Pressure is mounting on the global oil and gas industry to reduce environmental footprint at the same time as the industry is under significant cost pressure. Since business as usual is not an option, DNV GL has launched two papers to advise the industry on how and where to make impactful changes within financial constraints.

The paper, ‘A cost-efficient approach to reducing environmental impact’ provides a framework for the industry on how to improve environmental sustainability by identifying the most cost-efficient mitigating measures. To demonstrate how the abatement framework can work in practice, DNV GL has also carried out a case study for an offshore asset. The second paper, ‘CO2 abatement potential for offshore upstream installations’ demonstrates the results of a comprehensive case study on how CO2 emissions can be reduced through the implementation of a number of cost-effective measures for offshore production on the Norwegian Continental Shelf (NCS).

Elisabeth Tørstad, CEO, DNV GL – Oil & Gas, says: “Cost management is a top priority for the industry right now but it’s still possible to reduce our environmental footprint without breaking budgets. Cost-effective measures can be implemented across the lifecycle of assets and throughout the supply chain. Our papers will advise and support decisions in this critical area. Greater transparency by the industry on environmental risk management processes and sustainability reporting will give the sector much needed credibility and speed up sustainability improvements as a business advantage.”

The framework proposed in ‘A cost-efficient approach to reducing environmental impact’, is based on internationally recognized guidelines (IPIECA, API and IOGP) for sustainability reporting. It can also be used alongside other sustainability reporting initiatives or company specific sustainability KPIs. Aligned with UN Sustainable Development Goals for the environment, it covers a wide range of indicators, including emissions to air and discharges to sea (i.e. hydrocarbon spills, produced water, etc) for specific offshore assets. It is based on a three-step integrated approach: reporting and accounting of emissions and discharges; impact and risk assessment; and prioritizing cost-efficient environmental improvements.

“Our approach allows better informed decisions to be made on how and where to improve the environmental performance of a single or multiple mix of assets,” explains Tørstad. “This will support operators in reporting and communicating with stakeholders, as well as in their efforts for continuous improvements and benchmarking. It will also increase control and opportunities for improving global environmental risk management.”

The pathway study resulting in the paper ‘CO2 abatement potential for offshore upstream installations’ describes how adopting cost-effective practices could provide a 29% reduction in the current CO2 emissions from offshore production on the NCS whilst also securing significant cost savings. The results took into account efforts already made to lower emissions such as reduced gas flaring activity.

“Despite the NCS being known as best in class when it comes to combating CO2 emissions and footprint, the work we have done with the CO2 abatement reveals that there is still cost effective potential left. The promising and inspiring results are making a profitable case for already available technologies for energy efficiency and storage, and the earlier the measures are implemented for a field production, the greater the cost savings. As around 75% of global oil production in 2040 is projected to come from new fields, it should be possible to reduce CO2 emissions dramatically on a global scale over the next quarter of a century,” adds Tørstad.

In order to ascertain the status of sustainability efforts across oil and gas producing regions and current field developments, DNV GL has also developed a map based on publicly available databases and literature. The map identifies regions and field developments with the most and least potential for improvement on governance and production efficiency. The results are presented in a traffic light system detailing economic, environmental and social performance criteria of resources and production in regions. The results of the benchmark are dynamic and can be used to identify areas for sustainability improvements as well as enable a wider basis for investments decisions.

Tullow Oil announces that first oil has flowed from the Tweneboa, Enyenra, Ntomme (TEN) fields offshore Ghana, to the FPSO Prof. John Evans Atta Mills.

Photo credit: Tullow Oil

First oil has been reached on time and on budget three years after the Plan of Development was approved by the Government of Ghana in May 2013.

The TEN start-up process is now well advanced and Tullow expects oil production to ramp-up gradually towards the FPSO capacity of 80,000 bopd through the remainder of 2016. Tullow estimates that TEN average annualized production in 2016 will be approximately 23,000 bopd gross (net: 11,000 bopd).

Tullow is the operator of the TEN fields and holds a 47.175% stake. Tullow’s joint venture partners are Anadarko Petroleum Corporation (17%), Kosmos Energy (17%), Ghana National Petroleum Corporation (15%) and PetroSA (3.875%).

