Airborne Oil & Gas announces the start of a project to qualify Thermoplastic Composite Pipe (TCP) for a deepwater jumper spool application for French operator Total.
The non-corrosive and spoolable Thermoplastic Composite Pipe (TCP) is Airborne Oil & Gas’ answer to today’s industry call for cost effective spools, well jumper, flowline and riser solutions to deal with corrosive fluid conditions and deep water environments: TCP Flowlines, Jumpers and Risers are flexible, corrosion free, light weight and have high strength and thus enable a significant reduction in total installed cost. For the deepwater spool application, the TCP offers the possibility to save time and cost due to the inherent flexibility of the product. TCP allows installation without high-precision subsea metrology, as is the case for rigid steel spools.
The Airborne Oil & Gas’ TCP that will be qualified on this project targets deep water applications. Client Total foresees the first application by the company to be for water injection well jumpers: “The possibility with TCP to handle large deflections, the ability to cut-to-length and terminate the pipe at location and the subsequent installation with small vessels, make a compelling business case for TCP jumpers. We estimate we can achieve considerable cost savings by using TCP jumpers” says Frédéric Garnaud, R&D Deep Offshore Program Manager with Total.
Airborne Oil & Gas has been working with Total in the development of TCP since the start of the Cost Effective Riser Thermoplastic Composite Riser JIP in 2009. “The start of this project underpins our long-lasting relationship with Total. It demonstrates their trust in Airborne Oil & Gas’ ability to provide cost effective solutions that address the challenges of today’s SURF market” says Bart Steuten, Business Development Manager with Airborne Oil & Gas.
The project includes the manufacturing and qualification testing of full-scale (6 inch ID) prototypes and is planned to deliver qualification to DNVGL standard RP-F119 in Q1 2017.
The world’s first subsea gas compression system has now been in operation for one year on the Åsgard field. The system has been running like a Swiss clock with practically no stops or interruptions.
lllustration of Åsgard subsea gas compression. Image credit: Statoil
It was in September 2015 Statoil and its partners started up the world’s first subsea gas compression system on the Åsgard field in the Norwegian Sea.
“Quality in all sections of the project and also during operation has contributed to maintain a system regularity of close to 100% through its first year of operation,” says Halvor Engebretsen, vice president for Åsgard operations.
“Before start-up we carried out extensive testing, commissioning and verification of the technology, and thereby we could remove errors and weaknesses before the installation was placed on the seabed. We have already benefitted from this effort by stable and good operation,” he continues.
With this new and ground-breaking technology, the recovery from the Mikkel and Midgard reservoirs has been increased by as much as 306 million barrels of oil equivalent (boe), corresponding to a medium-sized field on the Norwegian continental shelf (NCS) and extending the fields’ life to 2032.
“During the first year of operation we have raised production by an excess of 16 million boe. Based on today’s prices the value added amounts to more than NOK 5 billion,” says Engebretsen. The recovery rate from the Midgard and Mikkel reservoirs on Åsgard has been raised from 67% to 87% and from 59% to 84% respectively.
“Åsgard subsea gas compression is one of Statoil’s most radical innovation projects. The technology represents a quantum leap that may contribute to considerable improvements in both recovery rate and lifetime for a number of gas fields.
The technology that has been in operation for a year was matured through many years by strong in-house expertise. In close collaboration with suppliers such as Aker Solutions, MAN and Technip, Statoil has qualified more than 40 new technologies.
“We have built test facilities at K-lab, storage and maintenance capacity at Vestbase, and we have access to ships that are capable of handling installation of large subsea modules. By reusing this technology, we have great opportunities for simplification and efficiency improvements, and for reducing carbon footprints of future gas compression systems,” explains Engebretsen.
The technology also represents a significant reduction in energy consumption and carbon emissions in a lifecycle perspective on Åsgard, compared to a compression platform. This technology represents a potential for further carbon reductions through use in future subsea solutions.
Åsgard Subsea Gas Compression video: Watch here
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.
