With a need to find more cost-effective solutions, for more complex systems, converging with the big data era, could it be time for the all-electric subsea system? Elaine Maslin reports.
Daniel Abicht. Image from UTC Bergen.
Going all-electric on subsea systems appears to offer many benefits. You can have simpler umbilicals without hydraulic lines, for one, which in turn removes the need for topsides hydraulic support systems and eliminates the risk of leaks to the environment. More flexible subsea architectures can be installed and more accurate control over, and knowledge of, subsea and downhole equipment can be achieved.
In the past, technology readiness, high oil prices, the costs of such systems and a reluctance to try new technology, have perhaps hindered progress. But, the picture is changing rapidly. System suppliers are edging closer towards qualifying subsea power distribution technologies. Vendors are further proving their all-electric equipment, and operators are continuing moves into areas (deepwater, long stepouts) and technologies where electric control would be beneficial.
Could it finally be time for all-electric? Operators believe so. French oil major Total, which began using the first fully electric subsea Xmas tree last year, says it has “a firm belief on all-electric systems.”
Daniel Abicht, leading advisor subsea control systems, Statoil, says that all-electric hits nearly everything on the Norwegian major’s technology strategy. This is no longer a subsea controls topic, it’s a system topic, he told the Underwater Technology Conference (UTC) in Bergen earlier this year.
All-electric can reduce CO2 footprints, eliminate the risk of hydraulic fluid leakage, reduce logistics and exposure to equipment under pressure, and enables a degree of automation – as well as advanced condition monitoring, which couldn’t be achieved otherwise. “Digitalization requires a higher degree of automation. To achieve a high degree of automation subsea is only achievable by going all-electric and this is even more applicable for subsea processing applications,” he says.
Statoil’s chief engineer subsea, Rune Mode Ramberg, adds another dimension – imagine being able to have an IP address for each subsea valve. This offers a huge difference in accuracy. Going all-electric also offers flexibility, plug and play capability and simplicity, says Einar Winther-Larssen, product manager, All-Electric, Aker Solutions.
All-electric could also achieve cost savings. In an Offshore Technology Conference (OTC) Houston 2017 paper, Abicht says all-electric subsea production systems provided capex savings of 7-14%, not counting the removal of the associated topside equipment and opex savings. A similar project by Total identified up to 13% total capex savings on an existing project.
Statoil’s Johan Castberg project, which could feature a DC/FO system.Image from Statoil/Kåre Spanne.
Traditionally, hydraulics were used to control subsea valves. Electro-hydraulic systems were introduced to overcome the slow response time and issues over scalability with hydraulic only systems. Electro-hydraulic systems are limited in terms of future tiebacks, long stepouts, deepwater applications, and add topside complexity. This means costly and complex Xmas tree control systems, which have arduous system startup and shutdown processes, Abicht says.
“The next step in technology development is to eliminate hydraulics… driven by performance needs, water depth increases and environmental constraints,” says a 2017 OTC paper by Johansen et al., from TechnipFMC.
Increases in subsea sophistication, such as chemical dosing, pumping, separation, and gas compression also add to the drivers, and indeed, in some cases, such as for fast modulated process valves, electric actuation is an “absolute need,” it says. Furthermore, the increasing emergence of resident remote operated vehicle (ROV) type technologies will also enable the “next generation inspection, maintenance and repair systems,” in all-electric fields.
Electric actuation is already well established. Statoil has had electric actuation since 2001, and has 8.5 million hours operational experience in non-safety critical applications, all using a spring return. There are 800,000 hours accumulated running time on electric Xmas trees across the industry, Abicht says. Statoil’s Åsgard subsea gas compression system has 79 actuators in operation and is an all-electric system.
TechnipFMC installed its first electric systems 15 years ago, 165 of their electric actuators have been installed since, and 8 million hours of operation have been accumulated in electric systems provided by TechnipFMC over that time, says Johansen et al.
Statoil want to start qualification an all-electric Xmas tree system in 2017-18, then adding a subsea safety valve in 2018-19. A stepping stone for the latter could be a subsea hydraulic power unit, Abicht says. Other items are also requiring qualification, specifically those on safety critical subsea applications, such as well barrier valves.
The first e-tree
Last year, Total launched the first all-electric subsea Xmas tree, including downhole subsea safety valve (DHSV), in the Netherlands (OE: September 2016) on the 18km stepout K5F-3 well in 44m water depth. Two earlier wells on K5F have had all-electric trees since 2008 – also firsts – but a hydraulic DHSV. The latest components were qualified to 3000m water depth, making it a deepwater-ready technology. The system uses Schlumberger-owned OneSubsea’s latest generation CameronDC subsea Xmas tree and controls technology and a Halliburton electric downhole safety valve (eDHSV).
To test the impact of going all-electric on a subsea development, Total performed a study on its Laggan-Tormore subsea tieback – the UK’s longest subsea tieback. The project, 143km from shore, in 610m water depth, came onstream with an electronic-hydraulic control system in 2016. Total looked at what difference it would have made if it had used a DC current and fiber optic (DC/FO) cable, for power and control, and all-electric subsea trees, with revised subsea control architectures, on the field. DC/FO has been proposed for the Johan Castberg development offshore Norway, with Statoil working with Alcatel Submarine Networks (OE: August 2016).
