Ave Maria

November 1, 2016

Germany’s Wintershall weighed several concepts for its Maria field development, which sits in a mature area off Norway. Elaine Maslin reports on how the firm drew upon multiple neighbors to select the right solution.

A Maria template close to installation. Photo from Wintershall/Thor Oliversen.

There’s a joke about how many engineers it takes to change a lightbulb. A similar refrain could be used for the Maria field offshore Norway. In this case, the question would be “how many host facilities does it take to develop a subsea tieback?” The answer is four, five if you count a subsea template.

However, far from being a joke, this project – German-operator Wintershall’s first development on the Norwegian Continental Shelf (NCS) – is a neat solution and an example of how things can be done in a mature basin in the future.

The project, currently under development, will see the Maria field brought online through the use of facilities – from gas lift to oil export – on the Kristin, Heidrun, Åsgard B, and Åsgard C production units, as well as a connection to the Tyrihans subsea template.

“To our knowledge, this is a fairly unique concept,” says Hugo Dijkgraaf, Maria project director, Wintershall, at ONS, in Stavanger, Norway, back in August. “It uses each host’s capacity to use what they do best.”

“We think the Maria project is a smart solution in a mature area,” says Dennis Dickhausen, Maria subsea manager, Wintershall, who also spoke at ONS. “We think this way of developing is a win-win. For existing hosts, which face a decline in production, Maria will extend production and there will be more players to share the costs. For us it is good because we can get down capex and costs.”

To tieback or not to tieback

One of the Maria templates before it was installed offshore. Photo from Vestbase/Ture Haugen.

The Maria field is in 300m water depth, 200km offshore Trondheim, Norway, in blocks 6407/1 and 6406/3 on the Halten Terrace in the Norwegian Sea. It was discovered in 2010, followed by an appraisal well in 2012, confirming about 180 MMboe recoverable resources, most of which is oil.

As at the end of August this year, the development project, one of only two plans for development and operation submitted last year in Norway, was about 35% into execution and on time and budget. Two templates have been installed with two of three pipelines installation and modifications on the host platforms ongoing. First oil is due in 2018.

The development’s complexity is due to the mature area in which the field is located. “When we started, we saw we didn’t have a clean sheet of paper,” Dickhausen says. “There was quite a lot of infrastructure (nearby), which we needed to assess. There are several floating installations and seafloor infrastructure.”

It was a big process, with hundreds of combinations of ideas, he says. “It’s a prolific area with many platforms and export lines in a 50km radius,” Dijkgraaf says. The number of concepts were narrowed down to five, including a traditional tieback, a standalone development with a floating production, storage and offloading (FPSO) unit, together with Statoil, taking in the Trestakk field, and a tieback to Åsgard. None were that simple, however.

“We found out that the tieback projects we had were not able to take the Maria fluids and provide all the services, because of flow assurance concerns, and issues on brownfield modifications, with space restrictions,” Dijkgraaf says. “We screened out tiebacks and worked hard on the FPSO and found a good technical solution, but the economics were marginal and not robust enough, and today [in the current oil price environment] we are happy we made that decision.”

A standalone facility would have required a lot of new, project specific equipment, a complete vessel, and up to three crews, resulting in a lot of capex and opex. Even when Trestakk was included in the concept, to share costs, there were too few synergies, Dijkgraaf says. “They had more gas than us and needed a big gas plant, so it (the vessel concept) grew and grew.

“In the end, we needed to make a decision and we decided to screen out the FPSO concepts, which had become too expensive compared to a tieback. But, it wasn’t easy because none of the hosts we looked at could provide all we needed or were too far away and we had to deal with flow assurance issues. So, we had to go back to the drawing board and find another solution.”

Despite the apparent challenges, the firm and its partners, Petoro and Centrica, decided to move forward with a subsea tieback development.

“We agreed to mature a creative tieback concept involving several of those host installations topside and subsea,” Dijkgraaf says. It was a commercially demanding decision, with agreements having to be made with four host licenses. While Statoil operated all of them, each is treated as a separate business unit and also had different third parties involved. Such negotiations are notoriously tricky and have put stop to or slowed to a near halt many a project on the UK Continental Shelf. But, offshore Norway, under the Petroleum Act, firms are compelled to provide opportunities for tie-ins if they have availability.



The solution is a two-template development with oil piped to the Kristin semisubmersible production platform (online since 2005), 23km away, via a 26km-long pipeline. The pipeline has a direct electric heating (DEH) system to avoid hydrate formation.

A Maria template close to installation with the Normand Oceanic. 
Image from Wintershall/Rolf Skjong. 

The two templates are standard NCS templates supplied by FMC Technologies, under a subsea production systems contract, which includes manifolds and riser bases, and installed by Subsea 7. Each template has four slots, with three wells planned on each template, comprising two producers and one injector. The Xmas trees are also standard and Wintershall says that it’s secured a cost-effective workover landing string system. It has a five-year contract with Expro for a complete workover riser system, including surface test tree and subsea landing string systems. The wells are controlled from Kristin.

For pressure support, water is supplied from Heidrun, a floating tension leg platform with a concrete hull (online since 1995), 43km away. A new pipeline has been installed for this. On Heidrun, a sulphate removal plant was due to be installed this summer, to treat the injection water.

Gas lift will also be used in the wells to aid the flow of the well stream. Gas from the Åsgard B semisubmersible gas and condensate processing platform (onstream since 2000) will be used, via an existing pipeline, which goes to the Tyrihans field (a subsea tieback to Kristin and Åsgard producing since 2009), then a new 22km-long pipeline back up to Maria.

Production fluids will go to the Åsgard C condensate storage and offloading vessel, from where they will be offloaded by shuttle tanker. Gas will go to Kristin and exported to Kårstø.

Subsea 7 is the main pipeline and subsea construction contractor, supplying the three pipelines linking Maria to the surrounding infrastructure, including the 26km, DEH production flowline, 46km-long plastic-lined water injection pipeline from Heidrun, and the 22km pipeline to supply gas lift.

While it sounds like a complex project, Wintershall believes 50% of capex was reduced by going forward with this concept. “We think it is a way forward and could be used by other players in the industry when you have discoveries in mature areas,” Dickhausen says. Indeed, Wintershall has said a similar system is under consideration for its Skarfjell development in the Norwegian North Sea.

One issue could be availability of gas for gas lift and water for pressure support from the different hosts. But, Dickhausen doesn’t think this is a big risk. “It carries more complexity, but you can rank (the risk) down because we can live without water injection, for months, without negative effects,” he says.

“For gas lift, that needs to be running and processing needs to be running,” Dickhausen says. “We have studied a lot and expected uptime of these systems and we came to the conclusion we expect good uptime. There is a risk but we think it is controllable.”

That the host facilities will support Maria through its life is also a question. But, Dickhausen says that they are not coming to the end of their life anytime soon. “Kristin and Åsgard are planned to run for a long time still,” he says. “It’s more about sharing the costs. Closer to the end I’m sure we will need to evaluate how long we need to keep going until limited by operational costs but then again there could be other discoveries. There are still exploration opportunities around.”

While significant savings have been made, Wintershall is still working on ways to reduce costs further, such as looking at how to reduce costs on rock dumping.

Production well drilling, with horizontal wells, using the Deepsea Stavanger semisubmersible drilling rig will start next year. The Deepsea Stavanger dual derrick sixth generation unit will drill six wells, three on each template, on the Maria field starting from April 2017. Start-up is planned for 2018, three years from after the plan for development and operation was submitted.

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