbeaten performance and longevity.

"The sensors use no consumable parts, meaning they excel in terms of durability," said Austwick. "Offering world class precision over a range of 1% to 100% oxygen, they are able to measure the oxygen concentration not only in flammable gas mixtures, but also in low concentrations and with high precision."

Two further gas sampling systems were supplied under the contract, both continuous oxygen gas sampling units. Both single point systems, the first is designed for use in the inert gas supply header and the second, in the high purity nitrogen header.

Both systems benefit from paramagnetic oxygen sensors to monitor oxygen enrichment. Both the sensor and the pump are installed in a single cabinet.

"Having only one sample line ensures the headers are continually monitored and no front-end control is therefore required," said Austwick. "A signal from the system analyser is connected directly to the distributed control system (DCS) on the vessel, ensuring optimum reliability through localised control functions near the equipment."

All gas sampling systems are now installed and the naming ceremony of the “Jangkrik” Floating Production Unit (FPU) vessel took place on March 21, 2017 at Saipem Karimun Yard, Tanjung Balai Karimun, Indonesia. The FPU then sailed to its final destination at the Jangkrik Complex in preparation for gas processing and export, which is expected to reach a capacity of up to 450 million standard cubic feet per day (mmscf/d).