Wild Well Control awarded Airborne Oil & Gas (AOG) a contract for the supply of two flexible TCP Jumpers. The two jumpers, 2 inch and 10 ksi rated, are collapse resistant to 3000 meters water depth. They are delivered in lengths of 300 ft each and will provide the flexible fluid connection between a drill string or downline and Wild Well Control's 7-series subsea intervention package.

AOG’s TCP Jumper combines flexibility with a smooth bore and high collapse resistance. This combination, unique in the industry, provides a superior solution for riser less Plug & Abandonment ( P&A ). Thomas Wilke, General Manager Subsea, explains: “ Our primary client, Marubeni Oil and Gas, will be plugging and abandoning 9 subsea wells, of which the deepest are at a water depth of some 7300 ft. We expect that some wells will be sub-hydrostatic, which may lead to significant differential pressures. Using AOG's non-collapsible jumpers removes the risk of hose collapse and the related project delays. We have worked with Airborne Oil & Gas for some time on this project and concluded that their product provided a significant operational advantage."

With this order, AOG has added yet another high pressure product to its portfolio, and secured their first order in the Gulf of Mexico. Frits Kronenburg, Area Sales Manager, comments: “We have developed our flexible jumpers as the superior product for deepwater well intervention, acid stimulation and P&A. To date we have already won orders for our 2.5 inch 10 ksi jumpers, and now for our 2 inch 10 ksi jumpers as well. The potential is so significant that we are manufacturing this jumper for stock, enabling us to supply quickly".

The two jumpers are shipped early November and are expected to be mobilized early December 2015.

On 20 April 2010, the Macondo blowout in the Gulf of Mexico killed 11 men, burned and sank the Deepwater Horizon drilling rig, devastated the Gulf of Mexico and caused unprecedented socio-economic and environmental damage to Louisiana and Texas. To unravel the cause of the blowout, the assessment of petroleum engineering data during the well's final hours has been critical.

This data will be discussed at an evening event hosted by the Society of Petroleum Engineers (SPE) Aberdeen Section on 25 November. Prior to retiring, John Turley (photo) spent much of his career at Marathon Oil as Gulf Coast drilling manager, UK operations manager, manager worldwide drilling and vice president of engineering and technology. He studied well data and investigative reports, ignored finger-pointing and hearsay evidence, and assessed the cause of the blowout from engineering and operating perspectives.

Commenting ahead of his SPE Distinguished Lecturer presentation, ‘Assessing and Applying Petroleum Engineering Data from the 2010 Macondo Blowout’, Mr Turley said: “Investigating the circumstances surrounding the cause of the blowout is essential, so we can then apply lessons learned from the incident to future well work in deep water, shallow water and onshore.

“This presentation will use working examples to help delegates understand the importance of applying petroleum engineering and process management fundamentals to day-to-day drilling work, in real time, both in the office and on the rig.”

Shankar Bhukya, SPE Aberdeen chairman, said: “Although tragic incidents like Macondo are rare, it is important that, as an industry we learn from them to avoid repetition in the future. Safety is at the forefront of the oil and gas industry and, as it has been highlighted at the first SPE Aberdeen conference of its kind in March last year – Another Perspective on Risk: The Next Tipping Point - it is essential that we collaborate and share best practices to ensure our employees are safe at all times, onshore and offshore.

Mr Turley, educated at Colorado School of Mines, University of Miami and Harvard, taught petroleum engineering at Marietta College before joining Marathon Oil. Post-retirement, he independently researched the Macondo blowout and published: ‘The Simple Truth: BP’s Macondo Blowout’ - a facts-based tome in which he examines the engineering causes of the disaster. Mr Turley, a member of SPE's Legion of Honour, chaired SPE's education and accreditation committee and published a number of SPE papers.

The presentation will take place on Wednesday 25 November at Pittodrie Stadium from 6 – 9pm. High attendance is expected for this event, therefore advance booking is recommended. For more information and to book, please click here.

Statoil (U.K) Limited has awarded contracts for the catering and facilities services for its UK offshore and onshore operations to ESS Offshore and 14forty, both part of Compass Group UK & Ireland.

