Statoil has, as operator for the Johan Castberg project, distributed a proposed impact assessment program for the largest field yet to be developed on the Norwegian continental shelf (NCS).
“During our improvement work we have created new opportunities for the Johan Castberg field in the far north. We have changed the concept and found new solutions that allow us to realize the project. But we are still vulnerable to increasing costs and a continued low oil price,” says Margareth Øvrum, executive vice president for Technology, Projects and Drilling in Statoil.
Johan Castberg field. Image courtesy: Statoil
The proposed impact assessment program is an essential part of the preparations before a final development plan for Johan Castberg is submitted in 2017, according to schedule. The plan will present the development, relevant development solutions and expected impacts on other businesses and communities. The proposed program is being sent to consultative bodies today to allow them to submit any issues for discussion during the consultation process related to the Johan Castberg impact assessment work.
“The Johan Castberg project may be a central project for further development of the NCS and in the far north. The field will provide significant tax income. The field development and operation will also create new opportunities for the industry throughout Norway and in North Norway in particular,” says Arne Sigve Nylund, executive vice president for Development and Production Norway.
Based on a spin-off report from Agenda Kaupang the Johan Castberg project, based on an investment estimate of between NOK 50 and 60 billion, will represent a significant part of NCS investments in the period 2018-2022. The first phase of the Johan Sverdrup development will be completed in this period. A continued low oil price may affect these plans.
According to Agenda Kaupang’s report the expected value creation in Norwegian supplies of goods and services to Johan Castberg amounts to NOK 29 billion, more than half of the project’s total investments. Value creation in North Norway during the development period is estimated to be NOK 1.7 billion.
“The Johan Castberg field will be producing for more than 30 years, and the major project spin-offs will be created in the long-lasting production phase. Castberg will trigger much activity for suppliers in North Norway and have ripple effects throughout Norway Norway, both in the development phase and the operating phase. In a normal year of operation the Johan Castberg field will generate 1200 man-years in Norway, of which 300 are expected to be in North Norway,” says Nylund.
Recommended power solution for Johan Castberg Statoil has, on behalf of the license, made an extensive analysis of possible power solutions for Johan Castberg. Aker Solutions, Aibel, ABB, Unitech, Pöyry and Thema Consulting have contributed to the power analysis. The power solutions include full and/or partial electrification based on power from land as well as gas-fired power.
Due to the long distance and technical challenges the cost of the measures related to partial/full electrification will be high, from just above NOK 5000 per ton of CO2 to just above NOK 8000 per ton of CO2. Investment costs for full/partial electrification will span from more than NOK 4 billion to just above NOK 12 billion. The Johan Castberg power solution effort reveals that costs related to land-based power, including technical challenges, represent a risk to both the timeline and feasibility of the project.
“We have developed a highly energy-efficient solution involving use of gas turbines for power generation on Johan Castberg. By use of heat recovery we achieve a turbine power efficiency of 64%, which is an outstanding result from use of gas turbines on offshore platforms. The license partners consider gas-fired power to be the most suitable and socio-economic solution for the development,” says Øvrum.
Johan Castberg will be prepared for future electrification by use of alternating current technology in case this becomes an efficient and feasible solution in the future.
Emissions from Johan Castberg by use of gas turbines will be 0.27 million tons of CO2 per year, or 2% of current annual emissions from the NCS.
The proposed impact assessment program covers only the offshore field development, not a possible terminal at Veidnes, which is a separate project with a separate timeline. Statoil is cooperating with the other licenses on Wisting, Goliat and Alta/Gotha to secure sufficient volume and a profitable basis for a terminal.
The Harris Pye Engineering Group has successfully completed repair works during the two-stage multi-million dollar Diamond Offshore demobilisation project for their semi-sub rig Ocean Endeavor from the Black Sea, which completed its contract in January 2016.
The initial phase of the repair work, which started in December 2015, while the rig was offshore Constanta, Romania involved cleaning of mud, brine, base oil and skimmer tanks. Steel repairs were carried out on a main column blister. The removal of three Seatrax crane pedestals, which included the supply and installation of internal steel stiffening to the pedestals, guides and jacking points, plus handling trunnions, were all required prior to cold cutting of the pedestal which coincided with the arrival of the heavy lift crane to remove them.
At work on Ocean Endeavor
Additional work awarded to Harris Pye in Romania was blasting and painting of four primary column ballast tanks. During the surface preparation steel renewal was added to the project - steel frames, piping, access trunks etc, out of which approx 24 tons of steel work was completed in Constanta. The blasting of all four tanks back to white metal was completed, two tanks received a first coat of paint and two tanks were fully coated before Ocean Endeavor departed from Romania to Fincantieri Shipyard in Palermo, Italy via a pre-booked scheduled heavy lift vessel.
