Statoil, on behalf of the Johan Sverdrup license, has awarded Samsung the contract for decks for both the process and riser platforms. The total contract value is NOK 7 billion.
The contract is a fabrication contract (FC) of decks for the process and riser platforms. Aker Solutions has previously been awarded engineering work and purchase of equipment packages for the two aforementioned decks.
The function of the process platform, which weighs approx. 26,000 tons, is to ensure stabilization of the oil and processing into rich gas.
The riser platform, which weighs approx. 22,000 tons, will serve oil and gas exports, water and gas injection, as well as any future connections. The power cable from onshore also ends at this platform, where the current is transformed from direct current into alternating current for further distribution to the field centre.
The platform deck will be manufactured at the Samsung’s shipyard in South Korea.
"Johan Sverdrup is a large puzzle in which many suppliers must deliver with precision, quality and on time in order for us to start production towards the end of 2019 and this contract is yet another important milestone for the Johan Sverdrup project. Samsung has extensive experience in manufacturing such installations and we already have a good collaboration with the supplier. They have provided a competitive bid in a tough international competition," says Margareth Øvrum, executive vice president for Technology, projects and drilling at Statoil.
With this latest award, all contracts for the four platform decks have been awarded. The decks for the drilling platform and accommodation platform have already been awarded to Aibel (EPC) and Kværner Stord (EPC). In addition, 65% of the equipment packages have so far been awarded to suppliers with Norwegian billing addresses.
"Johan Sverdrup will be of major significance to the whole of society for at least 50 years into the future. We now have in place a broad and strong team in the supplier industry to construct the decks for the four platforms. This provides the most optimal conditions for project delivery in terms of quality, time and cost," says Øivind Reinertsen, project director of Johan Sverdrup field development.
Facts Johan Sverdrup
The investment costs for phase 1 of the Johan Sverdrup development are estimated at some NOK 117 billion NOK (2015 value). Recoverable resources are projected at between 1.4 and 2.4 billion barrels of oil equivalent.
The development concept for Johan Sverdrup phase 1 will consist of four installations, including a utility and accommodation platform, a processing platform, a drilling platform and a riser platform, in addition to three subsea templates for water injection.
The platforms will be bridge-linked. The project aims at a recovery rate of 70% for Johan Sverdrup.
The Johan Sverdrup partnership consists of Statoil, Lundin Norway, Petoro, Det norske oljeselskap and Maersk Oil. The partnership has recommended Statoil as the operator of all field phases.
Overall main contracts at a value of more than NOK 27 billion and more than 45 equipment package contracts at a value of NOK 3.5 billion have been awarded to suppliers with Norwegian invoice addresses.
By: Rizwan Sheikh, Senior data analyst at BMT Scientific Marine Services
The need for mooring integrity monitoring has of late come back under the spotlight, not least because the use of floating production systems in the offshore Oil and Gas industry has been predicted to grow at a significant rate between now and 2017 with a peak in the number of new builds expected to occur in 2016/2017. Recently, an updated industry guideline on mooring integrity has been issued by Oil & Gas UK with the support of operators, contractors and vendors. The guideline reinforces how mooring integrity management through effective monitoring and data management can provide information to help detect mooring line failure and assist with validation of mooring design strength and fatigue analyses.
Station keeping through the life of a field is of critical importance for floating production facilities in all parts of the world. The mooring system performs this function, and although it has not always been the case, current design practice is to engineer mooring systems that can withstand extreme environments with single or even multiple line failure scenarios. Even so, the offshore industry has experienced numerous unexpected mooring line failures in recent years that, in a small number of cases, have resulted in mooring system failure. On average between 2001 and 2011, there were more than two mooring system failures per year. During this period, nine were multiple line failures1 and other mooring incidents resulted in riser failures and hence extended field shut down2. Based solely on these statistics, there is a clear business case for effective mooring integrity monitoring.
One of the challenges that has emerged from these failings is the need to monitor mooring system integrity reliably for the life of the facility without the need for costly inspection or maintenance of subsea sensors. In general, most mooring line monitoring systems that have been deployed to monitor mooring line tension have themselves experienced sensors failures, and the industry is now assessing ways of monitoring mooring line break detection as opposed to measuring mooring tension in a hope that the sensors will be more robust. However, many of the challenges of installing and maintaining these types of monitoring systems still need to be addressed.