The offshore catering and facilities contract was awarded to Aberdeen-based ESS Offshore and includes the provision of offshore catering services to the Mariner A platform and Mariner B floating storage unit, as well as housekeeping services, helideck operations and emergency response duties. The agreement is due to start in 2016.

The onshore total facilities management contract was awarded to 14forty, previously known as Eurest, and covers Statoil’s offices in Aberdeen, London and its Dudgeon wind farm operations base in Great Yarmouth.

The provision of catering, cleaning, security and property services will start immediately in Great Yarmouth and in 2016 in the London office and Aberdeen, with the opening of Statoil’s new UKCS operations centre.

“Combining the offshore and onshore scopes has created significant synergies and efficiencies for Statoil in the UK. We appreciate the innovative and cost-effective solutions presented by ESS Offshore and 14forty. This type of close collaboration with our suppliers is critical to ensuring efficient operations for Mariner in the long term,” says Tove Stuhr Sjøblom, managing director for Statoil Production (UK) Ltd.

Each contract has a duration of five years with options to extend to up to four years.

Statoil is the operator of Mariner with 65.11% equity. Co-venturers are JX Nippon Exploration and Production (U.K.) Limited (28.89%) and Dyas UK Ltd. (6%). The Mariner Field is located on the East Shetland Platform of the UK North Sea, approximately 95 miles east of the Shetland Isles.

The Mariner platform is currently under construction. Predrilling will commence in 2016, and production is scheduled to start in 2018. The development of the Mariner field will contribute more than 250 million barrels reserves with average plateau production of around 55,000 barrels per day.

Based in Aberdeen, ESS Offshore delivers market leading services to offshore locations in the UK and around the world. 14forty is one of the world's leading food and support services businesses, offering integrated facilities management.

CGG announces that it has been appointed as technical consultant by the Gabonese Republic’s Ministry of Petroleum and Hydrocarbons to help with the promotion of its 11th Licensing Round focusing on five highly prospective deepwater blocks.

The round was formally opened on 27th October 2015 by His Excellency, Minister for Petroleum and Hydrocarbons, Mr. Etienne Dieudonné Ngoubou, at this week’s 22nd Africa Oil Week conference in Cape Town South Africa. The round will then be promoted by a series of road shows starting in Libreville on 24th November, followed by Paris on 26th November, Singapore on 30th November and Houston on 3rd December 2015. A delegation from the Direction Generale des Hydrocarbures (DGH) as well as a technical team from CGG will be attending to answer any questions.

The round will be open for five months starting on 27 October 2015 and bids can be submitted from 15 February 2016 onwards and by no later than 31st March 2016. Prequalification for the bid round will require the purchase of a minimum amount of seismic data.

The deep water of Gabon has significant unexplored potential within a structurally complex setting, particularly in the pre-salt section. In response to the exploration challenges, CGG has been appointed to advise the Gabonese Republic on the promotion of the 11th Licensing round and has worked directly with the Ministry to acquire over 25,000 km2 of new 3D BroadSeisTM multi-client seismic data as part of an integrated geoscience program to support it. The new survey will enable better imaging of this exciting and underexplored area, and covers areas downdip and adjacent to recent pre-Aptian salt discoveries, such as Leopard, Diaman, Ruche and Tortue. It will benefit from integrated gravity and magnetic interpretation to enhance the pre-salt imaging and additional, complementary datasets including offshore hydrocarbon seeps and a full geological prospectivity report will be available.

Jean-Georges Malcor, CEO, CGG, said: “Ever since we acquired our first geophysical survey there in 1932, CGG has actively supported Gabon’s development of its natural resources. We are delighted to continue our fruitful cooperation with the Gabonese Republic by offering our full portfolio of Geoscience expertise to help promote the 11th Licensing Round. Given the high quality of the intermediate results we have seen so far from our recent BroadSeis survey, we expect the final results to be a significant resource for clients to de-risk this promising exploration arena. We are pleased to announce that several companies have already pre-committed to the dataset.”

