Statoil has delivered its application for the 23rd licensing round on the Norwegian continental shelf to the Norwegian authorities.

It is expected that the Ministry of Petroleum and Energy will announce the awards late first half of 2016.

The round represents the first opening of new acreage on the Norwegian continental shelf (NCS) since 1994. Statoil’s application aims to significantly contribute to the company’s ambition for 2030 and beyond.

The acreage that is offered in this round includes the south-east of the Barents Sea, which is an area that was clarified as Norwegian territory under the border agreement with Russia that came into effect from 2011. In addition acreage in the Hoop-Wisting area, opened in the 22nd round, is on offer.

“Statoil has been the guarantor for exploration and development in the Barents Sea since the mid-1980s and we have a clear ambition to remain in that role. The acreage offered is interesting and important and we hope we will earn the opportunity to drill as early as in 2017,” says Jez Averty, senior vice president Exploration Norway.

“Acreage in the 23rd round has significant volume potential, but never-the-less there is a debate where some say that these resources will not be commercial. We believe otherwise and our application is proof enough of that. Statoil’s preparations for our 23rd round application have included developing technology solutions that will reduce the break-even price per barrel for the significant discoveries we hope to make in the Barents Sea.”

In the run up to this license round, the cooperation within the industry has been unprecedented. In the Barents Sea Exploration Collaboration project, 16 companies are cooperating to find common solutions for exploration operations in the Barents Sea and to ensure cost-effectiveness and good safety standards.

In 2014, Statoil was operator for a group of 33 companies cooperating on seismic surveys in areas included in the licensing round.

The NCS is the backbone of Statoil and Statoil has an ambition to maintain production at current levels through to 2025-2030 and beyond.

With the exploitation of new cost-effective operational concepts, use of digital technologies and increased dependence on cyber structures, the oil and gas industry is exposed to new sets of vulnerabilities and threats. Cyber-attacks have grown in stature and sophistication, making them more difficult to detect and defend against, and costing companies increasing sums of money to recover from.

DNV GL has delivered a study to the Lysne Committee (Lysneutvalget¹) that reveals the top ten most pressing cyber security vulnerabilities for companies operating offshore Norway.

An international DNV GL survey of 1,100 business professionals found that, although companies are actively managing their information security, just over half (58%) have adopted an ad hoc management strategy, with only 27% setting concrete goals².

“Headline cyber security incidents are rare, but a lot of lesser attacks go undetected or unreported as many organizations do not know that someone has broken into their systems. The first line of attack is often the office environment of an oil and gas company, working through to the production network and process control and safety systems,” says Petter Myrvang, head of the Security and Information Risk, DNV GL - Oil & Gas.

While the study focused on operations on the Norwegian Continental Shelf, the issues are equally applicable to oil and gas operations anywhere in the world.

The top ten cyber security vulnerabilities:


DNV GL believes cyber security vulnerabilities can be addressed through a risk-based approach, using the bow-tie model familiar in safety barrier management. This allows companies to identify the threats to and vulnerabilities of assets and operations and plan barriers to prevent incidents and mitigate the consequences of cyber risks. This includes procedures to maintain the barrier quality documented in performance standards.
“As all oil and gas process plants are now connected to the Internet in some way, protecting vital digital infrastructure against cyber-attacks also ensures safe operations and optimal production regularity,” says Trond Winther, head of the Operations Department, DNV GL – Oil & Gas.
The company applies its independent, risk-based approach to designing, implementing, testing, monitoring and maintaining cyber security countermeasures for customers worldwide. The company’s software tool, Synergi™ Life – Risk Management Module, is used to establish a live asset and risk registry. This tool allows vulnerabilities and threats to be assessed and mitigations to be followed up.

Please see summary in English here.

Statoil and its partners were the successful bidders for six exploration licenses in the Flemish Pass Basin, offshore Newfoundland, and two licenses offshore Nova Scotia.

The licenses offshore Newfoundland total 1,466,918 hectares (14,670 km2), and are located in an area in proximity to the Statoil-operated Bay du Nord discovery. Statoil will operate five licenses, and participate in one license as a partner. The offshore Newfoundland licenses awarded are as follows:

• NL15-01-02: Chevron 35% (operator); Statoil 35%; BG 30% (274,732 hectares)

• NL15-01-05: Statoil: 40%; Exxon Mobil 35%; BG 25% (267,403 hectares)

• NL15-01-06 Statoil 34%; Exxon Mobil 33%; BP 33% (262,230 hectares)

• NL15-01-07: Statoil 34%; Exxon Mobil 33%; BP 33% (254,321 hectares)

• NL15-01-08: Statoil 50%; BP 50% (268,755 hectares)

• NL15-01-09: Statoil 100% (139,477 hectares)

The licenses offshore Nova Scotia (NS15-1 Parcels 1 and 2) cover an area totaling 650,000 hectares (6,500 square kilometers), and are located approximately 250 kilometers from Halifax, Nova Scotia. The growth of Statoil’s portfolio offshore Newfoundland and new entry offshore Nova Scotia strengthens the company’s long-term position in the Canadian offshore.