“The project was not without its challenges, but we relish those,” explains Harris Pye’s Chief Technical Officer, Chris David. “Painting and blasting of the four ballast tanks had to be performed within a one month period. An additional 40 tons of steel was required to ensure the work on the tanks was completed within the required timeframe; this had to be brought in from other parts of Europe.
“Additionally a mobile diesel high vacuum grit recovery system was shipped from the UK, due to the large distances involved from the ballast tanks to the recovery system onshore for the purpose of disposal.
“All labor was from the local market, with equipment and materials coming from mainland Europe and the UK. Support to the onsite project team was provided by our workshop in Llandow, Wales which undertook any pre-fabrication required, with Harris Pye UK (HPUK) stores (tools and equipment) and the HPUK purchasing department utilizing local suppliers where possible and outsourcing further afield into mainland Europe for items not available locally, to ensure work was able to continue accordingly.
“Once Ocean Endeavor reached Palermo, the Harris Pye repair team mobilized to work on the remaining steel repairs, and painting of the ballast tanks, including an additional contract to repair a section of column diagonal brace. All works were completed on schedule.
“The six-month long project enabled us to use specialist equipment including a 40 cubic meter per minute high pressure oil free compressor (no oil fumes in the compressed air) which worked 24/7; and Falch 2500 bar hydro blasting equipment.”
“The Harris Pye project team had a very methodical and professional approach to all the projects awarded to them,” stated Diamond Offshore Project Manager Dhaval Mehta. “All projects were completed in a timely manner to the satisfaction of Diamond Offshore’s stringent standards, Class and Statutory rule requirements.
“The project team worked very well with all the other vendors involved and was accommodating with certain last minute changes, without impacting on the end results of the project. The entire Harris Pye site team was well focused on customer satisfaction while keeping safety as the primary focus during the entire project. They also actively participated in Diamond Offshore safety meetings and provided valuable input. A job very well done by the entire HP team involved with the Ocean Endeavor demobilisation project.”
Harris Pye has supported Diamond Offshore on several projects in the past and continues to do so to date in order to build on the existing strong business relations between the two companies.
Anadarko Petroleum Corporation (NYSE: APC) announced on Monday, September 12, it has entered into a definitive agreement to acquire the deepwater Gulf of Mexico assets of Freeport McMoRan Oil & Gas for $2.0 billion. The transaction, effective Aug. 1, 2016, is expected to close prior to year end.
"This immediately accretive, bolt-on transaction strengthens our industry-leading position in the Gulf of Mexico and is a catalyst for the company's oil-growth objectives, with quality assets being acquired at an attractive price to create significant value," said Anadarko Chairman, President and CEO Al Walker. "We expect these acquired assets to generate substantial free cash flow,(1) enhancing our ability to increase U.S. onshore activity in the Delaware and DJ basins. Our current plans are to add two rigs in each play later this year, and to increase activity further thereafter, with an expectation of more than doubling our production to at least 600,000 BOE per day collectively from these two basins over the next five years. This increased activity would drive a company-wide 10- to 12-percent compounded annual growth rate in oil volumes over the same time horizon in a $50 to $60 oil-price environment, while investing within cash flows. Additionally, the transaction expands Anadarko's infrastructure in the Gulf, adds to our unmatched inventory of low-cost, subsea tieback opportunities, and bolsters optionality with new exploration prospects. The company's Gulf of Mexico position, with the addition of these properties, will have net sales volumes of approximately 155,000 BOE per day, comprised of approximately 85-percent oil."
Anadarko's operated Lucius facility in the deepwater Gulf of Mexico continues to achieve strong reservoir performance and facility productivity. As a result of this performance, the company is increasing the estimated ultimate recovery of the field to more than 400 million BOE from the previous 300-plus million BOE. Additionally, gross oil sales volumes through the facility recently surpassed 100,000 barrels of oil per day (BOPD). Under the terms of the transaction, Anadarko will increase its working interest in Lucius to approximately 49 percent from its previous 23.8-percent ownership, enabling the company to further capitalize on additional future value-adding opportunities at Lucius.
The acquisition and development cost of the acquired properties, excluding a total of approximately $300 million of materials inventory and seismic, is approximately $13.50 per BOE for the estimated proved reserves to be acquired. The assets are being acquired at an estimated EBITDAX multiple(1)(2) of 1.5 for the expected sales volumes over the coming 12 months, using the current futures strip price for oil and natural gas. Please see the supplemental information available here for additional details on the transaction.
Upon closing, the transaction is expected to add approximately 80,000 BOE per day to Anadarko's sales-volume guidance – more than 80 percent of which is comprised of oil. The company also is expected to increase its 2016 full-year capital guidance, not including the acquisition, to a range of $2.8 to $3.0 billion, primarily reflecting the increased activity in the Delaware and DJ basins.
