All Dutch rift basins that formed during Jurassic and Early Cretaceous extension have been inverted during the Late Cretaceous and Early Tertiary. Several inversion pulses occurred more or less simultaneously in all basins. Analysis of vitrinite reflectance data, in combination with fission track and fluid inclusion data show that the magnitude of uplift and erosion generally did not exceed 2 km. Inversion was strongest in the Broad Fourteens, Central Netherlands and West Netherlands basins. The direction of maximum compressive stress was generally not at right angles to the pre-existing fault trends, and resulted in transpressional movements. Within the NW-SE striking basins, dextral strike-slip movements can often be interpreted, which is consistent with a general N-S to NNW-SSE direction of maximum compression related to Alpine structural events. Where no Zechstein salt is present, trends of flower structures formed through reverse reactivation of pre-existing faults. Where the Zechstein salt is thick, re-activated faults could not breach the salt, and a broad uplift of the post-salt succession resulted, while faulting below the salt caused acceleration of halokinesis. In areas where the Zechstein salt was thin, and where the offsets of reverse faults exceeded the thickness of the salt, impressive thrusts with the Zechstein salt as detachment horizon developed. The later Tertiary inversion pulses did not affect all basins, and caused broad basin uplift in the West and Central Netherlands basins while individual faults were no longer reactivated. It appears that due to crustal diickening during the first inversion pulses the crust could become stabilised such that further compression could only be accommodated by broad basin uplift.
After more than half a century of production and with some 350 wells, the Groningen gas field must be one of the best-studied gas fields in the world. Initially, it was considered to be relatively simple and behaving like one big tank. Now that it is entering a phase of declining production it has become clear that many subtleties are not fully understood yet. Prediction and management of subsidence and induced earth tremors require a detailed understanding of the field geology. In addition, an optimum gas recovery is only possible if details of, for example, reservoir quality distribution and faulting, that did not appear relevant before, are well understood.The large Groningen field comprises a structurally high block during much of its history, probably already from Devonian times onwards. The desert sandstones of the Rotliegend reservoir exhibit a strong south-to-north proximal-distal relationship. Whilst diagenesis has in many fields led to deterioration of reservoir properties, this effect is small in the Groningen field. The field is dipping to the north, and bounded by a series of normal faults in the west, south and east. Almost all faults are normal extensional faults, but locally inverse reactivation has led to small pop-up structures.Reactivation of older faults must have resulted in oblique movements along most faults.The challenges for future development of the Groningen field are immense. Managing the risks associated with induced seismicity and recovery of the remaining gas will continue to require an increasingly detailed knowledge and understanding of its geology.
The structural evolution of the Southern North Sea region is controlled by a number of important tectonic phases. The dominant NW-SE structural grain first became evident during dextral wrenching in the Stephanian/Autunian. A second fault direction trends NNE-SSW, and probably also originated in pre-Permian times. Extensional faulting in the Triassic preceded major Middle Jurassic to Early Cretaceous rifting. Subsequent cooling subsidence was interrupted by inversion in the Late Cretaceous, the mid-Paleocene, and again in the mid-Tertiary. During these periods Jurassic basins were uplifted and, locally, subjected to deep erosion.Despite the multitude of tectonic events, a high degree of fault parallelism can be observed in the Southern North Sea. Fault patterns and directions are strikingly similar, whether viewed on a regional scale or at prospect level. The general structural model is, therefore, one of repeated reactivation of basement faults, which continue to control the structural grain despite changes in tectonic regime. Only rarely and by coincidence do the main structural features have orientations that conform to the regional stress. Consequently the predominant mechanism is considered to be one of oblique-slip.This phenomenon is particularly well observed on structural highs, such as the Cleaver Bank High, straddling the median line between the Netherlands and the UK. Here, the fault trend at Base Zechstein level runs essentially NW-SE. Repeated fault reactivation has led to anomalously high length-to-throw ratios. Locally short N-S and E-W link-ups accommodate oblique-slip. At higher stratigraphic levels en-echelon faults illustrate the strike-slip nature of the latest movements along the pre-existing NW-SE structural grain.The presence of salt in the overburden causes faulting at higher levels to be decoupled from basement faulting. Sandbox experiments show that reverse faults and extensional grabens can develop in the postsalt sequence in response to oblique-slip along the pre-salt structural grain. The location of such grabens is invariably offset towards the footwall of the basement fault, the amount of offset dependent on the thickness of the salt.These sandbox experiments provide valuable analogues for the structural mechanisms that are believed to have operated in the Southern North Sea. Applied to both 2D and 3D seismic interpretation, they allow fault mapping with a greater degree of confidence. Recognition of fault reactivation and oblique-slip will lead to a better understanding of the tectonic history, timing of structuration and trap development.
The impact of oil and, in particular, gas fields discovered in the Dutch subsurface has been very significant. However, 50 years after the discovery of the giant Groningen gas field the Netherlands has become very mature for exploration of oil and gas, and the gas volume left to be discovered in conventional traps is insignificant compared to what has been found already. The total portfolio of conventional prospects held by the industry contains several 100s of billions of cubic metres (bcm), as reported by the Ministry of Economic Affairs, but many of these prospects are unattractive to drill because of their small size or other geologically unfavourable aspects. Hence, for planning purposes of future national gas production the risk should be taken into account that the size of the conventional portfolio is overestimated. The major E&P companies have reduced their exploration efforts and the number of wells drilled as well as the size and total volume of discovered gas reserves has seen a steady decline over the last 10 years. Some surprises may still be in store and can occasionally add a welcome addition of gas. But the follow-up potential of new play and trapping concepts has been disappointing for many years now, and it is concluded that this is unlikely to be different in the future.Remaining conventional discoveries will mainly be in small near-field targets that as a result of technological advances made in the last few decades can be drilled with high confidence, despite their small volumes.This leaves the so-called unconventional gas (UG) resources for a real and significant increase in the exploration potential of the Netherlands.UG resources occur outside conventional structural or stratigraphic traps in tight (low permeability) rocks and are of regional or sub-regional extent, without well-defined hydrocarbon-water contacts. The potential for Basin Centred Gas, Shale Gas and Coal Bed Methane is reviewed. As, according to present-day technology, development of UG requires very dense drilling at low costs with well spacing of a few 100s of metres, only the onshore potential can be commercial, even in the longer term.Recent geological uplift is a characteristic for all North American commercial UG developments. Uplift helps bringing the resources close to the surface and facilitates development of fractures, which are essential for achieving commercial flow rates. This significantly reduces the area where commercial UG resources may occur in the Netherlands. In addition, sweet spots, where commercial flow rates and ultimate recovery per well can be achieved, represent only a fraction of the total 'play area'. The UG plays in the Dutch subsurface remain to be proven, and there is still a significant technical risk associated with these plays, on top of the commercial risk. Therefore, despite potentially enormous in-place gas volumes in these unconventional plays, recoverable volumes are much less. If UG resources can be proven and are commercially developable, their cumulative volume potential ...
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