What to do with the Tampen area? In this key region for Norway's offshore production, fields are maturing and facilities aging. A strategy is needed that takes into account the needs and potential of the area as a whole.
Statoil is leading this complex work for the Tampen 2020 project, which could involve a substantial reconfiguration of production and transport facilities. The first decisions are expected to be made next year.
Lying in the northern part of the Norwegian North Sea, the Tampen area contains the Statfjord, Gullfaks, Snorre, Tordis, Vigdis, and Visund fields, plus several satellites. Development facilities include nine platforms - three fixed installations each on Statfjord and Gullfaks, and two floaters on Snorre and one on Visund - and about 130 subsea wells distributed among Statfjord East, Statfjord North, Statfjord North Flank, Sygna, Gullfaks South, Rimfaks, Gullveig, Tordis, Tordis East, Borg, Snorre, Vigdis, and Visund.
Tampen is a critically important area both for Statoil and for Norway, says Torstein Hole, vice president for Tampen business development in Statoil's E&P Norway business area. It accounts for a high proportion of production - 41% of Statoil's overall production and 22% of Norway's in 2001. Current production is around 1 MMboe. The area, in which accumulated investments amount to some NKr 290 billion in 2002 kroner, has consumed over the last five years an annual NKr 10-16 billion.
Mature province
But the province is a mature one, and the issue now is how to produce the remaining reserves and develop the remaining potential in a commercial manner. There is still a potential for increased recovery beyond current plans. The first and most important phase will center on Statfjord and Gullfaks and will provide the framework for later phases that will include Snorre and possibly Visund. The effect of the strategy will be to extend the tail-end life of the various fields, in some cases through 2020.
Statoil, which already operates Statfjord and Gullfaks and their satellites, has the leading role as on Jan. 1, 2003, it is due to take over operatorship of the remaining fields, which are currently operated by Norsk Hydro. Its equity position in all the fields was strengthened last year by the acquisition of stakes from the State's Direct Financial Interest.
Much has been done in recent years to enhance production on Statfjord and Gullfaks. By last year, the recovery rate on Statfjord had been lifted to 65% of the 6.3 Bbbl in-place reserves. Statoil, which has talked of an ultimate aim of 70%, is currently working to achieve 68%. Similar gains have been made on Gullfaks, which consists of a more complex reservoir. Here the current target is 60%.
Despite these moves, unit operating costs will increase in a few years unless counter-measures are taken. On both Statfjord and Gullfaks, while oil production steadily declines, the total volume of liquids processed over the platforms remains about the same.
On Statfjord, some 1.43 MMb/d of liquids are processed from the main field and its satellites, of which 20%, or 260,000 b/d, is oil. Gullfaks will face the same problem a few years down the road. If no action is taken, operations will start to become uneconomic over the next few years. The first platform shutdowns would be expected to take place in 2007-2010, Hole says.
The planning of a late-life project for Statfjord has already been under way for some time. The intention is to produce the gas cap by reducing the reservoir pressure, a move that should yield an additional 50 bcm of gas plus 60-120 MMbbl of oil. This is the same route followed by Shell on the geologically similar Brent field, which lies not far from Statfjord on the UK side of the median line. Both Shell and ExxonMobil, which are Statfjord partners, have made a valuable contribution to planning how the strategy should be implemented on Statfjord, Hole says.
Statfjord strategy
The Statfjord late-life strategy is now being formulated in parallel with the area solution, and will be coordinated with it. In early 2003, the concept will be selected for Statfjord, and in mid-2003, a preliminary decision will be taken on an area solution. Both the area plan and the plan for Statfjord will be decided in 2Q 2004.
A range of measures is under study, but these can be grouped broadly under three main options, each with a series of sub-options. Hole stresses that there is as yet no preferred option or base case.