Aidan Heavey, CEO of Tullow Oil Plc, commented:

“I am delighted that the TEN fields have reached first oil. This is an important moment for Tullow as production begins from our second operated development in Ghana. I thank the Government of Ghana, the Petroleum Commission and our partners – GNPC, Anadarko, Kosmos and PetroSA - for their support and co-operation since we made the first discovery in 2009. I also congratulate the project team, our contractors and sub-contractors for delivering this project on time and on budget and with great skill and professionalism and commend them for their commitment to the participation of Ghanaian staff and companies in the project.”

Watch video here

STATS Group in collaboration with Paradigm Flow Services and Halliburton safely and successfully isolated, de-oiled, plugged and abandoned two 3.5” subsea flowlines as part of the Murchison decommissioning project.

After nearly 30 years of operation in the Northern North Sea, the CNR International operated Murchison field had reached the end of its production life. Prior to the removal of the topsides jacket, it became evident that two subsea flowlines were still connected to the platform. These lines were known to still contain hydrocarbons and required to be de-oiled and cut to enable the heavy lift scope.

When considering the available options to safely disconnect the flowlines, CNRI was progressing towards a conventional Diving Support Vessel subsea intervention that would result in hot tap penetrations being made at subsea to flush the jumper bundles free of remaining hydrocarbons.

Dale Milward, Director of EPRS and subsea services, STATS Group

Aberdeenshire-based STATS Group was initially approached to review the requirement for subsea hot tapping operations. However, following collaborative discussions with Paradigm Flow Services and Halliburton, an alternative solution that would mitigate a diver-intensive operation was proposed that could be completed solely from the platform topsides. This approach provided many safety benefits, reducing the risk to personnel and the environment and providing significant time and cost savings for the operator.

Initial discussions on the scope began in late 2013, and through regular collaborative meetings involving CNRI and all three service companies, each element of the project was explored, developed and risk accessed. In May 2014 CNRI progressed with the platform-based solution and the contract was awarded. At this stage, all individual and collective engineering, manufacture, assembly, testing and offshore execution, was completed within 12 months and in line with CNRI’s schedule.

In order to de-oil and abandon the subsea flowlines, full bore access was required in order to install Paradigm’s Flexi-Coil technology prior to pumping Halliburton’s Thermatek™ fluid system. As there was no suitable valves to offer a positive isolation or provide an access point to gain entry to the flowline, STATS utilised their hot tap installed BISEP™ isolation tool.

STATS patented leak-tight BISEP™ provided fail-safe double block and bleed isolation, deployed through a single full bore hot tap penetration from the platform. STATS provided mechanical tie-in clamps, ball valves and a hot tap machine which allowed the flowlines to be hot tapped (drilled) while under pressure, allowing access to deploy the BISEP™ from a pressure competent launcher.

Once deployed, the BISEP™ was hydraulically activated setting the dual elastomer seals isolating the flowline. The seal annulus was then monitored and vented, independently testing both seals with full line pressure.

With the flowline successfully isolated and vented from the platform behind the BISEP the line was cut, STATS then installed a mechanical connector and temporary launcher system, providing the full bore access required to deploy Paradigm’s Flexi-Coil technology.

The Flexi-Coil technology is a miniaturised coiled tubing system which is an ultra-lightweight, highly flexible pipe that has the ability to traverse multiple 5D bends in pipeline and riser systems. The Flexi-Coil was initially used to de-oil the flowline but subsequently acted as a conduit to pump Halliburton’s Thermatek™ fluid system through the line.

Halliburton’s Thermatek™ System provides a rigid setting fluid which is ideally suited to plugging and abandonment operations. The low viscosity non-shrinking nature combined with a controlled rapid right angle set and high compressive strength of the fluid, enabled a robust pressure barrier to be installed in the horizontal flowline, allowing the decommissioning of the topsides facility to continue.

The isolation, de-oiling and plugging of the two 3.5” unpiggable flowlines was successfully completed and allowed the platform decommissioning to progress on schedule delivering the project on time and with no lost time incidents.

Dale Millward, Director of EPRS and Subsea Services for STATS Group, said, “As a result of this collaborative project, the industry now has, where the field layout allows, a practical and cost-effective topsides solution for the isolation and abandonment of live or contaminated subsea flowlines. Unlike traditional techniques, this approach does not require a subsea intervention, eliminating the requirement for costly Diving Support Vessel or Work-class ROV vessels.

