New guidance approach supports industry in the safe and effective deployment of next generation drone and unmanned aircraft systems (UAS) technology that can significantly improve productivity gains through reducing risk exposure, survey times and in-service inspection costs of offshore, marine and onshore infrastructure.

Lloyd’s Register’s first phase of its guidance notes for drones and Unmanned Aircraft Systems (UAS) is launched today, giving operators in the energy and marine industries confidence in using UAS for offshore, marine and onshore surveys and in-service inspections.

“We are developing these guidance notes to provide a consistent approach to risk in UAS and drone deployment, offering practical operational considerations relating to regulations, personnel, quality, safety, hardware, software and operations,” says Lloyd’s Register’s Chief Technology Officer, Nial McCollam.

McCollam highlights: “Technology and innovation in the area of digital data, sensing technologies, unmanned systems and robotics are here to stay. We see an exciting and important journey ahead, and anticipate our efforts to increase and continue.”

UAS, commonly known as drones, provide an effective alternative to traditional methods of in-service operational assessment and survey, especially structures and assets at significant heights, difficult to access locations and hazardous environments.

Major operators such as Shell and Maersk Drilling are among early adopters of innovative technology with safety and quality as a priority.

“Shell views human and environmental safety as paramount in all of its operations. The use of robotic technology for inspection purposes reduces the need for personnel working in enclosed spaces and at heights. Minimizing risk across the industry by utilizing cutting edge technology in this way is of great importance to Shell,” says Adri Postema, General Manager of Shell Shipping and Maritime, Technology.

To unlock this potential, collaboration among industry partners throughout the value chain will be critical. In collaboration with Lloyd’s Register, Maersk Drilling and partners have conducted a number of pilots to assess UAS capabilities for inspection at heights and difficult areas.

“We can see the technology has many potential applications, and it has triggered ideas on new applications. One area we want to focus on is the safety aspect of this new technology, and how we integrate it with existing safety processes, and ensure we use it to enhance safety, and to limit the introduction of new risks. It only takes one or two accidents or near miss reports to set a bad record for robotics and unmanned systems in the industry, so the guidance notes will help the industry take into consideration important considerations,” says Jan Holm, Managing Director of Maersk Drilling Singapore.

The guidance notes from Lloyd’s Register will be updated regularly to provide industry with the latest practical information on issues such as how best to use UAS for inspection in confined spaces which is particularly relevant in energy and marine applications where Class surveys are needed, and which also improves safety for human life.

“In the past, small commercial UAS technology can be traced back to remote-controlled hobby aircraft, requiring significant skills to operate. However, rapid advancements in hardware and software including air stabilization, pre-flight planning tools, obstacle detection and avoidance technology have transformed these small aircraft into viable business tools that is likened to high-definition eyes in the sky,” says Chris Chung, Head of Strategic Research at Lloyd’s Register.

UAS are piloted remotely or autonomously, which reduces the need to send personnel into high-risk and challenging environments. This provides a real opportunity to decrease the number of falls and fatalities that occur due to traditional methods of working at heights, as reported by the US Bureau of Labor, Safe-Work Australia and the UK’s Health and Safety Executive.

Unlocking further potential


In March 2016, the Lloyd’s Register Foundation convened an international panel of industry and academic experts for a two day workshop on Robotics and Autonomous Systems (RAS) to identify current state of the art and the white space where the Foundation can add significant impact and contribution in line with its charitable objectives. The review will be published as part of the Foundation’s Foresight Review series of reports later this year. The Foundation is expecting to make a significant grant investment in RAS to deliver the findings from the report.

”We have been looking into robotics and unmanned systems for years, not just on the technology but also on design codes, policies and guidelines on safe and sustainable deployment. We see UAS as part of the unmanned systems and robotics story, which also includes underwater and ground-based systems,” highlights Chung.

“In addition to tried and tested applications such as safely inspecting assets of flare stacks and other outdoor critical infrastructure, we are collaborating with industry to enable inspection of the undersides of offshore structures maritime vessels and confined spaces such as storage tanks,” says Chung. “With increasing capabilities, we believe UAS will in the future have the ability to autonomously follow a pre-defined flight path, enabling higher measurement accuracy and repetition of collecting more relevant data and operational defects while inspecting and data-gathering in real-time.”

UAS also has a fundamental part to play in emergency response and improving situational awareness.

“A major challenge in any emergency situation is the lack of timely and accurate information on which to base informed decisions. In such instances, UAS can be used to gather data without sending in personnel, or at least limiting their risk exposure,” says Chung.

You can find out more about our UAS work with industry here.

Shell and its joint venture announce the start of oil production from the third phase of the deep-water Parque das Conchas (BC-10) development in Brazil's Campos Basin. Production for this final phase of the project is expected to add up to 20,000 barrels of oil equivalent per day (boe/d) at peak production, from fields that have already produced more than 100-million barrels since 2009.

Espitito Santo. Image courtesy: Shell

"The safe, early delivery of this production is a testament to the efficiency of our deep-water project execution," said Wael Sawan, Executive Vice-President, Deep Water, Shell. "With this phased project, we have again demonstrated value from standardization, synergies from contractual relationships, and the strategic deployment of new technologies. These barrels, like other subsea tieback opportunities across our deep-water portfolio, have development cost advantages and will contribute to the strong production growth we expect from offshore Brazil."

Shell is a global leader in deep water with a strong development pipeline following last month's completion of the BG combination, across offshore Brazil, the U.S. Gulf of Mexico, Nigeria, and Malaysia.