Typical requirements for mooring integrity monitoring of permanently moored floating systems encompass the need to measure mooring line tension and/or behavior, and to transmit this data to the facilities topside for display and archiving. Monitoring systems therefore need to be conceived to withstand high structural loads as well as harsh sea-states for the design life of the facility. This is achieved through robust design, proper installation and periodic maintenance and servicing once in service. Key questions to ask when selecting a system include: is the system for a new-build or a retrofit? Is position or inclination sufficient, or is a measurement of in-line tension required? Can the system be diver or ROV deployable or serviceable? Will data be transmitted wirelessly or through a hardwired connection? Last but not least, where is the most practical location to place the sensors without compromising safety or the quality of the measurement?
To meet the growing demand for a cost effective and reliable means of monitoring mooring system integrity, BMT has developed a novel system to assimilate data from a range of topside-based sensors (which monitor factors like the environment, position, vessel motions, draft and available mooring line information) into a topside Response Learning System (RLS). This system uses machine learning and cognitive science to learn the response of a system as well as the inter-dependencies of the numerous data sources. As a result, it is possible to estimate the behavior of a system (floating production facility) given a set of impulses (environmental loads from combined action of wind, wave and current) provided the RLS has sufficient measured marine data for learning.
There are numerous applications for machine learning algorithms. In fact, BMT is using them in the field to improve predictions of tension beneath the buoyancy can on a free-standing hybrid riser tower. In the context of mooring monitoring, work conducted on a turret moored FPSO, where a mooring line monitoring system was installed by BMT, showed that an RLS can estimate mooring line tension to within 30kN using only position and draft as inputs.
Excursion monitoring can also be used as an indirect way to monitor the integrity of the mooring system. Simple watch circle monitoring systems do not integrate metocean and vessel motions data to verify that the vessel offset from its moored origin is as should be expected, given the environmental loading and mooring stiffness. Furthermore, should the offset from design origin shift slightly in benign conditions, a watch circle processor would not be able to indicate a change in the mooring system. By using an RLS, the expected position, heading and response can be compared back to the measured position for the given environment. If the difference exceeds a pre-determined threshold, an advisory can be issued on the mooring system integrity.
In conclusion, with mooring integrity now under a renewed emphasis within the Oil & Gas industry, there is a heightened need for a robust and cost effective mooring integrity monitoring solution for both new-build and existing installations. The application of an RLS to monitor mooring system integrity builds upon BMT’s many years of experience in providing custom designed and custom built Integrated Marine and Mooring Line Monitoring Systems to the deepwater offshore oil and gas industry. With the rapid advances in computing power and data telemetry, the development of a topside based mooring integrity monitoring system like that described above is a natural progression and further unlocks the inherent value of data acquired by real-time monitoring systems.
Sources:
1 K. Ma, A. Duggal, P. Smedley, D. L’Hostis, H. Shu. “A Historical Review on Integrity Issues of Permanent Mooring Systems.” OTC 2013-24025, 2013.
2 S. Majhi, R. D’Souza. “Application of Lessons Learned from Field Experience to Design, Installation and Maintenance of FPS Moorings.” OTC 2013-24181, 2013.
International oilfield services company, Expro, has been awarded new contracts from Tullow Oil plc, Africa’s leading independent oil company.
Worth in excess of $100 million over three years, the contracts will see Expro work across Tullow Oil’s assets in Ghana, including the Jubilee Field and the Tweneboa-Enyenra-Ntomme (TEN) field project.
Following on from Expro’s phase one contract for Jubilee, involving more than 10 completions, the company has been awarded continued services for phase 1a. This covers completions on new wells for Jubilee, as well as interventions and remedial work.
A number of Expro’s product lines and services will be utilised, including large bore subsea completion landing strings, subsea exploration and appraisal landing strings, high flow rate surface well testing and sampling services. The TEN project will also see Expro provide subsea completion work in all planned wells.
The company has invested over $32m in Ghana since entering the market in 2008 to support key clients such as Tullow.
