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.

International manufacturer Roxtec is targeting the marine and offshore oil and gas sectors with a new innovative safety seal which protects life and assets from a multitude of hazards.

The firm’s Single Pipe Metal (SPM) product can be used to seal any kind of metal pipe in steel decks or bulkheads and specifically guards against fire, gas and water ingress.

Roxtec UK managing director Graham O’Hare said the patented technology is manufactured with highly elastic EPDM rubber allowing easy weld-free installation.

“The certified Roxtec SPM seal has been carefully designed to address specific requirements within the marine sector, and the offshore oil and gas markets,” said Mr O’Hare. “Fundamentally, we believe it will help drive greater cost efficiency across industry.

“It is a lightweight, single-sided solution which is quick and easy to install. The seal is made out of durable and malleable rubber, while the fittings are made out of acid-proof stainless steel.

“A crucial point is that it provides an alternative to the costly and laborious welding process often used to seal metal pipes. This process requires a re-paint after weld. In addition, current practices involve pipes being hit with hammers which can lead to damage. Our seal is easy to open up and re-seal for maintenance.

“It further comes with an A-60 fire rating, and is watertight to 1 bar and gastight to 0.67 bar. The comprehensive range of options – with 16 seal sizes catering for 12mm to 222mm pipes – also makes it a highly versatile solution.”

“We wanted to develop an intelligent and progressive product which will help drive efficiency for our customers, particularly in the current challenging economic environment.

“We also have an extensive portfolio in the oil and gas sector on major UK and international projects. Roxtec is accredited by FPAL to work in the UK North Sea. We have further subscribed to the UKCS Oil and Gas Industry Supply Chain Code of Practice which is administered by the Department for Energy and Climate Change (DECC).”

Watch an overview of the Roxtec SPM seal.

As part of the Obama Administration's continued commitment to safe and responsible domestic energy production, Bureau of Ocean Energy Management (BOEM) Director Abigail Ross Hopper has announced that the bureau will offer approximately 45 million acres for oil and gas exploration and development in the Gulf of Mexico in two March lease sales.

“These lease sales continue the President's commitment to create jobs through the safe and responsible exploration and development of the Nation's domestic energy resources,” said Hopper. “As an important component of the U.S. energy portfolio, the Gulf of Mexico holds vast energy resources that can continue to spur economic opportunities for Gulf producing states as well as further reduce the Nation's dependence on foreign oil.”

Photo credit: BOEM

Central Planning Area Lease Sale 241 and Eastern Planning Area Lease Sale 226 will be held consecutively in New Orleans, Louisiana, on March 23, 2016. The sales will be the ninth and tenth offshore auctions under the Administration's Outer Continental Shelf Oil and Gas Leasing Program for 2012-2017 (Five Year Program), which makes available areas with the highest-known resource potential for oil and gas leasing. These lease sales build on the first eight sales in the Five Year Program that offered more than 60 million acres for development and garnered $3 billion in high bids.

“These Gulf of Mexico lease sales reflect this Administration's commitment to facilitate the orderly development of offshore energy resources while protecting the human, marine and coastal environments, and ensuring a fair return to American taxpayers,” Hopper added.

Sale 241 encompasses about 8,349 unleased blocks, covering 44.3 million acres, located from three to 230 nautical miles offshore Louisiana, Mississippi and Alabama, in water depths ranging from nine to more than 11,115 feet (3 to 3,400 meters).

Sale 226 is the second of two lease sales proposed for the Eastern Planning Area under the current Five Year Program. The sale encompasses 162 whole or partial unleased blocks covering about 595,475 acres in the Eastern Planning Area. The blocks are located at least 125 statute miles offshore in water depths ranging from 2,657 feet to 10,213 feet (810 to 3,113 meters). The area is south of eastern Alabama and western Florida; the nearest point of land is 125 miles northwest in Louisiana.

Most of the Eastern Gulf of Mexico Planning Area (EPA) cannot be offered for lease until 2022 as part of the Gulf of Mexico Energy Security Act of 2006.

