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Confidence boost

Written by  Elaine Maslin Friday, 01 September 2017 00:00

Subsea boosting is helping to push otherwise uneconomic subsea projects over the line. Elaine Maslin reports on two tiebacks benefiting from a bit of boost – including the industry’s longest deepwater subsea multiphase boosting tieback.

Murphy Oil’s Dalmatian field layout.
Image from Murphy Oil.

It’s a common refrain – there are many known and mapped resources ready to be tapped. But, because of distance from host facilities, flow assurance concerns, and topside constraints, these potential developments are often left on the shelf.

Operators and vendors have been working hard to find solutions and subsea boosting is proving to be one. Australia’s Woodside is using subsea boosting to help make its Greater Enfield project fly, while Murphy Oil is using the same to boost and enable future tie-ins on its deepwater Dalmatian project in the US Gulf of Mexico. Both use high-boost multiphase pumping systems from OneSubsea, a Schlumberger company, and both projects were presented at the Underwater Technology Conference (UTC) in Bergen in June. “Subsea pumping is a mature technology,” says Arill Småland Hagland, senior systems engineer, OneSubsea, with more than three million hours operational experience. OneSubsea has more than 100 pump units in its portfolio – adding up to more than 200 MW of subsea power.

Many projects use the multiphase high-boost design, which is the result of a joint industry project launched with a number of oil majors in 2007. It aimed to increase boosting capabilities, to significantly more than 50bar achieved previously. It also makes use of balance pistons, which help counteract the axial force of the impellers in the pump. It is field proven on projects including Barracuda in Brazil, and Total’s Girassol and Moho projects off West Africa.

With the help of efforts to standardize these systems – and the processes involved in deploying them – subsea boosting is becoming an economic enabler, Hagland says. “There’s been a perception that subsea boosting is very expensive,” Hagland says. “We have spent time over the last few years trying to reduce cost based on this solution.” This has included a standardization program on the technology and system solutions, but also on how to execute projects, and how to run projects internally.” Indeed, Murphy’s Dalmatian project, which will have a multiphase high-boost pump installed in 2018, is the result of all of this,” he says.

Woodside’s Greater Enfield project. Image from Woodside.

Dalmatian

Murphy Oil’s Dalmatian field is in DeSoto Canyon, 260km from New Orleans, in the US Gulf of Mexico. The project, a daisy chained development tied into Chevron’s Petronius compliant tower, which sits in 550m water depth. Dalmatian was developed in two phases. The first, Phase 1, is a 35km, pipe-in-pipe oil well tieback and a 38km gas well tieback, with a common, 14-tube umbilical, in 1770m water depth. Phase 1 came onstream in 2014.

Phase 2 added an 18km pipe-in-pipe extension in 1980m water depth, taking the entire system out to 51km from Petronius. Phase 2 came onstream in 2015. Now, the firm is looking to add a subsea multiphase boosting system to the field, based at the end of the initial 35km step-out, making it the industry’s longest deepwater subsea multiphase boosting tieback. As well as adding boosting to the development, this could enable further opportunities in the area, said Mike Clarke, project manager, Murphy Oil, at UTC.

Dalmatian was a marginal development, Clarke says. But, “working with the vendor, with a unique contracting strategy, in the current climate we were able to make something like this work.”

Challenges on Dalmatian Phase 2 include flow assurance over 51km, and having to cycle the wells, because they’re competing to get into the system, and the need for depletion drive with a limited aquifer support. Clarke says that Murphy looked at a couple of enhanced oil recovery options, including water injection and artificial lift. But, there were concerns over water injection continuity within the reservoir. “At the end of the day, it was deemed that the lowest reservoir risk was to install a pump,” Clarke says. “By reducing back pressure, we get a nice bump in production, resolve flow assurance issues and improve the recovery quite dramatically.”

The OneSubsea high-boost pump system will be installed where the 35km step-out is now, which will enable it to serve the latest step-out, as well as enable the development of other nearby targets.

To make the project work, however, an increase in the voltage of the high boost pump’s motor was needed, to eliminate the need for subsea transformers and high voltage subsea wet-mate connectors. A qualification program for the higher voltage motor was completed June 2016.

“Such an approach, based on the same standard design on all electric pumps to date, significantly reduces hardware scope and complexity of the system,” Hagland says. There was just a minor adjustment of the windings to fit the increased voltage rating. “We believe this is game-changer for long step-outs,” says Hagland, who adds that the pump could work for projects at 55-65km step-out and still supply 2MW of power.

Part of the approach was changing the contracting strategy. Murphy went for an integrated subsea engineering, procurement, construction, installation and commissioning (EPIC), Clarke says. “We are not telling the market what we want, we’re letting them come to us with the solution. The bid package was a functional, fit-for-purpose specification.” This approach will also reduce the schedule to first oil by three months, thanks to reducing supplier interfaces, he says.

