Norway’s subsea sector remains resolute in its mission
Oil and gas are a lynchpin of the Norwegian economy. According to the most recent estimates from the Norwegian Petroleum Directorate (NPD), activity on the Norwegian Continental Shelf (NCS) accounts for 52% of the country’s export revenues, 23% of GDP and 30% of governmental revenues. So, it is no surprise that the sudden, dramatic decline in global oil prices has delivered a sucker punch to not only Norway’s E&P industry, but to the entire Norwegian economy.
In turn, a major component of the nation’s upstream industry is the subsea sector. Over the last four to five years, according to NPD, production from subsea wells has exceeded output from platform wells, and that trend is expected to continue. In addition, Norway is considered a leader in subsea technology development, with a number of Norwegian firms engaged in leading-edge R&D projects.
There is justifiable concern about the subsea sector’s near-term health during the global price and activity downturn. Yet, there is also cause for optimism in the medium-and-long term, as the companies involved soldier on in their efforts. “It is important to keep in mind, that we are in a long-term industry, and over the past 15 years, the price has fluctuated between $15/bbl and $147/bbl,” said Bjorgulf Haukelidsater Eidesen, Statoil’s leader for Subsea Technology & Operations, Processing and Systems. “Market fluctuations underline the importance of actions to ensure efficient operations, and make sure that our projects are robust and competitive. As is true for the rest of the petroleum industry, the subsea sector’s health is challenged by the high Capex increase that has been ongoing for several years, and even more so in the current business environment.”
Other Norwegian firms agree with Eidesen’s analysis. “We have experienced a significant decline in the NCS activity level (Fig. 1), both for new projects and for service activities,” said Arild Selvig, FMC Technologies’ director of Sales and Marketing for the Eastern Region, Subsea. “In reaction to the oil price collapse, operators revised their investment and operational budgets, and reduced capital spending. It is still uncertain when oil prices will stabilize, and on what level.” Following on Selvig’s comments, Hervé Valla, Chief Technology Officer at Aker Solutions, noted, “We are experiencing some pressure in field development. In a short-term perspective, we see a risk of postponement of some projects requiring large infrastructure investments, while projects related to subsea tie-backs to existing infrastructures are more likely to go forward.”
And, as Tom Huuse, regional leader for Subsea Systems Services at GE Oil & Gas succinctly put it, “In the past, the main focus has been on getting wells onstream, but the current oil prices are clearly affecting the Capex spend. Projects have sometimes run the risk of significant overruns, as the operators have tended to prefer costly tailor-made solutions, rather than focusing on standardization to allow for cost reductions.”
A NEED FOR COST REDUCTIONS
Indeed, as all of these experts agree, there is a clear need to reduce E&P costs, including subsea projects, to secure long-term profitability and growth. “The low oil prices work in two ways,” explained Helge Lunde, CEO at Seabox AS, which specializes in technology for subsea water intake and treatment, as well as IOR and EOR technology. “They reduce total investment for oil and gas developments, and that will, of course, have an effect on the total volume of available business. However, in this kind of environment, the push for better, more economical solutions may also increase, and this may open up new technologies quicker than in normal circumstances.”
The folks at DNV GL certainly agree with Lunde. “The recent price plummet has magnified the existing problem of high operating costs in deep offshore fields, with producers desperate to trim budgets and create new, cost-effective systems and solutions, even when prices were higher,” said Bjørn Søgård, DNV GL’s segment director for subsea technology. “Aligned with a squeeze on margins, it also faces challenges in technological collaboration.”
“Cost reductions are needed throughout the industry for more projects to become viable (Fig. 2),” agrees Aker Solutions’ Valla. “From a technology development point of view, some degree of investment will always be required to bring technology forward.” And GE’s Huuse reflects, “The short-term consequences linked to technology development may best be described as a directional change, with more focus on technology linked to cost benefit, efficiency and sustainability.”
