Abstract The Cretaceous chalk section of offshore Norway is a prolific hydrocarbon-producing trend. The fields are typically structural traps, often with a stratigraphic trapping component. The identification and evaluation of stratigraphic traps in this chalk section require differentiation of the porous reservoir and tight nonreservoir chalk facies. Integration of geologic models, petrophysical data bases, and seismic analysis has allowed the detection and mapping of high-porosity reservoir-quality chalks along this play trend. Sedimentologic studies of chalk deposition, burial histories, and reworking are combined with detailed petrophysical analysis of core plug samples in the lab to define rock properties that distinguish porous from nonporous chalk facies. Seismic analysis techniques, including stratigraphic processing, velocity analysis, modeling, inversion, and AVO analysis, enable the extraction of these rock properties from the seismic data, leading to prediction of the subsurface chalk porosity distribution. The results of these analyses indicate high-porosity reservoir-quality chalk. The drilling of this prospective high-porosity chalk anomaly resulted in an oil discovery. This study demonstrates that the distribution of porosities within the Cretaceous chalk section of offshore Norway can be detected by seismic data. Furthermore, the porosity distribution in the chalk can be accurately predicted and mapped from the analysis of seismic data integrated with a detailed understanding of the petrophysical rock properties and the geologic history of the sediments.

Abstract A biostratigraphic review, conducted on 34 wells from the chalk of the Eldfisk Field, Norwegian Central Graben, has been integrated with petrophysical, geophysical and sedimentological information resulting in a revised lithostratigraphic framework for the chalk on this structure. Chalk of Danian to Turonian age is divided into five formations: the established Ekofisk Formation of Danian age and Tor Formation of Maastrichtian age, together with a new three-fold division of the Hod Formation, namely the Magne Formation of Campanian age, the Thud Formation of Santonian age and Narve Formation of Coniacian to Turonian age. This work demonstrates the application of this three-fold division of the Hod Formation. Internal field specific subdivisions of all formations are also presented for the Eldfisk Field. This lithostratigraphic framework is applied across the Eldfisk Field, together with the recognition of erosional features, unconformities, areas of non-deposition, reworking and lateral changes in biofacies. The results have also allowed recognition of the following regionally synchronous tectonic phases for the first time on a Norwegian chalk structure: Stille's Ilsede phase (Late Turonian–Coniacian) and Wernigerode phase (Late Santonian–‘earliest’ Campanian), Mittel–Santon phase (Middle Santonian) of Niebuhr et al. and Reidel's Peine phase (‘latest’ Early Campanian), together with un-named phases of ‘latest’ Campanian, intra Mid Maastrichtian and (previously unrecognized?) intra Danian age. Evidence for these tectonic phases is compared with work from Denmark, Germany and the Anglo-Paris Basin. An innovative approach to mapping lateral biofacies (principally water depth) variations has been applied using the microfaunal database. This enhances understanding of the timing of structural phases when integrated with time lines generated by nanoplankton data. Biofacies proxies for silica content in the sediment may also correlate with changes in reservoir quality. Biofacies interpretations have also facilitated the identification and mapping of allochthonous bioclastic rich debris flow deposits. The fully calibrated biostratigraphic, lithostratigraphic and tectonostratigraphic frameworks presented can be applied to chalk structures regionally.

Abstract Deposition of the Upper Cretaceous–Danian Chalk Group in the Salt Dome Province of the southern Danish Central Graben took place during a tectonic period dominated by post-rift subsidence, halokinesis and structural inversion. This resulted in highly variable chalk distribution with >1300 m of chalk located in synclines and <200 m preserved on inversion highs and salt structures. The area is mature with respect to exploration with most of the chalk fields located in structural traps discovered in the 1970s. However, the Halfdan discovery in 1999 illustrates the existence of off-structural traps, leading to renewed exploration interest. To locate additional off-structural traps, a detailed geological model is necessary for prediction of chalk intervals with reservoir potential. To unravel basin development, we combine 3D seismic interpretation, well log correlation and 2D seismic inversion to estimate acoustic impedance along selected profiles. The 2D acoustic impedance profiles are converted to total porosity and used to identify areas with potential untargeted reservoirs. A prominent high-amplitude reflection is interpreted as a regional unconformity separating two distinctly different chalk deposition patterns. Nannofossil biostratigraphy suggests a latest Campanian to early Maastrichtian age for the unconformity. It corresponds to an increase in acoustic impedance and decrease in porosity in wells. The Tor Formation contains porous intervals while the underlying Hod Formation contains less porous chalk. The Hod Formation has a maximum porosity of <20% based on well log and inversion data. In contrast, inversion data indicate that the Tor Formation comprises reservoir-grade porosity at several locations on downflank structures. In several areas, the inversion-based maximum porosity is predicted to be higher than expected, compared with porosity/depth trends derived from well data. Therefore, the spatial porosity variation in chalk is complex and controlled by factors other than burial depth.

Abstract The Shearwater Field, located in Block 22/30b in the UK Central Graben, remains one of the best-known fields in the UK Continental Shelf (UKCS). At the time of the initial development, Shearwater represented one of the most complex and technically challenging high-pressure and high-temperature (HPHT) developments of its kind in the North Sea. During the early life of the field, pressure depletion resulted in compaction of the Fulmar reservoir, leading to mechanical failure of the development wells. The compaction also resulted in weakening of the overburden due to an effect known as stress arching. Over time, this resulted in in situ stress changes in the overburden which have been observed from 4D seismic datasets and are in line with geomechanical modelling. This is particularly true for the Hod Formation in the Chalk Group, and resulted in the need to make changes to infill well design, including the use of new drilling technologies, to ensure safe and effective well delivery. The insights presented here, which relate to the understanding of pore pressure and fluid fill in the overburden, and how the overburden has responded to stress changes over time, are of relevance to current and future HPHT field developments in both the UK North Sea and elsewhere.

Abstract The Valhall Field is an Upper Cretaceous chalk reservoir located in the Central Graben area of the North Sea with production coming from the fractured Tor and Hod formations. Well tests and production history indicate that these formations are highly heterogeneous and that significant fluid flow occurs through both the matrix and fracture system. However there remained significant uncertainty about the specific controls and location of the main productivity conduits and how they would influence sweep efficiency during planned water flood. To address these uncertainties a range of possible conceptual fracture models were considered with respect to controls on major flow within the reservoir. Analysis indicated that the reservoir is dominated by a connected series of seismic scale faults acting as major flow conduits with smaller fractures providing a less significant enhancement to matrix permeability. A key input to this study was the examination of over 80 well tests. Simulation of a number of key well tests using a simple discrete fracture network model comprising a connected fault network and pseudo-matrix layer was able to reproduce the majority of the observed pressure derivative shapes. This gave some confidence to the understanding of major reservoir flow paths as well as providing calibrated fault properties for direct inclusion within the simulation model.