The contract was awarded to the Subsea Integration Alliance, which was formed in July 2015 between OneSubsea, Schlumberger, and Subsea 7. The contract is for the multiphase boosting system, including topside and subsea controls, and a 35km integrated power and control umbilical. Execution will be in under two years and the payment structure is backend loaded, making payments closer to when production comes online.

The Ngujima-Yin FPSO vessel. Image from Woodside.

Greater Enfield

Woodside Energy and its partners made the decision to invest US$1.9 billion in the Greater Enfield development in June this year. It’s been a long time coming.

Woodside CEO Peter Coleman said the decision to go ahead was thanks to “breakthroughs in the development concept, technology and contracting. Leveraging the latest technologies and using existing FPSO (floating production, storage and offloading) infrastructure… allows us to accelerate the development of previously stranded resources.” Development costs on the project, expected to come onstream mid-2019, are $28/bbl, according to Reuters.

Greater Enfield is 60km off Exmouth in Western Australia in 340-850m water depth. The development is targeting 69 MMboe from the Laverda Canyon, Norton over Laverda and Cimatti oil fields via six subsea production wells and six water injections wells. The wells, in 340-850m water depth, will be tied back 31km to the Ngujima-Yin FPSO, which currently produces the Vincent field.

However, to maintain production assurance, subsea multiphase pumps would be needed in the Laverda area gas lift in the Cimatti area and water injection pressure support for both Laverda and Cimatti areas. The subsea pumps are a key enabler for long subsea tiebacks and are required to be high-boost capable of generating differential pressure over 100bar, said Tim Nallipogu, Woodside subsea pumping lead at UTC.

The Vincent field already has multiphase pumps, which were installed in 2008. These provided confidence in the multiphase pumping technology. Going from conventional boosting to high-boost (two and a half times the boost capacity of the existing pumps) was not seen as a major step-change. However, the long subsea tieback did pose challenges around topside constraints on the Ngujima-Yin.

The Ngujima-Yin, commissioned in 2008, has governed the design for the Greater Enfield subsea pumping system, Nallipogu says. The FPSO has a disconnectable turret mooring system, with the swivel system designed for a short ~4km Vincent field tieback. It has 7.2kV high voltage slip rings, which would mean subsea transformers and 30kV wet-mate connectors would be needed to support the high-boost system needed for the Laverda area, some 31km from the FPSO.

Woodside in conjunction with the pump system supplier took a change of tack. “We looked to upgrade the slip rings from 7.2kV to 12kV, and upgrade the multiphase pump motor from 6.6-10kV, which would eliminate the need for subsea transformers (transmission voltage at 12kV) and 30kV wet-mate connectors,” Nallipogu says. This simplified the power system and helped increase the motor rating from 2.4-2.6MW.

This approach still faced challenges, however. One being upgrading the slip rings and the second qualifying a higher voltage subsea pump motor. The Ngujima-Yin is due for a shipyard visit, as part of some planned refurbishment work on the swivel, during which the high voltage slip ring upgrade could be performed, however. A qualification program for a 10.5kV high voltage motor for Greater Enfield application (the turret disconnect connectors are qualified for 12kV maximum voltage, limiting any further increase in voltage) was completed with the pump system supplier between September 2015-June 2016.

The subsea pump system will be serviced by an integrated power and control umbilical. There will also be a water injection pipeline system for pressure support for Cimatti and Laverda Canyon. Hydrate management will be via a “risk-based approach.” The potential to form hydrates exists later in field life, but not in quantities that would cause blockage, Nallipogu says.

“Greater Enfield has been a challenging field,” Nallipogu says. “It has been in the portfolio for some time, but has not got across the line. The long tieback to [an existing] FPSO reduced the development cost and the high boost pumping system was a key enabler. In addition, the power distribution system could be simplified with qualification of the high voltage motor technology and upgrade of the slip rings during the shipyard campaign.”

OneSubsea was awarded the engineering, procurement and construction contract, totaling some $300 million. It covers the supply of the subsea production system and the dual multiphase boosting system for Greater Enfield. This will include six horizontal SpoolTree subsea trees, six horizontal trees for the water injection system, six multiphase meters, the high-boost dual pump station with high voltage motors, umbilical, topside, subsea controls and distribution, intervention and workover control systems, landing string, and installation and commissioning services.

Technip was awarded the contract covering project management, design, engineering, procurement, installation and pre-commissioning of carbon steel production flowline, carbon steel water injection flowline, flexible risers and flowlines totalling 82.2km; 38.9km of umbilicals (dynamic and static); subsea structures and valves; and the multi-phase pump system transport and installation.

The flexible pipes will be manufactured in Asiaflex Products, Technip’s manufacturing plant in Tanjung Langsat, Johor, Malaysia, the umbilicals will be supplied by Technip Umbilicals’ facility in Newcastle, UK. The offshore installation will be using several vessels from Technip’s fleet and is scheduled for completion in 2018.

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