Potential remedies. To achieve lower costs and greater efficiencies in the subsea sector, several firms offer some suggestions. “We see a clear potential and interest among our customers to engage in R&D programs, with a focus on subsea technology simplifications as a source for bringing down the cost of subsea deliveries,” said FMC’s Selvig. “The key word is ‘simplification,’ making the subsea equipment simpler and smarter.”
“We have several cost-reduction measures in mind,” said Aker Solutions’ Valla. “One is improved standardization, which means that operators and suppliers must have a coordinated approach to succeed. Another is limited project-specific adjustments to technology, which allows us to benefit from ‘larger scale’ production. We also favor technology development that drives cost-optimized solutions.”
“There is a clear shift toward more-focused development of selected technologies,” said Statoil’s Eidesen. “There is also a shift toward leaner technologies and Capex-reducing solutions. Additionally, there is increased focus on re-use and multi-use of developed technology. There is also a trend in the direction of more carbon-efficient solutions, which is positive for subsea.”
Over the last year or so, GE has started preparing solutions to drive down costs, to enable operators to meet their financial constraints, said Huuse. “At the same time, the operators need to keep their existing wells flowing, hopefully leading to a steady Opex spend, and this will go some way toward keeping the sector healthy.”
Collaboration is another ingredient that some firms believe will bring costs down. “Technology and expertise in oil and gas are typically split into different specialist fields,” explained DNV GL’s Søgård. “This has been absolutely necessary, to build and operate large, complex installations. However, there is now a drive underway for the industry to work more collaboratively to research, develop and deploy the most technically and financially efficient technologies and methodologies. Information from across all specialist fields must be included, to ensure that decisions are made on the best evidence available.”
Norway has built up an enviable record of subsea innovation. “Since the first generation of subsea technology was developed and put into production in the late 1980s, Norway has developed a globally leading subsea industry,” said Statoil’s Eidesen. “Operators are focusing on maturing new subsea developments, aiming at simplifying and developing smarter solutions to adapt to the new business context. The Johan Sverdrup field development has a subsea scope that will be awarded later this year. Subsea processing solutions are being matured in an IOR context.”
“Norway has a large subsea cluster, i.e. a lot of different companies with state-of-the-art subsea know-how and competence,” said Seabox’s Lunde. “The momentum for development of new technology and new solutions in the sector is good, and the required experience and know-how is there to make it happen.” As DNV GL noted, the industry’s overall drive to develop more cost-efficient ways to produce, process and transport oil and gas offshore has, in the past few years, led to tremendous developments in subsea technology. “The number of installed subsea Christmas trees is about 800 on the NCS and approximately 5,000 globally,” said Søgård. “These numbers are forecast to increase.”
From Aker Solutions’ point of view, “the delivery of the Åsgard subsea compression Project and the Aasta Hansteen project, which is the deepest subsea development in Norwegian waters to date, will represent significant milestones for the NCS.” And looking to the future, added GE’s Huuse, “The portfolio of recent discoveries on the NCS shows that the majority of the developments will be subsea.”
TECHNOLOGY DEVELOPMENT FOCUS
Norway’s subsea sector continues to progress on development of several technologies. These technologies include a subsea production plant, subsea compression, greater use of subsea tie-backs to keep development projects economical, and other related items.
Subsea production/Subsea Factory. As Aker Solutions sees it, “the main point of interest on the NCS now is the introduction of the advanced subsea production system, with subsea power, processing, compression and boosting,” said Valla. “Going forward, the focus will be to expand the offering with optimized and modularized systems.”
Central to this effort is Statoil’s concept for a process plant on the seabed, which the firm has dubbed a “Subsea Factory,” Fig. 3. Such a plant will make it possible to utilize remote-controlled transport of hydrocarbons at any offshore facility, even if farther from land, at greater depths, and in colder and harsher environments. Statoil believes that compact separation facilities on the seabed will be a key to success in harsh or deepwater areas. The company’s offshore portfolio is more than appropriate to the application of subsea production and processing. The firm operates 500-plus subsea wells and has a 25-year track record of subsea technology development, implementation and operation.