Riccardo Muttoni, Expro’s Sub-Saharan Africa Region Director, comments: “We are delighted to work with Tullow in delivering a range of world class projects, strengthening our existing partnership and delivering value to their Ghanaian business.
“These contracts build on investments Expro has made over the past 5 years including the establishment of our world class operating facility in Takoradi. We are proud that 70% of our workforce in-country, including 20 graduate engineers, is Ghanaian, which we are looking to increase to 85% by 2017.”
Charles Darku, Tullow Ghana’s General Manager, said: “We look forward to utilising Expro’s expertise in the offshore environment to deliver our key projects in Ghana. Major investments have been undertakento date by both Tullow and Expro, with emphasis on local content development plans to further create opportunities for local businesses and people.”
Expro’s Sub-Saharan Africa operational headquarters are in the Ghanaian capital, Accra.
Aker Solutions and Baker Hughes have agreed to cooperate on early-phase studies to help customers improve the overall economics and value of oil and gas field developments.
Aker Solutions' Front End Spectrum unit and Baker Hughes' Reservoir Development Services group will provide customers with development concept studies that address the entire value chain - from reservoir understanding and well design to subsea and topsides facilities, including flow assurance and risk management. Each company has expertise from the full spectrum of field development. Initial customer studies are already under way.
"Our ability to maximize value is greatest when we can enter a project early at the appraisal and feasibility stages and evaluate the potential of a field's total development instead of parts of it," said Henning Østvig, head of Front End Spectrum at Aker Solutions. "This greatly increases our success in finding solutions that improve the overall economics and value of a development by optimizing capital expenditure and production."
"While we always want to find the best solutions for our customers, the current market environment gives us an added sense of urgency," said Scott Reeves, president of Reservoir Development Services at Baker Hughes. "No tool is more powerful than an early, integrated approach to field design. This helps ensure that all parts of a project are designed to work together throughout the life of the field."
The new agreement comes after Aker Solutions and Baker Hughes in 2014 formed the Subsea Production Alliance to develop solutions that will boost output, increase recovery rates and reduce costs at subsea fields. The alliance uses Aker Solutions' capabilities in subsea production and processing and Baker Hughes' expertise in well completions and artificial-lift technology to deliver integrated in-well and subsea systems solutions. The importance of cooperating during the early phase of a project was recognized quickly in the alliance.
The Front End Spectrum unit and Reservoir Development Services group maintain independent offices in Houston, Oslo, London, Aberdeen, Kuala Lumpur, Perth, Dubai, Abu Dhabi and Moscow.
Aker Solutions' Front End Spectrum unit provides expertise in subsea and topsides systems, life-of-field production management and flow assurance. Baker Hughes' Reservoir Development Services group uses its subsurface expertise to improve reservoir understanding and determine efficient methods to capture a field's full potential.
Reducing expenditure while continuing to improve safety and reduce risk is a key driver for the oil and gas industry especially in today’s cost constrained environment. DNV GL and ExproSoft are now joining forces to offer a risk based approach to testing barrier valves in subsea completed wells applicable worldwide. The objective is to reduce both downtime and risk related to shut-in and restart of wells in addition to substantial cost savings.
“In Norway, today’s current prescriptive approach to well testing can result in up to 3 days lost production per test, equivalent to US$10M per asset. Changing today’s prescriptive test intervals and leak criteria to a risk and reliability-based approach, will achieve substantial year-on-year cost savings for operators in Norway and elsewhere,” said Kjell Eriksson, Regional Manager - Norway, DNV GL - Oil & Gas. “Our experts can use established methodologies from the process industry and safety systems to reduce the number of shut-ins and well downtime, thus lowering the need for expensive interventions and work-overs. All this can be attained while maintaining acceptable risk levels and meeting regulatory requirements.”
Currently, the NCS regime refers to NORSOK D-010 for well barrier testing and testing frequencies and leak criteria for well barrier valves are determined by API 14B/ISO 10417. DNV GL and Exprosoft will undertake a project to develop the risk based approach which will identify failure modes and causes, failure rates, analyze the consequences, establish a risk picture and translate the results into a recommended test frequency. Further, a method to develop risk-based leak acceptance criteria may also be an outcome of this work. The results can be applied globally and will be available in Q1 2016.
