Following a time of expansion of the oil industry, the period 1987-2012 and especially the second half of it reflects a diversification of exploration activities in the Netherlands. In addition to the ongoing discovery of classical hydrocarbon reservoirs, successful attempts have been made to explore deep geothermal energy. Shale gas and Coal Bed Methane received interest in the Netherlands too but so far no wells have been drilled in order to test the potential. Storage of gas and liquids has been introduced and salt mining more or less continued without many changes. In terms of drilling activity, the last 25 years show a decreasing trend and the discovered volumes are smaller. Testing of new play concepts was either successful (shallow gas) or not (Dinantian) and sometimes an unexpected discovery was made (Triassic Fat Sands). New techniques proved older fields to be exploitable again, e.g. redevelopment of the Schoonebeek Field. Therefore, despite a decline in number of wells drilled and reserves added, the diversification of use of the subsurface will guarantee ongoing exploration.

A five years geological mapping project, in which the Netherlands Continental Shelf has been re-examined using all publicly available data, resulted in an important update of the existing dataset. The stratigraphy of over 400 wells has been re-interpreted. New depth and thickness grids, based mainly on the interpretation of 3D seismic data have been produced for the most important stratigraphic intervals from Permian Upper Rotliegend to Neogene. New reservoir grids describe the top, base and thickness of 30 (potential) reservoir units in the area. In addition, the uncertainty related to interpretation and further processing of the data has been assessed. This resulted in maps displaying the standard deviation for the depth of the main stratigraphic intervals. Based on these results and the data already available for the onshore area, an updated structural element map was made for the Netherlands.

The Zechstein salt in the Dutch part of the North Sea Basin played a key role in the generation of successful petroleum plays. This is not only because of its sealing capacity, but also because the salt occurs in structures that provide lateral and vertical traps. The structural styles of areas with thick salt and those with none- or thin salt are completely different during phases of extensional or compressional tectonics. This indicates that, indirectly, the depositional thickness of the main Zechstein salt is essential in regulating the loci of the Dutch petroleum systems. In this paper we aim at quantifying current ideas on the relationship between 1) depositional salt thicknesses; 2) structural style of the main structural elements identified in the Dutch subsurface; 3) timing of deformation; and 4) thickness of the overburden. By finalisation of TNO's subsurface mapping program (see Kombrink et al., this issue), several data products are available that allow evaluation of these relationships. The depositional thickness of the salt was estimated using iterative smoothing of the present day thickness, the results of which account both for regional thickness variations and volume preservation (99%). Fault-distribution analysis shows that faults are only able to penetrate salt with a depositional thickness of <300 m, a transition that demarcates the division between thin- and thick-skinned salt tectonics. In the southern offshore where the salt is thin or absent, the overburden shows the same fault pattern throughout the stratigraphic sequence. In the northern realm, where salt is thicker than 300 m, the salt layer acted as decollement and sub- and supra salt strain are dissimilar. A strong genetic and temporal relationship exists between periods of regional tectonism, halokinetic intensity and thickness distribution of the Zechstein overburden. This relationship is further proven by burial history analysis across two selected profiles in the northern offshore. The analysis focuses on the vertical distribution of the salt by taking into account the depositional and erosional history of the salt overburden, without a-priori defined periods of salt flow. The results corroborate the notion that platforms and highs experienced less extension during the major phases of Jurassic rifting and further suggest that the absence of a thick Jurassic overburden precludes major salt flow during this tectonic phase. Main salt flow was triggered during the Sub-Hercynian and later phases of compression resulting in salt pillow geometries. In the basinal areas, where the Jurassic succession is thickest, salt diapirs and walls formed that are almost exclusively linked to major subsalt faults. Main salt flow occurred during Late Kimmerian rifting, whereas some minor structuration occurred during Sub-Hercynian inversion.

This paper presents and discusses the distribution of fluid and leak-off pressure data from the subsurface of onshore and offshore Netherlands in relation to causes of formation fluid overpressure and the permeability framework. The observed fluid pressure conditions demonstrate a clear regional difference between the southern and the north and north-eastern part of the study area. In the southern area, formation fluid pressures are close to normal and well below measured leak-off pressures. In the north, formation fluids are overpressured and may locally even approach the measured leak-off pressures. The regional differences in fluid overpressure can, in large part, be explained by differences in geologic framework and burial history. In the south, relatively low rates of sedimentary loading and the presence of relatively permeable sedimentary units have led to the currently observed normally pressured conditions. In the northern area, relatively rapid Neogene sediment loading plays an important role in explaining the observed overpressure distributions in Cenozoic mudstones, Cretaceous Chalk and Rijnland groups, and probably also in Jurassic units. The permeability framework of the northern and north-eastern area is significantly affected by Zechstein and Triassic salt deposits and structures. These units are characterised by very low permeability and severely restrict fluid flow and pressure dissipation. This has created hydraulically restricted compartments with high overpressures (for example overpressures exceeding 30 MPa in the Lower Germanic Trias Group in the Terschelling Basin and Dutch Central Graben).