Despite a recent oil price around the $45 per barrel range, Barclays Corporate Banking has predicted a rise to $50 by the end of 2015 and a further increase to $60 in 2016.

The topic was discussed at a recent event hosted by the bank’s corporate FX team which invited influential industry professionals to discuss the current challenging market. The bank predicts that the expected increase in oil price will be spurred on by a sustained doubling of growth in global demand of up to four million barrels per day.

The group gathered by Barclays Corporate Banking considered the future of the North Sea which found that while the general short-term picture for the region may appear stormy, there are growing signs of hope on the horizon, which may trigger an eagerly anticipated recovery.

The group started by discussing the significant differences between the oil crash of the mid-1980’s to that of 2014/15. During the earlier period, OPEC’s spare capacity was between 14% and 16% of global oil demand, which meant it was in a much stronger position to influence supply. Today, OPEC’s spare capacity stands at less than 4%. While Saudi Arabia is producing close to record levels, it is not expected that the Saudis would break the 11 million barrels per day barrier, which creates a limitation on the amount of oil OPEC can produce, and therefore the influence it ultimately has.

Since OPEC decided against reducing production in November 2014, global oil demand has recovered strongly, unlike in the 1980s. Since then, global demand growth rate has tripled to 2.1 million barrels per day, due mainly to the elasticity in price and consumer reaction to price. It was explained that the industrial sector has played little part in this demand growth; the drive has come from the end consumer.

However, the positive story of a tripling in demand growth has been overshadowed by the extent of the increase in the oil supply with OPEC production up at 32 million barrels per day. Barclays forecasts that the excess supply situation will continue throughout 2015 with Saudi Arabia producing close to record levels at 10.3 – 10.4 million barrels per day, while Iraq continues to be a strong supplier.

The recently lifted Iran sanctions could also affect supply, as the country is now open to the international oil and gas industry. However the event heard that increased production activity in Iran is unlikely to stat until Spring 2016 or later as the region still has 45 million barrels of oil in tankers which will be releases first. Only after that time will the country boost global supply through new production.

The US shale industry, with its lower cost base and rapid set up characteristics, has taken over from Saudi Arabia as the new swing producer. The sector is very reactive to the price of oil and can adjust its production reasonably quickly. Despite initial resilience, Barclays anticipates a significant reduction in the supply of US shale in the fourth quarter of 2015 as well as the first half of 2016. This is where we can expect the industry to see the real battle between global supply and demand take place.

The event heard that a combination of these factors means that even with a low commodity price, a surplus of oil has continued to build despite the rapidly growing demand. Barclays’ data supports the view that demand has been under quoted despite in excess of a two million barrel per day growth in 2015. The bank forecasts per day increase in demand in 2016, making an estimated overall increase of four million barrels per day since the beginning of 2015.

The group also heard how the bedrock of a stable oil and gas industry is the need for a strong US dollar, and the currency remains the global outperformer. Barclays expects the greenback to overtake in the coming financial quarters owing to the US economy’s better return to capital, safety characteristics and superior growth outlook.

In the next year, the industry will see a draw down in oil supplies, which Barclays predicts will result in an average oil price of $60 per barrel. This price level is expected to incentivise the appropriate amount of US shale supply to grow: if the sector experiences negative growth it will leave the market very tight, but production levels will most likely reduce from one million barrels per day to 200,000 – 300,000 barrels a day growth rate.

A higher commodity price, for example of $70 a barrel, would trigger a further increase in the amount of shale supply into the market and would once again tip the balance towards over production.

Walter Cumming, head of oil and gas at Barclays Corporate Banking commented: “There is no doubt that the UK North Sea oil and gas industry is under pressure right now but we do feel that signs of relief are there, and the forecast for $60 oil in 2016 with oil demand growth above trend again is encouraging.

“In the difficult market we are operating in today, it was a very valuable experience to get such a wide variety of industry experts together to discuss the issues that matter most to our customers and ourselves.