“The level of cooperation between all companies demonstrates the value of collaborative working to deliver solutions that would normally be out with any individual company’s capability. This solution has led to significant cost savings for the client in comparison to a conventional subsea intervention.

“A major element of the project success was the positive involvement and enabling influence of CNR International, who showed initiative and willingness to explore new ideas and technologies to increase safety and reduce project timescales”.

The Songa Enabler drilling rig has started drilling a new injection well for CO2 gas on the Snøhvit field off the coast of Hammerfest. Next a production well will be drilled for replenishment of gas for Hammerfest LNG.

On Friday 29 July the new Cat D Songa Enabler drilling rig started drilling on the Snøhvit field in the Barents Sea off the coast of Hammerfest. Arriving from the yard in South Korea the rig has started its first assignment on the NCS. Photo credit: Statoil

Snøhvit is still the only LNG project in the world capturing and storing CO2 separated from the well stream in a dedicated formation offshore.

So far more than four million tons of CO2 from Snøhvit have been stored. The stored CO2 is being monitored in order to ensure that it does not mix with the main producing reservoir. A new CO2 injection well is now required.

After the new CO2 injector is installed, the rig will move on to drill the first new production well at Snøhvit since the field came on stream in 2007. The drilling campaign is planned to last until Christmas.

Prevents carbon leak

The CO2 solution project was established in 2013 in order to build and install a new CO2 injection well, replacing the original injector that over time would leak CO2 into the gas reservoir on the Snøhvit field.

Hammerfest LNG needed replenishment of gas in order to maintain the high production and capacity utilization at the plant, while ensuring sustainable CO2 storage. This project is therefore important to Statoil,” says Geir Owren, asset owner representative for the project.

In the summer of 2015 an extensive marine campaign was performed. Pipelines and a template for the CO2 project were installed and tied in to the existing subsea facility on the Snøhvit field. The new subsea facility was built and installed without injuries and well within the budget of NOK 2.5 billion.

The distance to the Barents Sea presents extra challenges with regard to mobilization and sailing time, which requires careful planning, thorough preparations and close cooperation with the suppliers. We are pleased both with the equipment suppliers and marine operations, which resulted in successful project implementation,” says project leader Sveinung Øvretveit.

The next big development step for Hammerfest LNG is the development of the Askeladd field, which is part of the plan for development and operation of the Snøhvit license. It is expected to come on stream in 2020/2021. This development step will help ensure full utilization of the capacity at Hammerfest LNG.

Bureau of Ocean Energy Management (BOEM) Director Abigail Ross Hopper announced that last week’s oil and gas Lease Sale 248 garnered $18,067,020 in high bids for 24 tracts covering 138,240 acres in the Western Gulf of Mexico Planning Area. A total of three offshore energy companies participated in 24 bids. The sum of all bids received totaled $18,067,020.

In this sale, BOEM offered 23.8 million acres in federal waters offshore Texas for oil and gas exploration and development.

“The Gulf of Mexico continues to be one of the most productive basins in the world and is an important part of our Nation’s domestic energy portfolio,” said Hopper. “Though this sale reflects today’s market conditions and industry’s current development strategy, the bidding confirms that there is continued interest in the deepwater areas of the Gulf”.

BOEM oversees 160 million acres on the Outer Continental Shelf in the Gulf of Mexico. Approximately 20 million acres (3,762 blocks) are leased for oil and gas development; and 4.3 million of those acres (883 blocks) are producing oil and natural gas.

The August 24 sale in New Orleans, Louisiana, was the first federal offshore oil and gas auction broadcast live on the internet, delivering pertinent bid information immediately to a much broader national and international audience. Through this approach, BOEM aims to promote greater government efficiency and transparency. A video of the livestream broadcast will be posted to the BOEM website.

Today’s auction is the eleventh Gulf of Mexico offshore sale and the final one for the Western Planning Area, under the Administration’s Outer Continental Shelf Oil and Gas Leasing Program for 2012-2017 (Five Year Program). This sale builds on the first ten sales in the current Five Year Program, which offered more than 60 million acres and netted nearly $3 billion for American taxpayers.

Sale 248 included approximately 4,399 blocks, located from nine to 250 nautical miles offshore, in water depths ranging from 16 to more than 10,975 feet (5 to 3,340 meters). As a result of offering this area for lease, BOEM estimates a range of economically recoverable hydrocarbons to be discovered and produced of 116 to 200 million barrels of oil and 538 to 938 billion cubic feet of natural gas.

