Statoil looking to get to the next level in Brazil by solving subsea challenges

Being the operator of the producing Peregrino field located offshore Brazil, Statoil’s activities in the country have been bearing fruit for years now. To put things in perspective, it is worth mentioning that Peregrino is Statoil’s largest operated heavy oil field outside Norway. 

However, the Norwegian state-owned giant is looking to further solidify its position in Brazilian waters through new project developments.

This was confirmed in one of the technical sessions on the second day of the Subsea Valley Conference in Fornebu, Norway where Statoil’s subsea challenges in Brazil’s deepwater areas were discussed by Øystein Aa Myklebust and Patrice Aguilera.

As pointed out by Myklebust at the beginning of the session, Brazil is one of the most important areas for Statoil outside Norway. It is an area where Statoil has already had success in exploration and these two projects will enable it to go to the next level.

Two specific projects were topics of the discussion; the BM-C-33 license, which is located in the Campos Basin, and the Carcará discovery, which is located in the Santos Basin.


In the southern Campos Basin, some 200 km from the shore, Statoil is the operator of the BM-C-33 offshore license with a 35% interest and its partners are Repsol Sinopec, with a 35% interest, and Petrobras, with the remaining 30% interest. Water depth ranges from 2600 to 2900 m.

Aguilera, who is responsible for the subsea production systems, pipeline, flowlines and umbilicals in the BM-C-33 project, said that Statoil has been looking into many solutions for this deepwater project, which has three reservoirs, Seat, Gávea, and Pão de Açúcar.

A total of four appraisal wells have been drilled in the block, confirming a total volume of recoverable hydrocarbons estimated at around 1 billion barrels of oil equivalent.

One of the solutions includes eleven wells; ten producers and a possible gas injector well.

For the Seat reservoir two wells  and a 14-kilometer long direct electric heating (DEH) pipeline have been proposed and for the Gávea reservoir two wells and a flowline that is 12 kilometers long. The same two-well solution is proposed for the third reservoir but this reservoir would include production loops instead of the electric heating. These loops are designed this way because of the wax and they need to be cleaned almost once a month.

The solution includes a manifold with high functionality because of the high rates and the wax. Statoil has learned that, in Brazil, the wells need to be tested individually and, because they are owned by the communities, these communities need to know how much gas or oil the wells are producing. So the manifold has a special test line just for that.

Statoil is also looking into possible pipeline routes for the gas that will be produced, which is about 14 million cubic a day.

Another possible solution might include Xmas trees on the wells which would be connected to a cluster manifold on Pão de Açúcar and Gavea while for the Seat reservoir they would be connected individually to inline T’s. The Seat reservoir would include the DHE flowline.


Myklebust was in charge of introducing the Carcará project, which was called a world-class discovery when Statoil bought into it in 2016 through a deal with Petrobras.

A substantial part of the discovery is located in the BM-S-8 license where Statoil estimates the recoverable volumes to be in the range of 700 to 1,300 million barrels of oil equivalent so the potential for value is immense, Myklebust said.

However, in order to use this potential, Statoil has to solve quite a few challenges. A lot of the challenges are similar to the ones in the BM-C-33 license but there are some important differences.

This pre-salt field is located about 200 kilometers from shore in water depths of 2100 meters. The reservoir contains light oil with a substantial amount of associated gas and it is over pressurized, which means that the pressure in the reservoir is higher than what follows from the depth, giving a maximum wellhead shut-in pressure of 650 to 800 bars. This pressure is what distinguishes Carcará from some of the other fields in the area and therefore requires different solutions.

Statoil expects a very good productivity with wells delivering rates substantially above what the company is used to in the North Sea.

Two phases of development

The partners in the field have agreed to develop the field in two phases. The objective of the first phase is to obtain first oil between 2023 and 2024. The objective of the second phase will be to maximize the full field value.

The first phase is based on three wells proved by Petrobras inside the BM-S-8 area. However, the Carcará field extends into another block where Statoil also won interest in an auction at the end of last year. So now, Statoil has the possibility to develop the full field.

Going into more details related to the development of the Carcará field, Myklebust said that one possible layout is based on 12 production wells and six water injection wells. The injection wells will be drilled and started up a few years after the first oil. The wells are vertical or near-vertical. He pointed out that there are challenges in drilling horizontal wells in the pre-salt areas and no wells have been completed in this area with horizontal reservoir sections, not even with high deviations in the reservoir. Statoil has, however, assumed that it can have up to 500m horizontal step-out from the wellhead to the wellhead target and has used this in designing this first layout.

The development’s large spread FPSO would have an oil processing capacity of 180,000 to 200,000 barrels of oil per day and the gas processing would be ten million cubic meters per day.

Production lines made of carbon steel with wet isolation are meant to be installed in one go and the riser sections would be configured as lazy waves.

Manifolds, which allow routing of the flow in any direction, are fairly simple and are intended to be welded into the pipelines. This would be done with a pipelaying vessel. Statoil is also looking into rigid well jumpers between the wells and the manifolds.

The export line is riser-based and the gas lift riser is not for wells but for the risers.

This concept includes two dynamic umbilicals and a separate MEG riser as there is a fairly high need for MEG injection.

“We may be able to show that we can integrate those MEG and the dynamic risers but this is the way Statoil has put it for now,” Myklebust said.

However, Myklebust noted it is unlikely that this will be the final solution, but it does represent a good starting point for discussing some of the challenges and possible solutions.

Subsea challenges

One of the subsea challenges related to this project concept is the selection of deepwater risers. “We have some qualification elements that we will embark on and we see some opportunities that might not be feasible for the majority of the risers but could be a possibility,” Myklebust said. Statoil is also thinking that, even though some of it could not be implemented for phase one, it could still be useful to start working on it now to have it ready in phase two.

When it comes to flow assurance, Petrobras has used a concept for several of their pre-salt fields where they have two flowlines to each well, one production line and one service line. It is a solution that Statoil has not excluded but does not know it very well. Different solutions entail different mediations in terms of flow ensurance so Statoil needs to find out what is the best solutions for each of the layouts and then compare them.

Another challenge is that the wells are far apart. As already mentioned, Statoil assumes it can only have 500m horizontal step-out from the wellhead to the well target and it will work to expand that step-out. However, the work still has not been completed.

“So it’s quite likely that we need to have a big distance between the wellheads. Some areas of the field have more clusters together but others are more far apart so it’s important to find a solution that allows to connect each well, flowline, and umbilical in the cheapest way possible,” Myklebust explained.

Finally, Myklebust pointed out that installation-friendly solutions are even more important in deepwater than in shallow water. The cost of installation is higher and Statoil needs to work on reducing scope, simplifying methods and making them more effective.

In addition, the availability of vessels in Brazil is an added challenge for Statoil, meaning that it might be even more important to have flexibility in selection of installation vessels.

Myklebust concluded: “I think we need more effective concepts, products, and methods to succeed in Carcará. It has a huge value potential but we can’t just assume that we’ll take that value potential out by using existing solutions. Carcará is on top of Statoil’s portfolio in terms of reserves but not on top in terms of project economic.”

Offshore Energy Today Staff