DNV GL and ExproSoft‘s strategic cooperation and partnership agreement brings together ExproSoft’ s WellMaster, the world’s largest repository of reliability data for wells based on more than 40,000 well years of historical data, with DNV GL’s risk management expertise. “For an offshore platform with 25 wells producing 50 000 barrels a day, the average annual intervention cost is $26 Million,” said ExproSoft’ s CEO, Odd Are Svensen. “We are looking forward to working closely with DNV GL to combine our equipment reliability services with DNV GL’s risk management expertise to reduce intervention cost.”
Leading oil and gas operators in the US, UK and Norway use and share reliability data throughout the well’s lifecycle globally, and experience increased uptime, reduced cost (CAPEX and OPEX), and improved understanding of risk and failures, through access to the WellMaster Reliability Management System (WRMS) from ExproSoft.
Offshore Installation Services (OIS), an Acteon company, has been awarded a contract by Antrim Energy to decommission four subsea wells in the central North Sea. The offshore scope of the campaign, which also includes six wells from Centrica Energy, will include complete offshore and onshore project management, vessel charter, equipment and personnel.
Rhodri Davies, OIS president, said, “Since 1996, OIS has successfully completed more than 118 well decommissioning projects without a single lost-time incident. With Antrim Energy and Centrica Energy now involved in our 2015 subsea well abandonment campaign, OIS is currently decommissioning 10 subsea wells within the UK continental shelf. As an enabler of multi-operator campaigns, OIS values collaborations such as this in the decommissioning field and is well suited to working alongside progressive organisations such as Antrim and Centrica.”
The wells, in categories 2.1 and 1, will be abandoned using Acteon sister company, Claxton’s, Suspended Well Abandonment Tool (SWAT). SWAT is a diverless, vessel-based approach and will be completed as part of a multi-operator campaign in summer 2015.
The offshore campaign will be conducted from an anchor-handling tug supply vessel (AHTS), the Island Valiant. During phase one, SWAT will be deployed through the vessel’s moon pool to set cement plugs in the bore and across all the casing annuli. The second phase will use an abrasive severance system for the cutting of the wells and sequential removal from the seabed. This will conclude the offshore operations.
OIS is experienced in orchestrating multi-party collaborations, having planned and executed 17 campaigns involving more than one operator in the North Sea since 1996. The OIS business model enables operators to share project costs and provides a cost-efficient way to decommission suspended wells and comply with UK oil and gas legislation.
Global inspection, repair and maintenance (IRM) company Harkand, has commenced decommissioning work in the United Kingdom Continental Shelf supporting Maersk Oil UK’s work in the Leadon field.
Earlier this year, the IRM firm secured a multi-million pound 12-month frame agreement with Maersk Oil in the region for the provision of its two dive support vessels (DSVs), the Harkand Da Vinci and Harkand Atlantis as well as supporting onshore and offshore personnel.
This new award will see Harkand deliver project management and engineering services to the Danish owned oil and gas company around their drill rig program for subsea well plug and abandonment.
The scope of work which is being undertaken by the Harkand Atlantis includes barrier testing at 13 trees, removal of production and gas lift spools at trees and towhead ends along with power and control jumpers and mattress recovery. The works also involves flooding and disconnection of a 4” gas import flowline.
David Kerr, managing director of Harkand Europe said: “We are delighted to have secured this decommissioning work in the North Sea for such a high profile operator.
“Removal of subsea infrastructure can be challenging and this contract reflects our well-established and successful track record for decommissioning activities such as inspection and survey, valve operations, mattress removal, pipeline cutting and recovery.
“There’s an estimated 500 – 690 facilities reaching the end of their operational life over the next three decades, so North Sea asset decommissioning projects will play a large part in Harkand’s future. We look forward to successfully completing this work for Maersk Oil UK.”
Harkand provides offshore vessels, ROVs, diving, survey services, project management and engineering to the oil and gas and renewables industries. Headquartered in London with operations bases in Aberdeen, Houston, Mexico and Ghana, Harkand aims to be the leading subsea IRM and light construction contractor globally.
International oilfield support services company ASCO, has secured a key contract worth in excess of £50 million for work in the North Sea for Marathon Oil UK, further strengthening the company’s market leading positioning in the UK.
