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Retro perspective

Hindsight, the adage goes, is 20:20. But can it save 20% or more on new offshore development costs? For French major Total, that’s just a starting point

In these cost-conscious times, paring down the capital costs of a new deep-water project by 20% is quite a feat.

But Total has a much more ambitious goal in mind — a capex reduction of 50% for new projects.

It will not happen overnight — savings on that scale will require technologies not yet in use, and further refinement of existing practices.

However, there are significant incremental cost reductions that can be achieved now, says Luc Riviere, senior adviser in Total’s Deep Offshore business.

Barring a significant increase in the oil price, nothing less than the future of the deep-water sector is at stake, he says.

“Part of my job is to do business cases — to see what we have done in the past and how we have done it.”

It’s the sort of “comfortable and conservative” approach that the industry prefers, he says, one that uses tried-and-true methods and technologies.  

“But now, I would say, to save the deep offshore we have to reduce the cost, by a lot,” he says. “So we have to look for solutions and take some risks, but without jeopardising safety.”

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"To save the deep offshore we have to reduce the cost, by a lot."
Luc Riviere, Total E&P
 

Riviere is a strong advocate for technological solutions, a message he has been spreading both inside Total and at industry conferences.

That in itself is hardly notable — since the start of the downturn, oil executives have extolled the benefits of technology to address the industry’s economic woes.

What makes Riviere’s approach unusual is that it takes specific, completed Total projects and retroactively “redevelops” them, on paper, to show how the application of alternative technologies, many unavailable at the time of sanction, could have saved the company money while achieving the same ends.

Case in point: the Laggan-Tormore development west of Shetland, a remote gas field that came on stream in February 2016.

The initial four subsea production wells, in 600-metre water depths, tie back to the onshore gas processing plant at Sullom Voe, about 140 kilometres away.

The 90,000 barrels of oil equivalent per day development was Total’s first subsea-to-shore project, a money-saving option in itself when compared to alternatives once under consideration, including a new tension-leg platform.

“Laggan-Tormore was the first time we implemented a subsea-to-shore concept on a gas field,” Riviere says. “The concept is not new, but it was a challenge for us because of the harsh environment in the West of Shetland.”

At water depths greater than 600 metres, it was also the first deep-water project in the region, he points out. Strong currents, icy waters and generally harsh conditions presented challenges for both drilling and installation of the subsea architecture.

Total has not disclosed how much it and partner Dong spent to develop Laggan-Tormore, but with the sum said to be a few billion, a cost reduction of even 20% would be significant.

“That’s the idea of this Laggan revisited, as we call it,” Riviere says. “If we had to do it today, how would we do it? This concept is 10 years old.

"Today we have more confidence in flow modelling, and we have more confidence in the way we are developing new tools. So if we had to decide today, how would we do it?”

Laggan-Tormore’s onshore facilities include an extensive monoethylene glycol (MEG) storage and regeneration system, including five large tanks.

Totalgraphic1fixed.jpg SAVINGS: A graph illustrates how new technology and alternative practices can cut development costs.
 

The system provides continuous MEG injection via one eight-inch line. There is also a MEG filled two-inch service line used for tree valve testing and annulus management.

The onshore plant also features two large slug catchers, as well as gas treatment, gas compression and water treatment facilities.

Along with the MEG and service lines, the Laggan and Tormore subsea templates connect to shore via a 5.1-inch umbilical and two 18-inch concrete-coated production lines. The umbilical and MEG/service lines were installed and then separately rock-dumped.

In what Riviere calls an “optimised base case”, the service line would be eliminated.

“In fact, we don’t need it. We have a spare line in the umbilical, which we can use to provide back-up to the service line. We don’t need this two-inch line,” he says.

In an optimised base case, the MEG/service lines and umbilical would have been rock-dumped in a single operation, he adds. The two measures would have reduced the overall cost of development by about 4%.

Things get more interesting — and cost-saving — as Riviere details more ambitious scenarios for subsea-to-shore developments.