“The successful bids in these frontier areas offshore Canada are in line with Statoil’s strategy of deepening our position in prolific basins and securing access at scale, while also adding important optionality to our exploration portfolio,” says Tim Dodson, executive vice president for Exploration in Statoil.

“The significant exploration investment offshore Newfoundland will provide Statoil an opportunity to further advance our established exploration position in this region through a step-wise approach, while in Nova Scotia, we are able to apply the exploration knowledge and experience we have gained globally and in the North Atlantic specifically,” he said.

Statoil holds an extensive position in the Flemish Pass Basin, and the licenses awarded support developing the company’s exploration portfolio in an environment where Statoil is experienced. The licenses awarded are located in an area nearby to Statoil’s previous discoveries in the Flemish Pass Basin – the Mizzen discovery was made in 2009, and Harpoon and Bay du Nord were both discovered in 2013.

Starting in November 2014, Statoil has undertaken an 18-month exploration drilling program in the Flemish Pass. The program will appraise the Bay du Nord discovery and also test new prospects in the greater Basin area. Statoil is the operator of the Bay du Nord discovery with a 65% interest, and Husky Energy has a 35% interest.

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.

Leading classification society ClassNK (Chairman and President: Noboru Ueda) has released its Guidelines for Floating Offshore Facilities for LNG/LPG Production, Storage Offloading and Regasification (Third Edition).

The first edition of the guidelines laid out specific technical requirements for gas FPSOs and was released in 2011. In February 2015, the guidelines were revised and the second edition was released to clarify the application to FSRUs.

Key industry players, as well as ClassNK and Japan’s Ministry of Land, Infrastructure, Transport and Tourism recently gathered to discuss how to further enhance the safe design of FLNG. Based on the outcomes of this discussion, ClassNK has developed the third edition of its guidelines. Updates include specific requirements of mooring analysis of single-point mooring systems, such as turret mooring systems*. The combination of environmental conditions to be considered and statistical analysis methods using tension evaluation are set out in detail in the guidelines. Requirements for fire protection, fire extinction and so on have also been partly revised.

*Turret mooring uses the connection of bearings joining the mooring cables and hull structure to automatically rotate the hull structure in the direction where external forces such as waves, wind and tidal currents are minimized.

International oilfield services company, Expro, has achieved a significant milestone as it enters Qatar for the first time and expands its Middle Eastern presence with a five-year contract win.

The contract will see Expro provide its range of well intervention and slickline services including high deviation and heavy-duty fishing offshore Qatar, as well as in drilling and workover locations in-country.

Tarek Hekal, Senior Area Manager – Middle East, said:

“This contract is a key win for Expro in the region as we expand our presence to better serve our clients.

“In current market conditions, Expro recognises the need for operators to lower production costs. We will work closely with operators in the region to bring planning, operational and technical expertise that adds real commercial benefit to the cost of intervention.”

For the financial year ending 31 March 2015, Expro’s presence in the Middle East and North Africa region grew with stronger positions in all its main operating countries providing the opportunity to introduce a range of new technologies, products and services into these markets.

Decommissioning within the offshore environment is rapidly becoming a focused activity for the oil and gas industry. Latest figures from Decom North Sea suggest that there are, approximately, 470 offshore installations in the UK sector due to come out of service by 2030 with an associated cost of US$46.8 billion (£30 billion). With such a formidable undertaking ahead, oil and gas operators are developing their decommissioning plans.

The effective management and mitigation of potential environmental impacts and risks is key to the success of this process. Integral to this are marine growth assessments which are increasingly being used to provide valuable information for decommissioning plans. Faron McLellan, Environmental Consultant, Dr. Dorota Bastrikin, Senior Consultant, and Dr Joe Ferris, Associate Director at BMT Cordah, a subsidiary of BMT Group, discuss the importance of these assessments drawing on a number of projects carried out both within the North Sea and overseas, and how they can assist the planning process, minimise the environmental impact and financial risks. An important environmental issue is the occurrence and spread of marine species on decommissioned structures outside their naturally occurring range with the risk of introducing an invasive species.