Statoil and its equipment/service partners already have taken several technological steps toward making the Subsea Factory a reality by 2020. They have devised the world’s first complete subsea solution for separation, and injection, of water and sand from the Tordis oil field (North Sea) wellstream, Fig. 4. They also have developed the first subsea facility for injection of raw seawater at Tyrihans oil and gas field (Norwegian Sea). Additional projects, such as oil-dominated, multi-phase transport at Tyrihans, and gas/condensate transport at Snøhvit field, are leading development of multi-phase transportation over long distances. The next step in the progression is to realize subsea gas compression this year (see separate discussion below).
“There is a focus on subsea separation, to enable more scope on the seabed,” said Eidesen. “Statoil is also progressing on standardizing interfaces within the Subsea Factory, and is inviting other operators to a JIP in this respect. Running the JIP on behalf of Statoil is DNV GL. “Statoil believes that standardization will be important to securing a strong, coordinated approach to the supplier industry, to achieve the goal of more profitable subsea developments,” said Søgård. “In this era of spiraling costs and plummeting oil prices, standardization and industrialization are important elements in the industry’s drive to tighten belts.”
Søgård said the JIP’s first step has been to collect ideas and input from suppliers, regarding the areas they believe will benefit from standardization. “The company is now in the process of defining standards for the interfaces, support structures and installation tools for the modules, in a subsea processing facility. The Subsea Factory Interfaces standard will, as far as possible, build on open industry standards. The key issue is to leave ample room for innovation by standardizing how the technology is packaged, connected and installed.”
Subsea compression. This year, subsea compression will be realized for the first time on two of Statoil’s operated fields—Åsgard (Norwegian Sea) and Gullfaks (North Sea)—said Eidesen. “These (installations) are both game-changers that will pave the way for the Subsea Factory.”
Working in tandem with Statoil, Aker Solutions will deliver advanced subsea processing solutions this year through the Åsgard subsea compression project, Fig. 5. “This represents ground-breaking technology that brings us closer to placing a fully-functioning production and processing system on the seafloor,” said Valla. “The project is to be delivered in 2015, with testing and final preparations already underway. We expect to further develop the technology, to reduce costs by using more standardized tools and optimized module designs.”
Subsea compression is also something that Seabox has been watching closely, said Lunde. “In recent years, there has been a push for technology development related to the Ormen Lange development and the needs there. This drive has been related to subsea compressors and the high-power units required to drive them. Hence compressors, high-power drive units and high-power supply for long distances have been in focus.”
Increased use of subsea tie-backs. According to Statoil’s Eidesen and FMC’s Selvig, technical work also has focused on an increasing use of subsea tie-backs, as well as greater utilization of long-distance tie-backs. Part of this effort will look at “reduced complexity for subsea tie-backs, in terms of reduced topside scope,” said Eidesen.
With an increased focus on maximizing economic recovery, one of the key challenges is to increase the use of subsea tie-backs to existing installations,” said DNV GL’s Søgård. “The implementation of Subsea Factories, e-field, IOR and integrated operations, are all areas in which collaborative work is ongoing.”
Subsea power development. FMC’s Selvig said that his firm sees “a continuous development of subsea power solutions, to meet the increasing demand for subsea processing.” DNV GL concurs on this assessment. “The economic and practical advantages of moving as many topside processing components to the seafloor as possible, has become a driving factor in the development of subsea power technology, said Søgård.”
Most recently, noted Søgård, ABB entered the JIP with Statoil, to develop solutions for transmission, distribution, and power conversion systems, designed to power and control subsea pumps and gas compressors. The five-year program is pivotal to the development of technologies required to power and control large-scale subsea pumping and gas compression projects planned for the NCS and other places worldwide.
“As the scale and power consumption of the subsea process continue to grow,” commented Søgård, “there is a clear need for a reliable power transmission and distribution system to power subsea equipment over long step-outs, potentially through the use of high-voltage, direct-current (HVDC) technology. This is already established in the offshore wind sector.”