The Dresser-Rand business, part of Siemens Power and Gas Division, recently delivered power generation equipment for a combined cycle power plant (CCPP) for the Shell Appomattox deep-water oil and gas floating production platform. The platform will be located 80 miles off the coast of Louisiana in the Gulf of Mexico and is slated to start production around the end of this decade. The ~150 megawatt (MW) CCPP will feature four 27 megawatt (MW) gas turbine-driven generator sets equipped with heat recovery systems and a 40 MW steam turbine generator.
Photo courtesy: Dresser-Rand
The gas turbine gen-sets are self-contained mini-modules complete with all electrical wiring, piping, tubing and controls. The gen-set, ancillary equipment and baseplate remain connected after unit testing, substantially reducing the time required to install, commission and start-up the packages.
With CCPPs, a gas turbine generator produces electricity while the waste heat from the gas turbine is used to make steam to generate additional electricity via a steam turbine. The CCPP for the Shell Appomattox platform will improve overall fuel efficiency, reduce emissions of greenhouse gases, and increase total power generation for the platform.
“This project demonstrates the Dresser-Rand business’ unique capabilities to deliver full solutions for both power generation and oil and gas applications. Combined cycle power plants built for offshore applications are rare and we’re pleased to leverage our comprehensive portfolio to produce a solution that meets all of Shell’s requirements,” said Jesus Pacheco, Executive VP New Equipment Worldwide, Dresser-Rand business. “Our team designed and manufactured a compact, lightweight solution that will operate reliably and safely under the harsh conditions inherent in offshore applications.”
The packages feature a compact design and reduced weight to accommodate the platform’s footprint constraints. The design allows for easy accessibility to the package components for maintenance and service, along with adequate workspace.
The steam turbine generator package was manufactured in Wellsville, NY and packaged in Olean, NY. An 18.5 MW load test was performed on the steam turbine generator set using the steam-producing capability at the Olean facility. The gas turbine generator packages were designed in Kongsberg, Norway.
The Industry Technology Facilitator (ITF), together with Energie Beheer Nederland (EBN) and Petroleum Development Oman (PDO), has launched a joint industry project (JIP) which will reduce time and costs for oil producers to determine whether gas fields are economically viable.
The PETGAS III (Petrophysics of Tight Gas Sandstones) project sees the continuation of the successful work being conducted by University of Leeds in examining the petrophysical properties of tight gas sandstones. A robust database of key petrophysical properties has been formed to make rapid estimates of the properties of unknown samples based on their microstructure. Its specialist software, PETMiner, has been developed to visualise this and other petrophysical properties data.
The database of the petrophysical properties of tight gas sandstones will be used to improve the interpretation of wire-line log data for the characterisation of tight reservoirs during exploration, appraisal and production.
ITF CEO, Dr Patrick O’Brien
The project partners, EBN and PDO, are contributing £321K in total and the project, now in its third phase, will run for a period of three years. The project remains open to late participants.
Professor Quentin Fisher of University of Leeds, the principal researcher of the project said: “When oil producers are developing low permeability objectives, the petrophysical properties largely determine whether gas fields are economically viable. Current methods used in the industry are both expensive and time consuming.
The PETGAS research, which is now in its third stage, has been transformative in creating a workflow, database and datamining software that allows operators to reduce the cost and time to estimate to petrophysical properties of tight gas sandstone prospects.”
ITF CEO, Dr Patrick O’Brien said: “At ITF, we are seeing new opportunities for technology developers as the pursuit to increase efficiency is forcing the oil and gas industry to look for new technologies and solutions. The launch of a new phase of the PETGAS project demonstrates the leading edge work of UK Universities, and how the joint industry project model enables operators to effectively leverage the information they share into an advanced software model to radically transform industry outcomes. The work of the PETGAS JIP could in time play a key role in unlocking the significant, yet untapped, potential of stranded gas resources in the Southern North Sea and beyond.”
