Offshore Energy: A New "Lease" on Life
(Article originally published in Mar/Apr 2015 edition.)
With low oil prices sinking some of the more challenging and expensive offshore projects, 2015 looks to be the year of technologies that bring subsea cost savings and life extensions.
This year will see the world’s first subsea gas compression system come online at the Statoil-operated Åsgard field in the Norwegian Sea. The new system from Aker Solutions will extend the field’s production life by 20 years, enable the recovery of an additional 282 million barrels of oil by boosting gas pressures, and bring the industry a step closer to having a fully-functioning production and processing system on the seafloor.
Gas compressors have already been installed on platforms to maintain output as reservoir pressures drop over time. Placing them on the seabed and near wellheads improves recovery rates and reduces capital and operating costs. Subsea compression also leaves a smaller environmental footprint and is safer to operate than a platform. “The Åsgard project is an industrial game-changer,” says Aker Solutions’ Senior Vice President for Technology, Hervé Valla. “It has the potential to significantly impact the subsea production market.”
The Åsgard project will see two 11.5MW subsea compressors installed in a 74 x 44 x 20m subsea station weighing around 4,800 tons. The size and weight of the equipment are indicative of how moves into deeper water are generating the need for larger, more capable construction vessels such as EMAS’ Lewek Constellation, christened in March.
The ice-classed, multi-lay offshore construction vessel has ultra-deepwater pipe-laying and heavy-lift capabilities provided by an 800mt Huisman multi-lay system able to support rigid and non-rigid pipelines and a 3,000mt Huisman offshore heavy lift crane. Her first job will be a two-well tieback for the Gunflint Project in water depths of over 2,000 meters in the Gulf of Mexico, part of Noble Energy’s march into deeper waters.
“Over the last 15 years the number of subsea tiebacks and subsea developments has been increasing, and that trend will likely continue,” says Andrew Hughes, Vice President of Energy at London Offshore Consultants. “There are some economic factors that make them attractive in the right situation. Floating structures are a major capital investment, so some of these subsea tiebacks can be attractive on, say, a marginal field.”
Topside Life Extensions
Gulf of Mexico operators are also now looking at topside life extensions. “There are a lot of floating platforms that were installed in the mid to late ‘90s,” says Hughes, “so they are coming up to their 20-year anniversary, which is what a lot of them were originally classed for.” The aging of assets and a focus on cost savings driven by low oil prices have placed a premium on inspection, maintenance and repair above and below the surface.
Wood Group Kenny (WGK) has operated in Brazil since 2004 where the ultra-deep fields experience high waves and strong currents. According to Hugues Corrignan, Managing Director for WGK in Brazil, the high CO2 content of the fields also leads to highly corrosive fluids. These factors combined mean that Brazilian developments are particularly challenging for the design of subsea equipment, corrosion-resistant alloy pipe design, riser strength and fatigue performance.
“WGK has been particularly active in developing riser solutions for the pre-salt area, ranging from steel catenary risers (SCRs) to hybrid riser solutions to the steel lazy-wave riser (SLWR) configuration,” Corrignan explains.
The long-term integrity of subsea components is crucial, and it is important to develop the right tools, equipment and services related to design, inspection and monitoring, he adds. So WGK develops, maintains and sells its own proprietary suite of industry-leading subsea engineering analysis, flow-assurance and integrity-management software, including Flexcom (for riser analysis and design), DeepRiser (for drilling riser design and analysis), PipeLay (for pipeline lay analysis), Nexus (for integrity management) and Virtuoso (for production process simulation).
Inspection & Lubricant Innovations
Innovations continue to emerge across the upstream lifecycle. Tracerco’s Discovery system won two innovation awards last year because it can non-intrusively visualize wall deterioration and the contents of “unpiggable” (i.e., cannot be inspected with insertable robotic “pigs”) coated pipelines without interrupting production. It is not necessary to remove the pipe’s protective coating, and this reduces the risk of corrosion and eliminates the expense of deploying divers.
Kongsberg released K-Observer last year, a system that detects scouring, corrosion, deformation and marine growth that can destabilize subsea structures so experts on shore can initiate immediate action or preventative maintenance if required. This is lower cost, safer and more time-efficient than diver, ROV or vessel-based surveys.