Jefferies Group LLC and Latham & Watkins LLP are serving as advisors to Anadarko on the acquisition.
Gullfaks Rimfaksdalen (GRD) was scheduled for start-up on Christmas Eve this year, but the project has worked faster and now the field is on stream – at lower costs than planned.
The project delivered is more than NOK 1 billion below the estimate of the plan for development and operation (PDO), reducing costs from NOK 4.8 billion to around NOK 3.7 billion.
"I am pleased to see that the project starts up four months ahead of plan, demonstrating good and efficient project management," says Torger Rød, senior vice president for project development in Statoil.
Image courtesy: Statoil
Over time we have focused on reducing costs and raising the profitability of our projects to ensure long-term activity and value creation on the Norwegian continental shelf (NCS). Based on a smart concept using standard solutions and existing infrastructure, Gullfaks Rimfaksdalen strongly proves that we are on the right track to succeed on this work," continues Rød.
Recoverable reserves are approximately 80 million barrels of oil equivalent, mostly gas. The licensees are Statoil (operator) (51%), Petoro (30%) and OMV (19%).
"The volumes from Gullfaks Rimfaksdalen help us reach our ambition of maintaining production and a high activity level on the NCS beyond 2030. We have a well-developed infrastructure and we will keep realizing opportunities in the North Sea," says Arne Sigve Nylund, executive vice president for Development and Production Norway.
"This development leads to more production, improved value creation and higher activity level on Gullfaks, and also throughout the value chain related to the field," continues Nylund.
The Gullfaks Rimfaksdalen development consists of a standard subsea template with two simple gas production wells, and possibilities for tie-in of two more wells. The well stream is connected to the existing pipeline leading to the Gullfaks A platform.
Gas and condensate are transported in existing pipelines to the processing plant at Kårstø north of Stavanger for processing, and from there the gas is exported to markets on the European continent. Gullfaks Rimfaksdalen is one of Statoil’s fast-track projects, aiming to realize resources quickly and inexpensively, for example by using existing infrastructure while it is still available.
Location: In the North Sea, around 5-15 kilometers southwest of the
Gullfaks A platform
Volumes: around 80 million barrels of oil equivalent (boe) (gas and condensate)
Depths: water depth of around 135 meters, 3200 meters below the seabed
The Gullfaks field is operated from Statoil’s office at Sandsli in Bergen
The Deepwater Horizon oil spill Natural Resource Damage Assessment Trustees will hold a public meeting on September 28, 2016, at the Renaissance New Orleans Pere Marquette French Quarter Area Hotel. The Trustees will present an update on their work since the historic settlement with BP and describe current and future restoration planning activities and opportunities for public engagement. The settlement with BP included a provision for up to $8.8 billion in damages for injuries to natural resources.
The settlement also established seven geographically-focused Trustee Implementation Groups and allocated funds among the groups based upon the type and magnitude of injuries caused in each area. Representatives of the seven Trustee Implementation Groups will give updates on the planning and implementation of restoration projects for the natural resources injured by the Deepwater Horizon oil spill. The groups are responsible for restoration in these geographic areas: Florida, Alabama, Mississippi, Louisiana, Texas, Open Ocean and Region-wide.
This meeting will serve as the first annual meeting of the Trustee Council and the Region-wide Trustee Implementation Group.
The Trustees encourage the public to attend an open house where the Trustees and Trustee Implementation Group members will be available for conversations and questions. The public meeting, beginning at 6:30 PM, will include a presentation and a public comment session.
If you are unable to attend the public meeting, you will be able to view the meeting presentation and transcript on the Trustees’ website soon after the meeting concludes.
The Deepwater Horizon Natural Resource Damage Assessment Trustees represent five states—Florida, Alabama, Mississippi, Louisiana, and Texas—and four federal agencies—Department of the Interior, National Oceanic and Atmospheric Administration, U.S. Environmental Protection Agency, and U.S. Department of Agriculture.
The Trustee Council was established shortly after the oil spill to determine the type and magnitude of injuries caused by the spill to the Gulf of Mexico’s natural resources. Their injury assessment helped to determine the amount of damages BP was required to pay for those injuries. The Trustees also developed a programmatic restoration plan. The settlement funds are allocated in accordance with that plan.
Chet Morrison Contractors’ Deepwater Riser Services division recently completed work on a complex deepwater riser maintenance project for an offshore drilling rig that included complete disassembly, blast, paint and reassembly of 57 risers.