Meanwhile, GE researchers have developed what they believe is a novel power transmission and distribution concept—a modular, stacked direct-current (MSDC) system. “This achieves,” explained DNV GL’s Søgård, “the required direct-current (DC) transmission voltage by stacking a number of power converter building blocks in series, both onshore and in the subsea field. The technology potentially offers a much lower cost and higher reliability for a subsea power solution, compared with modern land-based HVDC technology.”
Aker Solutions is developing a subsea RotoConverter that enables a more compact, cost-efficient variable-speed drive (VSD) alternative, Fig. 6. In addition, this new technology enables operators to achieve long step-out, low-frequency AC transmission for high power, up to 200–300 km and beyond, which is not possible under today’s limit of 100–150 km. “The RotoConverter makes it possible to reach stranded prospects and develop new fields without new offshore infrastructure,” said Valla. “This could become a key technology for regions where Capex can be significantly reduced by having power from shore or existing offshore facilities.”
In another approach to subsea electrical power, Statoil and its partners in Johan Sverdrup field on the NCS have decided that phase 1 will be supplied with power from shore. A transformer on Kårstø will deliver DC to the riser platform, ensuring an estimated 80 MW. This potentially would capture more than 90% of the total CO2 emissions from that area. Production start-up is scheduled for fourth-quarter 2019.
Additional technologies. In addition to the technical areas already mentioned, Norwegian firms are working on some additional products/solutions. Two examples pointed out by FMC are low-cost injection systems and multiphase pumping. Aker Solutions thinks that operators’ switch, from horizontal to vertical Christmas tree solutions, will be important for future projects, including cost-effective solutions for reduced vessel and rig time, Fig. 7.
Commenting on one of its own initiatives, Seabox noted that Subsea Water Intake and Treatment (SWIT) technology (see discussion further down in this article), in combination with subsea membranes, could become a technological game-changer for production of low-salinity and sulphate-free water for injection purposes. This would overcome two problems with advanced water treatment—high cost and the requirement for a large treatment facility on topsides.
DNV GL recently launched a new “standard for certification of subsea equipment and components.” The firm hopes that major efficiencies will be the benefit of the standard, by means of streamlined quality control and manufacturing processes. “The need to manage the integrity of subsea production systems, including those being operated beyond the original design life, is becoming more significant and technically challenging as maintenance demands increase and the industry as a whole looks to drive down costs,” said Søgård.
DNV GL also has published a recommended practice (RP), providing guidance on how to establish, implement and maintain an integrity management system (IMS). The aim is to help operators carry out maintenance activities at the most cost-effective intervals, increase confidence in the condition of subsea equipment, and ensure a unified, reliable reference for both authorities and the industry.
FIRMS’ TECHNICAL INITIATIVES
In line with the broader achievements, goals and priorities of Norway’s subsea sector, a number of firms are pursuing individual R&D agendas. What follows is a representative sample of that work.
Aker Solutions. The company continues to invest in new technology, particularly in next-generation control systems, through the introduction of Vectus 6.0. This software and electronics platform, with a distributed architecture, brings a step-change in flexibility, management and monitoring. “We are also expanding the Christmas tree portfolio in the vertical tree segment, our subsea boosting product range, our workover systems for light intervention solutions, and our offering related to asset integrity products and services,” said Valla. “Finally, we are developing with our partner, Baker Hughes, in the Subsea Production Alliance, effective combinations of in-well and subsea technologies to enable greater production rates.”
In addition to its RotoConverter for subsea power, Aker Solutions also has developed a concept called IHS (Integrated Heating System), which combines long step-out power supply to subsea boosting/processing stations with flow-line heating. With this combination, it is possible to ensure flow assurance and enable advanced subsea production that transports hydrocarbons across long distances to the market.
FMC Technologies. The firm has recently developed, and is marketing, systems for asset integrity monitoring of subsea installations, named Condition Performance and Monitoring (CPM). In such surveillance, raw sensor data from a subsea production system operating on the seabed are collected, transmitted and analyzed. The analysis and information are used in a proactive, preventive way to maximize system uptime and minimize maintenance costs.
