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.
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.
PJ Valves (PJV), a specialist manufacturer and supplier of valves to the global energy industry, has been awarded more than £1 million worth of contracts to supply over 1,000 valves to Maersk Oil’s Culzean field in the UK North Sea.
PJV will manufacture forged cast gate globe and check valves in super duplex and super alloys for the well head, living and central processing platforms. The company will also supply wafer check valves to prevent fluid backflow on these facilities. PJV was awarded the contract because of its extensive North Sea experience and specialist Italian manufacturing capabilities, which meet the project’s high standards for quality.
Spencer Linsell, Sales Director at PJV, says: “We’re delighted to be working on such a historic project. This contract is validation of our global territory model whereby we build relationships with project teams in each region. Furthermore, our European manufacturing expertise in forged steel produces the highest quality of valves for frequent use in the most demanding industry applications.”
The valve package is scheduled to be delivered in 2017. Because of the success of the front-end scope, PJV has subsequently been awarded contracts for the compressor, metering and water treatment packages.
The Culzean gas field is expected to reach a peak production rate of 400 to 500 million standard cubic feet per day, providing for around 5 per cent of the UK's total gas consumption by 2020.
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.
Shell announced on July 28, a new exploration discovery in the deep water U.S. Gulf of Mexico. The initial estimated recoverable resources for the Fort Sumter well are more than 125 million barrels of oil equivalent (boe). Further appraisal drilling and planned wells in adjacent structures could considerably increase recoverable potential in the vicinity of the Fort Sumter well.
Fort Sumter map: Courtesy: Shell
“The Fort Sumter discovery builds upon Shell’s global deep-water leadership. Its proximity to our nearby discoveries in the area, and to highly prospective acreage to the southeast, makes Fort Sumter particularly significant,” said Ceri Powell, Executive Vice President Exploration. “These successes demonstrate there is still running room in the producing basins of our heartlands where large, high-value discoveries have the potential to further strengthen our deep-water competitiveness.”
Fort Sumter was safely drilled in the Mississippi Canyon Block 566, located approximately 73 miles (117 kilometers) offshore southeast of New Orleans, in a water depth of 7,062 feet (2,152 meters) to a total vertical drilling depth of 28,016 feet (8,539 meters) measured depth. The block is nine square miles (23 square kilometers) in size and is operated by Shell (100%). An appraisal sidetrack well was later drilled to a depth of 29,200 feet (8,900 meters) measured depth.
Shell’s material discovery in this heartland builds upon recent Norphlet exploration success at the Appomattox (2010), Vicksburg (2013), and Rydberg (2014) discoveries, bringing the total resources added by exploration in the Gulf of Mexico for Shell since 2010 to around 1.3 billion boe.
Shell global deep water, which is a growth priority for the company, currently produces around 600 thousand boe per day, and production is expected to increase to about 900 thousand boe per day by the early 2020s from already discovered, established reservoirs.
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.”
Statoil ASA (OSE:STL, NYSE:STO) and Petróleo Brasileiro S.A. - Petrobras (“Petrobras”) (BVMF: PETR4, NYSE:PBR) have agreed that Statoil will acquire Petrobras’ 66% operated interest of the BM-S-8 offshore license in Brazil’s highly prolific Santos basin. The acquisition includes a substantial part of the Carcará oil discovery, one of the largest discoveries in the world in recent years.
Carcará was discovered in 2012, on the geological trend of the nearby Lula field and Libra area. It is a world-class discovery of high-quality oil of around 30° API and with associated gas in a thick reservoir with excellent properties. It straddles both BM-S-8 and open acreage to the north, which is expected to be part of a license round in 2017. Statoil is well positioned for operatorship of a unitized Carcará field following this transaction and the license round will provide an opportunity to scale up the position in the field. Statoil estimates the recoverable volumes within the BM-S-8 license to be in the range of 700 to 1,300 million boe.
In addition to the Carcará discovery, BM-S-8 holds exploration upside that may significantly increase its resource base. The license is in its final exploration phase with one remaining exploration commitment well to be drilled by 2018.
“Through this acquisition we are accessing a world class asset, and we strengthen our position in Brazil, one of Statoil’s core areas due to its large resource base and excellent fit with our technology and capabilities. The Carcará field will significantly enhance our international production volumes in the 2020s and beyond. We are developing a strong Brazilian business with a broad portfolio, material production, high impact exploration opportunities and excellent potential for long term value creation and cash flow,” says Eldar Sætre, president and chief executive officer of Statoil.
The total consideration for the acquisition is USD 2.5 billion. Half of it will be paid upon closing of the transaction, with the remainder being paid when certain milestones have been met. These are partly related to the license award, but mainly to the future unitization of Carcará. The effective date for the transaction is 1 July 2016. Closing is subject to customary conditions, including partners’ and government approval.
Statoil and Petrobras are also in discussions regarding a long-term strategic cooperation. The focus will be in the Campos and Espírito Santo basins, as well as new cooperation within gas and technology projects in the Santos basin.
| Location | Interest | Status | |
|---|---|---|---|
| Peregrino | Campos basin | 60% (operator) | Production at 100,000 barrels a day Reserves of 300-600 million barrels of oil |
| Peregrino Phase II | Campos basin | 60% (operator) | Construction Production from 2020 at c. 60,000 barrels a day Reserves ~255 million barrels of oil |
| License BM-C-33 comprising the Pão de Açúcar, Gavea and Seat discoveries | Campos basin | 35% | Evaluation/development gas Approximately 1bn boe in recoverable reserves. |
| Eight exploration blocks | Espírito Santo basin | Four operated by Statoil, four by Petrobras | Exploration |
| License BM-S-8 comprising the Carcará discovery and exploration prospects | Santos basin | 66% and operator after transaction |
Statoil has been in Brazil since 2001. This year marks five years of production at the Statoil-operated Peregrino field. Peregrino Phase II is due to commence production in 2020, and in the third quarter of 2016 Statoil expects to assume operatorship of license BM-C-33 in the Campos basin which includes the Pão de Açúcar discovery. Statoil also has interests in eight licenses in the Espirito Santo basin, working in partnership with Petrobras, and expects to spud its first exploration wells during 2017. It has developed a strong local organization with nearly 90% of its workforce from Brazil and its operations have so far created 1,000 direct jobs. The addition of BM-S-8 to Statoil’s Brazil portfolio will help deliver profitable growth through greater operational flexibility and efficiencies.