While a separate line would be needed to supply injection chemicals (Statoil and others are looking at subsea chemical storage), using such a system could achieve savings of 8-11% on the combined subsea umbilicals, risers and flowlines package, or 4-5% on the whole project capex, according to a 2017 OTC paper by Pimentel et al., from Total. Switching out continuous MEG injection with continuous anti-agglomerant accumulation chemicals, via a dedicated line, increased savings to 20-25%, 10-13% of the total capex, according to Pimentel et al.
Stripping out cost
According to TechnipFMC, savings would be made by removing the costs associated with hydraulic control systems, from the design phase through manufacturing, testing, installation and commissioning and finally maintenance and hydraulic fluid consumption.
Abicht points out that there’s around 150m of small bore tubing on a Xmas tree. On the manifold, there’s 300-350m. “It’s not only the metal, but the process behind that. Welding, inspection, documentation,” he says. Removing all this metal also reduces Xmas tree weight and footprint, making installation easier.
A new architecture
The K5F-3 subsea all-electric Xmas tree from OneSubsea. Photo from TEP NL.
Removing a hydraulic control system also opens possibilities for alternative controls architecture. An all-electric system could have “intelligent nodes” in the subsea system, favoring the distribution of control, says Pimentel et al. Having decentralized nodes would have two benefits, it says: a smarter and simpler electrical distribution, with the removal of additional electrical flying leads, and a better communications schema, using a ring connection topology (where devices are connected in a ring and data is sent around the ring until it reaches its destination). “Both effects will equally help in the overall system availability by reducing the number of connections and increasing the network fault protection,” the paper authors say.
Adopting decentralized control architecture with intelligent actuators, reduces cost, while electric actuators in a centralized system increases cost, according to a comparative study done by Aker Solutions, Winther-Larssen says. Current control architecture is designed how it is because it’s easier to install control hydraulics that way, he says. Removing the hydraulics enables simplified distributed subsea control modules, retrievable electric actuators, with and without failsafe spring, at roughly the same size.
One challenge with all-electric systems is their monitoring and control, Total says.
“The response time between fault detection and the corrective action for a subsea power system is required to be faster than a subsea production or even a subsea processing system,” according to Pimentel et al.
“For instance, if a fault is detected in the subsea step-down transformer, the topside protection system should be notified on a fast and direct communication link to ensure that the topside circuit breaker can be opened within time to protect the transformer. Therefore, the performance requirement for data sampling of a subsea power automation system is in the range of a few milliseconds, whereas a range of 100 milliseconds to 1 second is acceptable for a subsea processing system, and a few seconds may suffice for a subsea production system,” say Pimentel et al. Fiber optic helps in this respect.
One of the building blocks for all-electric is power distribution. Pressure compensated power equipment is expected to be available in the market soon, “which may have the impact to change the game of subsea production and processing systems,” says Pimentel et al.
Indeed, Siemens, GE Oil & Gas and ABB are all working on subsea power distribution technologies. GE Oil & Gas qualified a system, as part of its work on Shell’s Ormen Lange subsea compression step out proposal, last year (OE: August 2016).
GE Oil & Gas’ system is based on marinized power components (variable speed drives, and transformers), which have been marinized in one-atmosphere containers for use on the seafloor.
ABB is working on a US$100 million joint industry project, signed in 2013, based on components in pressure balanced oil-filled containers. The project it looking to qualify an up to 100MW system for up to 3000m water depth and 600km step out. Full system testing is due in 2018, in shallow water. Siemens was planning a system integration test of its system, also in oil-filled containers, and full load testing in water this year (OE: August 2016). Early August, Siemens announced that Eni had joined its joint industry project, alongside Exxon, Chevron and Statoil.
New system, new mindset
For all-electric to be achieved, there’s a mindset to overcome, however, Abicht says. “We have big organizations and all-electric has always been in some sort of research and development bubble. Hence, close and multi-discipline collaboration across the various business units is required.”
Meanwhile, existing requirements for controls, Xmas trees, and subsea production systems are often circled around established (hydraulic) solutions rather than functions. This provides a challenge regarding implementation of new technology. Moving away from a hydraulic system that people have confidence is also a challenge, Winter-Larssen says. But, he adds: “We have come to a point where we believe we can make competitive electric system compared to hydraulic.”
It’s coming. “We know all the major operators are assessing all-electric and it is the same in supply chain. Everyone has a strategy in place,” Abicht says. “That’s something we didn’t have 10 years ago.”
1. Real Application of Electric Controls Technology to Subsea Systems: Success, Learnings and Recommendations. OTC Houston 2017. OTC-27657-MS. Johansen et al., TechnipFMC.
2. Seamlessly Integrated Subsea All-Electric Systems: Laggan-Tormore as a Case Study. OTC Houston. OTC-27588-MS. Pimentel, J. et al, Total.
French major Total has been considering its late-life compression options for the Laggan-Tormore step out in the UK North Sea. The development, a 143km tieback to shore, came onstream in 2016, via two subsea manifolds with slots for up to six trees in each and the potential to tie in third party infrastructure.
Subsea compression could be used later in life to boost production from Laggan-Tormore and help produce gas from third party fields tying into the Laggan-Tormore system.
Total thinks that it would need up to 7MW of power for each compression units on the field, supplied via a 143km subsea AC power umbilical, at 63kV, with a separate barrier fluid line for the motor-pump mechanical seals.
The details were outlined in an OTC Houston 2017 paper by Juliano Pimentel, Rory Mackenzie, Edouard Thibaut, and Frederic Garnaud, Total. •
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