The decision to hold these sales follows extensive environmental analysis, public comment and consideration of the best scientific information available. The terms of the sales include stipulations to protect biologically sensitive resources, mitigate potential adverse effects on protected species and avoid potential conflicts associated with oil and gas development in the region.

All terms and conditions for Lease Sales 241 and 226 are outlined in the Final Notices of Sale that will be published tomorrow and can be viewed today in the Federal Register. The terms and conditions for Sale 241 are fully explained in the Final Notice of Sale information package, which is available here. The Final Notice of Sale information package for Sale 226 is available here.

CD's of the sale package as well as hard copies of the maps can be requested from the Gulf of Mexico Region's Public Information Office at 1201 Elmwood Park Boulevard, New Orleans, LA 70123, or at 800-200-GULF (4853).

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:

GE Oil & Gas has signed a Master Service Agreement with Statoil for new subsea projects that will enable GE to continue to support the international energy company’s value creation in a low oil price environment.

The global agreement forms the basis for potential new contracts for subsea equipment and services on new projects and field developments. The contract is valid globally until 2025. “We are pleased to have secured an agreement with Statoil that paves the way for further and deeper collaboration between the companies within the subsea segment in the next decade,” says Tom Huuse, Managing Director of GE Oil & Gas in Norway.

GE Oil & Gas recently delivered subsea production system equipment for Statoil’s Snøhvit gas field in the Barents Sea on the Norwegian Continental Shelf.

In today’s oil price environment, sustained focus on costs and efficiency will ultimately be the key to develop several currently marginal prospects and discoveries. GE and Statoil are already working closely together in the Power Collaboration initiative, which aims to accelerate the development of sustainable cost efficient energy solutions. More about Powering Collaboration.

Statoil has agreed with OMV to acquire a 30% working interest in Petroleum Exploration Permit (PEP) 57073. This will further strengthen Statoil’s position in New Zealand.

The permit covers an area of 9,800 square kilometers in the East Coast Basin, and sits in water depths of 1,000-2,000 meters. OMV will remain the operator with 70% working interest. The transaction is subject to regulatory approval.

“This is an underexplored area with the potential for multiple plays, offering a considerable exploration upside,” says Nicholas Alan Maden, senior vice president for Exploration.

The permit is adjacent to permits 57083, 57085 and 57087 which were awarded to Chevron and Statoil in 2014.

“We now hold a working interest in more than 46,000 square kilometers of exploration acreage in New Zealand, and all of these permits have staged exploration programs. This is in line with our exploration strategy of accessing at scale,” says Maden.

OMV and Statoil will work together on the exploration program in PEP 57073. This includes geological and geophysical studies, as well as seismic acquisition over the coming years. The work will provide information necessary to decide, in 2021, if a well commitment should be made in the permit.

In addition to the partnerships with Chevron and OMV in the East Coast and Pegasus basins, Statoil also operates two exploration permits in the Reinga basin.

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

U.S. Gulf of Mexico (GOM) crude oil production is estimated to increase to record high levels in 2017, even as oil prices remain low. EIA projects GOM production will average 1.63 million barrels per day (b/d) in 2016 and 1.79 million b/d in 2017, reaching 1.91 million b/d in December 2017. GOM production is expected to account for 18% and 21% of total forecast U.S. crude oil production in 2016 and 2017, respectively.

Source: U.S. Energy Information Administration, Short-Term Energy Outlook, February 2016

Production in the GOM is less sensitive than onshore production in the Lower 48 states to short-term price movements. However, decreasing profit margins and reduced expectations for a quick oil price recovery have prompted many GOM operators to pull back on future deepwater exploration spending, reduce their active rig fleet by scrapping and stacking older rigs, and restructure or delay drilling rig contracts. These changes added uncertainty to the timelines of many GOM projects, with those in the early stages of development at greatest risk of delay or cancellation.

Contributing to the forecasted production growth are 14 projects: 8 that started in 2015, 4 starting in 2016, and 2 anticipated to start in 2017.