“The data are transmitted through our subsea control system, and via the production hub’s satellite link to FMC Technologies operations onshore, sometimes located on the other side of the world,” said Selvig. “Our operations are manned 24/7 and have regular contact with the customer to assist the operator in both short- and long-term actions and planning, to secure the uptime of the subsea installation.”
Reactive Flex Joint is another innovation for intervention of subsea wells. This is a flexible joint on the lower part of the riser that neutralizes the bending load on the wellhead, hence reducing the fatigue issue of the wellhead. “We are running a pilot with Statoil on this, and it is scheduled to be tested offshore during 2015,” said Selvig.
Seabox. The focus at Seabox is subsea water treatment for injection purposes. As alluded to earlier in this article, the company has spent the past 10 years developing its SWIT technology, Fig. 8. Seabox recently completed a pilot seabed test of the SWIT system, in combination with a membrane process plant for sulphate and salt removal, sponsored by the industry. “Highly convincing test results from the former JIP have triggered a new project,” said Lunde. “This is also reflected in the level of oil companies involved.”
In the new JIP, Seabox will complete a conceptual design for a subsea SWIT and membranes plant, capable of producing any quality water from surrounding seawater on the seabed. A key objective is to secure maximum longevity for important components, to prolong intervention intervals. “We think that being able to produce any required water quality directly from the surrounding seawater at the seabed is a game changer in the industry,” said Lunde. “This provides for much better green field and brown field developments, and thus is very important for operators in the current (operating) environment.”
DNV GL. The company provides technology qualification (TQ) services to the oil and gas industry, including the subsea sector. DNV GL’s portfolio within subsea technology qualification ranges from single components, such as seals, valves and electrical penetrators, to more complex systems, including large-bore vertical Christmas trees and subsea compression technology, Fig. 9. “The degree of involvement also differs significantly within our portfolio, ranging from facilitation of workshops and supporting clients in their qualification management processes, to acting on our client’s behalf toward their suppliers, and performing independent tests and analyses,” said Søgård. Projects include assisting Statoil in the assessment of the TQ processes, and TRL (Technology Readiness Level) evaluations for the Åsgard subsea compression project and qualification of downhole safety valves for Ormen Lange field.
Meanwhile, DNV GL’s JIP to streamline subsea documentation, involving 20 industry players, has delivered its first results. The JIP has made a major step forward, with the first draft of an RP establishing industry guidelines and recommendations. Working together, the partners have invested considerable time to scope out, and agree upon, a set of typical subsea production systems (SPS), and functions with common terminology and a required, minimum set of documentation between operators and contractors. The work has been performed in Norway but has an international focus, and is not just applicable to the NCS.
The JIP’s next phase will extend the scope of SPS to include subsea, umbilicals, risers and flowlines (SURF), and to further address documentation requirements between contractors and suppliers. Phase 3 of the JIP will be run in 2016, and will include, among other activities, identifying an improved, shared solution for governance of information and a finalized DNV GL recommended practice.
GE Oil & Gas. The company has taken a couple of steps to increase its presence in Norway’s subsea sector. Last December, it signed an agreement to acquire the Subsea Electric Actuator product line of Oceaneering. The product line specializes in the design and manufacturing of specialty subsea products, with a focus on electric valve actuators. The closing of the deal—subject to standard regulatory approvals—was set to complete in first-quarter 2015.
Oceaneering’s 16-person, Stavanger-based engineering team, dedicated to the Electric Actuator product line, will join GE Oil & Gas and transition into the Subsea Systems business that also is based in Stavanger.
In addition, last August, GE unveiled its new Technology Solutions Center (TSC) in Stavanger. The $5-million center offers a visual showcase of GE’s technologies across the oil and gas industry. Located opposite GE’s existing Subsea Systems facility in the port of Dusavik, the center features a combination of interactive digital displays, live demonstrations and scale models, including GE PII’s Intelligent Pigs, the Safire 2.0 multi-phase flow meter, and the Deepwater Vertical Xmas Tree.
This is the second article in a series on Norway’s E&P industry. A third article will run in the next several months.
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