Marten ter Borgh

The Southern North Sea Basin area, stretching from the UK to the Netherlands, has a rich hydrocarbon exploration and production history. The past, present and expected future hydrocarbon and geothermal exploration trends in this area are discussed for eight key lithostratigraphic intervals, ranging from the Lower Carboniferous to Cenozoic. In the period between 2007 and 2017, a total of 95 new hydrocarbon fields were discovered, particularly in Upper Carboniferous, Rotliegend and Triassic reservoirs. Nineteen geothermal systems were discovered in the Netherlands onshore, mainly targeting aquifers in the Rotliegend and Upper Jurassic/Lower Cretaceous formations. Although the Southern North Sea Basin area is mature in terms of hydrocarbon exploration, it is shown that with existing and new geological insights, additional energy resources are still being proven in new plays such as the basal Upper Rotliegend (Ruby discovery) for natural gas and a new Chalk play for oil. It is predicted that hydrocarbon exploration in the Southern North Sea Basin area will probably experience a slight growth in the coming decade before slowing down, as the energy transition further matures. Geothermal exploration is expected to continue growing in the Netherlands onshore as well as gain more momentum in the UK.

We used new high-quality 2D and 3D seismic data covering the northern Dutch offshore to develop a structural framework for Paleozoic–recent times. Early Carboniferous extension was accommodated predominantly along WNW–ESE-trending faults, and was characterized by an alternation of highs and lows; in the northern Dutch offshore, the principal high coincides with the present-day Elbow Spit Platform. An Early Carboniferous low, the North Elbow Basin, is present north of this high in the A and B quadrants. Lower Carboniferous deposits have been preserved here and on the Elbow Spit Platform. Late Carboniferous–Early Rotliegend deformation is accommodated primarily along normal faults with a NE–SW trend. These faults commonly show no significant offset of Upper Rotliegend and younger units. Development of the Dutch Central Graben and Step Graben occurred during the Triassic–Early Cretaceous, primarily along north–south-trending faults, but reactivation of pre-existing faults as oblique-slip faults occurred as well. Associated with these north–south-trending faults was another, not previously described, family of WSW–ENE-trending dextral strike-slip faults which are proposed to represent transfer faults that accommodated strain partitioning.

Following the play-opening successes of the Breagh and Pegasus gas fields, we evaluated the potential of the Visean and Namurian (Carboniferous) petroleum plays in the northern Dutch offshore. This evaluation incorporated seismic and well data from the Dutch, British and German North Sea sectors. The abundance and thickness of reservoir-quality Visean–Namurian sandstones was found to increase from Breagh towards the NE. Visean–Namurian coals and shales are considered promising source rocks to charge these reservoirs in the Dutch Central Graben (DCG) and Step Graben (SG). The presence of a mature Paleozoic source rock in the SG and DCG is supported by hydrocarbon shows and vitrinite reflectance data. In the southern E and F blocks, charge may also occur laterally from Upper Carboniferous Westphalian coals. A regional post-well analysis showed that the Visean and Namurian plays are virtually untested in the Dutch northern offshore. Two tests were positive but had high N ₂ contents, one was negative, while 10 wells were drilled off-structure and are therefore considered invalid tests of this play. Hence, it is concluded that the Visean and Namurian in the northern Dutch offshore have significant hydrocarbon potential.