Commencing in July 2015, the five-year contract with further extension options, will be serviced out of ASCO’s South Base in Peterhead and will include quayside services, warehouse management and the provision of marine gas oil in support of Marathon Oil’s Brae field.
Well established in the North Sea, ASCO has provided offshore supply base management services to key clients in the region for the last 48 years.
Commenting on the recent contract win, Craig Lennox, CEO Europe at ASCO, said: “ASCO has supported Marathon Oil for many years and we are delighted to secure a new long term contract with them.
“This contract demonstrates the value of ASCO’s integrated service provision within the North Sea and will allow us to build upon our existing strong relationship.”
Earlier this year ASCO announced significant contract wins with BP E&P and Statoil UK. Combined with recent wins, ASCO has secured long-term business in the North Sea worth in excess of £500 million.
NYC-based PIRA Energy Group believes that $60 oil is not enough: demand growth will outstrip supply growth without higher prices. In the U.S., the stock surplus continues to sharply narrow. In Japan, runs rise, crude and product stocks build. Specifically, PIRA’s analysis of the oil market fundamentals has revealed the following:
$60 Oil Is Not Enough: Demand Growth Will Outstrip Supply Growth Without Higher Prices
More than ever, the divide over where oil prices are heading in the future is driven by diverging views on supply costs. If you're one who believes that there will be very large quantities of shale oil (or light tight oil) available at a cost under $60/Bbl, enough to meet demand growth and offset depletion of existing production, then prices need not rise from current levels. Alternatively, if you believe that shale volumes will not be sufficient and higher-cost supplies, including oil sands and deepwater, will be required to balance global supply and demand, then a rise in price is likely required.
U.S. Stock Surplus Continues to Sharply Narrow
This past week’s 6.7 million barrel overall inventory decline sharply contrasts with last year’s 5.2 million barrel inventory build for the same week. The year-over-year stock surplus decreased by 12 million barrels to 128 million barrels, down from 177 million barrels at the beginning of April.
Japanese Crude Runs Rise; Crude and Product Stocks Build
Crude runs rose for the second straight week and crude imports recovered from low levels, which led to a sizable 3.7 MMBbls stock build. Major product demand performance was weaker and finished product stocks posted a build of slightly less than 1 MMBbls. The indicative refining margin remains very good. Light product cracks eased slightly while fuel oil cracks were a bit stronger.
Update on Russia Shale Oil Development
Interest in developing Russia's enormous shale oil was riding high in the last few years until the West imposed sanctions over the Ukraine crisis a year ago. Development of shale oil, which is specifically targeted by western sanctions, has slowed substantially. Activities in a number of JVs that have been formed with Western partners, notably between Rosneft and Exxon, Statoil and BP, Lukoil and Total, and Gazprom Neft and Shell, were put on hold. Efforts to replicate the shale boom in the U.S. have also hindered by the collapse of oil prices over the past year.
Financing Not a Major Concern for Most U.S. Independent Producers in Low Oil Price Environment
In the current low oil price environment, cash flow generated by U.S. independents has gone down, debt has increased and debt ratios (i.e. debt/EBITDA) have gone up. However, debt ratios are still acceptable for most U.S. independents, major debt repayments are not due for a few more years, and several companies have mitigated the downside by hedging future oil production. In addition, there is plenty of money available to be lent, interest rates are still low, it is fairly simple to issue new shares, and companies that try to sell assets to maintain liquidity are finding buyers. Therefore, financing is not a major concern for most U.S. independents. There are exceptions and some smaller and highly leveraged producers have had to restructure or declare bankruptcy.
U.S. LPG Prices Rebound
Prices rebounded strongly last week, as brine issues at Lonestar’s Mt. Belvieu storage terminal were seen as transitory and not endemic of a larger containment issue. July propane futures at the Texas market center rallied 10%, while butane, which has been unfairly dragged lower by C3 in recent weeks, jumped 14% to 57.2¢/gal by Friday’s settle. Ethane prices were mostly unchanged around 19¢/gal.