Operated by Shell (50%) and owned together with ONGC (27%) and QPI (23%), Parque das Conchas Phase 3 comprises five producing wells in two Campos Basin fields (Massa and O-South) and two water-injection wells. The subsea wells sit in water depths greater than 5,900-feet (1,800-meters) and connect to a floating production, storage and offloading (FPSO) vessel, the Espirito Santo, located more than 90-miles (150-kilometers) offshore Brazil.

Parque das Conchas Phase 3 is the latest, major deep-water project for Shell. Shell deep-water sanctioned projects currently in development include, the Stones project, whose FPSO vessel is now on location in the Gulf of Mexico, and the Appomattox project, also a Gulf of Mexico project, now under construction. Shell is also part of a consortium exploring and developing the giant, pre-salt Libra field, offshore Brazil, and recently completed the acquisition of BG, which includes significant deep-water Brazil positions.

Sparrows Group has partnered with leading engineering and manufacturing firm INNOVO to provide the offshore industry with the first fully electric-drive flexible cable and pipe lay system for rental.

The wider collaboration between the firms will see them deliver full back-deck equipment packages for sale and rental to suit both the oil and gas and offshore wind markets globally.

As part of the agreement INNOVO’s electric drive 700 Te multi-reel drive system will be rented alongside Sparrows Group’s wide range of electric drive tensioners as a fully packaged and managed lay system.

Stewart Mitchell, chief executive officer at Sparrows Group, said: “Combining an electric tensioner with an electric reel drive means we can offer the market a uniquely sophisticated system that delivers greater control and therefore better precision and accuracy than traditional hydraulic drive appliances which can dramatically reduce the risk of damage to the product. Both pieces of equipment are fitted with the same control systems, allowing easy system synchronization which also improves the control of lay operations.

“Compact in size considering its high capacity, INNOVO’s real drive is one of the most robust systems on the rental market which can be used with multiple reels if required. Combined with our 50 Te tensioner that works in both horizontal and vertical configurations, the system offers customers a high degree of versatility.

“Over the past 12 months, we have seen a rise in demand for packaged rental solutions as companies try to maximize efficiencies and reduce capex costs. The agreement with INNOVO will see us offer engineering services for the mobilization, installation and commissioning of any lay system as well as new build design and supply.”

Stefano Malagodi, managing director of INNOVO, said: “In partnering with the market leader in tensioners we are bringing together a wealth of experience and in-depth knowledge of specialist back deck equipment. The full lay system package is easily delivered anywhere in the world and with our 700 Te reel drive system on its way to Aberdeen just now it will soon be available for immediate mobilization in the North Sea.

“Together we will be providing engineering and technical support before and during operations through our qualified offshore technicians. By combining our expertise we will have the capability to offer specialist engineering services such as OrcaFlex analysis, point load seafastening, according to DNV GL, Lloyd’s Register and ABS codes, stability calculations and ship stability reports which all help optimize efficiency and save costs.”

INNOVO is devoted to providing high value professional services and high technology equipment for the renewables, oil and gas and marine business sectors. They are a member of DNV GL’s joint industrial panel for offshore equipment used for the laying and recovery of pipes and cables.

Established originally in 1946, the Sparrows Group moved into the oil and gas market in 1975 and has more than 40 years’ experience working offshore. The company provides engineered products and services, primarily to the offshore sector, specializing in lifting and handling, cable and pipe lay, and fluid power solutions.

2H Offshore, an Acteon company, has designed and launched a new Engineering Critical Assessment (ECA) software: FlawIQ. FlawIQ is a comprehensive tool that automates both BS7910 and API 579 procedures, making it faster and simpler to perform accurate fatigue assessments for offshore components.

FlawIQ is the only commercially available tool that incorporates both BS7910 and API 579 standards; eliminating the need for multiple software tools; saving operators both time and money.

Key benefits of FlawIQ include the ability for the user to automate flaw ranges, and to run multiple cases without manual intervention. The program is highly customisable, making it simple to incorporate new solutions and to increase the accuracy for special situations such as HPHT applications. The tool is web-based and features an easy to use online help facility, and access to 2H Offshore’s expert team of ECA engineers for technical support and training.

The software has many applications within the oil and gas, nuclear and construction industries, with various types of structures including pipelines, pressure vessels and piping, tanks and buildings, in both design and in-service phases.

Mike Campbell, vice president, 2H Offshore, said, “2H Offshore developed this software to provide our customers with an easier, more streamlined way to perform fracture mechanics. The current programs available on the market are useful, but fail to incorporate both BS7910 and API 579 standards. The incorporation of these standards is becoming increasingly important to our clients. With FlawIQ, everything is housed within one program, no matter which industry standard is required.”

Operators are seizing the opportunity to keep offshore structures in the region operating beyond the end of original design life

The Middle East faces a substantial challenge to keep hundreds of ageing offshore oil and gas structures operating safely and legally beyond original design life. “There are at least 700 to 800 fixed platforms and bridges in the region,” said Anupam Ghosal, regional manager for Middle East and India, DNV GL - Oil & Gas. “More than 70% are older than 25 years; some exceed 40 years. United Arab Emirates (UAE) alone has about 450.”

Life extension of ageing structures ensures continued operation within regulatory requirements, and helps to limit future operational expenditure (opex). “Constraining opex is vital to economically viable but safe operations,” he added. Operators in the Middle East are at different stages of implementing controlled approaches to asset integrity management (AIM) and structural integrity management (SIM) systems. Ghosal observed: “Several are in the planning stage. DNV GL is engaged in the process with quite a few customers in the region.”