By partnering with the Original Equipment Manufacturer (OEM) on the project, Chet Morrison Contractors was able to deliver key services that allowed for an OEM-recertification on the risers. In addition, by taking advantage of Chet Morrison Contractors’ available shop space and labor capacity, the OEM was able to provide the rig owner with a turn-key solution at a competitive price. This coordination allowed the two companies to maximize their respective resources and areas of expertise for the overall benefit of the client and project.
“We see this as a great example of how Chet Morrison Contractors is able to work effectively with other partners to deliver custom solutions for clients,” said John DeBlieux, Vice President of Deepwater Riser Services. “It is also important to note this project was delivered two weeks ahead of schedule. By combining resources, we were able to offer enhanced value that saved time and money.”
The OEM project lead, Wesley Barnett, stated, “as the OEM, we were very pleased with the overall attention to detail, product knowledge and quality that Chet Morrison Contractors displayed during the entirety of the project.”
Along with the teardown and reassembly of the risers, Chet Morrison Contractors also repaired 15 floatation modules, assisted the OEM with auxiliary line pin and box repairs, conducted hydro/pressure testing of all completed lines and successfully removed stuck set screws from 22 lifting lugs.
Chet Morrison Contractors’ Deepwater Riser Services performs comprehensive services throughout the life cycle of the riser, including inspections or repairs that traditionally require manufacturer support, along with superior safe-harbor storage and maintenance facilities at multiple locations with convenient access to the Gulf.
Maersk Drilling has been awarded a contract for the jack-up rig Mærsk Gallant with Maersk Oil. The contract covers the plugging and abandonment of the Leadon and James subsea fields in the UK sector of the North Sea. The duration of the contract is estimated to 230 days, with commencement in February 2017. The estimated contract value is USD 24m.
“Despite an extremely challenging market, I am glad to say that Maersk Drilling is still able to secure new contracts for our rigs. By focusing on operational excellence and technical problem solving, we strive to always be a trusted and value-adding partner for our customers,” says Michael Reimer, Head of Global Sales in Maersk Drilling and continues.
“Maersk Drilling has extensive experience with plugging and abandonment operations, and we are looking forward to working closely together with Maersk Oil to safely decommission the two subsea fields, Leadon and James.”
Mærsk Gallant is about to complete its current contract with Total E&P Norge A/S. The rig is designed for year-round operation in the North Sea, in water depths up to 120 m (394 ft) with an available leg length below hull of 138.5 m (454 ft). The rig is fully equipped for high pressure/high temperature drilling (HP/HT).
GE’s Marine Solutions business (NYSE: GE) and Zentech Inc. announced the signature of a cooperation agreement under which the two parties will work together to provide advanced vessels for their marine and offshore customers.
Covering a range of vessel types, including self-elevating lift boats, drill ships and semi-submersibles, the agreement leverages the strong capabilities from both companies. While Zentech will contribute with its in-depth knowledge and extensive experience in design, GE’s Marine Solutions business will provide smart and advanced engineering expertise and technology in power generation, propulsion and control.
The Z-210 is a self-propelled, self-elevating, DP-2 capable, ABS Class, high-temperature (55 degrees Celsius) rated, four-legged mobile offshore unit.
Both GE and Zentech Inc. are working together to solve the challenges faced by the industry and meet customer demands for greater levels of coherence in vessel and system design while simultaneously striving to reduce the cost of construction and overall cost of ownership. The landmark long-term deal has already started to bear results with a first implementation contract, which sees GE set to deliver its electric power and propulsion, dynamic positioning and vessel control system solutions for Zentech’s Z-210, currently under construction at CSSC Huangpu Wenchong Shipbuilding Company Limited in China.
The Z-210 is a self-propelled, self-elevating, DP-2 capable, ABS Class, high-temperature (55 degrees Celsius) rated, four-legged mobile offshore unit capable of operating in water depths of up to 280 feet. Scheduled for delivery in 2018, the Z-210 addresses the growing needs for lift boats in the Middle East, Southeast Asia and Far East markets where the production, well intervention and platform support activities require the capability for a wide range of water depths from as shallow as 13 feet all the way up to 280 feet.
Zentech Inc. is a Houston-based marine engineering and naval architecture firm that enjoys a global presence and a deep industrial expertise, which encompasses dynamically positioned semi-submersibles, drill ships, jack-up drilling units, modular platform drilling rigs, barge rigs, fixed offshore platforms, floating production systems, risers and pipelines.
Ramesh Maini, president and CEO of Zentech commented, “This is a defining moment in the evolution of Zentech as one of the world’s leading designers of advanced offshore solutions. As specialist designers, we are proud to be working with GE and look forward to incorporating the best of what GE has to offer into our customers’ future vessels. It’s a great prospect for Zentech, and we strongly believe that this collaboration will provide immeasurable value for our customers.”
