Anadarko Petroleum Corporation (NYSE: APC) announces that, along with the concessionaires of Offshore Area 1 (operated by Anadarko Mozambique Area 1 Ltd. (AMA1)) and Offshore Area 4 (operated by Eni East Africa (EEA)), it has signed a Unitization and Unit Operating Agreement (UUOA) for the development of the massive natural gas resources that straddle the two blocks.

"We appreciate the cooperation of the Government of Mozambique, Eni and our co-venturers in Offshore Area 1 for their collaborative efforts in achieving this UUOA, which is fair, equitable and consistent with best industry practices," said Mitch Ingram, Anadarko Executive Vice President, Global LNG. "We have already made tremendous progress advancing the natural gas resources in the Golfinho and Atum fields that are fully contained within our block, and with this UUOA, we can also expect to move the Prosperidade and Mamba straddling reservoirs forward more efficiently, while capitalizing on greater economies of scale."

Under the terms of the UUOA and previously announced Decree Law, the Prosperidade and Mamba straddling natural gas reservoirs, which comprise the Unit, will be developed in a separate but coordinated manner by the two operators until 24 trillion cubic feet (Tcf) of natural gas reserves (12 Tcf from each Area) have been developed. All subsequent development of the Unit will be pursued jointly by the Area 1 and Area 4 concessionaires through a joint-venture operator (50:50 Anadarko and Eni). The UUOA is subject to final approval by the Government of Mozambique.

DOMESTIC NATURAL GAS

In addition, Anadarko reached a Memorandum of Understanding (MOU) with the Government of Mozambique to provide natural gas from its Mozambique LNG development for domestic use.

Under the terms of the MOU, Offshore Area 1 will provide initial volumes of approximately 50 million cubic feet of natural gas per day (MMcf/d) per train (100 MMcf/d) for domestic use in Mozambique. The natural gas will be provided at pricing that is fair to all parties and supports local natural gas development, and the concessionaires are prepared to sell up to 300 MMcf/d of additional volumes into the domestic market in future years as projects are matured and commercial terms agreed.

"Signing this MOU is an important step," added Ingram. "We look forward to continuing to work with the Government of Mozambique to finalize the legal and contractual framework that will enable us to deliver natural gas for domestic projects and LNG cargoes for export to premium markets around the world, both of which will benefit Mozambique through a reliable source of cleaner energy and significant revenue generation."

OFFSHORE AREA 1

Anadarko is the operator of the Offshore Area 1 Block with a 26.5-percent working interest. Co-venturers include the National Oil Company Empresa Nacional de Hidrocarbonetos, E.P. (ENH) (15 percent), Mitsui E&P Mozambique Area 1 Limited (20 percent), Beas Rovuma Energy Mozambique Limited (10 percent), BPRL Ventures Mozambique B.V. (10 percent), ONGC Videsh Limited (10 percent), and PTTEP Mozambique Area 1 Limited (8.5 percent).

OFFSHORE AREA 4

Eni operates Area 4 with a 50-percent indirect interest owned through Eni East Africa (EEA), which holds 70 percent of Area 4. The other partners are Galp Rovuma (10 percent), KOGAS Mozambique (10 percent) and ENH (10 percent). CNODC owns a 20-percent indirect participation in Area 4 through Eni East Africa.

Pipeline development projects are becoming increasingly complex, spanning longer and deeper terrains. Pipelines must operate at higher pressures and temperatures, in harsher environments and to stricter regulatory requirements. Projects must also be feasible in a cost-constrained market. DNV GL is inviting industry players to take part in two Joint Industry Projects (JIP) to help the industry work more efficiently while maintaining safety.

The first JIP will reduce uncertainty in tensile testing results and the associated costs of inaccuracies and delays, while the second will help operators save time and money in adapting to new industry requirements.

Gaining confidence in tensile testing results


Inaccurate yield strength measurements can have significant negative implications for a pipeline project, ranging from schedule disruptions and commercial disputes to unanticipated costs and potential regulatory challenges. Current industry standards allow a wide range of tensile testing parameters, creating variability and uncertainty in the test results.