The decision to hold this sale follows extensive environmental analysis, public comment and consideration of the best scientific information available. The terms of the sale 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. The lease terms also include a range of incentives to encourage diligent development and ensure a fair return to taxpayers.

Following the sale, each bid will go through an extensive 90-day evaluation process to ensure the public receives fair market value before a lease is awarded.

Statistics for Western Sale 248 are available here.

Statoil and its partners have submitted the Plan for Development and Operation of the Byrding oil and gas discovery in the North Sea to government authorities.

Capital expenditures estimated at approximately NOK 1 billion, recoverable volumes are projected at approx. 11 million barrels of oil equivalent.

“This is another example of a new discovery being realized through existing infrastructure,” says Torger Rød, Statoil’s senior vice president for project development.

The development will boost activity and production on the Troll C platform. (Photo: Øyvind Hagen)

The Byrding development includes a duo-lateral well drilled from the existing Fram H-Nord subsea template through which oil and gas from Byrding will flow to Troll C.

Oil and gas will be piped from there through existing pipelines to Mongstad and Kollsnes respectively.

Capital expenditures have been reduced from initially approximately NOK 3.5 billion to the current estimate of approximately NOK 1 billion. “Byrding shows that successful improvement efforts in Statoil, and in this case particularly within drilling and well, allow new development projects to be realized,” Rød says.

The duo-lateral well to be drilled is some seven kilometers long, the first kilometers being shared by the two laterals.

“Combined with the use of an available well slot in an existing subsea template this reduces the costs of the project substantially. The project is profitable also in the current oil price environment,” Rød says. The field is scheduled to come on stream in the third quarter of 2017. The project will thus yield a return in the same year as investments are made.

“Byrding will add new profitable volumes from the Troll / Fram area, boosting the activity and production on the Troll C platform,” says Gunnar Nakken, Statoil’s senior vice president for Operations West.

According to plans Byrding will remain on stream for 8-10 years.

Facts

Partners: Statoil Petroleum AS (operator) 45%, Wintershall Norge AS 25%, Idemitsu Petroleum Norge AS 15% and Engie E&P Norge 15%

Discovery year: 2005

Location: north of the Fram field in the North Sea

Water depth: 360 meters

In the peak period in 2017/2018 Byrding is expected to produce almost 8,000 barrels of oil equivalent per day.

Ashtead Technology has successfully completed a subsea integrity management project to support BP’s Quad 204 redevelopment of the Schiehallion and Loyal fields, West of Shetland.

Ashtead, a leading independent provider of subsea technology and equipment, deployed its new Deflection Monitoring System (DMS), to capture critical data required to safely deploy and install two subsea manifolds at water depths of 400m. The technology was launched to the market earlier this year.

The system monitors deflection, heading, pitch, roll, depth and other parameters of subsea structures in real time. This allows informed decisions to be made during critical operations, ensuring specified tolerances and safety requirements are taken into account.

Ashtead’s Deflection Monitoring System (DMS) during mobilization.

The DMS was optimized to the exact pressures and water depths required for the scope of work at Ashtead’s UKAS accredited calibration laboratory before it was launched from a vessel and lowered 400m onto the seafloor.

The project was completed on time and allowed the subsea manifolds to be installed within 24 hours of the DMS being deployed. The entire project was controlled remotely via radio frequency and acoustic data links, removing the need for direct ROV or diver support intervention in order to gather attitude measurements.

Ashtead utilized a range of communication and positioning tools to enhance the accuracy of data collected and to ensure maximum performance of the subsea structure once in place.

This new approach to the installation and integrity management of subsea systems was developed by Ashtead Technology as part of its range of value-added services to significantly reduce risk and cost in subsea operations.

Allan Pirie, chief executive of Ashtead Technology said: “Whilst subsea structures look robust and are designed to last decades, they can be easily damaged during installation and incorrect orientation can lead to stress on flowlines and jumpers.

“In today’s increasingly harsh exploratory environments, data is key – it allows us to ensure subsea structures are installed to meet the differing complexities of developments around the world, offering long-term reliability and safety.

“Our Deflection Monitoring System was designed to provide a versatile platform for improved cost and safety performance, whilst reducing technological and operational risk and capturing key information that can extend the life of subsea assets.