Operators are seizing the opportunity to keep offshore structures in the region operating beyond the end of original design life. Photo: ADMA-OPCO

The Abu Dhabi Marine Operating Company (ADMA-OPCO), a major producer of oil and gas from offshore Abu Dhabi, is in the vanguard of Middle East operators addressing life extension opportunities; some of its earliest structures are more than 50 years old. “We have an extensive fleet of structures undergoing continuous brownfield project developments to ensure sustainable oil production over the extended field-life,” explained Dr. Tarek Omar, civil/structural engineering team leader, ADMA-OPCO. “Of these assets, 70% have already reached design life, and ADMA has taken a strategic decision to lead in the area of managing their integrity.”

Case study: ADMA-OPCO

ADMA-OPCO has developed a comprehensive structural management system (SMS) framework based on a fully quantitative approach. All changes are monitored and managed through an in-house developed management of change (MOC) system for structures which meets all the company’s requirements. ADMA's SMS uses a fleet management system (FMS) to manage the quantification and risk ranking of its fleet.

Continuous improvement is important, Ghosal agreed: “Technological advances provide opportunities to produce more hydrocarbons economically from existing structures. Low oil prices create the need to extract best value from current facilities. Other drivers include improved data on reservoirs, heightened regulation, updated design standards and knowledge, advances in risk management, and enhanced focus on safe operations.”

ADMA-OPCO plans to further increase effectiveness of SIM by: mandating use of the management of change system company-wide; continuously updating structural assessment methods; and continuous interaction and joint innovation with industry partners.

Greater activity around asset and structural integrity will generate substantial know-how for the Middle East and elsewhere. ADMA-OPCO’s structures, for example, are forecast to be among the industry’s longest lasting, Omar said. The company is actively taking key initiatives in joint industry R&D projects, and in adopting international standards for structural management. One key learning from ADMA-OPCO’s SMS is the importance of an effective MOC process and sophisticated inspection in capturing the risks, Omar said. “This earned continuous support from company management to make it a company-wide culture.”

One solution does not fit all

Another lesson is that one-size does not fit all when developing an SMS, he added. “Each company and region has its own special requirements and a structural management system needs to cater for these.” Ghosal commented: “Operators here face challenges encountered elsewhere in the world, but also ones that are specific to, or more pronounced, in this region, such as sour gas. DNV GL has had a presence here for more than 30 years and understands local needs.”

DNV GL’s software, database, quantitative and qualitative approaches, and other expertise in capturing, analyzing and managing information for SIM assists customers to scope, design and implement life extension strategies. The company’s ‘missing data methodology’ addresses the absence of historic documentation, a common challenge for operators in the region.

Key structural integrity goals

Engineering experts at oil and gas companies operating in the Middle East see ageing effects in grouted piles as one of the top structural integrity management (SIM) challenges. This emerged from interviews by DNV GL, and in a survey at its annual Ageing Structures Day in September 2015.

Some operators also expressed a desire to see regional acceptance criteria formulated for SIM of existing fixed structures, but with operators having flexibility to respond to local circumstances.

For offshore Abu Dhabi, they wanted to know: how lateral pile capacity might be enhanced in carbonaceous rocks; more about the seismic vulnerability of platforms; and, how a spectrum of site-specific responses might be formulated.

Others were interested in the implementation of online health-monitoring. Respondents saw a need for engineering studies to verify requirements for replacement of degraded appurtenances such as riser- and conductor-protectors.

Region-specific guidance on the below elements is useful when developing life extension strategies for ageing offshore structures.

1 Wave spectra suitable for benign sea conditions in the Arabian Gulf to predict fatigue reliability and to assess the remaining fatigue life of structures.

2 Corrosion mitigation strategies for structures and critical appurtenances to optimize the operating expenditure of ageing offshore structures.

New technology to acquire missing data on actual pile penetration depth and ageing grout strength to assure drilled and grouted foundation integrity.

Eni has started production of the Goliat field, located 85 kilometers northwest of Hammerfest, within Production License 229, in a ice-free area in the Barents Sea off Norway.

Goliat, the first oil field to start production in the Barents Sea, was developed through the largest and most sophisticated floating cylindrical production and storage vessel (FPSO) in the world. The Unit has a capacity of 1 million barrels of oil and was built with the most advanced technologies in order to tackle the technical and environmental challenges linked to operations in the Arctic’s context.

The daily output will reach 100,000 barrels of oil per day (65,000 boed net to Eni). The field is estimated to contain reserves amounting to about 180 million barrels of oil.

The Goliat field is located in production license 229 (PL229) which was awarded in the “Barents Sea Round” in 1997. The licensing round was initiated by the authorities in order to promote interest in the Barents Sea as an oil and gas region. The discovery was made with the first exploration well in 2000. Image courtesy: Eni Norge

Production will take place through a subsea system consisting of 22 wells (of which 17 are already completed), and of which 12 are oil producers, 7 water injectors and 3 gas injectors. Goliat, also, adopts the most advanced technological solutions in order to minimize the impact on the environment. Goliat receives power from shore by means of a subsea power cables, hence, reducing CO₂ emissions by 50% compared to alternative solutions, while water and gas products are re-injected into the reservoir.

Goliat’s start-up is an important milestone for Eni’s growth strategy and will significantly contribute to the cash flow generation.

In the Production License 229, Eni holds a 65% stake (operator), while Norway's Statoil holds the remaining 35%.

Eni has been present in Norway since 1965, where it operates through its subsidiary Eni Norge AS. In the country, the company has interests in exploration licenses and production fields, including Ekofisk, Åsgard, Heidrun and Kristin with a total equity production in 2015 of 106 thousand barrels of oil equivalent per day.

OneSubsea^®, a Cameron (NYSE: CAM) and Schlumberger (NYSE: SLB) company, has been awarded a contract from BP Exploration (Delta) Ltd., and partner DEA (Deutsche Erdoel AG), to supply subsea production systems for the West Nile Delta Giza/Fayoum and Raven fields, situated offshore Egypt.