The Standardization of Flattened-strap Tensile Testing of Line Pipe JIP will investigate different tensile testing variables that affect results, including material properties, sample flattening and preparation practices, testing equipment and testing procedures. The objective is to establish testing parameters and procedures to reduce the variability in yield strength results for large diameter line pipe. The results will be applicable to both onshore and offshore pipelines.

“The project will ensure that the tensile testing results are both more reproduceable and indicative of line pipe performance. It will reduce the uncertainty of the results and give pipeline operating companies the confidence they need when purchasing new line pipe as well as during the testing and analysis of existing pipe, ultimately saving time and cost,” says Melissa Gould, Senior Engineer, DNV GL - Oil & Gas.

The JIP will be carried out in conjunction with recognized parties such as the US National Institute of Standards and Technology (NIST) Material Measurement Laboratory (MML) and the former chair of the ASTM (American Society for Testing and Materials) Committee E28, Earl Ruth. The project is expected to last for 18 months and the results will be suitable for incorporation into standards and recommended practices, as applicable.

Standardized approach to meet new requirements for girth weld repairs


The offshore and onshore pipeline industry is adapting to the updated requirements for repair welding in the Twenty-First Edition of the well-known API Standard 1104, “Welding of Pipelines and Related Facilities”. The updates place more requirements on the qualification of repair welding procedures and welders.

The JIP on the Development of Industry Best Practice for Girth Weld Repairs will, in cooperation with pipeline engineering specialists Kiefner/Applus RTD, address the technical aspects of girth weld repairs and the practical aspects of repair welder qualification during the construction of new pipelines. The project is expected to be concluded within 18 months and will result in procedures and guidelines to help the industry meet the new API 1104 requirements.

“Repair welds are often made under more challenging conditions than production welds, which can potentially reduce the quality of the completed welds,” says Brad Etheridge, Senior Engineer, DNV GL – Oil & Gas. “The project fulfils an industry need to meet new requirements and has the potential to reduce cost and complexity, increase safety and reliability, and deliver better quality pipelines.”

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.”

Statoil has, on behalf of the Johan Sverdrup partners, awarded contracts for the linepipe , coating and pipe installation of the Johan Sverdrup export pipelines.

The total contract value is estimated at slightly less than NOK 2.5 billion, the three contracts cover both the oil and the gas export pipelines for Johan Sverdrup.

The linepipe fabrication contract for the export pipelines was awarded to Mitsui & Co. Norway A.S. Mitsui will deliver 220 000 tons of steel for the oil and gas pipelines, totaling 430 kilometers. Linepipe production will start at Nippon Steel & Sumitomo Metal (NSSMC) steelworks in Japan early in 2016.

Wasco Coatings Malaysia Sdn Bhd was awarded the contract for external anti-corrosion treatment and concrete weight coating for the oil and gas pipelines, as well as internal flow coating for the gas pipeline. The work will be performed at Wasco’s factory in Malaysia in 2017.

Saipem Ltd has been awarded the pipe-laying contract for the Johan Sverdrup oil and gas export pipelines. The pipe-laying operation is scheduled to start in the spring of 2018, using the laying vessel CastorOne.

“We have selected a solid team of principal suppliers for the Johan Sverdrup export pipelines, and are thus well positioned to deliver first oil from Johan Sverdrup from late 2019,” says Kjetel Digre, senior vice president for the Johan Sverdrup project.

Stabilized oil will be exported to the Mongstad terminal through a new oil pipeline connected to existing storage caverns. The oil export solution consists of a 274-kilometre, 36-inch pipeline to the Mongstad terminal, including required modifications at the terminal.

Gas will be exported to Kårstø gas terminal through a new gas pipeline. The gas export solution includes a 156-kilometre, 18-inch pipeline tied in to the Statpipe rich gas pipeline, including a hot-tap hook-up to this pipeline. No modifications are required at Kårstø for the reception of the Johan Sverdrup gas.

The oil and gas export development will meet the transportation needs for all phases of the Johan Sverdrup development.

Contracts worth more than NOK 50 billion have been awarded so far in the Johan Sverdrup project, about 75 percent of which have been landed by suppliers with Norwegian invoice addresses.