Source: EIA

During 2015, eight fields in the Gulf of Mexico came online. With the exception of Anadarko's Lucius field, each of the fields was developed as a subsea well that is tied back to nearby existing production facilities. The use of subsea tiebacks allows producers to reduce both project costs and start-up times. The Lucius field produces oil using a type of floating production platform that supports drilling, production, and storage operations known as a truss spar. The Lucius spar is the largest in Anadarko's fleet. It consists of a large, hollow, weighted cylinder supporting a deck and is connected to an anchor on the seabed through a mooring system. Its design provides increased stability in harsh offshore conditions.

Four fields are expected to start producing in 2016, including the Anadarko-operated Heidelberg field, which began producing in January. Heidelberg is producing at a spar that uses the same design as the Lucius truss spar, allowing the company to reduce development costs. Shell's Stones field development uses the first floating production, storage, and offload (FPSO) vessel in the GOM. FPSOs allow the development of fields that are complex, that have unique reservoir properties, and that do not have existing infrastructure. Crude oil produced from the Stones field will be transported from the Stones FPSO using tankers to refineries along the U.S. Gulf Coast. The other two fields expected to begin producing in 2016 (Gunflint and Holstein Deep) are subsea tiebacks. Two additional projects are projected to begin producing in 2017, and both are expected to be developed as subsea tiebacks.

Principal contributor: Terry Yen

Statoil has signed a farm-in agreement with Tullow to acquire a 35% working interest in offshore exploration block 15 in the Pelotas basin, deepening its position in Uruguay.

"With this transaction, we are increasing our exposure to the upside potential of this untested geological setting. This is in line with Statoil' exploration strategy of access at scale," says Nicholas Alan Maden, senior vice president of Exploration.

Map Image : Courtesy Statoil

Recently Statoil announced its entry into Uruguay as partner in exploration block 14. By accessing the adjacent block 15 Statoil continues to pursue this regional geological trend.

Block 15 covers an area of more than 8,000 km2 and sits in water depth of 2,000-3,000 meters. Tullow Uruguay Limited. Sucursal Uruguay remains the operator with 35% working interest, while INPEX Uruguay Limited holds the remaining interest. The transaction is subject to government approval.

A comprehensive data collection program has already been completed in the block. As operator, Tullow is planning to collect further 3D seismic before a decision is made on further steps.

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.”

Statoil Exploration (Ireland) Limited has been awarded six Licensing Options in Ireland’s 2015 Atlantic Margin Licensing Round.

Statoil will be the operator of four Licensing Options and partner in two Licensing Options, operated by ExxonMobil Exploration and Production Ireland (Offshore South) Limited. Ireland’s Department of Communications, Energy and Natural Resources (DCENR) yesterday published a map with grid locations for the Licensing Options awarded in the first phase of this licensing round.

The six Licensing Options awarded to Statoil total approximately 7,700 km2 in the Porcupine Basin in water depths ranging between 1,100 and 3,150 meters. Statoil and ExxonMobil each hold 50% equity in all the Licensing Options.

Work program commitments are limited to 2D and 3D seismic surveys to be acquired during 2016 and 2017. The analysis of that seismic data will then determine whether the company will seek to convert the Licensing Options into Frontier Exploration Licenses, enabling possible exploration drilling at a later stage.

"We are pleased with these awards that will see Statoil re-entering the Irish exploration scene. This supports Statoil`s exploration strategy of early access at scale and enables us to apply the exploration knowledge and experience we have gained globally and specifically on the conjugate margin offshore Newfoundland. We look forward to working with ExxonMobil on exploring these opportunities,” says Erling Vågnes, senior vice president Exploration Northern Hemisphere Statoil ASA.

Statoil has had a presence in Ireland since 1992. Currently, the company’s main asset in Ireland is a 36.5% interest in the Shell operated Corrib gas field off the country’s north-west coast.