Giza/Fayoum will be tied-back to modified onshore Rosetta facilities and integrated with a new onshore plant for Raven. The scope of supply for the long-distance gas fields includes large-bore subsea trees, manifold systems incorporating high-integrity pressure protection systems (HIPPS) for the high-pressure Raven field, connection systems, and controls systems, along with project engineering, management and testing. The booking was recognized in the fourth-quarter of 2015.

“BP continues to be successful in driving its standardization philosophy, and this is the third award to OneSubsea that will utilize the jointly-developed large-bore tree already being deployed to other BP projects,” said Mike Garding, Chief Executive Officer of OneSubsea. “OneSubsea continues to support BP in its West Nile Delta development goals, and we are proud to be a part of its long and successful track record in Egypt.”

Statoil has, on behalf of the Troll license, decided to use its contractual right to terminate the contract with COSL Offshore Management AS for the chartering of the mobile rig COSLInnovator.

COSL Innovator

“The conditions for terminating the contract signed with COSL Offshore Management AS have in our opinion been met, and we therefore choose to use our contractual right to terminate the contract,” says Geir Tungesvik, Statoil’s senior vice president for drilling and well.

In addition Statoil has decided to stop drilling operation with the sister rig COSLPromoter when it is safe to discontinue well operations. This is done in order to enable COSL to implement the necessary actions in order to fulfill the requirements of the contract.

The decision may have some short-term consequences for planned drilling activities, but will not have impacts on long-term production on the Troll field. The plans made by the license for gas and fluid production from the oil zone remain firm.

INDUSTRY CAUGHT IN CATCH 22, SAYS DNV GL

Only one in five oil and gas companies see themselves as highly digitalized today. However, close to half of senior oil & gas professionals1 (45%) already see solid or high potential for big data and analytics to transform the operating efficiency of the industry in 2016, according to research by DNV GL, the leading technical advisor to the oil and gas industry.

The research among over 900 senior oil and professionals reveals that despite it’s potential, only 36% plan significant or moderate investment in big data and analytics in 2016.The IT related technology expected to by most respondents to have significant or high investment is cyber security attack / prevention (44%), followed by automation / remote operation (43%).

“Early adopters are emerging, but many in the industry are still at early stages of maturity in data analytics and data-based decision making. The industry is in something of a ‘Catch 22’ situation; close to half of seniors in our industry see solid or high potential for big data and analytics to transform the industry’s operating efficiency in 2016. However, investment seems to be lagging just when we need it most. Our in-depth interviews point to cost constraints and uncertainty about the cost-saving potential of digital technologies as the key reasons,” says Nada Ahmed, Senior Engineer at DNV GL – Oil & Gas.

“As for other areas of innovation, collaboration could prove essential to bridge this digital gap and ensure experience transfer in the conservation of data, efficiency drivers and ways to ultimately leverage the opportunities big data represent for the industry,” adds Ahmed.

DNV GL has identified key opportunities to reduce costs by optimizing day-to-day operations2:

Condition monitoring for more effective maintenance and inspection regimes, dictated by specific, industry, historical and real-time data. Replacing planned maintenance with preventive maintenance, driven by early warnings from sensor data, can significantly reduce downtime.

Instant information from wells can provide timely decisions on underperforming wells and other potential issues that, if not dealt with, could lead to enormous costs.

Detecting anomalies while drilling and during operation can also lead to more effective decisions for cost savings.

Elisabeth Tørstad, CEO of DNV GL – Oil & Gas, says: “Our customers say that a number of challenges need to be addressed to capitalize on the opportunities within Big Data; robust strategies to capture, manage and utilize critical data, access to reliable, trustworthy data, and stringent security to minimize security breaches. We are working with the industry to help it manage the risks and leverage the opportunities associated with digitalization.

“Cyber-attacks on in the oil and gas industry have grown in stature and sophistication in recent years, making them more difficult to detect and defend against, and costing companies increasing sums of money to recover from,” adds Tørstad.

XACT Downhole Telemetry Inc., with offices in Houston and Calgary, ended a landmark year that included six deepwater Gulf of Mexico deployments, delivering an industry first, by providing real-time downhole data during a deepwater completion installation with BP.

BP successfully accessed real-time downhole data throughout the well’s completion, using XACT’s acoustic telemetry network, which was seamlessly integrated into the operation.

Six downhole measurement nodes from XACT spanned the 22,700-foot well, enabling BP to monitor critical parameters including downhole weight on the crossover tool, and pressures and temperatures during the well’s completion.

“XACT is thankful to BP for once again giving our team the opportunity to demonstrate the value of our Network,” said Jason Roe, President and CEO of XACT. “The success of this application illustrates the ability of the XACT Acoustic Telemetry Network to provide critical downhole parameters during complex operations.”

XACT has worked with BP’s Upstream Technology group to further develop and deploy the acoustic telemetry network. BP has provided investment funding to XACT through BP Ventures.

“BP partners with XACT to help develop technology that enhances well construction and completions,” said Issam Dairanieh, managing director at BP Ventures. “We view this as a promising digital technology and are pleased to support its deployment and wider industry acceptance.”

XACT achieved multiple industry and application firsts in 2015, including: transmitting real-time data; during a liner installation, cementing operations and while tripping. XACT delivered these operations in the Gulf of Mexico with major operators and demonstrated the value of real-time applied acoustics to enable decisions for lower cost wells.

Horizon Geosciences has announced the introduction of Cathodic Protection (CP) Surveys to its list of Survey services as demand for maintaining existing subsea assets rises in the oil and gas sector. CP Surveys are used to assess and control the integrity of metal subsea assets as environmental and time related factors can cause corrosion of important offshore and nearshore infrastructure and components.