“Quad 204 represents one of the most significant projects ongoing in the region and we are honored to have been able to support BP with an integrity management solution for such an important field development.”

Quad 204 is a major UKCS redevelopment incorporating a new FPSO and upgrade of the subsea infrastructure. It will enable the potential recovery of an additional 400 million barrels of resource from the existing Schiehallion and Loyal fields and extend production through to 2035.

DNV GL has welcomed the world’s largest semi-submersible drilling rig into class recently. Ocean Greatwhite is 123 meters long and 78 meters wide and was delivered at Hyundai Heavy Industries in Ulsan, South Korea. Owned by the Houston-based drilling contractor Diamond Offshore, the rig will be chartered to oil major BP and will operate in the Great Australian Bight.

The rig is to be a new design MOSS CS60E high specification state-of- the art semi-submersible drilling unit suitable for operations in harsh environments, which is the first MOSS CS60E and the largest rig in the world.

Ocean Greatwhite is 123 meters long and 78 meters wide and was delivered at Hyundai Heavy Industries in Ulsan, South Korea. Credit: HHI

“The Ocean GreatWhite is a unique rig purposely built for drilling in harsh environments,” said Karl Sellers, SVP Technical Services at Diamond Offshore. “HHI and DNV GL were integral in helping us get this rig to market as we prepare for the drilling project in Australia with BP.”

“We have a strong relationship with both DNV GL and Diamond Offshore – and it is thanks to this good cooperation that the project went so well. We are proud to deliver the first drilling ship of this size and look forward to many more projects on this scale,” Youngseuk Han, Senior Executive Vice President at HHI said. “We will keep moving the boundaries of technology by completing following large-scale and innovative projects.”

“Ocean Greatwhite is capable of operating in depths of up to 3000 meters and can drill down to a depth of 10,670 meters. It represents the state of the art in the semi-submersible sector and we are very pleased to have been asked to contribute our expertise to this project,” says Paal Johansen, Vice President and Regional Director, Americas at DNV GL.

Ocean Greatwhite is also the first new-build rig to receive the DNV GL Integrated Software Dependent Systems (ISDS) notation. ISDS are systems whose performance is dependent on the overall behavior of their integrated software components. DNV GL’s ISDS standard helps owners and operators minimize software integration errors and delays in projects involving complex integrated systems.

The certification ensures that software and integration issues are identified and resolved early on during the project design stages. It also represents a new approach to verification, as it emphasizes a review of the working methods and processes that lead to the delivery the systems, rather than simply focusing on the final review of documents and installations to ensure they meet product requirements.

Industry data suggests that high specification mobile offshore drilling units may experience 30 per cent down-time during their first years of operations, which makes a systematic framework for ensuring that ISDS achieve the required reliability, availability, maintainability and safety essential. “We expect that the operational performance of Ocean Greatwhite will demonstrate how the ISDS notation can contribute to increasing the reliability of the complex systems onboard,” adds Paal Johansen. DNV GL’s ISDS teams in Korea, Norway, and the USA all contributed to the project. DNV GL also provided advisory services to HHI on the integration of the various systems throughout the newbuilding process.

Last week, U.S. Department of the Interior Deputy Assistant Secretary for Land and Minerals Management Amanda Leiter and Bureau of Safety and Environmental Enforcement Director Brian Salerno announced final regulations to ensure that safety and maintenance requirements are current for offshore oil and gas production technologies. The Production Safety Systems Rule utilizes industry standards and best practices for the use of offshore safety equipment and systems, while also prescribing maintenance, testing and reporting requirements for specific production and subsurface safety devices.

“The Department has a responsibility to update its regulations to keep pace with advancing technology and ensure the safest possible offshore oil and gas operations,” said Deputy Assistant Secretary Leiter. “The regulations issued today reflect the industry’s shift to deeper waters and adoption of more sophisticated technology. The Administration is committed to safe and environmentally responsible operations utilizing the most effective technology available.”

These final regulations revise and update the Code of Federal Regulations section that addresses oil and gas production safety systems. The section was first published in 1988. The rule published today incorporates many Bureau of Safety and Environmental Enforcement (BSEE) policies that have been developed over the past 28 years. In 1988, many of the technologies currently in use did not exist. The final rule addresses a number of safety issues including production safety systems, subsurface safety devices, safety device testing, and production processing systems.