Inventories Drop to the Lowest Level Since January 2
U.S. ethanol production soared to 994 MB/D the week ending June 19, the highest level ever reported in the DOE's weekly supply report. Inventories declined by a whopping 878 thousand barrels to 19.8 million barrels, the lowest since the week ending January 2.
The information above is part of PIRA Energy Group's weekly Energy Market Recap - which alerts readers to PIRA’s current analysis of energy markets around the world as well as the key economic and political factors driving those markets.
McDermott International, Inc. (NYSE: MDR) has been awarded a sizeable lump sum contract by LLOG Exploration Offshore, LLC (LLOG) in support of LLOG’s Otis development located in the Gulf of Mexico. The lump sum contract will be included in McDermott’s second quarter 2015 backlog.
McDermott deepwater rigid reel Lay Vessel 105 (LV 105) is slated to complete offshore installation in early 2016. (Photo: Business Wire)
The Otis field, located in Block Mississippi Canyon 79, will be developed as a subsea tieback to the Delta House floating production system (FPS) and lies in approximately 3,800 feet of water. The contract scope includes:
• Project management;
• Engineering, fabrication and installation of a 75,000-foot insulated rigid flowline and insulated steel catenary riser (SCR) with associated pipeline end termination (PLET) and jumper; and,
• Pre-commissioning.
McDermott’s Houston office will perform the overall project management and engineering. The flowline and SCR are scheduled to be assembled and fabricated at McDermott’s new spoolbase facility in Gulfport, Mississippi.
Offshore installation is scheduled to be completed in early 2016 by McDermott deepwater rigid reel Lay Vessel 105 (LV 105).
“This award represents an important step in McDermott’s growth plans for the Gulf of Mexico,” said Scott Munro, Vice President, Americas, Europe and Africa. “This is our first contract award for rigid reel lay in the area since the delivery of the LV 105 deepwater vessel and development of our new Gulfport marine facility and spoolbase. We look forward to working with LLOG over the coming months and delivering this project safely.”
The Extel Survey gathers the views and rankings of international research analysts for the world's largest publicly traded companies
Repsol was ranked as the top oil & gas company in the 2015 edition of the prestigious international Extel Survey in four categories: Best CEO, Best CFO, Best Investor Relations Team, and Best Director of Investor Relations.
Imaz heads the Oil & Gas European CEO rankings in his first appearance in this survey. Research analysts recognize Repsol's efforts in communication and transparency and in particular those of its CEO, Josu Jon Imaz, in the company's approach to the markets following the purchase of the Canadian company Talisman Energy.
The Extel Survey is currently the most comprehensive of its kind, and is one of the most highly regarded among research analysts and stock market professionals. It is the most prestigious report at the European level, and is considered a benchmark of excellence by investors as well as consultants.
Repsol has this year consolidated the outstanding performance of its investor relations as the CFO, Miguel Martínez, and the Investor Relations Team were already awarded the highest ratings in the European sector in the previous edition.
The plugging and abandonment (P&A) of offshore wells represents a significant cost to operating companies and national authorities. On the Norwegian Continental Shelf (NCS) alone, the cost is estimated to be USD108bn (NOK1870bn) over the next 40 years. Now a new DNV GL guideline will introduce a risk-based approach instead of the current prescriptive practice. DNV GL estimates that when combined with optimized project execution and new technology, the P&A cost can be reduced by 30-50%.
When the production from an oil or gas reservoir ceases or is no longer profitable, authorities require the well to be P&A’d. The purpose is to establish a permanent barrier to prevent the migration of hydrocarbons to the surface. Traditional P&A methods are time consuming, costly and have remained unchanged despite technological advances across many other aspects of the industry. There are currently around 2,350 wells that will require P&A on the NCS, and 3,000 more wells are planned to be drilled in the future. In the UK, close to 5,000 offshore wells will need P&A.
Blackford Dolphin
“These costs are enormous. With current practices, the wells on the NCS will require the deployment of 15 rigs full-time over the next 40 years. Based on the 2013 cost, this is equivalent to more than a tenth of the current value of Norway’s sovereign wealth fund (GPFG),” says Per Jahre-Nilsen, Senior Principal Engineer in DNV GL – Oil & Gas. “We believe the time has come to tackle this issue head on by assisting regulators and the industry to establish a new methodology for dealing with the decommissioning of wells,” he continues.