A full package of services is being offered to Horizon’s clients, from data acquisition to processing and reporting with CP Survey options including ROV and Trailing Wire (proximity and contact). Horizon also confirmed they use a new, cutting edge CP system considered to be one of the smallest in the world.

Horizon Geosciences Project Manager Sean Lowe commented;

“The CP System we use is very compact and robust. Due to its size, the CP can be deployed in smaller ROV models. It’s compatible with any ROV and industrial communication protocols (RS485 and RS232). It produces very low noise data, highly accurate results and can be mobilized in less than an hour with no surface equipment required.”

Horizon recently completed its first CP Pipeline Survey for Halul Offshore Services nearshore, Qatar. The Trailing Wire method was used, whereby teams of engineers made hard wire connections at test points along a beach, these ran to the water line where the trailing wire was connected. The Survey vessel ran 6 X 3KM survey lines individually towing a dummy fish with a AG/AGcl cell attached. Both the cell and Trailing Wire were connected to online data acquisition software to record the data, against the provided navigation. The results were then processed and presented to the client in a comprehensive report.

Horizon Geosciences Project Manager, Sean Lowe concluded;

“Corrosion is an electrochemical process that occurs in stages and if left untreated, subsea infrastructure can become hazardous and restoration costly. Horizon’s CP Survey services enable clients to assess important subsea assets and make informed maintenance decision.”

Dedicated to quality marine science, Horizon Geosciences is a leading provider of marine survey and geotechnical services to the offshore industry. Working across sectors including oil & gas, renewables, civil, subsea and offshore construction, Horizon can support every stage of offshore and nearshore projects across continents. With offices in the UAE, India and the UK Horizon’s fleet of offshore vessels are primarily dedicated to the North Sea and Atlantic region plus the Middle East and Indian Ocean.

Quick facts about Horizon’s assets & history:

On Tuesday, March 1^st, the Deepsea Atlantic drilling rig commenced on the first of a total of 35 wells to be drilled in the first phase of the Johan Sverdrup field development.

“The Deepsea Atlantic drilling rig is currently predrilling the first production well for the first phase of the Johan Sverdrup development. This is a central operation in a complex Johan Sverdrup puzzle. Predrilling allows the production capacity on the field to be utilized as efficiently as possible when Johan Sverdrup has come on stream late in 2019. This way, we maximize value from the field from day one,” says Kjetel Digre, senior vice president for the Johan Sverdrup project.

The exploration rig Deepsea Atlantic. (Credit: Statoil. Photo: Marit Hommedal)

The rig is drilling the first production well through a predrilling template that was installed on the field in the summer of 2015. A total of eight wells will be drilled through the predrilling template, before the rig is relocating to drill injection wells on three locations on the field.

In 2018 the permanent Johan Sverdrup drilling platform will be installed as the second of four platforms. The drilling platform is currently being constructed at Aibel’s yard in Haugesund, north of Stavanger, and in Thailand. When the drilling platform is installed and operational, the eight predrilled wells will be hooked up from the predrilling template. At this point Deepsea Atlantic will be drilling the injection wells providing reservoir pressure support to maintain high field production.

The operator Statoil, the rig owner Odfjell Drilling and the drilling service provider Baker Hughes have cooperated closely to ensure safe and cost-effective deliveries. The Johan Sverdrup project introduces integrated drilling services as a new concept, which means that Baker Hughes will provide the main deliveries together with Odfjell Drilling.

“Statoil and the drilling service providers have worked as an integrated team in planning the drilling operation. Deepsea Atlantic is a good rig and everything is set for a safe and cost-effective drilling operation on Johan Sverdrup. This is vital to ensure production start from the field at the end of 2019,” says Digre.

The contract for integrated drilling services worth NOK 1.5 billion was awarded to Baker Hughes on 6 July 2015.

The contract for rig and drilling services on Johan Sverdrup, totalling more than NOK 4.35 billion, was awarded to Odfjell Drilling on 15 June 2015.

Contracts worth more than NOK 50 billion have been awarded by the Johan Sverdrup project. More than 70% of them have been awarded to suppliers with a Norwegian billing address.

Facts about Johan Sverdrup

Johan Sverdrup is one of the five biggest oil fields on the Norwegian continental shelf.

With expected resources of between 1.7 – 3.0 billion barrels of oil equivalent, it will also be one of the most important industrial projects in Norway over the next 50 years.

Peak production on Johan Sverdrup will be equivalent to 25% of all Norwegian petroleum production.

First-phase investments estimated int the plan of development and production (PDO) at NOK 117 billion (2015 value)

Daily production during first phase estimated at 315,000 – 380,000 barrels per day

Peak production estimated to reach 550,000 – 650,000 barrels daily

Partners:

Secretary of the Interior Sally Jewell and Bureau of Ocean Energy Management (BOEM) Director Abigail Ross Hopper announced on Tuesday, March 15, the proposal for the nation's Outer Continental Shelf (OCS) Oil and Gas Leasing Program for 2017-2022.

After receiving extensive public input and analyzing the best available scientific data, the Proposed Program released evaluates 13 potential lease sales in six planning areas – 10 potential sales in the Gulf of Mexico and three potential sales off the coast of Alaska. The Proposed Program does not schedule any lease sales in the Mid- and South Atlantic Program Area due to current market dynamics, strong local opposition and conflicts with competing commercial and military ocean uses.

Image credit. BOEM

“This is a balanced proposal that protects sensitive resources and supports safe and responsible development of the nation’s domestic energy resources to create jobs and reduce our dependence on foreign oil,” said Secretary Jewell. “The proposal focuses potential lease sales in areas with the highest resource potential, greatest industry interest, and established infrastructure. At the same time, the proposal removes other areas from consideration for leasing, and seeks input on measures to further reduce potential impacts to the environment, coastal communities, and competing ocean and coastal uses, such as subsistence activities by Alaska Natives.”

