Seeing the (electric) light

Elaine Maslin

September 1, 2016

While French oil major Total has demonstrated the first all-electric Xmas tree, Norway’s Statoil is eager to do the same. Elaine Maslin examines the subsea all-electric initiative.

The Åsgard subsea gas compression system, complete with eActuators and electric process control valves.  Image from Statoil. 

With cost efficiency and simplification high on the subsea agenda, all-electric subsea facilities are coming back under close scrutiny.

All the parts are in place. Subsea actuators have become established tools, Total has demonstrated a full, all-electric subsea tree, and Halliburton has qualified an electric downhole safety valve (eDHSV).

The will is also there. Statoil wants to achieve its own all-electric tree within five years, says the operator’s leader of subsea technology within the research and technology division, at this year’s Underwater Technology Conference (UTC) in Bergen.

Operators are keen on an all-electric subsea concept because it could remove the need to install hydraulic conduits, reducing cost. Yet, the path to the all-electric subsea tree has been a long one.

A long electric road

The first subsea well was in installed in 1961, in 17m water depth in the US Gulf of Mexico by Shell. It was direct hydraulic drive. In the 1970s, electric-hydraulic systems were developed, to enable longer distances for control than hydraulics could cope with.

The Norwegian Continental Shelf had its first multiplex electric hydraulic control system in 1986, on Statoil’s Gullfaks satellites, says Bjørgulf Haukelidsæter Eidesen, leader subsea technology and systems, Statoil, at UTC earlier this year.

By the 1990s, work on electric actuators (eActuators) started, with Statoil using them in 2001, Eidesen says. On the Åsgard subsea gas compression project, the world’s first subsea gas compressor, there are some 79 eActuators, Eidesen says, and worldwide running time of eActuators is above 8 million hours.

Achieving a full electric Xmas tree took longer, however. In 2003, BP, working with Cameron, developed the first all-electric subsea control system for a six-month offshore field trial at the Magnus field, in the UK North Sea, in 185m water depth. An “electric tree” – a set of valves and a choke on a skid – was deployed, not connected to a well, but pressurized from the surface and connected to the Magnus facility for power and communications. However, BP didn’t take it much further.

It wasn’t until 2008 that the first all-electric Xmas tree system, with a hydraulic downhole safety valve, was deployed on two wells, in the Dutch sector. This summer, a fully all-electric system, including eDHSV was deployed on a third well at the same site (see pages 38-39). With electrical process control valves now proved on Statoil’s Åsgard project offshore Norway, a full subsea system, qualified to 3000m water depth, is close at hand, says Frederic Garnaud, deep offshore research and development program manager at France’s Total.

Why electric?

A hyperbaric test of Aker Solutions’ subsea rotary electric actuator, simulating 4000m water depth. Photo from Aker Solutions. 

Christopher Curran – ex-BP, and now working as a contractor for several companies including Edinburgh-based wireless subsea instrumentation and control and communications firm WFS, and consultancy Endeavor Management – based out of Houston, was involved in the Magnus trial. He says there are a number of benefits to going all-electric.

“You don’t have to keep filling the system with hydraulic fluid,” he says. About a gallon of hydraulic fluid is consumed for every valve operation, points out Bjørn Søgård, segment director, business development, subsea and floaters, DNV GL.“You don’t have people standing around high pressure systems, especially when we’re going to 15,000psi and higher,” Curran continues. “You get an awful lot more data out of the system. You get more knowledge about the health of the system. You can get some real indication if you’re having issues with a valve, actuator, from scale, waxing etc. You get very little information from a hydraulic actuator. And there is potential for savings on the umbilical side. Telecommunications cables are a fraction of the cost of an umbilical.”

The time it takes to operate a valve is also shorter with electric, Søgård adds, due to the time it takes to get back to a steady state after each operation, with no phase lag. Removing the hydraulic elements, and even the spring failsafe, replacing it with a battery, would also reduce the size and, therefore, cost of subsea trees, as well as the cost to install them, which means smaller vessels could be used.

Right timing

So, why has it taken so long and why the fuss now? Statoil assessed all-electric in 2009 for the Tyrihans field, but it was later canceled. At that time, Statoil found costs were too high, Eidesen says.

“A problem has been that everyone says electric and water do not mix, ‘it’s a bad idea.’ If you look at an electric actuator and compare it to hydraulic, you could say it’s too complicated,” Curran adds. “But, then, if you look at the whole system – with a hydraulic power unit on the topside, etc. – in those days there was at least parity between the two systems in terms of reliability.”