“By updating the requirements for these critical safety systems, we are meeting our commitment to promote the highest level of protection for both offshore workers and the environment,” explained BSEE Director Salerno. “The rulemaking process allowed us to develop the most effective and timely revisions by incorporating input from our partner federal agencies, industry, and research organizations.”

The revised requirements have been sent to the Federal Register and will go into effect 60 days following the publication of the final rule. BSEE has deferred the compliance dates for certain provisions of the final rule. These provisions and deferred compliance dates can be found in the Federal Register notice.

Click here for a copy of the final rule

Click here for a Production Safety System Rule fact sheet

Decom North Sea, the representative body for the offshore decommissioning industry, launches the ground-breaking Late Life Planning Portal.

The operational website – also known as L2P2 – has been designed to support the North Sea oil and gas industry in the planning and execution of late life and decommissioning projects. Providing a single access point for knowledge sharing and cross sector learning, L2P2 reflects Decom North Sea’s overarching objective to bring the regulators, operators and supply chain together to create the co-operative environment required by the decommissioning industry.

Roger Esson, Decom North Sea Chief Executive

Roger Esson, chief executive of Decom North Sea explains the drive behind the portal: “Decommissioning is a long game, with over 40 years of decommissioning activity yet to take place and around 90% of North Sea assets yet to be decommissioned. For that to happen as efficiently and as cost-effectively as possible in the long term, we need to make good decisions in the Late Life phase.

“Taking that into account, it is easy to understand why Decom North Sea has developed a portal which provides the ultimate decommissioning toolkit: a repository for lessons learned, a forum for discussion and a gateway to contacts, analytics and market intelligence. At this stage in any industry, a toolkit such as this provides fundamental support in achieving the overarching objectives of efficiency, simplification, standardisation and cooperation.”

Project workstream champions have populated the portal with what have been characterised as foundation tools and lessons learned. Decom North Sea business manager – and L2P2 project manager – Pamela Ogilvie explains why industry engagement is a fundamental to the portal: “It is now up to industry to share the tools and processes that have materially added value to their decommissioning projects, so that others can share the benefits.

“Given the incredible level of genuine collaboration on this project to date, I am confident that L2P2 will be adopted as an industry standard information portal – we believe the potential is limitless.”

Fugro has been awarded a contract by Total E&P Uruguay B.V. to support its drilling campaign offshore Uruguay. The contract provides for ROV and tooling services in the Raya-1 field in 3,400 metres water depth.

Fugro’s FCV4000 ROV recovers the ADCP deployed to monitor subsea currents at the Raya-1 field offshore Uruguay. Photo credit: Fugro

Fugro is supplying two state-of-the-art 200hp FCV 4000D work-class ROV systems and subsea tooling, which are installed on board the Maersk Venturer drilling ship, and a field support vessel.

In addition to specialist tooling tasks, Fugro is performing a range of activities typically required during drilling operations such as bullseye checks, seabed survey, and general cleaning on and around the subsea BOP. Real-time video provided by Fugro and Total telecom network enables Total to observe critical operations from its onshore office should it be needed.

Raya-1 is the deepest well, by water depth, ever to be drilled. “Fugro’s top class intervention tooling is key to supporting Total in this world leading contract,” said Richard Mathieson, Fugro ROV Services Project Manager.

Read how Fugro provides subsea support during deepwater frontier drilling operations.

Brazil is set to lead the global offshore oil and gas industry in terms of planned projects, with a staggering total of 40 developments scheduled to start operations by 2025, out of an anticipated total of 236 worldwide, according to research and consulting firm GlobalData.

The company’s latest report* states that the UK and the US follow Brazil, with 29 and 21 planned projects respectively. Key offshore planned projects around the world are expected to contribute an incremental 6.8 million barrels of oil per day in 2025, and 36.3 billion cubic feet per day of natural gas.

Matthew Jurecky, GlobalData’s Head of Oil & Gas Research and Consulting, explains: “The offshore commercial reserves in Brazil are second only to Russia, Iran, and Mozambique. GlobalData’s analysis shows there are an estimated 13.3 billion barrels of commercially recoverable reserves from announced projects in offshore Brazil. To put this in perspective, planned offshore projects in Norway, United States, United Kingdom and Nigeria total 12.9 billion barrels of commercially recoverable reserves altogether.”

