Abstract The North Sea Basin contains a widespread Permian salt layer that reached a depositional thickness of c. 1 km in the basin centre. This layer profoundly affected structural style of the post-salt succession and the basin can be divided into structural domains on this basis. In combination with regional 3D seismic data and several thousand wells this makes the North Sea a natural laboratory for salt tectonics. Four principal structural domains are illustrated here. (1) Minibasin subsidence and salt wall growth on the West Central Shelf in the Late Permian to Triassic. This area was exhumed and differentially eroded prior to Jurassic rifting, creating palaeogeomorphology analogous to the present-day Paradox Basin, Utah. (2) Regional tilt during the Mesozoic and Cenozoic led to basin-scale gravity sliding with updip detached extensional faults and downdip compressional structures, similar to gravity sliding in the circum-Atlantic salt basins. (3) Jurassic rifting propagated across the salt basin, displaying spatial variation in extensional fault style, partly as a function of salt layer thickness. (4) North Sea salt thickness was not sufficient for salt canopy development but there are two suites of minor intrusions: cylindrical, passive diapirs with associated fault and fracture patterns in the central North Sea, and sills where Permian salt from reactive diapirs intruded along thin Triassic salt layers in the southern North Sea. Cretaceous to Palaeogene regional shortening affected all these domains, resulting in a variety of reactivation styles that do not fit within commonly used definitions of inversion tectonics. The North Sea salt tectonic domains form the basis of a matrix approach to salt structure initiating and driving mechanisms, and a mechanostratigraphic scheme for tectonic structure classification.

Abstract Unexpected incidents leading to lost time when the rig is on location cause unplanned cost to the hydrocarbon industry of over one billion dollars annually. Processing and interpretation of 3D seismic data usually focuses on reservoir levels. But from a drillers perspective, geological features of the overburden are often more significant than those at reservoir level, since over 90% of the well is typically spent drilling the overburden, coping with a wider variety of challenges than those associated with the reservoir itself. 3D seismic data defines overburden tectonostratigraphy, the framework of a geological model that can be used in well planning to reduce geological uncertainty, surprises and expense along the whole well track. Many technologies applied in reservoir modelling are equally valid in defining overburden features relevant to well planning. The overburden 3D volume can be populated with key parameters for well design, such as pore pressure and geomechanical attributes, though the complexity of the model will often be restricted by well cost and perception of drilling risk. The role of 3D seismic data in forming the tectonostratigraphic framework of multi-attribute, kilometre-scale Earth models, is illustrated here by a number of examples where model sophistication has been scaled to match project requirements. Overburden Earth models also provide a framework where several ‘academic’ research themes, for instance 3D fault geometry, can be put into a commercial context. Construction of overburden models for well planning has also highlighted a number of future geological research areas that could have a significant impact on drilling performance. Some of these, such as hydraulic properties of fault systems, are highlighted here.

Abstract The curvature of structured geological surfaces can be used to assess the degree of strain they have undergone. In many hydrocarbon reservoirs, this strain is expressed as brittle fracturing that may significantly impact reservoir performance. Here we describe the development of an algorithm for measuring the curvature of gridded surfaces derived from seismic data. For any grid node, the algorithm calculates the magnitude and orientations of the two principal curvatures, K 1 and K 2 , from which other curvature measurements can be derived, such as Gaussian curvature and summed absolute curvature ( K 1 + K 2 ). The algorithm has also been used to generate plots of summed absolute curvature as a function of grid node separation ( k versus λ ). These ‘spectral’ or kλ plots can be generated for each grid node and allow the definition of short-wavelength, high-amplitude noise cut-off lengths. They also deliver intermediate wavelength features such as fault drag or buckle folding and the identification of long-wavelength (basin-scale) curvatures. Portions of these data can be collapsed into single values by calculating the integral of the kλ curve. Further filters designed to screen the effects of background tectonic, or non-tectonic, curvatures can be applied to the kλ integral. This algorithm has been tested using data from several North Sea chalk fields. A range of alternative types of curvature and curvature spectra are compared with other approaches to curvature calculation and other factors relevant to the calibration of such techniques in terms of the distribution of brittle fractures in sedimentary rocks. The kλ integral provides a relatively simple approach to calculating the degree of multiwavelength strain present at a particular grid node. Freeing algorithms from the restriction of the ‘arbitrarily’ selected minimum grid node spacing is a key step towards calibrating measured curvature against strain mechanisms. However, care must be taken to separate intrinsic and tectonic curvatures when generating and interpreting kλ plots and their integrals.