Subsurface temperature is a key parameter for geothermal energy prospection in sedimentary basins. Here, we present the results of a 3D temperature modelling using a thermal-tectonic forward modelling method, calibrated with subsurface temperature measurements in the Netherlands. The first step involves the generation of a coherent dataset of temperature values for the calibration of the model. In the Netherlands, most of the available measurements (98.8%) are BHT measurements and therefore need to be corrected from the thermal perturbation created during drilling. The remaining 1.2% is composed of DST measurements, which closely resemble the formation temperature (i.e., ±5 °C). The resulting dataset, after correction, gives a total number of 1293 values in 454 wells. Included in this dataset are 412 highly reliable values corrected with the Instantaneous Cylinder Source (ICS) method and 829 values of a lower reliability corrected with the AAPG method. In addition to the corrected values, 52 DST values in 26 wells are available from the Dutch subsurface. The average thermal gradient of this whole dataset is 31.3 °C/km with a surface temperature of 10.1 °C. The second step in the modelling process was the generation of a 3D forward model that focuses on calculating the temperature distribution of the sedimentary basin fill, taking into account the basin evolution of the past 20 Myrs and thermal properties and processes of the whole lithosphere. From the 3D thermal model, we extracted 2D cross sections across well locations to compare model temperatures with calibration data. Furthermore, we present vertical profiles, isodepth maps and temperature projection on geological layers, to discuss the relationship between temperature and geology. Anomalies in this relationship can have several causes and include: 1) the extreme thermal conductivity and complex geometry of the Zechstein salt; 2) enhanced radiogenic heat production of the upper crust due to magmatic intrusions. In addition, our model supports earlier findings that shallow hydrothermal convection in highly permeable sediments can effectively lower thermal conductivity and temperatures in shallow sediments.

In this paper we study the effects of timing of salt movement and mechanical compaction on the generation of overpressures in Mesozoic rocks. To that end we apply 2D basin modelling on two N-S trending cross sections in the Dutch Central Graben and Terschelling Basin, respectively. Several overpressuring scenarios were calculated by modifying the mechanical compaction of the sealing layer, the rate of sedimentation, and the timing of salt movement. Pressure and porosity measurements from several wells along the cross sections were used as calibration data. The results show that rapid sedimentation and early compaction of Pliocene to Quaternary mudstones explain most of the overpressures in the Cretaceous and Jurassic rocks. The modifications of the mechanical compaction of the Upper Cretaceous Chalk Group performed in this study could not explain the overpressure anomalies in the southern part of the Dutch Central Graben. Processes such as chemical compaction are probably more important in this respect. Overpressures in the Triassic are mainly controlled by the timing of salt movement and the closure of lateral seals. This study has lead to a better understanding of the processes that generate overpressures and those that are involved in their lateral distribution. The integration of modelling scenarios and information on the timing of seal formation enables to define new play concepts and is important for the assessment of possible drilling hazards as well.

3D basin modelling is used to investigate the history of maturation and hydrocarbon generation on the main platforms in the northwestern part of the offshore area of the Netherlands. The study area covers the Cleaverbank and Elbow Spit Platforms. Recently compiled maps and data are used to build the input geological model. An updated and refined palaeo water depth curve and newly refined sediment water interface temperatures (SWIT) are used in the simulation. Basal heat flow is calculated using tectonic models. Two main source rock intervals are defined in the model, Westphalian coal seams and pre-Westphalian shales, which include Namurian and Dinantian successions. The modelling shows that the pre-Westphalian source rocks entered the hydrocarbon generation window in the Late Carboniferous. In the southern and central parts of the study area, the Namurian started producing gas in the Permian. In the north, the Dinantian source rocks appear to be immature. Lower Westphalian sediments started generating gas during the Upper Triassic. Gas generation from Westphalian coal seams increased during the Paleogene and continues in present-day. This late generation of gas from Westphalian coal seams is a likely source for gas accumulations in the area.