While National Iranian Oil Company is expected to lead in terms of production volumes, Petroleo Brasileiro S.A (Petrobras) will lead globally in terms project count, with 35 planned, of which 34 are crude and one is natural gas. Petroleos Mexicanos and Chevron Corporation occupy second and third places with nine and eight projects planned, respectively.

In GlobalData’s Brazil-focused webinar, Adrian Lara, GlobalData’s Senior Upstream Analyst covering the Americas, explains: “Brazil’s pre-salt was a game-changer which the government tried to protect, but after being hit by political and corruption scandals on top of economic recession, a clear opportunity has emerged where international oil companies can play a more central role in a more balanced regulatory environment – but the political trade-offs to allow this will be challenging.”

GlobalData’s report also states that in terms of proposed capital expenditure, US$871.7 billion is estimated to be spent bringing planned offshore projects online globally, of which US$500.5 billion is expected to be spent between 2016 and 2025. Brazil will also lead in this regard, with capital investment of US $116.2 billion over the forecast period. Petrobras will have the highest share of spending among companies in the global offshore oil and gas industry, and is expected to spend US$90.9 billion on key planned projects over the next 10 years.

*Q2 2016 Production and Capital Expenditure Outlook for Key Planned Upstream Projects in the Global Offshore Industry

NOIA President Randall Luthi issued the following statement on yesterday’s Western Gulf of Mexico Oil and Gas Lease Sale:

“Congratulations to the Bureau of Ocean Energy Management on their first livestream oil and gas lease sale. The relatively modest results of today’s Western Gulf of Mexico lease sale are indicative of the current market conditions and regulatory environment. Despite these challenging circumstances, the companies that participated in today’s sale are investing millions of dollars in the future of America’s energy and economic security with no guarantee of success or financial return. The purchase of a lease block is a first step in a lengthy process that involves rigorous regulatory oversight including extensive environmental reviews, permitting, and safety checks.

Gulf of Mexico Western Planning Area Lease Sale 248, Map courtesy: BOEM

“The development of offshore oil and natural gas helps power our nation. Oil and natural gas are abundant and affordable sources of energy needed to fuel our vehicles and heat, cool and power our homes, schools and businesses. While government estimates show that non-traditional sources of energy will continue to provide more of our nation’s energy mix, they also show that for the foreseeable future, oil and natural gas will provide the bulk of reliable, reasonably priced energy to U.S. consumers, including those who protested today’s sale.

“It’s hard to miss the irony of activists traveling to such protests in gasoline fueled vehicles, or the fact that oil and natural gas provide low cost fuel to the income dis-advantaged populations that these activists claim to protect. Should the ‘keep it in the ground’ movement stop federal leasing, we can all expect to pay far more for our basic energy needs and we will witness the loss of thousands of jobs in the Gulf of Mexico region. Billions of dollars to state and federal treasuries will also be left in the ground.

“Attempting to link the recent flooding and disaster to the offshore lease sale not only lacks wide-spread scientific backing, it is also shameful to take advantage of a disaster that impacted thousands of Louisianans, who now find themselves in need, to try to score cheap political points. As a matter of fact, oil and natural gas are helping these communities that face disaster. From fueling the vehicles that helped people evacuate, to powering the boats of the "Cajun Navy" that rescued thousands, to getting the lights back on so clean-up efforts could begin, not to mention all the petroleum-based goods and services that will be needed as the recovery process continues, fossil fuels are helping save lives and rebuild communities. For protesters to try to use this awful disaster to further their political objectives is ill-conceived and does nothing to help the people of Louisiana.”

Contributing to India’s exploration and production (E&P) activities in the oil and gas sector, GE (NYSE: GE) has signed an exclusive Memorandum of Understanding (MoU) with L&T Hydrocarbon Engineering Limited, a wholly-owned subsidiary of Larsen & Toubro (L&T). Together, the firms will partner in the manufacture of subsea manifolds destined for future deep water projects in the Krishna-Godavari basin on the east coast of India.

The partnership brings together the manufacturing and technological excellence of two leading companies in the oil and gas space, and also marks India’s entrance into local subsea equipment manufacturing.