“The detailed research that we have undertaken and shared at our Aberdeen meeting emphasises our message as a bank to our customers. We believe the North Sea still has a viable future and the expected increase in demand would support this. Barclays Corporate Banking is committed to investing in the region and it was clear from our event that those who attended shared our commitment to the North Sea and the belief that while business may be difficult in the current environment, there are grounds for optimism.”

OPTION (Optimizing Oil Production by Novel Technology Integration) aims to significantly improve simulation tools for the prediction and control of the flow between the horizontal wells and the reservoir – with a focus on enhancing oil recovery.

As part of their investment in the project, DONG Energy will contribute with the complete subsurface dataset from the Siri and Stine fields, located in the Danish sector of the North Sea.

Dr. Michael Kragh Engkilde, Subsurface Manager of Siri Asset at DONG Energy says: “With our ambition to extend the life of the Siri Area, we are continually investigating opportunities for enhancing production. The knowledge exchange with the other industry partners and academia in OPTION could be central to our further development work to improve recovery performance.”

The joint industry project breeds a close link between industry and academia and as such helps to progress research exploitation and knowledge transfer.

This €3.9 million project is a collaboration between industry partners Lloyd’s Register Energy, and its consulting business - Lloyd’s Register Consulting; LR Senergy; Welltec; DONG Energy; the Technical University of Denmark (DTU); and the University of Copenhagen. It is supported by a €2 million grant from the Innovation Fund Denmark.

Dr. Kenny Krogh Nielsen, Chairman of the OPTION Steering Committee and Team Leader at Lloyd’s Register Consulting states: “DONG Energy’s participation marks a decisive step for OPTION. By applying real reservoir data, DONG Energy’s contribution is reinforcing the expected benefits and value of OPTION, and will help bridge the gap between theory and practice.”

DONG Energy will be contributing with data and advisory support to ensure proficient analysis and integration of the dataset. Dr. Krogh Nielsen says: “Collectively, we are committing expertise to analyze and refine this data, which will help optimize the future development of the Siri Area.”

Christian Krüger, VP of Intervention Solutions at Welltec A/S says: “With still fewer field discoveries and a growing energy demand, there is an industry imperative to develop innovative methods for improving recovery from existing reservoirs. OPTION could help to enhance and extend production from existing fields, which would benefit the oil and gas industry’s supply chain and contribute to renewed employment and economic prospects in Denmark.”

By providing more accurate results, OPTION strives to advance decision-making and well designs with a focus on enhancing oil recovery. A one percentage point increase in the oil recovery factor for the Danish fields would represent an estimated value of DKK 40 billion to the Danish economy with today’s oil price.

More information on OPTION is available here.

Chevron Corporation (NYSE: CVX) announces that its subsidiary, Chevron Overseas (Congo) Limited, has commenced oil and gas production from the Lianzi Field, located in a unitized offshore zone between the Republic of Congo and the Republic of Angola.

Located 65 miles (105 km) offshore in approximately 3,000 feet (900 meters) of water, Lianzi is Chevron's first operated asset in the Republic of Congo and the first cross-border oil development project offshore Central Africa. The project is expected to produce an average of 40,000 barrels of crude oil per day.

"This milestone demonstrates that we continue to make steady progress on delivering major development projects," said Jay Johnson, executive vice president Upstream, Chevron Corporation. "We have the industry's strongest queue of major capital projects that are expected deliver significant value and production growth."

"As the first offshore energy development spanning national boundaries in the Central Africa region, Lianzi represents a unique cooperative approach to share offshore resources and may serve as a model for the development of similar cross-border fields between two countries," said Ali Moshiri, president of Chevron Africa and Latin America Exploration and Production Company.

The field, discovered in 2004, includes a subsea production system and a 27 mile (43 km) electrically heated flowline system, the first of its kind at this water depth. The system transports the oil from the field to the Benguela Belize–Lobito Tomboco platform in Angola's Block 14 and utilizes a Direct Electrical Heating (DEH) system to ensure fluid flow under a wide range of conditions.