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.
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.
The AUGUST 2016 MTS Houston Section luncheon will be held on August 25, 2016 and will feature a presentation by Stephen Whitaker, Project Director for Hess’s Stampede Development. Mr. Whitaker will provide an update on the development of this deepwater field.
The Hess-operated Stampede deepwater oil and gas field is one of the largest un-developed fields in the Gulf of Mexico, with gross recover- able reserves estimated in the range of 300-350 million barrels of oil equivalent.
Discovered in 2005, the field is located in Green Canyon Blocks 468, 511 and 512 in the Gulf of Mexico in 3,500 feet of water, 115 miles south of Fourchon, Louisiana. Oil and gas reserves at Stampede are located within the Miocene reservoirs at a depth of approximately 30,000ft.
The front-end engineering and design (FEED) for the project started in the second quarter of 2013 with the final investment decision (FID) made in October 2014.
The project leverages Hess’s proven capability to safely execute deepwater development projects and top-quartile performance in offshore drilling and project delivery. It is scheduled to come onstream in 2018 and is expected to provide a significant contribution to Hess’ future growth. Production facilities will consist of subsea production and injection wells tied back to a single Tension Leg Platform. Gross topsides processing capacity for the project is approximately 80,000 barrels of oil and 100,000 barrels of water injection capacity per day. Hess, the operator, has a 25 percent working interest in the field, alongside its co-owners – Union Oil Company of California, a Chevron subsidiary, Statoil, and Nexen, which each hold a 25% interest.
At the August luncheon, Stephen Whitaker, Hess’s project director for Stampede will provide an update on the development, along with some of the challenges and accomplishments.
Stephen Whitaker is Project Director, Offshore - Stampede Deepwater Development for Hess Corporation, a global independent energy company engaged in the exploration and production of crude oil and natural gas. In this role, Whitaker is responsible for managing the development of the Stampede oil and gas field. Prior to this he was responsible for developing Hess’s subsea assets in the Gulf of Mexico and West Africa, and in expanding the role of the Subsea Development Group to Hess assets offshore Europe and in the Asia Pacific region.
Before joining Hess in 2005, Whitaker worked for J.P. Kenny, where he held a number of technical and managerial positions around the globe, culminating in his position as CEO of J.P. Kenny in Houston in 1998.
Whitaker has also held a variety of positions with BP, Technip and Atkins. He started his career in the UK with Horizon Exploration after graduating from the University of Wales Institute of Science and Technology in 1980.
September 22, 2016 – Lunch – Topic to be confirmed
October 10-12, 2016 - Dynamic Positioning Conference, Westin Memorial City, Houston
October 27, 2016 - MTS Houston Annual Barbecue Social - Seanic Ocean Systems
March 25, 2017 - Sporting Clays - American Shooting Center
Venari Resources LLC (“Venari”), a deepwater oil exploration and production company in the Gulf of Mexico, announced today that it has acquired an additional seven percent working interest in the Shenandoah field on Walker Ridge Blocks 51, 52 and 53. The company also reported successful results from the Shenandoah #5 appraisal well.
Map courtesy: Venari Resources
The Shenandoah #5 well was drilled on Walker Ridge Block 51 in approximately 5,900 feet of water to a total depth of 31,100 feet. The well was drilled up-dip of the Shenandoah #2 appraisal well and was designed to confirm and extend reservoir boundaries. The well encountered over 1,000 net feet of high-quality oil pay in the Lower Tertiary Wilcox sands and extended the field further east. The next appraisal well, Shenandoah #6, is expected to spud later this year to further quantify the full resource potential of the field. Earlier this year, Venari increased its working interest in the Shenandoah Unit to 17% from 10%.
“With a high-quality reservoir and substantial net oil pay, the well results confirm Shenandoah to be a significant oil accumulation,” said Brian Reinsborough, President and Chief Executive Officer of Venari. “We are excited that we were able to increase our ownership in the field and continue building our relationship with Anadarko across this strategically important region.”
In partnership with Anadarko Petroleum Corporation, the operator of Shenandoah, Venari owns significant working interests in several exploration prospects proximate to the Shenandoah discovery.
Venari holds a 17% working interest in Shenandoah. Other co-owners are Anadarko Petroleum Corporation (NYSE: APC), as operator (33%), ConocoPhillips Company (NYSE: COP) (30%), and Cobalt International Energy, L.P. (NYSE: CIE) (20%).
Venari Resources, a privately held offshore exploration and production company founded in 2012 by deepwater E&P expert Brian Reinsborough, is focused on the prolific oil-prone subsalt region in the Gulf of Mexico’s deep waters. Since its formation, preeminent global investment firms led by Warburg Pincus, Kelso & Company, Temasek, and The Jordan Company have committed $2.4 billion of capital to Venari’s exploration program and development projects. Venari has built a large inventory of drillable prospects and leases in the Gulf of Mexico including the Shenandoah discovery in the Walker Ridge area, the Anchor discovery in Green Canyon and the Guadalupe discovery in Keathley Canyon. The Company is headquartered in Dallas and has an additional office location in Houston.
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