The giant Statoil-operated North Sea oil field Statfjord is currently far down its production decline curve. During 23 years of production more than 60% of the STOOIP has been recovered, and the remaining reserves are characterized by complex distributions of oil, water and gas.
In order to obtain a cost-effective production of the remaining oil, an aggressive drilling and intervention programme is necessary. The main challenge that the geoscientists and reservoir engineers face in this scenario is to identify remaining oil in targets becoming increasingly smaller, more complex and more uncertain, and to drain these in the most profitable manner. This paper reviews the working method that has been used at the Statfjord Field when defining a drilling schedule. It shows how the different work processes are linked, starting with the identification of possible new well locations, continuing with the estimation of reserves and risk evaluation and ending up with final drilling projects.
Introduction
The Statfjord Field was discovered in 1973, declared commercial in August 1974, and started production in 1979. The field is more than 25 km long and averages 4 km in width, and is the largest producing oil field in Europe. Statfjord is located in the Tampen Spur area, in the northern portion of the Viking Graben and straddles the border between the Norwegian and UK sectors. Figure 1 shows a map of the Tampen area. The field is developed by three fully integrated Condeep concrete platforms, from north to south, the Statfjord C, A and B platforms. All three platforms have tie-ins, as shown in Figure 2.
Production is from the Brent, Dunlin and Statfjord reservoirs, with Brent and Statfjord being the main reservoirs. Cumulative oil production as of May 2002 is 612 million Sm3, giving a current recovery of 60% of the STOOIP. The expected recovery factor is 65%. The oil production along with injection of water and gas has resulted in a field with three phases and several fluid contacts. The remaining reserves are therefore scattered over a wide area and in several reservoirs. Consequently each new well location is gradually decreasing in size and associated with considerable risk. Presently, each location is still economic but requires a considerable effort to mature.
A multidisciplinary organization applying well-defined work processes is necessary to recover the remaining reserves in a cost-effective manner. Resulting in an optimised drilling programme, the implementation of the work processes ensures the maintenance of a high activity level in the field.
Field Status
Production History.
Since its discovery in 1973, more than 280 wells have been drilled on the Statfjord Field. About 340 production logs and 220 saturation logs have been acquired. At present the activity level on Statfjord is higher than ever, with a drilling schedule comprising 15 infill wells drilled per year and more than 100 annual well interventions. There are currently 124 active wells in the field, and no spare slots available. Therefore all new wells are drilled as sidetracks from existing wells. Figure 3 illustrates the significant contribution from infill wells and well interventions on total production potential for the Statfjord Field during 2001.
Although the size of the remaining oil accumulations is decreasing, there is still producible oil remaining in all reservoirs. The oil is mainly found in structurally complex areas, poor quality sandstone or wedged between the emerging gas- and waterfronts. The distribution of remaining oil is a result of several individual drainage histories, resulting in a large variation in fluid contacts within each reservoir and hence a complex distribution of oil accumulations.
At present the average field water cut is above 80%, the gas-oil ratio is increasing, and both injection and liquid production are limited by process capacity on the platforms. Historical production for the Statfjord Field through December 2001 is illustrated in Figure 4.
Production History.
Since its discovery in 1973, more than 280 wells have been drilled on the Statfjord Field. About 340 production logs and 220 saturation logs have been acquired. At present the activity level on Statfjord is higher than ever, with a drilling schedule comprising 15 infill wells drilled per year and more than 100 annual well interventions. There are currently 124 active wells in the field, and no spare slots available. Therefore all new wells are drilled as sidetracks from existing wells. Figure 3 illustrates the significant contribution from infill wells and well interventions on total production potential for the Statfjord Field during 2001.
Although the size of the remaining oil accumulations is decreasing, there is still producible oil remaining in all reservoirs. The oil is mainly found in structurally complex areas, poor quality sandstone or wedged between the emerging gas- and waterfronts. The distribution of remaining oil is a result of several individual drainage histories, resulting in a large variation in fluid contacts within each reservoir and hence a complex distribution of oil accumulations.
At present the average field water cut is above 80%, the gas-oil ratio is increasing, and both injection and liquid production are limited by process capacity on the platforms. Historical production for the Statfjord Field through December 2001 is illustrated in Figure 4.