Chevron Overseas (Congo) Limited is operator of the Lianzi Field and has a 15.75 percent interest, along with its affiliate Cabinda Gulf Oil Company Limited (15.5 percent), Total E&P Congo (26.75 percent), Angola Block 14 BV (10 percent), Eni (10 percent), Sonangol P&P (10 percent), SNPC (the Republic of Congo National Oil Company – 7.5 percent), and GALP (4.5 percent).

Global integrated drilling waste management and environmental services firm, TWMA, has been awarded two major contracts, building on a strong relationship with Maersk Oil North Sea UK (Maersk Oil) spanning more than a decade.

The projects, which are led by an Aberdeen-based team, involve work on the Culzean development – one of the largest gas discoveries in recent years in the UKCS – and the continuation of provision of innovative technology across Maersk Oil’s Central North Sea operations.

To ensure the company continues to offer the best, most cost-effective and safe solutions available to the global oil and gas industry, multi-million pound equipment investments are being made. The new work will also result in the creation of up to 20 new jobs.

TWMA men at work

Neil Potter, Chief Operating Officer at TWMA, said: “We are delighted to have been selected to support Maersk Oil on these projects as they expand their drilling activity within the UK sector of the North Sea.

“Our experienced, skilled team are working closely with Maersk Oil and have been since the award to carry out the pre-fabrication R&D activity needed for the Culzean operations. To date, this has included working on-site in Singapore with rig builder Hercules to develop solutions where we aim to use our proven technical know-how to design, manufacture and install best-in-class technology to handle Maersk Oil’s drilling waste processing requirements.

“By delivering exceptional results that improve operational efficiency while maintaining a quality service over a considerable period of time, we have nurtured a strong working relationship with Maersk Oil. We are delighted to have been awarded a new scope of work on the prestigious, high-profile Culzean development and a renewed agreement for the continuation of our services across Maersk Oil’s Central North Sea projects.

“Despite extremely challenging market conditions, TWMA has maintained high-levels of investment in R&D which is exceptional in the current climate and demonstrates our awareness of the need to continue to build on our strengths and offer the best possible integrated drilling waste management services and environmental solutions.’’

The Culzean project involves TWMA providing drilling waste processing and waste management services for five years with the option of two one-year extensions.

Delivered using a 950kW electric drive within TWMA’s proprietary TCC RotoMill and EfficientC equipment, the Culzean project will also see TWMA recruit up to 20 personnel to support the existing workforce within the engineering, commissioning and operations phase.

The second contract will provide existing drilling waste processing and management services for Maersk Oil’s Central North Sea projects, again utilising the firm’s TCC RotoMill and EfficientC technologies. The new agreement will continue for the next three years, with the option for two one-year extensions.

International project services consultancy, Cambla, heralds its move into the decommissioning sector, having been awarded contracts with two major operators in the oil and gas industry.

The contracts will see Cambla provide expert project services support and utilize its specialist Schedule Animation Tool (S.A.T) software to ensure efficient and effective planning for decommissioning projects in the North Sea.

Alexander MacLeod, founder of Cambla

Alexander MacLeod, founder of Cambla, said: “We are delighted to have secured our first decommissioning contracts, which have been awarded as a result of the excellent reputation we have built with the operators on previous projects. Decommissioning is now high on the agenda for many companies in the energy industry and we are delighted to have established ourselves as project services experts in this sector.”

Cambla has also expanded its services by providing its first interim in-house consultancy service for another major operator. The work scope will involve the provision of a project services in-house consultant for asset planning.

Alexander continues: “The wide scope of work required for these contracts allows us to deploy various elements from our pre-built toolbox of processes and reports to save clients time and costs, in the implementation of a robust planning system.

“We continually strive to broaden our service offering and the provision of an interim in-house consultant highlights our ability to support large companies in the management of their project planning as well as our capability to provide bespoke solutions tailored to each client’s needs.”

Established in 2013, Cambla offers expert project planning, cost control and probabilistic services to support oil and gas projects using a pre-built toolkit of processes and reports. Cambla’s team of expert project planners support client projects across the globe, from early appraisal through to the final close-out period, ensuring a high quality result is achieved at all stages of the project.