Release of the Proposed Program follows the publication of the Draft Proposed Program (DPP) in January 2015 and is one of several steps in a multi-year process to develop a final offshore leasing program for 2017-2022. Before the program is finalized and before any lease sales occur, the Department will consider another round of public input on the proposal and its accompanying Draft Programmatic Environmental Impact Statement (EIS). Today's proposal was informed by more than one million comments, 23 public meetings and extensive outreach with members of the public, non-profit organizations, industry, elected officials and other interested parties across the country.

“Public input is paramount to our planning process, and the proposal benefits from extensive stakeholder engagement,” said Director Hopper. “We will seek additional input from citizens, industry, other Federal and state agencies and elected officials as we develop the proposed final program.”

The OCS Lands Act requires the Secretary of the Interior to prepare a Five-Year Program that includes a schedule of potential oil and gas lease sales and indicates the size, timing and location of proposed leasing determined to best meet national energy needs, while addressing a range of economic, environmental and social considerations.

BOEM currently manages approximately 5,000 active OCS leases, covering more than 26 million acres – the vast majority in the Gulf of Mexico. In 2015, OCS oil and gas leases accounted for about 16 percent of domestic oil production and five percent of domestic natural gas production. This production generates billions of dollars in revenue for state and local governments and the U.S. taxpayer, while supporting hundreds of thousands of jobs.

A REGIONALLY TAILORED APPROACH

The Proposed Program continues a tailored leasing strategy set forth in the current 2012-2017 Program that takes into account regional differences and information from each planning area.

Gulf of Mexico:

The Proposed Program includes 10 sales in the Gulf of Mexico - one of the most productive basins in the world - where resource potential and industry interest are high, and oil and gas infrastructure is well established. The proposal continues a new approach to lease sales by proposing two annual lease sales that include all of the Western, Central, and the portion of the Eastern Gulf of Mexico not subject to the current Congressional moratorium. To provide greater flexibility for investment in the Gulf, this shifts from the traditional approach of one sale in the Western Gulf and a separate sale in the Central Gulf each year.

Alaska:

The Proposed Program evaluates one potential sale each in the Chukchi Sea, Beaufort Sea, and Cook Inlet planning areas, while taking comment on other options, including an alternative that includes no new leasing, as well as other measures to protect natural resources and reduce conflicts with other ocean uses, such as subsistence activities.

During the public meetings to scope the Environmental Impact Statement, several North Slope communities noted additional areas that may not be appropriate for oil and gas leasing. Using significant input and traditional knowledge from these communities, as well as other public comments and the best available science, BOEM has identified several areas where there is potential conflict between oil and gas activities and important ecological resources and subsistence activities. These areas are labeled “environmentally important areas” in the EIS and are analyzed therein. BOEM is seeking additional public input, particularly from Alaskan communities, regarding the resources and activities in those areas.

Additionally, in a Joint Statement with Canada’s Prime Minister Trudeau last week, President Obama announced principles for Arctic leadership, including a commitment to ensure that any commercial activities in the Arctic will occur only when the highest safety and environmental standards are met, including national and global climate and environmental goals, and Indigenous rights and agreements. As BOEM moves forward with offshore oil and gas planning, the agency will work with Canada to meet the world-class standard for Arctic stewardship set by the two nations.

“We know the Arctic is a unique place of critical importance to many – including Alaska Natives who rely on the ocean for subsistence,” added Jewell. “As we put together the final proposal, we want to hear from the public to help determine whether these areas are appropriate for future leasing and how we can protect environmental, cultural and subsistence resources.”

President Obama in January 2015 designated portions of the Beaufort and Chukchi Seas off limits from consideration for future oil and gas leasing in order to protect areas of critical importance to subsistence use by Alaska Natives, as well as for their unique and sensitive environmental resources. In December 2014, President Obama similarly placed the waters of Bristol Bay off limits to oil and gas development, protecting an area known for its world-class fisheries and stunning beauty.

Atlantic:

After an extensive public input process, the sale that was proposed in the Draft Proposed Program in the Mid- and South Atlantic area has been removed from the program. Many factors were considered in the decision to remove this sale from the 2017-2022 program including: significant potential conflicts with other ocean uses such as the Department of Defense and commercial interests; current market dynamics; limited infrastructure; and opposition from many coastal communities.

“We heard from many corners that now is not the time to offer oil and gas leasing off the Atlantic coast,” added Jewell. “When you factor in conflicts with national defense, economic activities such as fishing and tourism, and opposition from many local communities, it simply doesn’t make sense to move forward with any lease sales in the coming five years.”

Pacific:

Areas off the Pacific coast are not included in this proposal, consistent with the Draft Proposed Program and the long-standing position of the Pacific coast states in opposition to oil and gas development off their coast.

NEXT STEPS

In conjunction with the announcement of the Proposed Program, the Department is also publishing a Draft Programmatic Environmental Impact Statement (EIS), in accordance with the National Environmental Policy Act.

The Proposed Program and Draft Programmatic EIS will be available for public comment following the publication of the documents in the Federal Register. BOEM will hold public scoping meetings for areas included in the Proposed Program and will accept comments for 90 days on the Proposed Program and for 45 days on the Draft Programmatic EIS.

Following this opportunity for public comment and environmental review, the Department will prepare a Final Programmatic EIS with the Proposed Final Program (PFP).

For more information, including maps, click here.