“We are committed to meeting the operational requirements of ship operators and marine companies. Thanks to the GE Store, GE’s Marine Solutions business has one of the broadest capabilities within the industry. From prime movers, smart automation and control systems to software analytics, we are able to provide a fully integrated solution for our customers to lower project risk and cost of ownership,” said Tim Schweikert, president & CEO, GE’s Marine Solutions business. “We are very much looking forward to working with Zentech on this project and in the future.”
On Monday September 19, minister of petroleum and energy Tord Lien together with Statoil, Centrica and ExxonMobil celebrated the 5 billion barrels of oil equivalent delivered by Statfjord since first oil in 1979.
The minister got the honor of filling the barrel, which was decorated in golden color for the occasion.
“The spin-offs created by Statfjord can hardly be exaggerated. Generating more than NOK 1500 billion in revenues and 200 000 direct and indirect man-years since the 1970s the field has been of great importance to the Norwegian society,” says Arne Sigve Nylund, Statoil’s executive vice president for Development and Production Norway. He took part in the celebration on Statfjord A.
After Statfjord has been on stream for more than a generation Statoil and its partners still have a horizon until 2025 for the field. Originally the partnership hoped to recover 40 percent of the oil at Statfjord. The result so far is record-high 67 percent.
451 wells have been drilled on the field, and more than 40 years after the field was discovered new profitable wells are still being drilled. (Photo: Harald Pettersen)
The additional resources recovered beyond what was initially believed to be possible equal the lower production estimate for Johan Sverdrup.
“On this is a historic day we take a retrospective view. This, however, is also a story about the future, describing how knowledge, skills and experience acquired through many years across the oil industry are harnessed to create ever more values and new activity. Statfjord was supposed to be shut down more than ten years ago. Instead technology development, smart solutions and clever decisions have extended the productive life and increased the level of activity. This is characteristic of Norwegian oil history and something we will build on in Statfjord’s next chapter and on the NCS for many decades to come,” Nylund says.
NOK 23 billion was invested, and production was maintained during the conversion process. The work included the drilling of 70 new wells and extensive modifications to the platforms. The high recovery factor is largely thanks to the Statfjord Late Life project, lifting the horizon towards 2025. This means that the old oil giant Statfjord will still be producing when a new giant by the name of Johan Sverdrup has started its 50-year production.
Statfjord field partners: Statoil Petroleum AS (44.34 % - operator), ExxonMobil Exploration and Production Norway AS (21.37 %), Centrica Resources (Norge) AS (19.76 %) and Centrica Resources Limited (14.53 %).
Danos’ Amelia-based custom fabrication yard recently completed the interconnect piping and production deck extension for a client’s deepwater platform in the Gulf of Mexico. The deck’s installation was the culmination of a two-year process in which Danos worked closely with the client to design and fabricate the 165-ton, fully-integrated production deck extension.
“This project is a great example of how our integrated line of services benefits our customers,” said Mark Danos, vice president of project services. “We’re proud to have met or exceeded every delivery fabrication milestone with zero recordable safety incidents.”
Several Danos service lines supported the project, including fabrication, project management, automation, scaffolding, construction and coatings. In addition to the deck structure, 550 pipe spools were fabricated, with more than 100 installed on the extension. The automated services division supplied panel fabrication, while the project management team coordinated the planning and support of the workpack.
Following the installation and completion of the project, the customer recognized Danos for achieving “Quad Zero.” This means that throughout the 100,000 project man-hours, the company logged zero recordable safety incidents, zero lost time, zero work days and zero motor vehicle accidents.
Award-winning technology developed in the east of England is to be presented as a cost-saving solution for North Sea decommissioning at a major industry conference in Scotland this week.
Scour Prevention Systems will showcase how its patented scour prevention mats using end-of-life tires offer alterative effective protection for decommissioning oil and gas pipelines to delegates at this week’s Decommissioning: Technology Innovation Platform event hosted by Decom North Sea and the Oil and Gas Innovation Centre.
The company, based at OrbisEnergy, Lowestoft, is one of 10 companies chosen to present technology that has the potential to help companies achieve the 35% decommissioning cost reduction targeted by the Oil and Gas Authority (OGA).
Speakers at Thursday’s event at Aker Solutions’ building in Dyce, Aberdeen, include Colette Cohen, chief executive of the Oil and Gas Technology Centre, and Jim Christie, OGA head of decommissioning. Scour Prevention Systems’ John Best and Alistair Punt will explain to delegates the potential savings of tire mats compared to traditional methods such as concrete mattresses or rock armor.
They take less time to install, have no threat of pipeline damage and need no direct remedial works. Furthermore, with an increasing number of cables of offshore wind being installed, the mats provide an effective crossing bridge at an interface with a decommissioned pipeline, they will tell delegates.