The PETGAS consortium has been running for eight years and has received sponsorship from San Leon, BG, BP, EBN, Engie, Shell and Wintershall. Results of PETGAS I and PETGAS II have been used by industry to justify drilling new prospects and to improve understanding of the controls on gas and water production in existing fields, which has shaped appraisal and production strategies. The PETGAS III project will extend the database by a further 15 samples per sponsor and continue the extensive special-core-analysis (SCAL) test work on a further seven samples per sponsor.
ITF is driving oil and gas technology development and collaboration. With a membership of international oil and gas operator and service companies, the industry technology facilitator has launched over 200 innovative joint industry projects. ITF champions technology development and believes investment is crucial to solving the most pressing challenges the industry faces in securing reserves and maximising economic recovery.
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.
As human beings, we are creatures of habit. We quickly adapt to routines and like things a certain way, ordering our favourite dish off the menu to avoid disappointment for example. The same can perhaps be said of the oil and gas industry. We know this is a cyclical industry with peaks and troughs. For the past two years, we have been stuck in the trough part of the cycle, as oil prices have gone through a period of volatility. Still, at every level of an organization, we all need to focus on what we can control. Only then can we navigate through this challenging time and emerge stronger. As an industry, we need to increase efficiency while maintaining safety and keeping costs under control.
Great steps have been made through advances in technology and the introduction of digital industrial solutions, however the potential to improve productivity further remains vast. One challenge that equipment manufacturers face in the oil and gas industry is the differing engineering standards and product specifications of end users. Each operator on the market has its own customized standards by which it works.
Embracing manufacturing standardization, particularly during a down-cycle period—such as the one we’re in now—would lead to higher-quality products, better productivity, increased reliability, shorter delivery time and most importantly, lower costs.
A lack of industry-wide standardization means that a large amount of time and money is spent tailoring solutions to each customer’s specific requirements. For example, the aviation industry has benefited heavily from industry-wide standardization—it is regulated in such a way that all manufacturers must comply with centralized FAA standards. This means that when an aircraft manufacturer purchases an engine, they know they’re getting a product that meets industry-wide regulations.
Operators, OEMs and partners are looking at new ways to achieve a unified goal—keeping costs under control, mitigating risks and injecting speed and efficiency in the industry for the long term. From innovative commercial models to closer partnerships and new collaborative frameworks from the early stages of a project life cycle, there is a lot going on in this sector. Designing and implementing manufacturing standards would further benefit both end users and providers alike, bringing a number of advantages, such as:
The low oil price environment has put pressure on the industry to drive down cost. Now is the time for the industry to come together, agree on standards and simplify the way we work. If that were to happen, we could all benefit during a future upturn in the oil price. If you wish to continue this conversation, please visit the online community Tech Talks.
By Luca Passaleva, Oil & Gas Commercial Director, GE’s Marine Solutions
Bureau of Ocean Energy Management (BOEM) Director Abigail Ross Hopper has announced that the bureau will offer approximately 47 million acres offshore Louisiana, Mississippi, and Alabama for oil and gas exploration and development in a lease sale that will include all available unleased areas in the Central Planning Area (CPA).
Proposed Central Gulf of Mexico Lease Sale 247, scheduled to take place in New Orleans in March of 2017, will be the twelfth offshore sale under the Administration’s Outer Continental Shelf Oil and Gas Leasing Program for 2012-2017 (Five Year Program). This sale builds on eleven sales, already held in the current Five Year Program, that have netted more than $3 billion, and supports the Administration’s goal of continuing to increase domestic oil and gas production.
“As one of the most productive basins in the world, the Gulf of Mexico remains a critical component of the Administration’s domestic energy strategy to create jobs, foster economic opportunities, and reduce America’s dependence on foreign oil,” Hopper said. “The exploration and development of the Gulf of Mexico’s vital energy resources will continue to help power our nation and drive our economy.”
Sale 247 will include approximately 8,878 blocks, located from three to about 230 miles offshore, in water depths ranging from 9 to more than 11,115 feet (3 to 3,400 meters).
“The decision to move forward with plans for this lease sale follows extensive environmental analysis, public comment and consideration of the best scientific information available,” said Hopper. “This proposed sale is another important step to promote responsible domestic energy production through the safe, environmentally sound exploration and development of the Nation’s offshore energy resources.”