Statoil has, on behalf of the Johan Sverdrup license, awarded a contract to Jacktel AS, a wholly owned subsidiary of Master Marine AS, for providing accommodation services on the Johan Sverdrup field.

Jacktel AS, a wholly owned subsidiary of Master Marine A, located in Oslo/Norway, has been awarded a contract for the Haven jack-up accommodation rig for the installation and commissioning period for the Johan Sverdrup project phase 1.

The Haven jack-up accommodation rig. (Photo: Sondre Steen Holvik)

Included in the accommodation services is bed capacity and catering services for project personnel. The accommodation rig will provide up to 400 beds on the Johan Sverdrup field.

To ensure required capacity for working on the Johan Sverdrup field, Haven will undergo an upgrade related to strength and length of the legs, including provision of new spud-cans/suction-caissons. The upgrade is expected to be performed at a yard in Norway.

The contract period is 18 months with an estimated start 15 June 2018. In addition there are 5x2 months options. The total value of the firm contract period is approximately 178 million USD. including expected upgrade cost of approximately 100 million USD.

"We are very pleased with the contract awarded to Jacktel AS. The Haven jack-up accommodation rig will be an important tool in the final offshore installation and commissioning phase, putting together the different pieces of the Johan Sverdrup puzzle "says Kjetel Digre, senior vice president for the Johan Sverdrup development project.

The development concept for Johan Sverdrup phase 1 will consist of four installations, including a utility and accommodation platform, a processing platform, a drilling platform and a riser platform, in addition to three subsea templates for water injection. 

Also announces Humpback well results offshore the Falkland Islands

Noble Energy, Inc. (NYSE: NBL) announces that the Big Bend oil development in the deepwater Gulf of Mexico commenced production on October 26, 2015. The single-well field is ramping as expected and is anticipated to reach a maximum gross production rate of approximately 20 thousand barrels of oil equivalent per day (MBoe/d) over the next couple of weeks. Approximately 90 percent of the volumes being produced are oil. In addition, the Company has continued to accelerate the Dantzler development and now expects first production from the Dantzler field by early November. Big Bend and Dantzler, located in Mississippi Canyon 698 and 782, respectively, are subsea tiebacks to the third-party Thunder Hawk production facility. Combined, the fields are estimated to contribute a maximum net production rate of 20 MBoe/d to Noble Energy.

Gary W. Willingham, Noble Energy's Executive Vice President of Operations, said, "We continue to build on our strong track record of major project execution with Big Bend coming online less than three years from discovery and within our sanctioned budget. Big Bend is the first of three major projects planned to come online for us in the Gulf of Mexico over the next nine months, contributing significant oil production and cash flow to the business. Short cycle times to first production, strong well deliverability, and low production costs from our Gulf of Mexico projects deliver attractive returns even in today's environment."

Noble Energy operates Big Bend with a 54 percent working interest. Other interest owners are W & T Energy VI, LLC (a wholly owned subsidiary of W & T Offshore Inc.) with 20 percent, Red Willow Offshore, LLC with 15.4 percent and Houston Energy Deepwater Ventures V, LLC with 10.6 percent.

The Company is also the operator of Dantzler with a 45 percent working interest. Partners include Ridgewood Energy Corporation (including ILX Holdings II, LLC a portfolio company of Riverstone Holdings, LLC) with 35 percent working interest and W & T Energy VI, LLC with 20 percent.

Noble Energy also announced that the Humpback well offshore the Falkland Islands reached total depth and is being plugged and abandoned. Humpback was drilled in the Fitzroy sub-basin of the Southern Area License and encountered non-commercial quantities of crude oil and natural gas. Full well assessment and the integration of drilling results into the Company's geologic models is ongoing to determine remaining exploration potential in the Southern Area License. The geologic play including Humpback is only one of a number of prospect play types in the Southern Area License.

The rig which drilled the Humpback well will be released to another operator before returning to Noble Energy to spud the Rhea prospect in late 2015 or early 2016. Located in the Northern Area License offshore the Falkland Islands and approximately 265 miles from Humpback, Rhea is in a proven petroleum basin near existing oil discoveries. Rhea is a Cretaceous-aged prospect with multiple reservoir targets and total estimated gross mean unrisked resources in excess of 250 million barrels of oil.