The first option would replace continuous MEG pumping with a flow assurance strategy based on anti-agglomerant low-dosage hydrate inhibitor (AA-LDHI) injection.

LDHIs are injected at much lower amounts than MEGs — between 0.5% and 2.0% of the fluid to be inhibited, compared with a 60% to 80% content in MEG applications.

The technology has been used in gas fields, Riviere says, but could be a viable option in fields that, like Laggan-Tormore, produce an adequate amount of condensate.

“The advantage of this is that you remove the regeneration and reclamation (system), which is a huge capex, and replace with AA,” he says.

AA-LDHI is comparable to MEG in operational expense but could significantly reduce the cost of a subsea-to-shore gas development.

In the Laggan-Tormore example, the AA-LDHI option would eliminate need for the eight-inch MEG line, as well as the onshore MEG storage and regeneration facilities.

The umbilical could be expanded to a diameter of 5.8 inches to accommodate an additional injection line. In all, the switch to AA-LDHI would bring capex down by another 8%, to 88% of what was spent on Laggan-Tormore.

Option two would replace the electro-hydraulic equipment and controls with an all-electric alternative. This, Riviere admits, is a few years off, both in technology application and in overall industry acceptance.

Confidence boost

But the trend is under way, and Total is betting heavily on the subsea electronics. The company helped boost confidence in subsea electronics with last year’s successful start-up of the K5F3 well in the Dutch sector of the North Sea, billed as the industry’s first all-electric subsea well.

Total has said the all-electric subsea alternative will allow development of deep-water satellite fields in West Africa and subsea-to-shore fields in the North Sea. “We believe the future of subsea is all-electric,” Riviere says.

An all-electric development strategy at Laggan-Tormore would have required the umbilical to include an electric power and fibre optic cable, but the diameter of the umbilical would be reduced to 3.6 inches with the elimination of hydraulic power channels.

That in turn would mean the umbilical could be installed in a single length. The all-electric option would bring capex down by another 4%.

“We can work on the size of the template, reduce the weight of the jumpers, but that saves a few million,” Riviere says.

More dramatic measures, such as all-electric subsea infrastructure, will be necessary to reach Total’s ambitious capex reduction goals.

A further step would eliminate the second production line.

“We have two 18-inch production lines because want to do pigging,” he says. The conventional loop system enables frequent pigging but is costly with long deep-water tiebacks such as Laggan-Tormore.

Option three calls for a single production line. “But in order to pig the line we need to install a subsea pig launcher that can launch a pig every three months,” Riviere says.

The technology is not in place today but Total has been working with National Oilwell Varco to develop a fully automatic subsea pig launcher that can store multiple pigs on the seabed. NOV hopes to bring the system to the market in 2018.

Option three eliminates one production line and one pig catcher, but savings are offset somewhat by the cost of the subsea automatic pig launcher and the operational constraints of a single production line, which would become more pronounced as the field ages, he says.

In the short term, however, the strategy would bring the capex facilities cost down an additional 7%, to 77% of Laggan-Tormore’s actual cost.

Riviere’s final tweak to the Laggan-Tormore layout involves subsea chemical storage. The technology is in development for oilfields but could be applied in gas fields, he says.

It will be some time before subsea chemical storage is ready for field tests, he notes.

Like the subsea automatic pig launcher, subsea chemical storage is a nascent technology NOV acquired in the 2016 purchase of Kongsberg Oil & Gas Technologies’ subsea division.

Swapping out subsea storage tanks will pose less risk to the environment than delivering chemicals through an umbilical from a supply vessel, Riviere says.

The technology will not save on subsea production system costs but capex for an option four that includes the technology still comes in at 79% of the base case scheme, a saving of more than 20%.

That is a big step toward Total’s capex cost-cutting goal and a worthy target for the industry at large.

“These are the kind of studies we are producing and presenting at conferences,” Riviere says.

“We want to share with partners, competitors and contractors. We have to bring down costs and make these projects more profitable.”