Another reason could be that the production control system is only about 2-5% of the total system cost, Curran says. Saving money there doesn’t seem like it would make a big impact in the overall cost, so it wouldn’t seem worth the risk.

There is also concern around the failsafe – the function that maintains the tree as a barrier to the reservoir, Søgård says. At the moment, mechanical spring failsafe hydraulically operated valves are used, something the industry is comfortable with. Hydraulic pressure holds the spring back, if the hydraulic fails, the spring closes the valve.

Going all-electric means either using a spring-based failsafe (API required), with a local electronic circuit, or a clutch solution, so that the open position is maintained using only a small amount of power, and use a battery as the failsafe option. Total’s K5F-3 is using a spring failsafe, without hydraulics – more details were not available.

Søgård says that while an electric-operated failsafe is not hard to achieve, technically – “Xmas trees are simple compared to process equipment” – the simplicity and industry comfort with hydraulically actuated Xmas trees means a change in philosophy is needed to move to something else, not least because a well barrier is being dealt with. “We are in a way reluctant to put on something delicately engineered to take care of this safety function,” Søgård says. Statoil’s Eidesen adds that the Norwegian oil major is going to evaluate both options – a spring and a battery failsafe solution.

A subtler problem, as all-electric is adopted, could be that the industry falls into the trap of each vendor producing its own type of electric tree, before there are standards, Søgård says. “There is a lack of standards. Shall we use DC or AC? We don’t know that. What voltage levels do we need? We don’t know that. No one has agreed a common design so we end up with tailor made solutions.”

Fast forward

Still, the industry is moving forward, partly driven by cost reduction, but also to help it move into deeper waters and to achieve longer step outs, as part of a wider all-electric system.

In 2014, even before oil prices plummeted, cost reduction was high on the agenda for subsea projects, not least in Norway. Operators are looking at how to simplify subsea systems, reducing the number of flowlines, umbilicals, connectors, etc. All-electric could help.

Indeed, in 2015, Norway’s OG21 group published a report on subsea cost reduction. It said that in order to reduce subsea costs by 50%, an important technology step was achieving all-electric. In addition to achieving an all-electric subsea tree within five years, Statoil is also working towards a local hydraulic power unit subsea – due to be qualified this year – to power the 7in downhole safety valve, but ultimately, the firm wants to see a 7in eDHSV developed.

Furthermore, “Being able to lay a power and communications cable, not complex umbilicals, will save cost, especially for long distance tiebacks,” Curran says.

Statoil has done just this on the Johan Castberg development offshore Norway. It is planning to use a DC and fiber-optic cable in daisy chain to power the subsea wells at Johan Castberg (OE: August 2016), reducing cost and complexity.

Electric enabler

A high voltage subsea electrical actuator, from Aker Solutions.  

However, it isn’t just about lowering cost, Eidesen says. DC fiber optic, for example, is a lean system that can enable tieback distances of 300km or more, he says, and is independent of subsea production system supplier because it offers an open channel.

“It provides the power necessary to power electric actuated valves and even small chemical injection pumps,” Eidesen says. “It can power AUV (autonomous underwater vehicle) systems, seismic cable grids or environmental monitoring systems. There’s a lot to it apart from powering. And it is proven in telecommunications.

“In the case of Åsgard subsea compression, the process control of this system could not have been done with electro-hydraulic actuated valves, due to the high complexity and valves,” he adds. “It also reduced umbilical and topside cost.”

Changing the mindset

But, there’s still the mindset challenge. “To me the big, important question is that it’s not the technology [that hinders development], it’s the choice of philosophy and accepting new philosophies,” Søgård says, which can often be driven by just one individual in an organization.

“Sometimes conservatism can get in the way,” Eidesen says. The industry should take care not to standardize too much so that all-electric is hindered, he warns. Failsafe standards should also be written to enable a battery solution, he adds.

Another more practical piece to the puzzle is chemical supply for injection. Taking away the hydraulic umbilical is one thing, but you would still need chemical lines. However, a number of people are working on subsea chemical storage and injection, Curran says, including Total.

“We need to break the paradigm of everything being connected together by cables,” Curran says. “With the advent of wireless systems and long battery life of up to 10 years, it is now much easier to add sensors later and gain the measurements you need.”

Achieving the all-electric tree could open up new possibilities, he says. “Suddenly you step across this line and there are so many things possible that weren’t possible before or were near to possible.

“It’s about how to make subsea cost efficient at $50/bbl, breaking the convention of having to have dual flowlines. It’s also life of field extension, the ability to wirelessly recharge AUVs without having to dock to connectors, which WFS can achieve.”