New reservoir simulation models have recently been established for the Snorre field based on updated geological models and fully revised input data. The Snorre reservoir is highly heterogeneous, comprising stratified and heavily faulted fluvial deposits. The field is pressure supported by water alternating gas (WAG) injection, resulting in complex drainage patterns. Time-lapse seismic is amongst the technologies applied to improve reservoir understanding and has provided valuable information on fluid front movement and fault communication. The paper describes a first systematic effort on honouring 4D data in the Snorre reservoir simulation models. A workflow converting 4D responses into 3D volumes in the reservoir modelling software for easy comparison to simulated reservoir performance proved very useful in the multidisciplinary work process. The models are history matched with respect to pressures, production rates and fluid front movement from tracer and 4D data. Though the seismic time-lapse responses are matched qualitatively, they have improved the overall Snorre reservoir understanding. Different applications of 4D data in the history matching process are discussed, e.g. determining fault transmissibilities and water front movement, identifying water producing intervals and re-allocation of zonal contributions in wells. A successful water shut-off based on 4D interpretations and simulated future performance is also discussed. Introduction Snorre is a major producing oil field located in the Norwegian North Sea, with Stock Tank Oil Originally In Place (STOOIP) of 513 MSm3 and reserves of 234 MSm3, corresponding to an expected recovery factor of 46%. Approximately 2/3 of the reserves have been produced, and the current production rate is 25 000 Sm3/d. The field has a large IOR potential, expressed by the ambitious goal of 55% recovery factor. The reservoir consists of several rotated fault blocks comprising the Statfjord and Lunde Formations of Lower Jurassic to Upper Triassic age, characterized by complex packages of inhomogeneous stratified fluvial sandstones dipping 6 to 8 degrees. The reservoirs contain undersaturated light oil and the main drive mechanism is water alternating gas injection. A sequential development causes different production phases across the field, where some areas are highly mature, producing at high water cuts, whereas others are not yet developed. Snorre reservoir simulation models are important decision making tools used for production forecasting, remaining oil identification, well planning and IOR project evaluation. History matched simulation models are premises for effective reservoir management.

The objective of this paper is to highlight the necessary steps for the successful use of integrated asset modeling. It presents the full workflow for optimzing production and injection cycle times with the help of a simplified reservoir model (SRM) through the set up of an integrated asset model (IAM) to validate the SRM results and control the actual production performance. A discusson of the theory of the IAM as well as the steps to set up a SRM and IAM are presented in this paper. The steps are described in context of an actual field operation. A WAG cycle optimization workflow for the Snorre field has been created to demonstrate the advantages of using the SRM and IAM technology. The optimization process is performed using a SRM able to run a simulation run in a matter of minutes and hence being suitable for sensitivity analysis and optimization. The optimized WAG injection and production cycle is then carried forward to an IAM in order to accurately determine the well performance and the reservoir production. The IAM couples the modeling results from reservoir and well model with the surface facility network and process plant model. The coupling and integration allows investigating the impact of changes in one model to all the other models and hence also handles the proper propagation of constraints throughout the system. Introduction Coupling a full field reservoir simulation model with a surface facility network model allows for more accurate computation of hydrocarbon recovery since both system imposed constraints (fluid flow from the reservoir and surface constraints), can be considered simultaneously. The integrated asset model (IAM) comprises of a coupled system of reservoir simulation models with surface facility network models. The purpose of coupling is to balance a reservoir simulation model with the response of the surface facilities. The IAM consists of three distinct parts: The reservoir model, the well model and the surface facility model. These three models are coupled at coupling points, each passing the conditions at the coupling point on as a new boundary condition for the next model. The reservoir simulation model as a starting point computes the fluid movement and pressure distribution in the reservoir model, passing the information about the pressure and fluid saturation at the subsurface coupling point (well locations in the reservoir model) to the well models (conditions at sandface). In the well model the information about the conditions at the coupling point (sandface) is used as a boundary condition in order to compute the fluid rates or the pressure at the surface coupling point (e.g. well head), where the well model is linked to the surface facility model. The well model surface boundary condition acts as sink or source term in a surface network, which has to be balanced to account for varying fluid flow and pressure conditions in every well in the system. Their interaction will ultimativley lead to a newly calculated backpressure of the production system for every well. The system backpressure is then conveyed all the way back through the well model back into the reservoir in order to account for the changed boundary condition imposed by the surface model in the reservoir.

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.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe 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.

TX 73083.3836, U. S.A., fax OT-972-952-9435. AbstractAn unconventional thin-bed an~ysis based on logs, core and minipem data was needed to calculate the petrophysical properties of a reservoir under development in the Norwegian Sea.More than half of the resenroir section under investigation is composed of heterolithic facies: thinly interbedded sandstone and mudstone layers from one to several centimeters in thickness and of variable quality. By using miniperm measurements with 1-cm spacing on slabbed core, it was possible to resolve the properties of the rock far below the vertical resolution of conventional wireline logs and relate them to the bulk log measurements.