“Our aim is to raise awareness that our product is out there as a proven, market-ready and cost effective solution to be considered when people planning decommissioning are evaluating solutions,” said Mr. Best. “Our technology of matrices of recycled vehicle tires has proved to be very successful and is something we believe potential users need to be made aware of so they have a wider choice.”
“When pipelines are being decommissioned, our mats’ design helps to reinstate seabed cover and leave the pipeline secure and protected in a non-obtrusive manner.”
“The product effectively stabilize the seabed over pipelines forming a secure protective layer, protecting the pipeline from exposure and damage, providing a cost effective and easy-to-install solution to pipeline decommissioning.
The mats have been trialed and successfully demonstrated in the North Sea and used to remediate and prevent further scour around offshore wind foundations, and protecting telecoms cables subsea infrastructure.
Lightweight and modular, they require one-off installation without divers or trenching and provide a smooth contour created by the unique properties of the patented design. The mats also protect the pipeline from dragged anchors, fishing equipment and hydrodynamic forces.
Scour Prevention Systems have developed their effective product range, consulting with industry, clients and with assistance from research bodies including expert advice from the Offshore Renewable Energy Catapult. They also secured a SCORE grant to help it take its technology to the next phase two years ago and support the development of appropriate lifting and decommissioning procedures
A new £6m SCORE program launched earlier this year at OrbisEnergy will help companies develop their innovations.
The tire mat invention was a previous winner of the East of England Energy Group’s (EEEGR) Innovation Award.
Mr. Best, a former EEEGR CEO, said: “I am particularly delighted that, in my previous role with EEEGR, Scour Prevention Systems’ mats was an innovation award winner and seeing it moving forward into the industrial deployment is particularly exciting.”
Statoil aims to conduct a major exploration campaign in several parts of the Barents Sea in 2017. The company is also strengthening its position in the area through several transactions with other companies.
“We have worked systematically on developing an exploration portfolio for testing good and independent prospects in 2017 and 2018. For 2017 we see promising prospects in different parts of the Barents Sea. For example, we want to explore the Blåmann prospect in the Goliat area, Koigen Central in PL718 on Stappen High and the Korpfjell prospect in PL859 that was awarded in the 23rd licensing round,” says Jez Averty, Statoil’s head of exploration on the Norwegian continental shelf (NCS).
Image courtesy: Statoil
In addition to an exploration well in PL849 (Blåmann), awarded in the Award in Predefined Areas (APA) in January 2016, Statoil and the operator ENI have also agreed on drilling a new exploration well in PL229 (Goliat) in 2017. Statoil has already a rig on contract which is suitable for operation in the Barents Sea. The company is working on obtaining approval from partners and authorities for an exploration campaign in 2017 covering between 5 and 7 wells in the Barents Sea.
During the past months Statoil has entered or increased its share in five licences in the Norwegian part of the Barents Sea by a number of agreements with Point Resources, DEA, OMV and ConocoPhillips.
“Giving us access to new acreage, the transactions demonstrate our belief in continued exploration potential on the NCS. We have played a leading role in the Barents Sea for 40 years, and we are still a guarantee for high activity in the area,” indicates Averty.
New and major discoveries are crucial to maintain the current NCS production level up to 2030 and beyond. The areas off North Norway will play a key role in reaching this ambition.
“Through these agreements we are strongly increasing our presence in the Hoop area, we are fortifying our position around Johan Castberg, and we see new opportunities in the southwestern part of the Barents Sea,” says Averty.
Statoil completed a comprehensive exploration campaign in the Barents Sea in 2013-2014 without any impact discoveries, but with additional volumes to Johan Castberg through the Drivis discovery. Exploration is a long-term process requiring patience, and information from the previous campaign has been used to further deepen the company’s understanding of the petroleum potential of the Barents Sea.
“We are working actively on replenishing our exploration portfolio through government awards, developing new ideas in existing licences and making agreements with other companies on acquiring licences. This provides a good basis for exploring more interesting opportunities,” says Averty.
“We have also worked efficiently on reducing costs by developing new technology, such as Cap-XTM, and improving drilling efficiency. The wells to be drilled in the south-eastern part of the Barents Sea next year seem to be the most inexpensive offshore exploration wells throughout Statoil,” continues Averty.
Through the Barents Sea Exploration Collaboration (BaSEC) the industry has formed a good basis for carrying out safe and consistent drilling operations. The industry’s joint seismic data gathering in 2014 further demonstrates its will and ability to solve common issues efficiently while taking into account other interests in the same areas.
