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Structurally complex reservoirs form a distinct class of reservoir, in which fault arrays and fracture networks, in particular, exert an over-riding control on petroleum trapping and production behaviour. With modern exploration and production portfolios commonly held in geologically complex settings, there is an increasing technical challenge to find new prospects and to extract remaining hydrocarbons from these more structurally complex reservoirs. Improved analytical and modelling techniques will enhance our ability to locate connected hydrocarbon volumes and unswept sections of reservoir, and thus help optimize field development, production rates and ultimate recovery. This volume reviews our current understanding and ability to model the complex distribution and behaviour of fault and fracture networks, highlighting their fluid compartmentalizing effects and storage-transmissivity characteristics, and outlining approaches for predicting the dynamic fluid flow and geomechanical behaviour of structurally complex reservoirs. This introductory paper provides an overview of the research status on structurally complex reservoirs and aims to create a context for the collection of papers presented in this volume and, in doing so, an entry point for the reader into the subject. We have focused on the recent progress and outstanding issues in the areas of: (i) structural complexity and fault geometry; (ii) the detection and prediction of faults and fractures; (iii) the compartmentalizing effects of fault systems and complex siliciclastic reservoirs; and (iv) the critical controls that affect fractured reservoirs.Structurally complex reservoirs form a distinct class of reservoir in which fault arrays and fracture networks, in particular, exert an over-riding control on petroleum trapping and production behaviour

Summary Lithospheric stretching can successfully account for the overall evolution of many sedimentary basins, and detached normal faulting the detailed geometry of the upper crust. In an instantaneously stretched, isostatically compensated basin, the equations which describe these two processes can be combined to define a ‘notional depth to decollement’. Only at this level can the sole to the normal fault system maintain a constant depth below sea-level during extension. The notional depth to decollement depends primarily on the mean density of the basin fill and for a constant-density basin fill (e.g. sea water) coincides with the level of no vertical motion during stretching. In a sediment-filled basin, the notional depth to decollement will increase with the stretching factor β as early-deposited sediments are compacted and the mean density of the sediment column increases. In general, a physical sole fault will not lie at the notional depth to decollement, and must move vertically to maintain isostatic equilibrium: such movement precludes the use of balanced cross-section techniques to determine the physical depth to decollement. In typical crustal situations, uplift of the sole fault will be more common than subsidence and will in turn cause uplift of any residual, unfaulted basement blocks which rest upon it. Footwall uplift can also be modelled using area-balance constraints, referred to the notional depth to decollement rather than to the physical sole fault. The amount of uplift depends primarily on the initial fault spacing. Three fields can be distinguished: one in which footwalls subside at an increasing rate as β increases, one in which they are uplifted above sea-level then subside below sea-level, and one in which they are uplifted then subside, but always remain above sea-level. Similar relationships exist in an uncompensated basin, where the depth to the physical sole fault replaces the notional depth to decollement. Curves showing uplift and subsidence versus β have been constructed in dimensionless form (referred to depth to decollement) and for a model basin with an exponential sediment compaction relationship. They agree closely with uplift/subsidence histories inferred from seismic and well data for the North Sea, and with published descriptions of other areas (the Armorican margin, the Aegean Sea).

The Clair oilfield is a large fractured sandstone reservoir lying 75 km west of Shetland on the UK continental shelf. Fracture analysis and modelling was carried out in preparation for the phase 1 development, which started production early in 2005. Fracture clusters and discrete fluid inflows observed in wells are associated with faults and other localized deformation features tens or hundreds of metres apart. The reservoir has moderate to good matrix permeability, but well flow rates and profiles are fracture-dominated. Full-field geological models were built using conventional object modelling approaches for matrix and discrete fracture networks for fractures, and upscaled to populate a reservoir simulation grid. Dual-porosity, dual-permeability dynamic modelling (full-field and well-test) was undertaken to understand the fracture and matrix flow contributions and their interaction. Fracture models were conditioned to wells and to seismic data, including coherency and multi-azimuthal velocity information from a four-component, ocean bottom cable three-dimensional seismic survey. At this early stage in field development, there is insufficient calibration to select a single fracture model. Instead, well and depletion plans have been tested against multiple fracture models chosen to encompass a wide range of plausible outcomes.