There are over 1,500 registered offshore oil and gas installations in the North Sea, 470 of which are in United Kingdom (UK) waters with more than 10,000 km of pipelines and circa 5,000 wells. Many of these structures are over 40 years old and are now coming to the end of their design life. Over the next couple of decades a growing number of redundant oil and gas installations will be taken out of service and decommissioned. As well as the physical removal of the component parts, decommissioning of offshore subsea structures must include the management and mitigation of any potential environmental impacts and risks. This includes the consideration of organisms that colonise submerged oil and gas structures referred to as ‘marine growth’. These colonies may form habitats from a range of species assemblages, the composition of which will differ depending on the structure’s depth, geographical location and age. Marine growth introduces a wide range of issues in the context of decommissioning, including the added weight to a structure, colonisation by protected species, the potential for transfer of invasive (non-native) species and management of marine growth waste. Existing literature indicates that the colonisation of offshore structures can commence within weeks of submergence, continuing until the time of decommissioning. Throughout that period, marine growth can colonise and re-colonise, sometimes with species different to those originally found on the structure. In some cases, facilities may have been in place since the late 1970’s, providing opportunities for colonisation by a succession of marine species.

There are two protected species in the North Sea that must be recognised during the decommissioning process: Lophelia pertusa, a cold-water coral and Sabellaria spinulosa, a reef building polychaete worm. The Department of Energy and Climate Change (DECC) Guidance Notes on the Decommissioning of Offshore Oil and Gas Installations and Pipelines under the Petroleum Act 1998 provide guidance on these. If either of these species is likely to be present, it is prudent to confirm or disprove their presence prior to undertaking decommissioning operations. Both of these species are listed under the Convention on International Trade in Endangered Species of Wild Flora and Fauna (CITES). This listing means that a CITES certificate is required if transporting Lophelia or Sabellaria between states.

Factors influencing the distribution and occurrence of marine growth colonisation include water temperature, salinity, depth, distance from shore or from other fouled structures, exposure to wave action and predation. Geographical differences in these parameters exist as demonstrated in the variation in marine growth between the northern, central and southern North Sea. For example, Lophelia has not been recorded on southern North Sea structures and is typically only observed in the northern and central North Sea in deep waters (>50 m) and colder conditions. Marine growth will develop at different rates, but it is not unusual for significant cover of marine growth to be established in as little as five years after installation. Lophelia has not historically been recorded within the first decade after installation. However, with an increasing number of platforms with Lophelia, these colonized platforms may provide a “stepping stone” effect and facilitating colonisation within the first decade. In the SNS Sabellaria has been reported growing on the exposed surface of pipelines in areas designated as conservation sites. The decommissioning options for these pipelines may be affected by the occurrence of this species.

The differences in species composition and distribution between areas of the North Sea can be demonstrated through two marine growth assessments carried out by BMT Cordah.

Considering the aforementioned factors, the importance of a marine growth assessment in the management of the decommissioning process to minimise potential environmental impacts and risks becomes more apparent. Whilst not a statutory requirement within UKCS decommissioning environmental impact assessments (EIA), marine growth assessments offer a practical and cost-saving option for its effective management. Furthermore, a marine growth assessment contributes to both the environmental and socioeconomic aspects of the EIA. At a minimum, these assessments can be used to provide a quantification of the weight of fouling organisms and identification of species, including those subject to protection. The weight of the structures to be decommissioned is a fundamental consideration when planning lifting, transportation and disposal operations. Marine growth, by increasing the structural weight, can increase costs and the complexity of lifting operations.

Current approaches to the management of marine growth include (i) offshore removal of marine growth by a Remotely Operated Vehicle (ROV) and/or divers in situ; (ii) onshore removal from cut jacket sections and subsequent landfilling; and (iii) land-spreading or composting of removed marine growth. All of these options bring with them potential environmental impacts which need to be considered Potential seabed impact from marine growth removed in situ will also be influenced by the species composition. The suitability of landfill or composting sites will depend on species composition. The EU Landfill Directive (1999/31/EC) includes an obligation for member states to reduce the amount of biodegradable waste, which includes marine growth destined for landfill. The UK targets, based on the 1995 waste quantities, are a reduction of 75% by 2010, 50% by 2013 and 35% by 2020. Therefore disposal in landfill may become a last resort for this waste.

Offshore structures brought to shore with marine growth have often resulted in complaints from local communities regarding the odour. The major sources of smell following removal of structures laden with marine growth are the biologically-emitted odors from dying organisms, disturbed anoxic layers and removal of putrefying organisms, particularly originating from highly productive areas. The intensity of smell can become a considerable nuisance to local communities. The platform location and time of year for planned removal should be taken into consideration when developing the decommissioning programme. Due to the seasonality of the productivity of fouling organisms, jackets and other subsea structures removed during the summer and autumn would be expected to emit a stronger odour for longer than those removed in spring from the same location.