The Company now expects total third quarter 2015 exploration expense to be approximately $200 million, which includes the majority of net costs related to the Humpback well.

Brazil will lead global growth in the Floating Production, Storage and Offloading vessel (FPSO) industry despite the country’s national oil company, Petrobras, recently facing allegations of corruption, says research and consulting firm GlobalData.

Petrobras registered its biggest ever loss in 2014, partly due to the write-down resulting from the corruption scandal, which in turn resulted in spending cuts on its future projects.

GlobalData’s report* states that despite the challenges, Brazil has spearheaded recent growth in the global FPSO industry, with the country deploying 17 FPSOs between 2009 and 2014.

Adrian Lara, GlobalData’s Senior Upstream Analyst, says: “Petrobras’ strategic plans in 2013 and 2014 had almost 40 FPSOs deployed in Brazil through 2020. Based on the company’s latest plan, there are currently seven FPSOs still on time for delivery, whereas 11 have had their delivery date moved back a couple years and about 12 FPSOs are now expected after 2020.”

While Petrobras is planning to spend $108.6 billion, or 83% of its total capital expenditure, on the exploration and production sector as part of its 2015-2019 Business and Management Plan, corruption allegations have hampered its ability to execute the planned projects, including those involving FPSOs.

Lara comments: “Planned projects have been affected in large part by the ongoing investigation into corruption. In particular, domestic shipyards have been hit hard.

“Sete Brasil was set to build 29 offshore rigs for Petrobras but has scaled back to 15. The uncertainty around when and how many rigs will be available will have a knock-on effect on FPSO delivery dates.”

Despite these challenges, Petrobras plans to prioritize oil production projects focusing on sub-salt resources and will deploy and operate a higher number of FPSOs than any other company in the world by 2019, according to the report.

Matthew Jurecky, GlobalData’s Head of Oil & Gas Research and Consulting, concludes: “FPSOs are an ideal development option for offshore oil fields given current uncertain oil prices, as they can easily be scaled up if the market improves, or scaled down to maintain economic viability despite low oil prices.

“For example, the Sea Lion development in the Falkland Islands is progressing through reducing the initial scope despite being a frontier project.”

*Global FPSO Industry Outlook – Brazil Leads Record FPSO Deployments Despite Deteriorated Project Economics

The Middle East faces a substantial challenge to ensure hundreds of ageing offshore oil and gas structures operate safely beyond original design life.

Constraining operational expenditure (opex) is vital to economically viable operations, according to Anupam Ghosal, newly appointed regional manager for Middle East and India, DNV GL - Oil & Gas. “Of the 700 to 800 fixed platforms and bridges in the region, we believe more than 70% are older than 25 years and some even exceed 40 years. The United Arab Emirates (UAE) alone has about 450.”

The structural integrity management challenge is complex and critical for many operators seeking to extend the economic life of assets. Life extension of ageing structures needs to ensure continued operation within regulatory requirements, and to limit future opex.

“Life extension of ageing structures and assets is moving firmly up the agenda for oil and gas operators in the Middle East,” says Ghosal. “Collaboration, joint innovation, best practice sharing and research, such as for CO2 injection for enhanced oil recovery, are prerequisites for smarter lifetime extension projects.”

Anupam Ghosal joined DNV GL’s Abu Dhabi office in April 2010. He brings more than 23 years of industry experience and led the Verification and Asset Integrity Management unit with Noble Denton marine assurance and advisory services up until the DNV GL merger in September 2013.

DNV GL is engaged with several customers in the region to implement controlled approaches to asset integrity management and structural integrity management systems. The company’s software, database, quantitative and qualitative approaches, and other expertise in capturing, analyzing and managing information for structural integrity management assists customers to scope, design and implement effective life extension strategies. The company’s ‘missing data methodology’ addresses the absence of historic documentation, a common challenge for operators in the region.