Most subsea equipment is designed specifically for the industry, including its lubricants. According to Tony Globe, Business Development Manager for Castrol Energy Lubricants, subsea tiebacks are remotely controlled from a host installation, and most control systems are electro-hydraulic with the motive force to operate control valves provided by hydraulic actuators mounted on the subsea equipment and, in some cases, within the well bore.
The hydraulic fluids are conveyed from the host installation to the subsea facility via hoses within a control umbilical. The offset distance between the equipment and the host can vary from a few hundred meters to over 100 kilometers. Hydraulic control fluids have been specifically developed to have low viscosity to provide acceptable response times over these long distances. Castrol works directly with equipment designers and manufacturers to design lubricants, but Globe sees an ongoing need to continue lubricant development as offshore operations become more demanding.
Drilling operations have been moving into more demanding areas where the latest (fifth and sixth) generation drilling vessels and large blowout preventers (BOPs) are required. However, larger BOPs, now weighing more than 300 tons, have been shown to increase fatigue damage rates by a factor of 17 compared with older, smaller designs, so here again there is the challenge of extending equipment longevity.
“Wellhead failure is a catastrophe that can impact the environment, operations, profitability and the reputation of the companies involved,” says Ken Kirkwood, Project Manager for Structural Monitoring at Fugro GEOS. The wellhead, a relatively small component, is where the forces from the riser and the BOP transfer through to the conductor and the surrounding soil. These massive forces are transferred through the approximately 30-inch-diameter tube that is the wellhead.
Two types of instrumentation can provide high-quality measurements that assist with BOP design verification: self-logging and real-time monitoring systems. Measurements can be used to build up a fatigue database. “Self-logging equipment is typically installed and recovered while the riser or BOP is running – in other words, when the drilling vessel is at its busiest and most critical phase,” says Kirkwood. “Recent improvements have led to the installation of receptacles on the riser and BOP offline, away from the critical phase. The measurement equipment is then installed by ROV after completion of the critical riser-running phase. As well as operational benefits, there are significant safety benefits in ROV deployment.”
As for real-time data logging, Kirkwood states that “It has previously relied upon cabled solutions although this is not a popular method. Installing cables on the riser adds time to the riser running, could expose the individuals fitting the cables to increased risk, and could mean that the cables are susceptible to damage in extreme weather. However, recent improvements in technology can provide real-time data from the BOP without using cables.”
The new developments have been driven by the availability of low-power components: sensors and data loggers, high-energy-density lithium batteries, improved processing capabilities of data-logging equipment and the reliability of the latest generation of hydro-acoustic data modems. With the latest technology, measurement equipment can be installed subsea for up to a year, making data available at the surface in real-time over that period.
Seeing Is Believing
Video communication is commonly used to optimize drilling operations and enable collaboration between geographically dispersed stakeholders, and the scale of operations can be huge.
Oceaneering typically receives between 200 and 250 live subsea video feeds simultaneously from its ROVs. In one project, there were 29 ROVs in the water at any given time, each with up to six cameras, which were collectively delivering over 100 live video feeds. Already a bandwidth challenge at these feed volumes, the problem will only worsen as the size of video files continues to increase beyond standard definition to high definition.
Video can be used to provide a critical real-time look at all ROV, vessel and dockside operations as well as drills and incident-response activities. Never was the value of live video images delivered from an offshore oilfield more powerfully showcased than during the 2010 Deepwater Horizon oil spill. Transmitted continuously for more than three months from approximately 5,000 feet below sea level, the live video stream was viewed by 20 million people each day and played a pivotal role in everything from crisis response and management to how policy and public opinion were formed around the incident and in its aftermath.
Oceaneering delivered that live feed from a land-based location, demonstrating the cost and efficiency benefits of video for round-the-clock incident response management as well as its many other roles during the upstream project lifecycle. The company is anticipating the move from high definition to 3D formats next, adding further sophistication to what is being achieved subsea already. – MarEx
Wendy Laursen is the magazine’s Asia-Pacific News Editor.
The opinions expressed herein are the author's and not necessarily those of The Maritime Executive.