A marine growth assessment also provides information on the presence of potentially invasive alien (non-native) species (species from outside of their natural range) which can threaten the diversity or abundance of native species, the ecological stability of infested waters and/or commercial, agricultural or recreational activities. Invasive species can often out-compete indigenous species, detrimentally affecting local ecosystems. Mobile structures, such as Floating Production Storage and Offloading (FPSO) vessels, could act as sources for the introduction of invasive species when taken to different geographical regions for decommissioning or reuse. The European Union (EU) Marine Strategy Framework Directive (MSFD) that came into force on 15th July 2008 aims to protect the marine environment across Europe by achieving and maintaining Good Environmental Status (GES) by 2020. It lists prevention of the adverse alterations to the environment by non-native species, as one of the vital elements of maintaining GES. In 2014, UK published Part Two of the Marine Strategy which focuses on a coordinated monitoring programme for the ongoing assessment of GES and includes invasive species. A new EU Regulation No. 1143/2014 on Invasive Alien Species came into force on 1st January 2015 and foresees three types of interventions: (i) prevention; (ii) early detection and eradication; and (iii) management. A marine growth assessment can satisfy requirements for detection and management.

With the transportation of offshore structures comes an increased potential risk to the marine environment of the introduction of invasive species. This is particularly important if the structure is to be transported out of the North Sea. This risk is determined by the:

Presence and abundance of invasive alien (non-native) species and/or species that have the potential to become invasive;

Period of air exposure of the marine growth during transport and resultant mortality of the species; and

Capacity of alien organisms to colonize, survive and out-compete native species along the transport route and at the final destination.

The major considerations when deciding the movement of the FPSO and geographical location of the decommissioning yard were:

Identification of the suspected invasive coral;

Consideration of remedial options for in situ removal; and

Assessment of existing international regulations and compliance with the transportation and deposition of non-indigenous species in international waters.

An assessment of the marine growth on offshore structures is an important component of decommissioning programmes. The implications of additional weight and the occurrence of protected or invasive species are key drivers in lifting operations and final disposal. These must be considered to ensure the decommissioning process is completed safely, cost-effectively and within the frameworks of both best practice and relevant legislation.

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.

By Julia Schweitzer

Lack of properly assessed and defined wear limits for jacking systems can lead to significant downtimes with financial implications for jackup operations. DNV GL, supported by leading global industry players in the jackup industry, has established a joint industry project (JIP), to provide guidelines on determining relevant wear criteria for self-elevating units.

The ‘Wear acceptance criteria for jacking systems’ JIP, is expected to begin early 2016 with eleven partners already confirmed. The JIP is building on a DNV GL Recommended Practice (RP) issued last year to address maintenance and inspection challenges of a jackup system. It will document relevant design arguments, considerations and calculations to enable the industry defining acceptance criteria and giving guidance on the correct assessment of jacking systems in a RP.

“Defining maximum limits of wear across all parts of a jacking system is technically complex,” says Michiel van der Geest, product manager offshore classification, DNV GL – Maritime. “It not only involves the interaction of all elements of the system, including the different materials applied, but also relevant operational and maintenance strategy considerations.

Incorrect or unclear assessments can increase cost and also the reliability and availability of jacking systems. By creating a clear guidance this JIP will ultimately improve asset management and reduce delays and maintenance costs.

”Several partners have expressed the need for this JIP: “There is a clear benefit in participating in this JIP, taking into consideration the need of users, class authorities, and OEM to have a common language when talking about jacking systems. The recommended practice which will be issued from this JIP will give the users confidence in long term predictive operation, supported by OEM diagnosis,” says Philippe Gadreau, Chairman and CEO of NOV-BLM.

Another partner adds: "Allrig is delighted to extend its participation in this next phase of the JIP and continue to share its extensive knowledge of jacking systems best practice,” says Mark Hannigan, CEO, Allrig Group. “Through collaborations of this nature the offshore industry as a whole can emerge from the downturn stronger, safer and more efficient to face the challenges of the future."

Thomas Burley, CEO of David Brown Gears, comments: “David Brown Gears has received strong support from our growing customer base in the UAE to participate in the DNV GL JIP on jacking system wear criteria. We believe that the JIP offers the right forum to define best practice for the industry.”

“This new JIP on wear acceptance criteria for jacking systems is the latest offspring from our successful collaborative initiatives to improve jackup operations,“ adds Michiel van der Geest. “We are constantly looking into improvements for the jackup industry.”