“We persistently endeavor to understand the challenges of our industry in this region and we are already playing a central role with a number of major operators,” adds Ghosal. “Our aim is to develop cohesive and cost-effective strategies to attain life extension of ageing assets and secure the economic benefits it brings.”

“In our 38 year presence in the region, we have built a strong position in the market founded on trust and competent delivery, while setting the benchmark in industry best practice and offering access to more than 300 standards and recommended practices.”

In the oil and gas sector, DNV GL has advanced from having the majority of the offshore pipelines in the UAE being designed and certified to DNV GL standards to currently being engaged in ALL the major offshore projects in Abu Dhabi. The company is currently working with a number of major operators to provide Technical Integrity Verification services and in-service inspection.

McDermott International, Inc. (NYSE:MDR) announced on Monday, November 9th, that it has been awarded a large brownfield contract by RasGas Company Limited (RasGas) for the engineering, procurement, construction and installation (EPCI) of a flow assurance and looping project consisting of 74 miles of 6- and 8-inch pipeline and topside modifications, offshore Qatar. Work is scheduled for completion by the end of the third quarter of 2017.

McDermott and RasGas have worked closely together for two decades with McDermott having fabricated and installed numerous RasGas facilities offshore Qatar. Currently, the companies have an Engineering Service Agreement (ESA) under which McDermott has executed several concept studies and Front End Engineering Design (FEED) projects. Additionally, the McDermott team is assisting with the upgrade and replacement of three helidecks.

“Some 20 years ago, McDermott and RasGas began building what has become a historically strong working relationship,” said Tom Mackie, McDermott’s Vice President, Middle East. “This set the stage for this award. By combining our knowledge of the customer’s current production infrastructure, early collaboration through our ESA, and our unique brownfield capabilities, McDermott provided RasGas with an optimal EPCI solution.”

Engineering, procurement and fabrication is expected to be performed by McDermott’s teams based in Dubai, U.A.E. Vessels from the McDermott global fleet are expected to undertake the installation work.

Revenue for the order will be included in McDermott’s third quarter 2015 backlog

Statoil has completed a farm-in transaction with ExxonMobil Exploration and Production South Africa Limited (ExxonMobil), acquiring a 35 percent interest in the ER 12/3/154 Tugela South Exploration Right.

The remaining interests are held by the operator ExxonMobil (40%) and co-venturer Impact Africa Limited (Impact Africa) (25%).

“This opportunity is in line with Statoil’s exploration strategy of access at scale. It represents access into a frontier basin where we believe we see indications of an active petroleum system and which has impact potential,” says Nick Maden, senior vice president for Statoil's exploration activities in the Western Hemisphere.

“The position strengthens and increases the optionality in Statoil’s long-term international portfolio. We look forward to working with ExxonMobil, Impact Africa and the South African government to explore for oil and gas in this new area for Statoil,” says Maden.

The Tugela South Exploration Right covers an area of approximately 9,054 square kilometers. It is located offshore eastern South Africa in water depths up to 1,800 meters.

The farm-in represents a country entry for Statoil into South Africa. Statoil enters in an early exploration phase with a step-wise exploration program. Work commitments between 2015 and 2017 include the acquisition of 1,000 square kilometers of 3D seismic data and geology and geophysics (G&G) studies. There are no commitment wells during this exploration period.

The information obtained from the initial studies and seismic survey will form the decision basis for the co-venturers’ next steps in the Exploration Right.

Statoil has decided to cancel the contract with Songa Trym, four months before the expiration of contract on 4 March 2016.

Songa Trym (Photo: Kjetil Larsen - Statoil)

Statoil has previously notified Songa Offshore that the rig would be suspended for a period, and Statoil has tried to find other assignments for the rig after the suspension period and up to the expiration of contract.

“We informed the supplier earlier in October about suspending the contract after the rig has completed the drilling operation on the Tavros well on the Visund field. Statoil has hoped for further activity in the remaining contract period, but we now realize that we must cancel the contract, as we have not succeeded in finding more assignments. We regret that we need to cancel the contract before it expires,” says Tore Aarreberg, head of rig procurements in Statoil.