The proposed terms of this sale include conditions to ensure both orderly resource development and protection of the human, marine and coastal environments. These 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. BOEM’s proposed economic terms include a range of incentives to encourage diligent development and ensure a fair return to taxpayers. The terms and conditions outlined for Sale 247 in the Proposed Notice of Sale are not final. Different terms and conditions may be employed in the Final Notice of Sale, which will be published at least 30 days before the sale.
All terms and conditions for Central Sale 247 are detailed in the Proposed Notice of Sale information package, which is available here. Copies of the PNOS maps can be requested from the Gulf of Mexico Region’s Public Information Unit at 1201 Elmwood Park Boulevard, New Orleans, LA 70123, or at 800-200-GULF (4853).
The Notice of Availability of the Proposed Notice of Sale will be available tomorrow for inspection in the Federal Register here and will be published in the September 16, 2016 Federal Register.
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.
Following the accident involving COSLInnovator on 30 December 2015, some 100 semi-submersible rigs approved by DNV GL will be reviewed. Preliminary assessments indicate that a limited number of rigs will be subjected to modifications or operational limitations.
The semi-submersible rig COSLInnovator was drilling for Statoil in the Troll field when it was hit by a large, steep wave. Several windows on the rig's two lower decks were shattered. One person was killed. “Since the incident, we have made great efforts to identify what happened, understand how this could happen and, most importantly, implement actions to prevent similar incidents from occurring again,” says Ernst Meyer, DNV GL Director for Offshore Classification. “We have been working with rig owners, designers, operators and authorities towards a common goal; to ensure the safety of all those working on board the rigs.
COSLInnovator
The incident investigation report presented by the Norwegian Petroleum Safety Authority in April 2016 concluded that the incident involving COSLInnovator has provided new knowledge that must be utilized in order to prevent similar incidents in the future. DNV GL therefore published a new technical guideline (OTG-13 – Prediction of air gap for column-stabilized units) as early as in June 2016. This gives a consistent and updated approach for calculating the air gap - the clearance between the highest wave crest and the bottom of the deck box in all relevant sea conditions.
Last week, DNV GL asked all owners of DNV GL-classed semi-submersible rigs to provide updated documentation of each rig's air gap.
Rigs that, based on the new technical guideline (OTG-13), can confirm a positive air gap, will be able to operate as before without reinforcement or operational limitations. This is expected to apply to most of the semi-submersible rigs operating on the Norwegian shelf.
“I can't indicate how many rigs have negative or positive air gaps before each rig's calculations have been performed,” says Ernst Meyer.
“A limited number of rigs may not have a positive air gap, but most of these will be able to avoid changes. The prerequisite is that they are able to document a positive air gap for a specific location, or that they simply do not have windows that may be exposed to waves.”
He elaborates on the consequences for the other rigs – those that are unable to prove a positive air gap in all sea conditions – including the hundred-year wave:
“Initially (for the next winter), these rigs will be required to remove windows in exposed zones. If the strength calculations show that further structural modifications are necessary, such modifications will be required as part of the permanent solution.
“The most important thing is that the windows are removed before the coming winter. This action eliminates the largest risk elements if a similar incident occurs,” Meyer explains. He emphasizes once again that operational limitations and limitations with regard to areas of operation may solve the air gap issue in the short term.
Rigs that are certified for worldwide operation must be documented according to North Atlantic wave data. Most rigs operate in milder areas, such as the North Sea, and can postpone modifications that may be necessary in the Norwegian Sea or Barents Sea.
DNV GL is the classification body that certifies the largest number of semi-submersible rigs, and these rigs operate under the most extreme weather conditions globally. The company works continuously to improve the class regulations used in certification work through future-oriented research and the thorough examination of and learning from incidents and accidents.
“The work behind the new guideline includes the use of updated statistical weather data and knowledge acquired from several independent model tests conducted in light of the COSLInnovator incident. We have also learned from previously conducted model tests and from operational experience after 40 years classing hundreds of similar rig types,” Ernst Meyer concludes.
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.
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