Image credit: GE

Spread over an area of 600,000 sq.m. and with an annual capacity of 50,000 MT, L&T’s modular fabrication facility in Tamil Nadu was chosen as the production site after a rigorous qualification process. The plant is equipped with advanced welding and fabrication capabilities along with a 150m jetty, making it an ideal location to manufacture advanced hardware for the seabed. Utilizing a modular approach, GE’s subsea manifolds will provide long-term reliability, safety and quality, while addressing the complexities of the subsea environment.

Ashish Bhandari, CEO, GE Oil & Gas, South Asia said, “GE continues to grow its widespread manufacturing footprint in India and this latest collaboration will continue our contributions towards Make in India. Our strategic partnership with L&T has opened new avenues for us to manufacture highly advanced equipment to serve the needs of India’s oil and gas sector as well as the broader, global industry.”

Commenting on the development, Subramanian Sarma, CEO and MD, L&T Hydrocarbon Engineering, said: “Associating with GE will help L&T to broaden its offering in the deep water space and provide a compelling value proposition to our customers. Projects of such strategic importance and magnitude bring huge responsibility and we are poised to make significant contributions to India’s growth curve going ahead.”

In addition to this MoU, L&T Infotech has also joined the GE Digital Alliance Program, with the organizations collaborating to develop innovative digital industrial solutions powered by GE’s Predix operating system for the Industrial Internet. They will work together to leverage analytics and real-time insights to enhance competitiveness and transform the way companies manage their assets and workforce.

GMC Limited announces the safe and successful installation of a seawater caisson in the North Sea; eight days ahead of schedule.

This is the first installation that has been carried out by the company in the North Sea; with a further two fabricated caissons completed and ready to be installed later this year.

GMC 30” TSA coated caisson being moved. Photo credit: GMC

The TSA coated 30” OD diameter caisson was installed in nine sections using eight sets of GMC’s high fatigue non-rotational caisson connectors. All connections were made up quickly and efficiently first time.

GMC’s handling and installation methodology greatly reduces the installation time over convention installation methods. GMC provided sufficient handling tools to ensure continuous operations were maintained throughout, thereby eliminating delays normally associated in handling caisson operations.

A first for GMC in the UK, this project demonstrates the company’s competence in providing a complete fabricated caisson with connectors, dead weight support, and guide nose cone, all fabricated and coated to the client’s requirements. It also demonstrated the mobilization of tools and competent personnel to carry out the critical ‘make up’ operation in connecting the caisson sections together safely and efficiently in minimal time.

The GMC solution eliminates the need for offshore welding of caissons, and provides the client with a safe and efficient fabrication and installation service that delivers considerable cost savings, whilst also extending the life of ageing assets.

DNV GL has been awarded a 5 year contract to provide in-service verification work for Wintershall Noordzee B.V.’s (‘WINZ) RAVN and A6-A platforms.

The two platforms based in the North Sea are the unmanned RAVN in the Danish sector and manned A6-A in the German sector. RAVN is the first field in Denmark that Wintershall Noordzee will transition to the production phase as operator. The A6-A platform is undergoing a major overhaul, with WINZ extending it to include an oil processing plant alongside the current gas condensate facilities.

DNV GL’s scope of work will cover the Independent Verification of Management of Safety and Environmentally Critical Elements (SECE’s). This will include independent verification activities as detailed in the Written Scheme of Verification for RAVN and the A6-A installations. This involves a combination of onshore review of assurance records (i.e. certification, maintenance activities and integrity management activities), physical survey and witness of offshore/site activities. The main focus will be on the onshore review activities with a tailored offshore scope.

The work undertaken will be based on new EU Directive (2013/30/EU) on Safety of Offshore Oil and Gas Operations which aims to reduce the risk of major accidents associated with offshore oil and gas operations. The Directive requires owners and operators to prevent and mitigate the impact of major accident hazards through the implementation of a systematic and effective approach to risk management.

WINZ’s Justin Jansen and Richard Heijkoop from the Operations Engineering Department stated that “We have chosen DNV GL as supplier for the independent verification services because their approach to the project aligns very strongly with our way of working. DNV GL has also been offering these services for the offshore market for more than 30 years in Denmark so that really gave us confidence in their experience and credibility.”

Ben Oudman, Director and Country Manager Netherlands, DNV GL - Oil & Gas stated “We are very excited to have won this contract with Wintershall Noordzee and begin the work on these platforms. I believe DNV GL’s ability to deliver the combination of Danish, German and Dutch expertise will be a real benefit to the whole project.”