Harkand has been awarded a multi-million pound contract with Maersk Oil North Sea UK Ltd to deliver subsea support services to the operator including a commissioning support campaign for the Flyndre development located in the south-eastern part of the Central Graben Basin in the North Sea.

The Aberdeen office of the global inspection, repair and maintenance (IRM) company will oversee the mobilization of its sister dive support vessels the Harkand Atlantis and Harkand Da Vinci. The Flyndre campaign will see personnel carrying out choke valve replacement work as well as delivering umbilical tie-in operations.

David Kerr, Managing Director

David Kerr, managing director for Harkand Europe said: “We have a well-established relationship with Maersk Oil having delivered successful diving scopes for the company last year including decommissioning work at the Leadon field and also completing their subsea inspection campaign in 2013.

“We look forward to working once again with Maersk and delivering their scopes to the high standards they expect from Harkand.”

A joint industry project (JIP) to standardize subsea processing systems has been kickstarted by DNV GL with industry partners Petrobras, Shell, Statoil and Woodside. Subsea development projects have been under substantial pressure due to cost inflation and the low oil price, prompting a need to simplify the industry’s approach. DNV GL is seeking additional collaborators for the project to drive standardization, beginning with subsea pumping, to ensure benefits throughout the subsea supply chain.

Subsea processing is a relatively young and undeveloped field of technology, requiring operators to tailor-make solutions to meet field-specific requirements. If that technology could be better understood and harnessed, there is considerable potential for it to deliver increased value at reduced costs.

Experience in the field has already grown significantly in recent years with subsea pumping developments from the JIP members (Petrobras, Shell, Statoil and Woodside) and other major operators.

Subsea closeup illustration screen version. Credit: DNV GL

The JIP ‘Subsea Processing – Standardization of Subsea Pumping’ seeks to deepen industry knowledge and encourage progress in this area by examining the potential for standardization in subsea processing, beginning with subsea pumping. Standardization still allows for flexibility to custom-make facilities at a system level through standard functional descriptions and specifications. However, it also increases predictability in the value chain, thus lowering transaction costs and improving the speed of implementation, while still allowing freedom to innovate and to employ new technology.

"One of the best ways to create value is by performing well in crisis situations. This JIP intends to contribute by taking the Subsea Processing and Boosting to a higher value level. Petrobras experience with VASPS, MARLIM, MOBO, and other subsea processing systems clearly demonstrates that simplicity, delivery time and competitiveness are mandatory for future applications. The standardization of parts and subsystems is one of the potential keys to achieve that. Common specifications will potentially increase the number of business cases for subsea systems and bring synergies to the surface," says André Lima Cordeiro, Executive Manager of Petrobras Research and Development Center.

“Subsea boosting systems provide the ability to increase recoverable reserves and further increase economic viability of a project by optimizing production. For complex systems such as subsea pumping to be successfully and more widely deployed, overall system costs need to be significantly reduced. Alignment of operators and system suppliers through this standardization initiative can make a significant contribution in achieving this cost reduction goal,” says Graham Henley, Vice President Projects – Upstream Operated and JV, Shell Projects & Technology.

“With today's low oil price, it is more important than ever to create cheaper, leaner and standardized subsea solutions. This challenge goes across the oil industry and collaboration is key. The industry needs to lower costs to enable more subsea developments and increase the use of subsea processing technology,” says Margareth Øvrum, Executive Vice President of Technology, Projects & Drilling at Statoil.

“The oil and gas industry needs to re-assess stand-alone host developments due to higher costs and look more closely at tie-back opportunities. Subsea processing technologies enable long distance tie-back opportunities for remote and marginal fields. Cost reduction through simplification and standardization is key to ensuring application of these technologies,” says Sean Salter, Vice President of Technology at Woodside.

Additional collaborators sought

DNV GL is currently calling for collaborators within the oil and gas supply industry to input into the JIP, to suggest additional areas which they believe could benefit from standardization and to input into the creation of this important new industry standard. The JIP will initially focus on subsea pumping in two phases: firstly, to establish a focus for the study by developing a functional description for subsea pumping and specific targets for possible standardization; and, secondly, to share industry knowledge and create best practice guidance through the creation of a recommended practice for industry-wide use.

The JIP participants will contribute their own standardization studies and initiatives previously performed as well as current and future portfolio requirements, ideas on minimal industry specification and methodology for maturing technology gaps.

“Taking the time to think long term, and consider the best way to drive progress and best practice in subsea processing, will also help us address pressing issues in the current downturn” says Kjell Eriksson, Regional Manager for Norway, DNV GL – Oil & Gas. “Industry collaboration, through JIPs such as these, drives efficiency at a collective level, raising the bar for all operators, sharing knowledge and experience, and creating trust and certainty by establishing new or consolidating existing standards and practices,” he adds.

Situated approximately 80 kilometres off the east coast of Trinidad and Tobago, this unmanned gas platform holds a special place in one major oil operator’s family. Since it went into production in 2009, it has become one of the largest net producers of natural gas in the operator’s global portfolio.

The platform’s average production is around 600 million standard cubic feet of gas per day (or 600 MBTU per day) in addition to associated condensate, from four wells at a depth of approximately 300 feet (90 metres). These figures make the platform a significant revenue generator for the Trinidad and Tobago operation.

The challenge: sand and the sea

As with any asset, maintaining integrity to ensure optimum output and meet regulatory requirements is a priority – which presents its own logistical problems in an offshore, unmanned platform.

Sand erosion is a particular challenge and one that the operator was conscious of from the outset. Traditionally difficult to detect and evaluate, the rate of erosion is rarely linear over time, and intensifies rapidly with an increase in flow rates. Sand can remove metal and cause damage very quickly. Operators must therefore walk a careful line between conservative production rates, which lower revenues, or driving the assets harder and increasing the risk of unplanned outages or even loss of hydrocarbon containment.