Westphalian coals might have produced early nitrogen prior to or during the main gas generation occurrence in the Paleogene. Namurian shales may be a source of late nitrogen after reaching maximum gas generating phase in the Triassic. Temperatures reached during the Mid Jurassic were sufficiently high to allow the release of non-organic nitrogen from Namurian shales.

Exploration in a mature basin requires a detailed classification and standardisation of rock stratigraphy to adequately comprehend the depositional history and prospect architecture. The pre-Quaternary Stratigraphic Nomenclature of the Netherlands compiled by Van Adrichem Boogaert & Kouwe in 1993 provided a consistent framework for use by the Dutch geological community. Over the past twenty years, new biostratigraphic techniques and continued exploration in the Netherlands have provided additional stratigraphic information. Based on this information the Late Jurassic lithostratigraphy in particular, shows significant inaccuracies. The Callovian-Ryazanian strata from the northern offshore of the Netherlands' territorial waters, termed the Central Graben Subgroup and Scruff Group, reveal a complex sedimentary history. The combination of non-marine to shallow marine lateral facies changes, repetitive log and facies characteristics in time, sea-level and climate change, salt tectonics and structural compartmentalisation hamper straightforward seismic interpretation and log correlation. Recognition of three genetic sequences by Abbink et al. in 2006 enabled an improved reconstruction of the geological history. Further improvements in refinement and reliability of the stratigraphy together with new information on the facies and ages of the successions and about the subsequent tectonostratigraphic development of the northern Dutch offshore area form the basis of the present revision. As a result, earlier lithostratigraphic models have been changed and new lithostratigraphic relationships and names are introduced in this paper.

In this study, seismic stratigraphic criteria have been used to characterise the evolution of the Southern North Sea (SNS) shelf-delta system that progressively filled the Southern North Sea basin during Plio-Pleistocene times. Based on the prograding and down-stepping architecture of the shelf-delta sequence it is inferred that deposition occurred during a time of high sediment supply and overall sea-level lowering. During this time the delta slopes failed several times, creating at least 30 internally coherent Mass Transport Deposits (MTDs) mainly grouped in common areas, affecting the same clinoform set and partially sharing the basal shear surface (groups of MTDs). The most important features of the studied MTDs are 1) the dominance of brittle deformation; 2) the small amount of material removal from the headwall domain (lack of completely depleted areas above the basal shear surface); and 3) the lack of an emergent toe domain above the un-failed sediment located basinward, although proper confining geometries for the MTD are not detected. Therefore, the studied MTDs can neither be classified as frontally confined nor as frontally emergent but they are a new intermediate type of submarine landslides which has not been described before. These characteristics suggest that the mass movement ceased relatively soon after initiation of failure. Incisions on top of the MTDs suggest the presence of erosive flows. These flows were probably generated due to a concentration of the drainage in the negative morphology the failure event left behind in the upper sector of the slope. The stronger progradational character of the reflections on top of MTDs confirms a concentration of drainage after the erosional phase too.

The interplay between high sediment supply and constant or even decreasing accommodation space (caused by constant or decreasing sea-level) is supposed to be the main precondition for slope instability for most of the MTDs in this study area. Slope failures themselves can also be considered a preconditioning factor by the creation of local very high sedimentation rates (see groups of MTDs). Salt-induced seismicity and storm waves' effect superimposed on high frequency sea level fall are considered the most important triggering factors.

In 1992, the well L9-7, drilled by the Nederlandse Aardolie Maatschappij (NAM) unexpectedly found a thick previously unknown sandstone interval with excellent reservoir characteristics in the Middle Buntsandstein (Triassic) of the Dutch Northern Offshore: the ‘Fat Sand’. A follow-up well, L9-8, found this reservoir gas-bearing in an accumulation that turned out have recoverable reserves of circa 1 Tcf of gas distributed over several fault compartments. This serendipitous discovery led to a frantic period in NAM's office trying to understand the setting of this local sand development and, most importantly, assess follow-up potential; could this sand be present elsewhere in a trapping configuration? The local depocentre in which the Fat Sand accumulated is considered to be caused by local extension along a strongly listric fault soling out on the top of the Zechstein Salt. This supra-salt fault seems to be caused by early east-west extension in the Dutch northern offshore. The shape of the fault plane was strongly influenced by the presence of the nearby Zechstein Salt, and by early salt flow, which was also triggered by E-W extension.