The first option is centered on a large new gas processing platform serving the whole area and probably located near Statfjord. New pipeline connections would be required from each of the Statfjord platforms, Gullfaks A and C, and the two Snorre platforms. The Statfjord platforms would be transformed into wellhead or minimum process facilities, while Gullfaks B, which has only partial processing capability, would either be transformed into a wellhead platform or shut down entirely.
A common solution for oil storage and export could be adopted, using the facilities on Statfjord and decommissioning those on Gullfaks. Gas could be exported, as now, via the Statpipe, with any volumes in exceeding the Statpipe capacity being piped into the Far-north Liquids and Associated Gas Gathering System in the UK sector. Among issues arising are whether gas processing should continue on Gullfaks A and C platforms, where facilities have only recently been installed, and to what extent gas injection should continue on the Gullfaks field.
A second option is based on debottlenecking and streamlining the Statfjord and Gullfaks process facilities to expand gas handling. Common oil export, using the Statfjord facilities, would again be a likely option. Some new pipeline connections would be required. Decisions would be needed on a gas export route and to what extent gas injection should continue on Gullfaks.
Using Brent facilities
The third option involves using the Brent facilities for processing Statfjord production. In this case, the Statfjord platforms would be reconfigured for minimum facility operations, separating out the produced water that would be injected into the Utsira formation. New pipeline connections would be required from Statfjord to the Brent B and C platforms. Snorre production would be sent exclusively to Statfjord (it currently also has a pipeline connection to Gullfaks). Statfjord oil and gas would be exported via the Brent facilities, to Sullom Voe and St. Fergus, respectively. Gullfaks operations would remain unchanged.
For purposes of comparison, it is being assumed that all options would be implemented in 2007, when the Statfjord late-life project is due to start up. The first option, for a new gas platform, involves high investments - the other two much less so.
In the case of the Brent option, determining an exact level of costs is difficult, as the possible tariffs are unknown. Moreover, while calling for different levels of investment, each option also offers a different potential with respect to recovery and revenues, making it a complex matter to determine which constitutes the best choice overall.
"We see definite value creation potentials we can take out," says Hole. "But at this stage it's very difficult to say how big the values are."
Other initiatives are being considered independently of the three main options. One is the possibility of generating power for the whole area from a single central location. This could reduce both generation costs and greenhouse gas emissions. At present, all nine platforms generate their own power.
A fundamental reorganization of logistical arrangements in the area is also being considered. Two supply bases currently serve Statfjord/Gullfaks and Snorre, while the operations organizations for the various fields are divided between Bergen and Stavanger.
Statoil is keen to encourage the partners in the various licenses - altogether eight licenses and 11 companies - to contribute to Tampen 2020.
In the long term, an alignment of ownership in the area is likely to be required, but some of the partners have expressed their desire to see how much progress can be made before embarking on such a step. Finding common ground may not be easy, given that the different partners have their own views on how much investment they wish to commit to their operations in Norway.
Contractor role
Contractors also have an important role to play. One in particular is Aker Kværner, which earlier this year was awarded a long-term contract for maintenance and modifications for the Tampen area. The company will be an important partner both in implementing changes and developing operating practice in coming years, Hole says.
Aside from the complexities involved in assessing the main options, the decision-making process is further complicated by other elements. New technologies such as subsea separation, which Statoil is planning to deploy on the Norne field in the Norwegian Sea, could make an important contribution.
Finally, though the Tampen area is mature, it is by no means devoid of exploration and development potential. The Kvitebjørn gas/condensate field is currently being developed. It is not itself linked to any of the other offshore facilities in the Tampen area, but has been identified by Hydro as the preferred evacuation route for gas from Visund, which the company is planning to start exporting in 2005.
A second stage of development of the Vigdis field is also about to begin, and Statoil is preparing plans to develop the small Ole and Dole fields discovered recently between Statfjord and Gullfaks. There are other exploration targets in the area, such as the Dolly prospect, and also in block 34/7. As likely subsea developments, these and other future discoveries should be relatively easy to incorporate within the future framework of facilities, whatever shape this turns out to have.
