A monster facility

Elaine Maslin

June 1, 2017

Johan Sverdrup is the largest ongoing project in the North Sea. Elaine Maslin looks at Statoil’s progress, cost reduction and technology use on the development.

How it will look: Johan Svedrup, illustration. Image from Statoil.

Trond Stokka Meling, technical director on the Johan Sverdrup mega-project, calls the facility, “one of the largest hotels in the North Sea.” Indeed, with more than 560 beds, it’s large.

Johan Sverdrup is a massive project. Some 14,000 people are currently working on the facilities construction project at 23 different sites across the globe. So far, 29 million man hours have been spent on the project, Meling told the Subsea Valley Conference in Olso, in early April, with a total of 100 million expected to be reached when the project’s first phase completes in late 2019.

The Johan Sverdrup field is 155km west of Stavanger. The field was found in 2010, with the Avaldsnes discovery in PL501, by Lundin Norway, followed by the Aldous discovery in PL265 by Statoil in 2011.

Once complete, Johan Sverdrup Phase 1 will comprise a field center, with four, bridge-linked platforms, with 35 wells, and three subsea satellites for water injection, all in about 120m water depth. Phase 1 will include power from shore for the Johan Sverdrup field.

Phase 2 will add another 28 wells, 18 of which are due to be satellite wells, and an additional process facility, to increase production capacity by 220,000 b/d, from about 440,000 b/d, to 660,000 b/d, amounting to 25% of Norwegian oil production. It will also add in power from shore for the wider Utsira High. In all, the development of the 200sq km field is expected to tap some 2-3 billion boe and potentially more. As part of its drainage strategy, Statoil is planning permanent seismic monitoring across 80% of the field. The operator also has a commitment to at least trial polymer flood on the medium-oil viscosity field.

Statoil also plans to make Johan Sverdrup a digital oilfield. “We are going digital,” Meling says. “There’s a lot of data gathered in the planning and operation phase. We are looking at how we can use it and maximize value.” The ambition is to create a fully integrated “digital twin” of the Johan Sverdrup field and development, on which analytics can be run.

Progress report

Drilling on Johan Sverdrup. Photo by Kjetil Eide, from Statoil.

Phase 1 of Johan Sverdrup is being built at a cost of US$11.35 billion (NOK97 billion), or $20/bbl breakeven, compared to the $14.39 billion (NOK123 billion) original estimate. Phase 2, on which an investment decision is due in 2H 2018, with first production in 2022, will be $30/bbl breakeven, costing $4.68-6.44 billion (NOK40-55 billion). Full field breakeven is expected to be below $25/bbl.

Early April, the Phase 1 project was about 40% complete, Meling says. Two topsides are under construction at Samsung Heavy Industries in South Korea; three of the jackets and the 19,500-tonne living quarter topside are being built in Norway, by Kvaerner. The latter is expected to be installed offshore in 2019.

The Phase 1 drilling platform, with 48 slots, is being built by Aibel at three sites: one in Thailand and two in Norway (Haugesund and Grimstad [Nymo]). It will weigh 21,500-tonne and measure 40m x 83m. Its parts will be assembled in September this year in a fjord in Norway, creating a 147m-tall topside, which will then be positioned outside Haugesund, Norway, until it’s installed offshore in summer 2018. Pre-drilling is ongoing using Odfjell’s Deepsea Atlantic semisubmersible, where eight producers are pre-drilled and pre-drilling of 10 water injectors at subsea satellites are ongoing.

The riser and process platform topsides are being built at Samsung Heavy Industries in South Korea. The riser platform – the largest of the four platforms constituting the Johan Sverdrup field center – will be the first of the Johan Sverdrup topside to be installed in 2018. The platform will be 124m-long, 28m-wide, 42m-tall, and weigh some 23,000-tonne. The process platform will be 100m-long, 23m-wide and weigh 26,300-tonne.

For Phase 2, which will target the Avaldsnes, Geitungen and Kvitsøy reservoirs, Statoil is assessing an unmanned wellhead platform, with 12 slots available, plus subsea satellite wells. However, it could also be all subsea satellite wells, which can offer more flexibility with well locations (as Statoil learns more about the reservoir’s subsurface and hones its Phase 2 plans), Meling says.

Phase 2 is yet to be sanctioned, but startup is planned for 2022. Decision gate 2, or concept select, was in March this year. A development plan is due to be submitted on 1 September 2018.

Cost reduction

“It is a huge area to develop and a lot of infrastructure and investment,” Meling says. But, he adds: “We cannot afford to fail on this project.”

While the oil price has been hurting a lot of projects, Statoil’s focus on making Johan Sverdrup work has made it a “robust project” at today’s oil prices, he says, and it’s not been about squeezing suppliers. “There has been a lot of news in the media about how we have been pushing our suppliers. But, we are dependent on everyone making a profit or we would be short-sighted. The way we work with contractors and suppliers is key.”

Securing deliveries and quality, improving collaboration with suppliers and contractors, simplifying the concept and reducing the number of wells needed have all helped to reduce costs, he says.

“We have worked hard to simplify technical requirements and we have improved the quality of specifications and worked with suppliers so they understand what we are requesting, being there and solving issues when they are coming up,” he says. Reusing designs from Phase 1 in Phase 2 will also help reduce costs by being able to use the same designs documents, he says.

Drilling performance on the Deepsea Atlantic has also helped reduced costs: eight wells have been delivered in what has been considered “perfect well time” under Statoil’s “perfect well” program, meaning they were completed in almost half the time of the original plan.

The decision to use Allseas’ Pioneering Spirit to install three of the topsides has also reduced costs, he says. “Usually, we would use the Thialf or S7000, with 10,500-tonne [lifting] limitation and have to lift in modules and then connect, hook-up and commissioning [after that]. This [the Pioneering Spirit] has up to 48,000-tonne topside weight [lifting capacity] in one piece.

“We have gone through an extensive qualification program, to safeguard that this vessel will operate as intended, [that the] lifting beams, controlled by a computer system, work as intended together with the DP system, keeping the vessel in the correct position,” Meling says. Allseas has run offshore tests with Pioneering Spirit installing and removing a dummy topside, also in rough weather, and the vessel “worked perfectly,” Meling says. “It has done [the] Yme [removal] and Brent [Delta removal] in May,” he says, further reducing risk for Statoil. “At almost 1 million-tonne displacement, with a [pipelay] stinger and jacket lifting [system], it’s a fantastic vessel and it is a very efficient way of doing this [topsides installation].”


Meling says that there has not been much new technology on Johan Sverdrup, but mentions, in addition to using Pioneering Spirit, use of automatic inflow chokes on wells to reduce the number of wells needed is thanks to better control. The project is also using VisiTrak reservoir navigation to improve the placing of wells, to more efficiently drain the reservoir.

Statoil is also looking to use its Cap-X subsea template concept, which reduces the size of subsea templates, with one suction can instead of four, and uses glass fiber. The firm plans to use Cap-X on the Njord and Bauge fields, and was ready to be used, following qualification, Meling says. “We need to collaborate with industry to get it [Cap-X] built,” he says.