Draugen was the first field developed in the Norwegian Sea 20 years ago—Shell now expects it to produce for a further 20 years, doubling its expected life span. Asset manager Odin Estensen explains how.
The story of Draugen is more than just the story of a field. It is a also story about courage, learning, understanding, and implementation.
Draugen was the first field to be developed in the Norwegian Sea, pioneering production from an area which later became one of the important petroleum provinces in Norway. In 2013, Draugen marks 20 years since the start of production. Draugen was expected to reach end of field life in 2013, according to the initial plans, but we are currently in the process of extending Draugen’s lifetime till 2036.
The reservoir history:
Draugen was discovered in 1984, in an area where most geologists did not bother looking for hydrocarbon-bearing reservoirs. Oil from Haltenbanken had migrated eastwards and up, and Draugen was discovered at a shallower level than the other reservoirs in the area. The producing formation had excellent characteristics. We assumed a recovery factor which seemed realistic at the time, in the late 1980s: about 17% of the oil would be produced. Today the recovery is multiplied by four, now getting close to 70%. The average recovery factor in Norway is 46%. We are in the lead in Norway when it comes to extracting the maximum amount of oil out of a reservoir.
However, the good reservoir quality is not the only reason why Draugen has achieved such a high recovery rate. By natural underground pressure, the statistical recovery rate is expected to be only 5-15%. We therefore implemented an active reservoir management strategy.
Our first step was to add pressure support. This key decision was already in Draugen’s Plan for Development and Operation (PDO), submitted in 1988. We installed water injectors at each end of a long and fairly narrow field. By doing this, the reservoir pressure was maintained while also pushing the oil towards the middle of the field, where the platform is located. This approach raises the statistical recovery factor to 35-45%.
We have continuously monitored the fluid movements in the Draugen reservoir by extensive use of seismic surveys. The first seismic acquisition was made before production start-up and has since been repeated four times at regular intervals. With the exception of one high resolution seismic acquisition in 2004, these have been conventional seismic acquisitions. The next seismic will be broadband seismic, but still compatible with the previous seismic, such that 4D data still will be achieved.
The sixth seismic survey will be conducted in the summer of 2013, using PGS’ Atlantic Explorer. Seismic surveys enable us to understand the reservoir dynamics and make even better decisions.
To give an example: based on the seismic information acquired in 1998, we changed the location of a planned production well from west of the platform to more than 1km away to the north of the original target. The outcome was a well that was tested at 78,000 b/d. That is one single well performing close to an entire oilfield. If the location had not been changed, we would have ended up with a poorer well, with significantly higher water cut.
There are relatively few wells on Draugen, only 11 production wells. Several of them have produced over 150 million bbl, which is more than many fields produce from all their wells throughout their entire field lifetime.
Seismic surveys have thus given us a good understanding of the reservoir dynamics, to see where the oil flows, and where it is trapped. Drilling additional subsea wells was part of the initial Draugen development concept. This, too, would be done based on the “less is more” philosophy – not many, but efficient wells. Future subsea wells were included in the platform design phase and a significant subsea development was foreseen in the PDO (Plan for Development and Operation) document. Six of the 11 wells on Draugen today are subsea wells, while five are platform wells. Four of the subsea wells were drilled and commissioned west and south of the platform in 2001 and 2002. The two last subsea wells were installed in 2007 and 2008.
We have planned four strategically placed subsea production wells for the upcoming drilling campaign, which will start shortly using the West Navigator drillship. This summer’s new seismic can hopefully tell us where we might locate additional future wells.
Subsea wells usually give a lower recovery than platform wells. In response, Shell will rely on technology similar to that first pioneered in 1993: mudline pumps. Through partnership with Framo Engineering, Shell plans to install a subsea, multiphase booster pump downstream of the Garn West manifold, about 4 km from the platform in 280m water depth. This is predicted to help boost the recovery factor to over 70%, which is probably one of the highest recovery factors achieved from an oil reservoir.
We have assessed CO2 injection for pushing yet more oil out of the reservoir, but found it uneconomic for Draugen. The next step is to assess injection of other types of chemicals, which will make the oil smoother and hence easier to move towards the production wells.
So far, the reservoir-technical recipe for a high recovery on Draugen is water injection, our production philosophy and planning with seismic, and subsea tiebacks. But there is one more key factor:
Maintenance
The older the installation, the more maintenance is needed. Technical integrity is one of the major factors for increased oil production from existing platforms. We made a calculated risk in designing Draugen with a just a few wells and only one processing train. It required lower investment and less need for maintenance and monitoring. However, it also led to greater risk and greater consequences if something went wrong. It presumed that all wells and processing equipment would function optimally – all the time. This scheme requires solid integrity management. Draugen delivers production reliability normally above 90%, which is very high compared to most offshore installations of similar age.
Draugen was supposed to produce until 2010, and the authorities approved a lifetime until 2013. Even so, our maintenance and operations philosophy has always been that Draugen will live forever. A pledge that is now paying off.
Our commitment to meticulous maintenance and ensuring well-run machinery that is carefully looked after has been an important factor in safely maximizing the extraction of resources from the Draugen reservoir. The stable and dedicated workforce running the platform has been of paramount importance.
Our maintenance philosophy has been based on ‘doing it right the first time.’ It requires good planning and well-prepared job packages from the onshore support organisation in Kristiansund, allowing the offshore workforce to focus on the physical execution. Proactive maintenance has not only been narrowed to technicalities, but also involves tailormade “on the job training” for continuous development of people skills and competencies.
Draugen has an impressive history and we think there is more to come. This is the reason for purchasing BP’s interest in the partnership last year. Shell’s ownership interest is currently 44%. We have just submitted an application to extend Draugen’s lifetime from 2013 to 2036. The application defines what measures will be necessary to upgrade Draugen for the future. Project examples involve upgrade and expansion of the platform living quarters, upgrade of the control room systems, installing new lifeboats, installing reinjection of produced water, removing the old loading buoy, and installing a new crude oil loading system. From Jan. 1, 2012, Aibel AS has been the main contractor on Draugen. There is often a strong focus on new discoveries, new developments, and new installations. The activity level on Draugen shows that maintenance and long-term strategies pay off with high reliability and stable production. Our actions show that we see opportunities for profitable operations on Draugen for many years to come.
Draugen is a field that has delivered more than what we dared to hope for. OE
Odin Estensen is asset manager for Shell operated production in Norway. He has held various Shell positions in Norway, the Netherlands and UK since 1990, as drilling supervisor, project engineer, and contract engineer in well engineering. He has been offshore installation manager on Draugen, non-operated venture asset manager, HSE manager Shell Europe, and safety and environmental delivery manager for Shell Upstream International. He earned an MS in Petroleum Technology at NTH-Trondheim and an Executive MBA in Strategic Management at NHH-Bergen.
Subscribe
