Faults can severely compartmentalize pressures and fluids in producing reservoirs, and it is therefore important to take these effects into account when modelling field production characteristics. The Brent Group fields, northern North Sea, contain a complex arrangement of fault juxtapositions of a well-layered sand-shale reservoir stratigraphy, and fault zones containing a variety of fluid flow-retarding fault rock products. It has been our experience that these fault juxtapositions impact the ‘plumbing’ of the faulted layering system in the reservoirs and the models that are built to mimic them – and are, in fact, a first-order sensitivity on compartmentalization of pressures and fluid flow during production simulation. It is important, therefore, to capture and validate the geological feasibility of fault- horizon geometries, from the seismic interpretation through to the static geocellular model, by model building in conjunction with the interpretation. It is then equally important to preserve this geometrical information during geocellular transfer to the simulation model, where it is critical input data used for calculation of fault zone properties and fault transmissibility multipliers, used to mimic the flow-retarding effects of faults. Application of these multipliers to geometrically weak models tends to produce ambiguous or otherwise potentially misleading simulation results. We have systematically modelled transmissibility multipliers from the upscaled cellular structure and property grids of geometrically robust models – with reference to data on clay content and permeability of fault rocks present within drill core from the particular reservoir under study, or from similar nearby reservoirs within the same stratigraphy. Where these transmissibility multipliers have been incorporated into the production simulation models, the resulting history matches are far better and quicker than had been achieved previously. The results are particularly enhanced where the fault rock data are drawn from rocks that have experienced a similar burial–strain history to the reservoir under study.

Reservoir Compartmentalization -the segregation of a petroleum accumulation into a number of individual fluid/pressure compartments -occurs when flow is prevented across 'sealed' boundaries in the reservoir. These boundaries are caused by a variety of geological and fluid dynamic factors, but there are two basic types: 'static seals' that are completely sealed and capable of withholding (trapping) petroleum columns over geological time; and 'dynamic seals' that are low to very low permeability flow baffles that reduce petroleum crossflow to infinitesimally slow rates. The latter allow fluids and pressures to equilibrate across a boundary over geological time-scales, but act as seals over production time-scales, because they prevent crossflow at normal production rates -such that fluid contacts, saturations and pressures progressively segregate into 'dynamic' compartments.

This paper describes the nature and relative significance of stratigraphic and structural compartmentalization in dryland fluvial reservoirs using data drawn from the Heron Cluster (Heron, Egret and Skua) oil fields in the UK Central North Sea. The Triassic Skagerrak Formation reservoir in these fields was deposited in a variety of dryland terminal fluvial settings, ranging from relatively arid terminal splay and playa to more vegetated, channel-confined systems with associated floodplain and palustrine facies. Laterally extensive floodbasin shales punctuate this terminal fluvial architecture. Static and dynamic data indicate that these fields are compartmentalized: geochemical data indicate significant fluid variations both between wells and vertically within individual wells; material balance calculations suggest production from restricted connected volumes, locally from a subset of the range of oils present; and re-perforation across significant shale boundaries access undepleted reservoir with different fluid compositions. Lateral variations could be ascribed to prominent structuration within these fields, but in general these high net:gross reservoirs do not have a viable fault seal mechanism. Early (syn-halokinetic) grounding of Triassic 'pods' between salt swells during salt withdrawal has resulted in zones of intense faulting along the zone of contact of the pod and the underlying basement, and also on the flanks of pods as the margins collapsed under further salt withdrawal. This deformation occurred under relatively shallow burial depths and is largely expressed by disaggregation zones and phyllosilicate fault rocks. Fault property averaging algorithms (e.g. shale gouge ratio), indicate that the sands should communicate across the juxtapositions, implying that the fluids and pressures should equilibrate between reservoir sands. However, the stratigraphic differences across major shales in both fluid geochemistry and pressure caused by draw-down are preserved despite the presence of these faults. The preservation of stratigraphic compartments indicates that for these faults the deformation mechanism was probably dominated by clay smear, in which the shale-prone sequence was smeared down the fault planes without losing its coherence. This style of stratigraphic compartmentalization occurs across several shale-prone intervals that are correlatable across the region. In some cases these mark the boundaries to major changes in fluvial depositional character, provenance and floodplain drainage, suggesting an extrinsic control that led to shale packages defining consistent barriers in all the fields. Other shale barriers do not show major changes in depositional character and, although correlatable, appear to be the product of semiregional advance and retreat of the fluvial systems, possibly combined with nodal avulsion. In contrast to reservoirs deposited by large exorheic rivers, the terminal nature of these dryland fluvial systems appears to have resulted in the repeated interfingering of fluvial and floodb...

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