NorSea Group (UK) Ltd has won a five-year contract with Wild Well Control for the storage of its emergency response WellCONTAINED System at NorSea Group’s facilities in South Base, Montrose.

The WellCONTAINED system of services includes contingency planning and response from Source Control Emergency Response Planning (SCERP) through field deployment of the system capping a subsea uncontrolled well.

Mike Munro, Operations Director at NorSea Group (UK) said: “This type of hi-tech intervention equipment is designed to minimise exposure in the event of an offshore emergency and a top priority is the ability to respond without delay. Our storage and supply base operations at Montrose, with direct quayside access and geographical proximity meet all the requirements for optimising response time.”

Freddy Gebhardt, Wild Well (left) and Mike Munro, NorSea Group (UK Wild Well Control’s WellCONTAINED System

Freddy Gebhardt, Wild Well President, who visited Montrose to view the facilities, said Wild Well was very pleased to make a commitment to the region for the exclusive use of warehousing facilities for the WellCONTAINED system.

“Having immediate access quayside in the case of mobilization and deployment offers an all-encompassing logistics solution for our consortium members,” he said. “Providing 24/7/365 emergency response to ensure our clients get the timely service and support they need is a pre-requisite, and the set up at South Base guarantees that requirement will be met.

“We extend a warm welcome to our new partners in this arrangement— NorSea Group (UK) and the Montrose Port Authority— and look forward to a healthy working relationship between all parties for the term of the agreement.”

Nik Scott-Gray, Chief Executive of Montrose Port Authority (MPA), said: “We are delighted that NorSea Group and Wild Well have forged this new relationship, which broadens the marine and offshore services portfolio we can offer at Montrose Port. The port is strategically placed as a service and logistics hub for the offshore oil and gas sectors, and this new agreement helps advance our ongoing development and expansion plans. We look forward to working closely with NorSea Group and Wild Well over the coming years. ”

NorSea Group has a 15-year lease agreement with MPA on the South Base covering warehousing and 11,000m2 of external quayside laydown. Quayside support services include stevedores, forklifts, cranes, water and fuel. It also has additional internal and external storage at nearby Broomfield Industrial Estate in Montrose.

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.

McDermott International, Inc., (NYSE:MDR) announced it has been awarded a sizeable transport and installation contract by an upstream oil and gas operator for a project offshore Trinidad, West Indies.

The contract award includes the transport and installation of a 1,000-ton deck and 1,600-ton jacket. It also covers the onshore fabrication, reel-lay and pre-commissioning of 14,000 feet of 14-inch pipeline that includes the pull-in of a 12-inch riser at an existing offshore platform scheduled to be completed using McDermott vessels, Derrick Barge 50 (DB50) and the North Ocean 105 (NO105). Project completion is expected to be in the third quarter of 2016. The pipeline will be welded at McDermott’s new Gulfport, Mississippi, spoolbase.

“McDermott’s customer-focused approach, in combination with project execution expertise, best-in-class assets and alignment with the client on project objectives set us apart,” said Scott Munro, Vice President for Americas, Europe and Africa. “We’re pleased to be able to provide an integrated approach involving our new spoolbase in Gulfport, the NO105 and the DB50 that addresses all project drivers to deliver the best overall solution.”

Revenue from the award will be included in McDermott’s fourth quarter 2015 backlog.

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.

The Bureau of Safety and Environmental Enforcement (BSEE) has announced that offshore oil and gas lessees and owners of operating rights are now required to submit summaries of their actual expenditures for the decommissioning of wells, platforms and other facilities on the Outer Continental Shelf (OCS) as part of the final Decommissioning Costs Rule.

This information will help BSEE to better estimate future decommissioning costs related to OCS leases, rights-of-way, and rights of use and easement. The Bureau of Ocean Energy Management may use BSEE's future decommissioning costs estimates to set necessary financial assurance levels to minimize or eliminate the possibility that the government will incur decommissioning liability.

The Final Decommissioning Costs Rule will be published in the Federal Register Reading Room today and can be viewed by clicking here.

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.