The main barrier to change in this sector has been today’s prescriptive approach to the regulations, which represents a conservative interpretation of past experience. Practice also differs from country to country. In the upcoming P&A Guideline, DNV GL will use well-known and accepted risk-approach methodology in which both environmental and safety risk aspects will be key factors. DNV GL has already worked with international operators to develop an initial set of criteria. These will be further strengthened through collaboration with regulators and the oil and gas industry. The guidelines are under development and will be issued in the second half of 2015.
“This means that hazardous wells will get the attention they deserve, and benign wells will avoid excessive rig-time and expenditure. We can potentially halve the costs of plugging and abandoning wells. We're looking at potential cost savings of more than USD32bn on the NCS alone, and even more globally,” adds Jahre-Nilsen.
“DNV GL’s contribution as a risk-management expert is to help the industry, which is facing increasingly complex and demanding operations, to understand the risks and find the most efficient way to deal with these risks. Risk-based approaches are widely used in all other offshore disciplines, ensure appropriate long-term environmental protection and also represent the most rigorous method to enhance safety. It is time to apply these principles to P&A,” says Elisabeth Tørstad, CEO of DNV GL -Oil & Gas.
Bureau of Safety and Environmental Enforcement (BSEE) Director Brian Salerno today announced that BSEE Alaska Region Director Mark Fesmire this week oversaw testing of Shell’s proposed Arctic-ready capping stack system in Puget Sound to ensure compliance with stringent Federal safety standards for oil and gas exploration on the Arctic Outer Continental Shelf. A key piece of Arctic oil exploration containment equipment, the capping stack is used to contain the flow of oil in the unlikely event all primary and backup blowout prevention equipment fails during drilling. It is required to be in position for all of Shell’s potential drilling activities in the Arctic.
During tests last week, BSEE personnel witnessed the deployment and maneuvering of the capping stack off the rear deck of the M/V Fennica to 150 feet of water, which is deeper than Shell’s current well sites in the Chukchi Sea. BSEE confirmed that the capping stack functioned properly under pressures exceeding the maximum expected pressures Shell may encounter in the Arctic. Deployment of the capping stack and stack pressure testing were completed in two separate exercises spanning two days.
BSEE is currently reviewing Shell’s request to drill two exploratory wells in the Chukchi Sea this summer. If BSEE approves the drilling permits, Shell would be required to maintain the capping stack in a ready-to-deploy state on the M/V Fennica, which would be available to respond to a loss of well control within 24 hours.
In addition to containment and engineering observations such as the ones conducted this week, BSEE is overseeing additional on-water oil spill response exercises and drills and on-site inspections of oil spill response equipment throughout the proposed drilling operation. BSEE will use its authority to conduct a variety of equipment inspections and deployment exercises, some of which may be unannounced, to validate the tactics, logistics, resource availability, and personnel proficiency specified and relied upon in the approved plans and permits.
DNV GL, the leading technical adviser to the oil and gas industry has launched a research paper exploring the viability of moving offshore oil and gas processing subsea, including the techno-economics of an ‘all subsea’ solution. The report addresses current limitations, but also highlights opportunities for subsea technology.
To lend clarity to the topic, the paper compares a benchmark FPSO set-up with a hypothetical all-subsea field development solution. However, instead of making a direct comparison between the two alternatives, the paper adopts a stepwise approach, moving the various main parts of the processing from the topside to the seabed in nine steps until nothing remains on the surface.
Cutting through complexity
Principal researcher and lead author of the paper, Tore Kuhnle, said: “Debates about the viability of ‘all subsea’ solutions can quickly become overwhelmed with complexity due to the interrelations and dependencies between the processing, power, control and safety subsystems, as well as the effects on the reservoir performance and commercial aspects. With our stepwise approach, one can evaluate the business case of subsea solutions progressively and with clarity.”
For each step, the report includes a business case assessment of whether:
• The step is enabling (i.e. opens up new opportunities for the industry that other technological solutions cannot achieve); and / or is enhancing ( i.e. that that aspect of subsea processing offers superior efficiency relative to any other technical solution).