Airborne Oil & Gas has been awarded a contract for the supply of TCP Downline, Jumpers and deployment system for acid stimulation.

A West African operator selected Airborne Oil and Gas’s Thermoplastic Composite Pipe (TCP) technology as the preferred solution for injecting large volumes of stimulation fluids offshore in deep water offshore West Africa. Airborne Oil & Gas will supply a 1450 meter long, 3 inch ID 5000 psi working pressure TCP Downline and TCP Jumpers, the latter connecting the downline to the injection skid and subsea wellhead. In addition, Airborne Oil & Gas will supply the complete deployment spread, including reeler, tensioner and all pipe ancillaries such as end fittings, bend restrictors etcetera. Airborne Oil & Gas will perform all related engineering including global dynamical analysis of the downline system.

The TCP Downline and TCP Jumpers provide the high flow rates required for effectively stimulating reservoirs. Acid stimulation is a key element in the EOR strategy of most operators; where the flow rate is a prerequisite, the good fatigue performance, lightweight and easy maintenance ensures a good business case compared to alternatives such as steel-coiled tubing.

“Following the other orders that Airborne Oil & Gas won recently, on downlines and acid stimulation systems, this most recent order is clear evidence of a growing acceptance of TCP technology in the offshore industry, and of our leadership position in the acid stimulation and intervention business”, says Martin van Onna, Airborne Oil & Gas’s Chief Commercial Officer. “We are working with all of today’s leaders in the field of intervention, stimulation and plug and abandonment and see a strong growth over the coming period. Cost effective intervention is key to enhanced oil recovery for subsea wells. Especially in these times, where cost reduction is a central theme for many operators, our technology provides new ways to increase recovery ratios in the most cost efficient manner.”

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.

With the oil and gas industry forced to work harder to extract oil around the globe and an increasing reliance on reserves in difficult to reach locations, the resurgence in floatover installation practices continues. In its new whitepaper, ‘The Floatover Forecast, Trelleborg’s engineered products operation recounts the lessons learned, changes in technologies and materials; as well as the trials and errors that have contributed to developments in the field.

Over the past 15 years in particular, incremental improvements have established the floatover approach as an often preferred alternative to traditional heavy crane lifting. Trelleborg’s JP Chia, has been an active industry expert on the global scene since the technology came to the fore for topside deployments in the early 2000s.

Supported by statistics from a current research paper, the whitepaper details just how far the offshore industry has come in three decades of development of the floatover process and how much further it can advance as oil companies utilize the technology in even harsher environments.

JP Chia, Engineering Manager within Trelleborg’s engineered products operation, says: “Oil and gas exploration continues to grow and develop year on year and as technology becomes more sophisticated, the effectiveness of extraction will further increase. However, as floatover installations increase, it is vital that the industry applies the right thinking to ensure that projects are implemented safely and efficiently from beginning to end.

The whitepaper provides details to achieve this, enabling owners, operators, EPC contractors and consultants to confidently keep up to speed with the world of floatover installations.”

Aker Solutions won a framework agreement to provide maintenance and modifications services at BP-operated oil and gas fields offshore Norway.

The contract has a fixed period of five years valued at as much as NOK 3.2 billion. It also contains options to extend the agreement by as many as four years. The accord starts on December 1, 2015 on expiration of an existing agreement for similar services.

"This contract was won in stiff international and national competition and will help secure jobs on the west coast of Norway as well as provide crucial support for our development of operations further north," said Per Harald Kongelf, head of Aker Solutions in Norway. "We're very pleased to continue our strong partnership with BP on the Norwegian shelf."

The agreement is for work on the North Sea fields Ula, Tambar, Hod and Valhall as well as the Skarv deposit in the Norwegian Sea. The work will be managed and executed by Aker Solutions' maintenance, modifications and operations units in Stavanger and Sandnessjøen and at the company's fabrication yard in Egersund.

"Aker Solutions is a very experienced and capable supplier that has over many years had large and demanding deliveries to BP both in development projects and in the production phase," said Eldar Larsen, vice president of operations for BP in Norway. "The company has shown great flexibility and willingness to develop and use local businesses, which is especially important for activity in Sandnessjøen."

Aker Solutions has worked with BP in Norway for more than twenty years and signed the first long-term framework agreement contract of this type with the company in 1999.

"We look forward to continuing the constructive relationship we've developed over the years with BP as we work together to find the most cost-effective solutions for these fields," said Knut Sandvik, head of Aker Solutions' maintenance, modifications and operations business.

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.