Permanently mounted acoustic sand detectors and alarms were deployed on the stainless steel topside risers of the platform. These sensors could detect the presence and quantity of produced sand, and therefore indirectly indicate the likelihood of erosion taking place. However, they provide little information about the shape, size and hardness of the sand particles however – all of which can significantly affect metal erosion rates.

Intrusive methods, that place a sacrificial probe inside the fluid stream and measure its demise as it corrodes or erodes, are also able to indirectly detect periods of high wear. However, since they are not measuring the pipework, they do not give the operator an understanding of the actual asset condition. Intrusive methods also come with additional hazards, getting the worn probe out from inside the pipe is a skilled and dangerous activity. Safety concerns around online probe replacement are causing many operators to reduce their use, or not replace them once they have expired.

The acoustic sand detectors and intrusive probes were not able to measure the actual impact of the produced sand – metal loss - on pipework integrity as it happened. Instead of continuous monitoring of asset piping integrity during production, maintenance operatives had to take periodic manual wall thickness measurements and make incomplete extrapolations on erosion rates using very minimal data sets. The reliance on manual measurements was made more expensive by the hard-to-access site: a dedicated crew of four was helicoptered in every three months to inspect the integrity of the topside risers and pipe work. In addition, the acoustic sand sensors had to be recalibrated on-site every six months.

The operator also ran computational models to understand the impact of given levels of sand production. But the shortage of actual integrity measurements meant that the production rates were being throttled back substantially to avoid sand erosion issues.

The solution: continuous wall thickness measurements

As one of the most advanced and technologically sophisticated platforms in the operator’s estate, they wanted to ensure that production was optimised to maximise revenue and increase payback from the significant capex investment.

Tom Fuggle, Business Development Director at Permasense said, “The initial discovery well for this platform indicated that there was upwards of two trillion cubic feet of natural gas in place. For the client, sand erosion wasn’t solely a question of maintaining its assets, essential though that is. They also wanted to maximise output from this significant discovery. But increasing production without understanding the immediate effect on well integrity would be as reckless as driving blind in the Monte Carlo rally – with equally damaging consequences.”

The operator had previously worked closely with Permasense to develop a new method of measuring the level of erosion and corrosion within piping. Already installed in all of its refineries, a programme to roll out the technology to upstream assets was underway – and this platform was identified as a valuable target where the technology would offer significant advantages.

The Permasense solution uses proven ultrasonic principles for measuring the thickness of any fixed equipment. But instead of relying on inspection teams to periodically take these measurements and record them manually, permanently mounted sensors deliver their data wirelessly to existing communications infrastructure used by the onshore operations team. The team can then view and analyze the information without leaving their desks.

Implementation: targeted measurements and instant data

Permasense sensors were initially installed in areas of elevated erosion risk. This included areas experiencing the highest flow velocities in one of the producing wells that had the highest sand production rate. A cluster of sensors were installed in an array formation downstream of the first cushioned Tee and a circumferential ring of sensors was installed downstream of the choke.

Once the initial installation on a single well was complete and providing a regular supply of consistent and robust data, a similar system was installed on the additional producing wells. In addition, the operator was concerned that produced sand from this platform would carry over through the flow line to the neighbouring gathering platform, from where the produced gas is then pumped back to shore. A further 80 sensors were therefore installed in a grid formation on the inlet manifold of the carbon steel flow line from this platform on the neighbouring manned platform.

The first round of sensors were mounted onto threaded studs that had to be welded to the pipe. However, to overcome difficulties associated with qualifying a weld procedure for use in a live production environment, Permasense mounted the next group of sensors onto clamps designed to further simplify installation in an upstream production environment. Permasense has since developed a magnetically mounted sensor that can measure through external corrosion protection coatings to further ease installation.

Peter Collins, Permasense CEO says, “Once the locations for monitoring were selected, installation and commissioning of the Permasense system was very straightforward – and took just one day on the platform. When specifying and supporting the installation of the initial system, our team thoroughly understood the requirements of the client – and the system started to deliver data immediately and reliably to the desks of the operator’s onshore engineers.”

The results: production, safety, integrity

With the Permasense system installed, previously unavailable insights into the condition and capability of the fixed equipment on the platform have become available.

By default, the system transmits measurements on wall thickness back to shore every 12 hours. Although, onshore engineers have occasionally increased measurement rates during periods of elevated risk such as periods of high sand production or changes to production flow rates. Data management software within the system calculates the rate of wall loss and classifies the measurement locations by user-defined rate thresholds.

The data is mainly viewed and analysed by asset-integrity specialists at the operator’s office in the Port of Spain, but is also available for viewing from any PC on the operator’s network.

The Port of Spain team can instantly analyse data and compare it against historical trends. Graphical representations of the data indicate which sections of the infrastructure show signs of degradation. In effect, the system acts as an early warning which enables the Trinidad and Tobago operating team to monitor the impact of changes to production rates and adjust them as necessary.

With this new insight, they have increased production of the well by 12 per cent - confident that the impact on erosion rates is well within the safety parameters. This increase in production rate is equivalent to an increase in saleable gas of 30 million standard cubic feet of gas per day, or US$ 90,000 a day increase in revenue (at a price of three dollars per million standard cubic feet).

Jake Davies, Marketing Director at Permasense says, “The Permasense monitoring solution revolutionised the operator’s knowledge and management of sand erosion. We use trusted ultrasound technology, and the level of data, insight and analysis that this gives the operator is making a major contribution to optimising output at the site. Because of the safe increase in production, they saw payback in just days.”

The operator is now installing the Permasense system on other manned and unmanned gas production platforms in the region.

Summary