• A bright future for subsea, also in the current market
“The industry has moved from ‘breaking boundaries’ to ‘cost cutting’ in recent years. In that respect, it is reassuring to see that subsea processing is both enabling and enhancing technology for brownfield applications,” added Kuhnle. “Even though brownfields will continue to drive subsea processing development, we have also identified possibilities for greenfield applications. We see that the technology has matured considerably for limited-depth and limited-range applications. With our short-term focus, we see the completely submerged alternative more as a mature-area, midsize oilfield solution, rather than an extreme deepwater, long-range problem-solver. I’d say these are good findings for the industry to consider as we need efficient production replacement projects in the current market, and both these alternatives fit very nicely.”
Elisabeth Tørstad, CEO, DNV GL - Oil & Gas, says,"For DNV GL, it is important to provide foresight and seek alternative solutions which lie far in the future while looking for short-term improvements. This specific research shows that subsea processing is essential to enable prolonged production from mature fields. There are also indications that complete subsea solutions may be a new option for medium sized fields in mature areas."
Hermes Datacomms, a SpeedCast Group Company, announced that it has partnered with O3b Networks, a global satellite operator offering next generation satellite networks, to deliver communications to a global oil company, with major operations in the world’s most important oil and gas regions. Under the contract, Hermes will deliver critical communications for the company’s operations in West Africa and a connection back to their regional headquarters in Europe.
The use of O3b satellites, which are in a unique orbit closer to the earth than conventional geostationary satellites, reduces latency, increases data rates and improves voice and video quality for the end user. The high throughput O3b satellites also offer much greater capacity, with the ability to support up to 1.6 Gigabits in a single beam.
“We are delighted to be the first to provide O3b capacity for the oil and gas sector in West Africa. This will provide our customer with the benefits of satellite connections with the latency of fibre connections,” said Barry Bouwmeester, Business Development Manager, Africa, Hermes Datacomms. “Access to the O3b network gives us the ability to open up new services where it would be difficult to obtain access to fibre.”
Hermes Datacomms and SpeedCast have been working closely with O3b Networks over the last 2 years. The Group now has a number of fully trained O3b installation engineers, who have completed the O3b Networks Installation Training at their factory in Virginia, USA. This announcement follows two other recent announcements by the Group working closely with O3b to deliver service in the Pacific and South East Asia regions.
“Delivering innovative solutions to meet the needs of our energy customers is the cornerstone of our success. With O3b’s network, we are able to deliver high performance capacity and low latency for a superior end-user experience,” said Keith Johnson, SVP of Energy, SpeedCast. “As a company, we pride ourselves on being technology agnostic, always looking for the best solution to provide exceptional customer service in the key countries where our customers operate. This announcement represents our strategic partnership with O3b in the energy business.”
Hermes Datacomms is the newest addition to the SpeedCast Group (“SpeedCast”). The Group’s combined capabilities enable it to provide global coverage, an expanded service portfolio and fully managed, end-to-end communication and IT solutions. This is backed by proactive 24/7 support, local engineering presence and spare management in some of the most demanding markets in the world. Leveraging its global size and scale, SpeedCast is able to effectively deliver and support customers wherever they are.
Leveraging its expertise to meet ultra-deepwater challenges
Technip was awarded by Chevron North America Exploration and Production Company, a division of Chevron U.S.A. Inc., a lump sum project for the decommissioning of the brownfield development and installation of new subsea equipment supporting a floating production system located in Mississippi Canyon, Gulf of Mexico, in a water depth of approximately 2,000 meters. The project scope includes:
Technip's operating center in Houston, Texas, USA, will perform the overall project management. The infield flowline and riser will be welded at the Group’s spoolbase in Mobile, Alabama, USA. The offshore installation is expected to be performed in the second half of 2016 by vessels from Technip’s fleet. The Deep Blue, one of the world's largest ultra-deepwater pipelay and subsea construction vessel shall install the steel lazy wave riser, flowline, and gas lift umbilical, and the Global 1200, will install the manifold and foundation.
Deanna Goodwin, President of Technip in North America, commented: "We are delighted to have secured this work. Technip will utilize its unique subsea vertical integration to deliver an all-in solution for the ultra-deepwater de-commissioning of the current field to installation of the new subsea equipment”.
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