Decision time approaches for pioneering subsea compression technology

World Oil: How is the Nyhamna pilot project progressing?

Mathias Owe: We installed the pilot in 2011, introduced gas into it in January 2012 and started performance testing in October. The program will probably be complete in the spring of 2013. A panel of experts will then review the study, and if it’s endorsed, it will be considered by the Ormen Lange license partnership. That will probably take until near the end of this year. After that, we will choose between the floating platform option and a sub-sea commission for Ormen Lange.

If we put the compressor on the seabed, then that would be powered from the shore. With the floater option, everything, including the power generation, would go on the floater. We hold both options open.

WO: What factors will influence your decision on whether to use seabed or floating compression?

Owe: It’s a combination of different selection criteria. Cost is one, the technology is another. There are several.

Initially we wanted four compressors on the field, either on a platform or subsea, but last year we decided to install two compressors onshore at Nyhamna, which would start up in around 2016. We plan to lower the receiving pressure at Nyhamna, so that we can produce the field more easily and then compress there. We then plan to put two compressors in the field from around 2020. The timing will depend on the data analysis we are doing, and how we develop the resource.

WO: Do you envisage using this subsea technology elsewhere, even if it isn’t right for Ormen Lange?

Pascal Montoulives: Yes. When the pilot is completed, the technology will be available for use in other locations and conditions. It is an elegant fit with a field with remote infrastructure, where subsea compression should help the cost of development. It also helps somewhat in helping the recovery of the field, by having the source of boosting closer to the well. When you are looking at a remote field, typically in offshore Australia or potentially in the Arctic, this technology should be considered—and it will be considered as far as Shell is concerned.

Also, when we talk about subsea compression, the compressor is only one component of the whole system. You have gas/liquid separation, liquid pumping, viable speed drive, transformers and so on. All of those components could be incorporated in a different system to meet different needs.

WO: What are the advantages of putting both compression and power on the seabed?

Montoulives: Compression needs a lot of power to create the kind of flow you need to justify using the equipment, so they go hand-in-hand. If you are confident in the technology, then there is no need to use a topside location.

With the floater concept, you have the weight, the associated equipment, the systems needed to sustain a human presence onboard, and so on. We have established that there is a difference of magnitude in safety between the floating concept and the subsea compression concept, where effectively there is no human exposure, except when you have to go to the site to change modules.

Some operators have chosen to put the electricity generation on the topside. If distances are below 30 to 40 km from shore, you can do that. But further out, it becomes extremely difficult

Owe: The maintenance is not done offshore; you just replace modules. You take a new module out on the boat, install that, and bring the module that needs servicing back to the beach and do it safely in the workshop.

WO: How does the Nyhamna test facility simulate operating conditions on the sea floor?

Owe: The test site we have at Nyhamna is unique, Fig. 2. You will not find anything similar, anywhere in the world. We have built a test basin 42 m long, 28 m wide and 17 m deep, and we have installed one full-scale 12.5-MW compression train at the bottom. We can run 15 MMcmgd through this system. Gas, condensate, MEG [mono-ethylene glycol] and fines can be fed into a mixture that simulates what we find at Ormen Lange. We can change the composition, as we like, in terms of pressure, volume and temperature. There is a 1,000-ton process module sitting at the edge of this basin, which is effectively a big laboratory. This module can mix the input composition from 48 bars up to 140 bars.

WO: Reliability is going to be important with seabed technology. How do you test for that?

Owe: That’s important, of course. It’s one of the reasons that we have to do so much testing. We want to learn how long the intervals between maintenance need to be. We’ve done RAM [reliability, availability and maintenance] analysis, based on existing fields and installations, and used that data to feed into the model for a sub-sea solution. We are now working to validate the data model, to see if our data model fits with the real life, when you run it on a test.

WO: Has the testing process thrown up any problems?

Owe: It has worked very well on the power side. On the compressor side, one thing we have had to work out is how many times you can hard-land a compressor.

This compressor is quite special, because it is floating—it is lifted by active magnetic bearings. The system has a back-up battery package, which comes into effect, if you lose power, and smoothly lowers the compressor, so that it doesn’t hard-land on its back-up roller bearing. These bearing systems are new to the industry.

But there is a limit to the number of times that you can land a compressor on its bearing, when it’s at full speed. We have sensors that measure the tolerance in the roller bearing, and we could see from the readings that we were starting to get close to the maintenance interval, so we decided to stop, take out the bearing and replace it with a new one to continue testing.

WO: Is there a limit to the distance from shore that you can run subsea power cables, and what are the limiting factors?

Owe: The limit is currently around 200 to 300 km out. Ormen Lange sits at 120 km, but you could probably go twice as far. The two main factors that come into play are the power supply and flow assurance; for example, you could get hydrates in the pipeline.

Montoulives: The power supply is the most limiting factor. As you reach the limit of the AC technology, you lose too much power. There could be circumstances that you could go further with flow assurance, but it would still be a great challenge.

WO: And what about depth limits? How deep can it go?

Montoulives: It’s qualified for a 1,000-m depth now, as that’s what Ormen Lange needs. My opinion is that there is no difficulty in going deeper than that.

WO: Why did Shell choose Norway to test its seabed technology?

Montoulives: Because of its scale, complexity and history, Ormen Lange offered this unique opportunity to build and test new subsea technology. It also gives us proximity to the expertise that Norwegian firms have in this field. They have a tremendous amount of experience. It’s also a good environment to work in, because there are a lot of projects of this nature being carried out by others here. That makes our decision-makers and partners much more likely to sanction technology projects.