Geothermal low enthalpy heat in non-magmatic areas can be produced by pumping hot water from aquifers at large depth (>1 km). Key parameters for aquifer performance are temperature, depth, thickness and permeability. Geothermal exploration in the Netherlands can benefit considerably from the wealth of oil and gas data; in many cases hydrocarbon reservoirs form the lateral equivalent of geothermal aquifers. In the past decades subsurface oil and gas data have been used to develop 3D models of the subsurface structure. These models have been used as a starting point for the mapping of geothermal reservoir geometries and its properties. A workflow was developed to map aquifer properties on a regional scale. Transmissivity maps and underlying uncertainty have been obtained for 20 geothermal aquifers. Of particular importance is to take into account corrections for maximum burial depth and the assessment of uncertainties. The mapping of transmissivity and temperature shows favorable aquifer conditions in the northern part of the Netherlands (Rotliegend aquifers), while in the western and southern parts of the Netherlands aquifers of the Triassic and Upper Cretaceous / Jurassic have high prospectivity. Despite the high transmissivity of the Cenozoic aquifers, the limited depth and temperature reduce the prospective geothermal area significantly.

The results show a considerable remaining uncertainty of transmissivity values, due to lack of data and heterogeneous spatial data distribution. In part these uncertainties may be significantly reduced by adding well test results and facies parameters for the map interpolation in future work. For underexplored areas this bears a significant risk, but it can also result in much higher flowrates than originally expected, representing an upside in project performance.

A resource assessment methodology has been developed to designate prospective high permeable clastic aquifers and to assess the amount of potential geothermal energy in the Netherlands. It builds from the wealth of deep subsurface data from oil and gas exploration and production which is publicly and digitally available. In the resource assessment various performance indicator maps have been produced for direct heat applications (greenhouse and spatial heating). These maps are based on detailed mapping of depth, thickness, porosity, permeability, temperature and transmissivity (methodology presented in other papers in this NJG issue). In the resource assessment analysis 14 lithostratigraphic units (clastic aquifers) have been considered, ranging in age from the Permian to the Cenozoic. Performance maps have been made which include a) the expected doublet power (MWth) to be retrieved; b) the number of houses or hectares that can be heated from one doublet; and c) a potential indicator map, which provides insight in subsurface suitability for specific applications from a techno-economic perspective. To obtain a nationwide overview of the resource potential in terms of recoverable geothermal energy, a progressive filtering approach was used from total heat content of the reservoirs (Heat In Place – HIP) via the heat that can potentially be recovered (Potential Recovery Heat – PRH) to energy maps taking into account a techno-economic performance evaluation (Recoverable Heat – RH). Results show that the HIP is approximately 820,000 PJ which is significantly more than previous estimates of around 90,000 PJ. This considerable increase in geothermal energy potential is the result of accurate geological mapping of key reservoir properties and the development of state-of-the-art techno-economic performance assessment tools that performs Monte Carlo simulation. Moreover, for the previous estimates boundary conditions were set with the aim to compare the geothermal potential between different EU countries (Rijkers & Van Doorn, 1997). Taking into account techno-economic aspects, the RH is in the order of 85,000 PJ. This is equivalent to ~70% of the ultimate recoverable gas of the Slochteren Gas field. In total over 400 maps have been created or used as input for the resource assessment. Together, they provide comprehensive information for geothermal energy development from various stakeholder perspectives. The maps can be interactively assessed in the web-based portal ThermoGIS (www.thermogis.nl). This application complements existing subsurface information systems available in the Netherlands and supports the geothermal community in assessing the feasibility of a geothermal system on a regional scale.

In this paper we present a probabilistic fast model for performance assessment of geothermal doublets for direct heat applications. It is a simple yet versatile and multipurpose tool. It can be well applied in better understanding the sensitivity of performance to key subsurface parameters and depth trends therein, and for assessing the probability of success for geothermal projects under technical and financial constraints.

The underlying algorithms deliver a sensible accuracy given the uncertainties associated with geothermal projects at exploration state. A public release of the software, available under the name of DoubletCalc, is easy to handle and requires a limited set of input parameters. Thanks to an open source code, DoubletCalc can be implemented in other software applications and extended as it has been implemented for the integration into the national geothermal information system in the Netherlands (ThermoGIS, 2011).

Apart from its application for site assessments, the tool can be integrated into automated workflows processing faster representations of key aquifer properties and capable to produce indicative maps for predicted doublet power, economic feasibility and prediction of cumulative amount of heat that can be recovered. These capabilities are specifically important for decision support for policymakers while assessing the effects of particular insurance schemes and funding mechanisms.

DoubletCalc cannot and is not intended to substitute geologic exploration approaches. As exploration measures, such as seismic surveys are cost intensive, DoubletCalc can be used to focus geothermal exploration on areas and sites where an enhanced probability of success can be expected.