This paper describes how petrophysical thin-bed analysis is applied to an integrated static and dynamic modelling workflow to obtain a history match based on 3 years of production, for a series of relatively thin heterolithic reservoirs. Previous reservoir simulation work based on conventional petrophysical interpretation for property modelling, indicated insufficient connected STOIIP and permeability-thickness to match flow behaviour observed from surveillance data. Therefore, an alternative thin-bed approach was proposed to address this fundamental reservoir characterization issue. It is well known that across highly-laminated sandstone-shale intervals, the acquired log measurements of the sandstone laminations are adversely affected by shoulder effects due to inadequate vertical resolution of most logging tools. Furthermore, the resistivity of thin sandstones is suppressed by the high conductivity of silt-clay laminations which further compounds the problem. Thisleads tothe underestimation of reservoir properties and consequently, in the underestimation of hydrocarbon volumes and permeability-thickness. The thin-bed approach utilises available core and high-resolution resistivity-based wellbore images together with open-hole logs. These are used as inputs to generate a set of petrophysical properties, via a log resolution enhancement (LRE) method, which are more representative of the reservoirs under study. The petrophysical improvements made, relate particularly to net pay thickness, porosity, permeability and saturation estimations. This paper also demonstrates how thin-bed properties are propagated into the static modelling workflow, to produce a series of realizations which results in improved reservoir characterization, with more accurate in-place volumes and flow characteristics. In practice, the application of thin-bed analysis requires careful refinement to 3D grid design so that the effects of thin-bed heterogeneity are captured to facilitate history matching in simulation. By integrating this thin-bed approach, an improved history match is obtained more efficiently and without significant application of local modifiers. This improvement further infers that thin-bed log analysis is much more appropriate than ‘conventional’ log analysis for thinly-bedded heterolithic reservoirs not only in this field, but potentially to many similar reservoirs in this basin, and elsewhere. This work ultimately led toa successful infill drilling programme and opened up potential for extended development to include secondary recovery; as opposed to ad-hoc workover potential, as described in the original Field Development Plan.

Introduction The Dunbar Field is situated in the south-central part of the East Shetland Basin, about 135 kms east of the northernmost Shetland islands and 25 kms south of the Alwyn North field (figure 1). The basin, an intermediate terrace region between the East Shetland Platform and the deep North Viking Graben, is characterised by a series of pre-Cretaceous structurally aligned tilted fault-blocks whose relief are clearly seen on the base Cretaceous seismic reflector. The Dunbar area is 55 km2 (17 km long × 2 to 5 km wide). Dunbar is limited to the north and east by a major NNW SSE fault, down-throwing to the east. Internally, the field is compartmentalised by a number of N - S faults and by a secondary alignment of NE - SW faults which cross-cut and often offset the main N - S faults. The larger-scale faults downthrow to the east and subdivide the field into three main areas, namely the Westflank, the Central Panel and the Frontal Panel. In general, the flanks of the resultant fault-blocks dip gently in a westerly direction. Sedimentary thicknesses were controlled by major synsedimentary faults. The Brent Group/Upper Massive Sands thickness in the Westflank/Central Panel 'footwall', where perhaps only partial sequences are preserved, is around 90 metres, whereas in the Frontal Panel 'hanging wall' more complete sequences were accommodated with thicknesses in the order of 280 metres. Hydrocarbon accumulations are present at several stratigraphic levels in the Dunbar area. P. 329

The Brent East reservoir of the Alwyn North Field, with few producer wells and a relatively short production life, represents a challenge for data gathering and reservoir management. Accurate reservoir description had to be obtained rapidly to adjust to unexpected events in order to maximise recovery and prepare enhanced oil recovery programmes.

SPE Members Abstract Advances in computing technology have allowed the development of sophisticated 3D cellular modelling and visualisation software which has found a variety of applications in the oil industry. This includes spatial attribute modelling and the visualisation of hydrocarbon reservoirs to improve the understanding of the geological structure including internal features, the distribution of formation properties and the movement of fluids once field production begins. This paper discusses experiences gained in building a geological 3D model of the West Flank of the Alwyn North reservoir and the subsequent manipulation and transfer of this data into a 3D reservoir simulator for initialisation. The techniques used differ considerably from the traditional method using 2D surface mapping packages. The advantages of both geoscientist and reservoir engineer being able to see and review the 3D image of the reservoir at an early stage in the project is discussed. The paper covers the modelling of the reservoir's complex heterogeneities, the handling of both vertical and sloping fault surfaces, deviated wells and the contrasts in the number of cells of the geological model compared with the number of blocks in the reservoir simulation model. Procedures for up-scaling from geological to reservoir model are discussed along with the errors introduced in the transfer of data and subsequent re-sampling by different software packages. The paper concludes with suggestions for future developments of software to further enhance this effective method of modelling. Introduction The Alwyn North Field is jointly owned by Total Oil Marine plc. (operator), 33.33% and Elf Exploration U.K. plc., 66.66%. The field lies in blocks ½a and 3/9a of the Northern Sector of the North Sea, (Figure 1). The field produces hydrocarbons from both the Brent and Statfjord sandstone reservoirs. The initial recoverable reserves are estimated to be 218 MMstb of oil and 27 GSm3 of gas. The field came onstream in November 1987 and by the end of September 1993 had produced 170 MMstb of oil and 16.1 GSm3 of gas. The field can thus be regarded to be at a mature stage in its development. Extensive 3D seismic coverage has delineated a series of westerly dipping fault blocks which show extensive erosion and slumping along the eastern edge. There are two principle fault directions, a major NNW-SSE trend and a secondary ENE-WSW transverse trend. This faulting has divided the Brent reservoir into a series of five hydrocarbon bearing panels as indicated in Figure 2. The three panels comprising Brent North West, Brent Central West and Brent South West are referred to collectively as the West Flank. Four separate reservoir models have been constructed to cover the Alwyn North field. These are the Statfjord model, the Brent East model, the Brent North model and the West Flank model. It is the construction of the latter model which is discussed in this paper. P. 263^