Online Exclusive: Statoil, improved production, subsea factories: An interview with Øistein Bøe
Øistein Bøe, Statoil’s Vice President Petroleum Technology Mature Fields, talks about the company and its approach to improving recovery from existing oil and gas fields. His comments are in anticipation of the2013 Deep Offshore Technology Conference & Exhibition taking place in The Woodlands, Texas, Oct. 22-24.
“It is always a benefit to discuss and share experience with other experts in the industry, and to discuss challenges ahead. Sometimes science fiction becomes reality,” said Bøe in talking about DOT.
Q. What particular problems are you seeing with IOR/EOR in deepwater?
A. IOR in deepwater is not a very big problem per se when it comes to technology; it is the higher cost of wells, equipment, operations, etc. in deepwater environments that makes it more challenging to get an economical IOR project that can compete with other projects in terms of ‘value-for-money’ barrels.
The same holds for EOR, or advanced recovery, projects. The additional challenge there is that limited experience can be found in offshore fields worldwide. To qualify new technology and reduce investment risk, piloting and step-wise implementation are often considered necessary, yet expensive.
Q. What are the long-term recovery targets from Oseberg, Gullfaks, Sleipner, Statfjord, Veslefrikk, and other fields which have been in production for 20 years or more?
A. Current expected oil RF’s are Oseberg, 63%; Gullfaks, 61%; Sleipner area, 76% (gas): Statfjord, 66%; Veslefrikk, 45%; and Troll, 86% (gas) + 41% (oil).
Even though many of these fields have been producing for a long time, we still see large potential in our mature fields. We recently announced that while we have an average expected oil recovery factor in our Norwegian fields of 50%, we would like to get this number up to 60%. This means that also the old, successful fields that are currently well above 60% need to contribute; they might even need to go up to 70% to support the 60% overall goal. Of course these ambitions are strongly dependent on price developments, new technology, fiscal conditions, etc.
Q. Statoil is a leader in subsea separation and pumping. How does that play into IOR/EOR?
A.Subsea IOR is obviously very important to Statoil, with over 500 subsea wells. About half of our production comes from subsea wells. Developing and applying subsea technology is one of the four cornerstones (“Business-Critical Technologies”) of our Corporate Technology Strategy set up to support Statoil’s ambition of profitable growth.
We aim to have a complete subsea factory on the seabed, including subsea production, separation, boosting, compression, storage, and injection. We are well under way with the qualifications and have taken many components already in use in both new and mature fields.
Q. What is the status of Statoil’s progress toward a ‘subsea factory’? Where will it be employed? Does Åsgard fit into that description?
A. The subsea factory is still high on the agenda for Statoil. We have a long-term focus and are in the process of qualifying all the technology elements in order to have a complete subsea factory on the seabed, including subsea production, separation, boosting, compression, storage, and injection.
We are currently well under way with the qualifications and have taken many components already in use in both new and mature fields. The Åsgard compression project is a major milestone which will be realized in 2015 and is expected to contribute with 280 MMboe. Installation of the template is currently on-going.
Q.What is the status of Statoil’s efforts to supply electricity from shore to power subsea facilities? Are you still investigation AC versus DC? What is the status of the joint industry project with ABB?
A. High technical availability of the subsea power transmission and distribution system is of key importance to creating successful future processing applications. Several initiatives are ongoing to develop and qualify new power and subsea power solutions including subsea variable speed drive and switch gears. Statoil have technology development project with both Siemens and ABB for subsea power technology.
Q.While estimates vary, with something like 25% of the yet-to-be-discovered petroleum in arctic conditions, what special problems will have to be addressed for successful EOR/IOR for those fields?
A. Technology and infrastructure will both be very important in developing arctic resources. In the first place for getting access to arctic resources, in the second place for successful development of these resources, and in the third place for safe and sustainable operations.
In Statoil harsh and arctic environments are one of the strategic areas where we believe we can make a difference, at least based on our long history with the Norwegian continental shelf.
Q.What are the subsea development plans for the Barents Sea floating production platform? What differences are there in subsea operation in frontier and arctic regions?
A.For the green field factory there will be many different purpose build factories conquering the longer, deeper, and colder challenges. New oil field will typically have a plateau phase of six to eight years. If several fields could be developed in to a field center scenario, this will prolong the production period and the capacity in the transport system will be utilized over a longer time period. This will also enable higher investment in transport pipeline to the host facility.
Existing infrastructure might have large constraints in weight and/or space as well as limitations in flowlines, riser, and processing capacity. In many cases we are studying process solutions moving equipment from the platform to the seafloor.
The main subsea factories in the green field factory will be:
• Subsea to host factory for debottlenecking
• Extended reach factory to enable long oil/gas tiebacks
• Deepwater factory
• Heavy oil factory
• Arctic factory.
Flow assurance will in many of the potential business cases be as important as the subsea processing solutions. How can we ensure transport quality of the gas and oil which minimizes risk for hydrate or wax plugging of the pipeline system? New technologies being important for the green field factories will be subsea coalescer, compact separation technology, gas treatment including dewpointing, high-capacity boosting, dual boost, high viscosity pumping and cold flow oil transport.
For the future beyond 2020 we are talking about subsea factories enabling processing and transport to marked specifications.
There might be a need in arctic field developments and for fields aiming to utilize existing gas transport system with established water- and hydrocarbon dew point specification.
Q.Are there plans to apply any of Statoil’s deepwater subsea facility developments to projects in the Gulf of Mexico and/or offshore Brazil?
A.Processing on the seabed could open up areas that are not currently accessible with traditional technology. A big effort is now being made to complete the final step on the way towards a subsea factory. The current generation of technology elements in the “facilities” category is being qualified typically to 3,000 m water depth.
Also, to further develop subsea production and processing systems, including subsea factories, towards more remote as well as deeper locations new elements will need to be developed and qualified such as.
• Subsea ‘hubs’ – More complex manifold designs enabling new field tie-ins subsea
• Subsea storage of both oil and chemicals
• More sophisticated separation and processing equipment, including high-efficiency hydrocarbon and water dewpointing, gas sweetening, crude oil treatment/polishing, improved seawater and produced water treatment and monitoring, and new local power generating concepts
• Fit for purpose IMR concepts (techniques, vessels, autonomous underwater vessels).
About Øistein Bøe.Bøe holds a PhD in Applied Mathematics from the University of Bergen. From 1987 to 1990 he worked for IBM, and then became a reservoir engineering for Hydro, which since has become part of Statoil. He has spent the past 15 years in management and advisory position at the operator.