After a successful survey, DNV GL and the Danish Maritime Authority can confirm that the AHTS Magne Viking, owned by Viking Supply Ships, is in compliance with the new IMO Polar Code.

“Having followed the development of the Polar Code for some years, it is a great achievement to finally survey the first vessel to comply with the Code” says Morten Mejlænder-Larsen, responsible for Arctic and Polar activities at DNV GL - Maritime.

Magne Viking, care of Viking Supply Ships.

Based on long experience from Arctic operations in low temperatures and ice covered waters, Viking Supply Ships saw the value in the IMO Polar Code and decided to implement it early on. The process has included updates of vessel and equipment, as well as providing the required documentation.

“As this vessel was already winterized and built for operation in cold climate, most of the additional requirements in the Polar Code were already fulfilled before we started the implementation process,” says Andreas Kjøl, Project Director at Viking Supply Ships.

The IMO Polar Code is mandatory for all SOLAS vessel entering Arctic and Antarctic waters from 1 January 2017. The Code is an add-on to existing IMO codes where the main requirements are related to safety (SOLAS) and protection of the environment (MARPOL). DNV GL will, on behalf of the Flag Authorities, issue the Polar Ship Certificate for vessels complying with the new code.

As a result of less ice and easier access to polar waters, IMO saw the need for a common set of minimum requirements for vessels operating in these areas which are not covered by other regulations. In addition, increased shipping to support the oil and gas industry, mineral export, and an expansion of cruise visits to these regions, prompted IMO’s work with the code.

The main additional risks identified when operating in polar waters are addressed in the IMO Polar Code and the different chapters describe different measures to mitigate these risks.

Magne Viking is an ice-classed AHTS vessel capable of operations in harsh environment offshore regions, as well as Arctic/Sub-Arctic operations. The DNV GL classed vessel is owned and operated by Viking Supply Ships.

President Obama’s fiscal year (FY) 2017 budget request for the Bureau of Safety and Environmental Enforcement (BSEE) provides critically needed resources to further strengthen BSEE’s regulatory and oversight capabilities for oil, natural gas and renewable energy development on the U.S. Outer Continental Shelf, promoting a culture of safety and environmental protection by ensuring compliance with Federal regulations.

The FY 2017 budget request is $204.87 million, a $196,000 increase above the FY 2016 enacted level, and includes $96.34 million in current appropriations and $108.53 million in revenue from rental receipts, cost recoveries, and inspection fees.

“The President’s proposed FY 2017 budget fully reflects the Administration’s continued emphasis on ensuring the safe and responsible development of the Nation’s offshore energy resources,” said Director Brian Salerno. “The President’s request supports BSEE’s efforts to build a robust culture of safety, with a strong focus on risk reduction to protect lives and the environment.”

“The Bureau uses a comprehensive program of regulations, compliance monitoring and enforcement, technical assessments, inspections, and incident investigations to mitigate and reduce risk,” Salerno said.

The FY 2017 budget also supports research and the development of new technologies and scientific investments to best manage the country’s offshore energy resources.

The request includes $190 million for offshore safety and environmental enforcement programs. BSEE is also working collaboratively with the Bureau of Ocean Energy Management to establish appropriate permitting and oversight processes for offshore renewable energy projects.

The FY 2017 proposal includes $14.9 million for Oil Spill Research, equal to the 2016 request level, to address key knowledge and technology gaps, focusing research on deep-water and Arctic environments. The Oil Spill Research program plays a pivotal role in initiating applied research to support decision making to prevent or mitigate oil spills, which is a critical component of the offshore permitting process. Funds are used to sponsor testing of new equipment or methods and also to support the bureau’s oil spill and renewable energy test facility, Ohmsett.

The President’s FY2017 budget request of $13.4 billion for the Department of the Interior reflects his commitment to responsibly managing energy development on public lands and offshore waters, conserving vital national landscapes across the Nation, meeting Federal trust responsibilities to Native Americans, supporting the next century of our Public Lands.

Additional details on the President’s FY 2017 budget request are available online.