All agreements are subject to government approval.
| Seller | Licence | Area | Share | New Statoil Share |
|---|---|---|---|---|
| Point Resources | 722 | Hoop | 35% | 35% |
| ConocoPhillips Skandinavia AS, OMV (Norge) AS | 615 | Hoop | 25%/ 20% | 80% |
| ConocoPhillips Skandinavia AS, OMV (Norge) AS | 615B | Hoop | 25%/ 20% | 80% |
| ConocoPhillips Skandinavia AS, DEA Norge AS | 718 | Stappenhøyden | 30%/ 10% | 60% (operator) |
| ConocoPhillips Skandinavia AS, DEA Norge AS | 720 | Stappenhøyden | 30%/ 10% | 60% (operator) |
Statoil has, on behalf of the license partners, decided to exercise the option for engineering, procurement, construction and installation (EPCI) of a gas module that will increase gas processing capacity on the Troll B platform.
The contract has a value of approximately NOK 370 million, and is an option in a front-end engineering and design (FEED) contract awarded to Aker Solutions in January 2016.
“The gas module is an important contribution to reaching the licensees’ IOR ambition for the Troll field. It will raise production capacity on Troll B and help us recover as much as possible of remaining resources during tale end production. From the module starts up in the autumn of 2018 until Troll B is shut down in 2025 it will increase recovery by around 4.7 million barrels of oil,” says project director Eric Normann Ulland.
The engineering work will be carried out by Aker Solutions in Bergen and module construction will start at Aker’s yard in Egersund in 2017. Weighing just above 500 tons, the module is scheduled to be lifted onto Troll B in the spring of 2018 and become operational in the third quarter of 2018.
The Troll Field
The Troll field lies in the northern part of the North Sea, around 65 kilometers west of Kollsnes, near Bergen.
The field comprises the main Troll East and Troll West structures in blocks 31/2, 31/3, 31/5 and 31/6.
Containing about 40 per cent of total gas reserves on the Norwegian continental shelf (NCS), it represents the very cornerstone of Norway’s offshore gas production.
Troll is also one of the largest oil fields on the Norwegian continental shelf. In 2002 the oil production was more than 400,000 barrels per day.
Statoil operates the Troll A, B and C platforms and the landfall pipelines, while Gassco is operator for the gas processing plant at Kollsnes on behalf of Gassled. Statoil is technical service provider for Kollsnes operations.
The enormous gas reservoirs lying 1,400 meters below sea level are expected to produce for at least another 70 years.
Proven in 1979
Norske Shell was chosen as operator when block 31/2 was awarded in April 1979. A large gas find with an underlying oil zone was proven later that year. The block was declared commercial in 1983.
The neighboring blocks were awarded to Statoil, Norsk Hydro and Saga Petroleum in 1983. Block 31/2 contains 32 per cent of the Troll field’s reserves, while the remaining 68% lies in the three other blocks.
The license terms for block 31/2 specified that Statoil could take over as operator for this acreage eight to 10 years after a discovery had been declared commercial.
In 1985, the two licenses were unitized so that Troll could be developed as a single field.
Statoil took over as production operator for Troll Gas on 19 June 1996, while Hydro started production from Troll Oil in the fall of 1995.
The National Oceanography Centre (NOC) has launched a new collaborative way of working with the oil and gas industry. NOC will provide innovative science and technology to enable industry to work safely and efficiently, with minimum impact on the marine environment.
The launch comes off the back of many years of working with the industry on both an individual and collaborative basis, to develop science and technology to enhance competitive advantage, maximize investment and reduce operational costs during exploration, production and decommissioning. NOC has unique expertise in marine autonomous and robotic systems and sensors, for operations in challenging, hazardous and deep-sea environments. NOC’s fleet of Autonomous Underwater Vehicles, Remotely Operated Vehicles, Unmanned Surface Vehicles and submarine gliders have all been developed to operate in extreme conditions. NOC’s science teams have had many years of experience in testing and demonstrating the capabilities of our autonomous platforms and sensors, in such hazardous environments.
NOC Associate Director, Innovation and Enterprise, Kevin Forshaw commented “Building on our existing relationships, we are hoping that this offer will encourage more oil and gas companies to develop long-term relationships with us, as we believe there are benefits to be gained on both sides. With the many challenges facing the industry, companies are recognizing the value of novel science and technology, to create real business value. By accessing external funding opportunities and joint-industry funding, companies are benefiting from responsive and flexible innovations to drive down operational costs, maximize existing investments, access and share innovation expertise, and respond to government fiscal and environmental regulations.”
The collaboration package is an annual subscription which includes access to efficient, authoritative and rigorous science research services, responsive to the industry’s needs, expert interpretation of valuable data-sets, access to software and data-products and alerts for public funding opportunities. Collaborators will also have Associate Membership of the NOC’s Marine Robotics Innovation Centre.
For more information about this project, the NOGIC website can be found here.
Shell announced on Tuesday, September 6, 2016, that production has started from the Stones development in the Gulf of Mexico. Stones is expected to produce around 50,000 barrels of oil equivalent per day (boe/d) when fully ramped up at the end of 2017.
The host facility for the world’s deepest offshore oil and gas project is a floating production, storage and offloading (FPSO) vessel. It is the thirteenth FPSO in Shell’s global deep-water portfolio and produces through subsea infrastructure beneath 9,500 feet (2,900 meters) of water. Stones underscores Shell’s long-standing leadership in using FPSOs to safely and responsibly unlock energy resources from deep-water assets around the world.
Stones is the world’s deepest oil and gas project, operating in around 2,900 meters (9,500 feet) of water in an ultra-deep area of the US Gulf of Mexico. Photo courtesy: Shell
“Stones is the latest example of our leadership, capability, and knowledge which are key to profitably developing our global deep-water resources,” said Andy Brown, Upstream Director, Royal Dutch Shell. “Our growing expertise in using such technologies in innovative ways will help us unlock more deep-water resources around the world.”
Stones, which is 100% owned and operated by Shell, is the company’s second producing field from the Lower Tertiary geologic frontier in the Gulf of Mexico, following the start-up of Perdido in 2010.
The project demonstrates Shell’s commitment to realizing significant cost savings through innovation. It features a more cost-effective well design, which requires fewer materials and lowers installation costs; this is expected to deliver up to $1 billion reduction in well costs once all the producers are completed.
The FPSO is also specially designed to operate safely during storms. In the event of a severe storm or hurricane, it can disconnect and sail away from the field. Once the weather event has passed, the vessel would return and safely resume production.
Shell’s global deep water business is a growth priority for the company and currently produces 600,000 boe/d. Deep-water production is expected to increase to more than 900,000 boe/d by the early 2020s from already discovered, established reservoirs. Three other Shell-operated projects are currently under construction or undergoing pre-production commissioning: Coulomb Phase 2 and Appomattox in the Gulf of Mexico and Malikai in Malaysia.
- Visit the Stones project page to watch a film and download fact sheets
Semco Maritime has been awarded a contract on Atex Management Services including software supplied by SafeEx for inspection of approximately 30,000 pieces of equipment in Maersk Oil's Culzean project.
After a bidding round, it is official that Semco Maritime will be suppliers of a system based on the SafeEx Software for inspections in Maersk Oil's Culzean gas field. The software will be used to perform the initial Ex-inspections on a production platform, which consists of a residential platform, a process platform, a wellhead platform and a FSO operating in the field.
Though the system initially will be used for Ex-inspections, there is a further desire to use it for mechanical completion and other maintenance and inspection tasks. The system will be integrated to Maersk Oil’s ERP systems SAP and technical completion system PIM360.
SafeEx’ tablet-based inspection and maintenance software allows you to perform all routines in one procedure.
- The advantage of the SafeEx Software is that the system provides a uniform way to make inspections that increases safety and save 30 to 60 percent on man-hours, says Market and Business Development Manager Erik Grønborg from Semco Maritime, who for years has designed and produced equipment for Maersk Oil.
SafeEx’ tablet-based inspection and maintenance software allows you to perform all routines in one procedure. Technologically it is the leading solution on the market right now.
A standard rig or platform typically have 30 to 40 different checklists for inspections, but the SafeEx Software converts these checklist into electronic tasks. The tasks are conducted in guidance from the hand-held tablet using integrated layout drawings. This gives a significant reduction in the number of man-hours.
Each piece of equipment has a RFID chip installed, which is approved for Ex zone 1. This enables the software in the handheld device to create an electronic time-stamp and a full electronic audit trail. After each completion of an inspection, all information is instantly available online both off-shore on the unit and among the onshore management.
- Our mission with the tablet-based software solution has been to streamline work procedures of inspections, in order to make them faster, easier and more cost-effective in performance. In addition, there is the whole safety aspect in which our software provides a full overview of the maintenance condition, explains CEO Henrik Andersen from SafeEx.
The contract with Maersk Oil is one of the largest installation in terms of number of equipment that SafeEx has ever won. Besides the fact that the system will be used at Maersk Oil, the DNV GL-verified SafeEx Software is being used for inspections at among others Petronas, Statoil, Dong Energy, Seadrill, Noble, BW Offshore, Aker Solutions and Arla Foods.
The Maersk Oil operated Culzean project is located about 145 miles east of Aberdeen and is one of the largest gas discoveries in the UK North Sea.
The first gas from the project is expected in 2019 and it is expected to provide for around five percent of UK’s total gas consumption by 2020/21 with a peak production rate of 400 to 500 million standard cubic feet per day.
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