In the past 10 years the mature hydrocarbon province the West Netherlands Basin has hosted rapidly expanding geothermal development. Upper Jurassic to Lower Cretaceous strata from which gas and oil had been produced since the 1950s became targets for geothermal exploitation. The extensive publicly available subsurface data including seismic surveys, several cores and logs from hundreds of hydrocarbon wells, combined with understanding of the geology after decades of hydrocarbon exploitation, facilitated the offtake of geothermal exploitation. Whilst the first geothermal projects proved the suitability of the permeable Upper Jurassic to Lower Cretaceous sandstones for geothermal heat production, they also made clear that much detail of the aquifer geology is not yet fully understood. The aquifer architecture varies significantly across the basin because of the syn-tectonic sedimentation. The graben fault blocks that contain the geothermal targets experienced a different tectonic history compared to the horst and pop-up structures that host the hydrocarbon fields from which most subsurface data are derived. Accurate prediction of the continuity and thickness of aquifers is a prerequisite for efficient geothermal well deployment that aims at increasing heat recovery while avoiding the risk of early cold-water breakthrough. The potential recoverable heat and the current challenges to enhance further expansion of heat exploitation from this basin are evident. This paper presents an overview of the current understanding and uncertainties of the aquifer geology of the Upper Jurassic to Lower Cretaceous strata and discusses new sequence-stratigraphic updates of the regional sedimentary aquifer architecture.

The Netherlands has ample geothermal resources. During the last decade, development of these resources has picked up fast. In 2007 one geothermal system had been realised; to date (1 January 2019), 24 have been. Total geothermal heat production in 2018 was 3.7 PJ from 18 geothermal systems. The geothermal sources are located in the same reservoirs/aquifers in which the oil and gas accumulations are hosted: Cenozoic, Upper Jurassic – Lower Cretaceous, Triassic and Rotliegend reservoirs. Additionally, the yet unproven hydrocarbon play in the Lower Carboniferous (Dinantian) Limestones delivered geothermal heat in two geothermal systems. This is in contrast to the Upper Cretaceous and Upper Carboniferous with no producing geothermal systems but producing hydrocarbon fields. Similar to hydrocarbon development, developing the geothermal source relies on fluid flow through the reservoir. For geothermal application a transmissivity of 10 Dm is presently thought to be a minimum value for a standard doublet system. Regional mapping of the geothermal plays, with subsequent resource mapping, by TNO discloses the areas with favourable transmissivity within play areas for geothermal development. The website www.ThermoGis.nl provides the tool to evaluate the geothermal plays on a sub-regional scale. The Dutch geothermal source and resource portfolio can be classified using geothermal play classification of, for example, Moeck (2014). An appropriate adjective for play classification for the Dutch situation would be the predominant permeability type: matrix, karst, fracture or fault permeability. The Dutch geothermal play is a matrix-permeability dominated ‘Hot Sedimentary Aquifer’, ‘Hydrothermal’ or ‘Intra-cratonic Conductive’ play. The Dutch ‘Hot Sedimentary Aquifer’ play is subdivided according to the lithostratigraphical annotation of the reservoir. The main geothermal plays are the Delft Sandstone and Slochteren Sandstone plays.

The Danish onshore subsurface contains very large geothermal resources that have the potential to make a significant contribution to transforming Danish energy consumption toward a more sustainable energy mix. Presently, only a minor fraction of this green energy is exploited in three small plants. The main factors that have hampered and delayed larger-scale deployment are related to uncertainties in the geological models, which inevitably lead to high economic risks that are difficult for smaller district heating companies to mitigate without support from a compensation scheme. To facilitate and stimulate much wider use of the Danish geothermal resources, the Geological Survey of Denmark and Greenland (GEUS) and other research institutes have conducted several regional research projects focusing on the geological and geochemical obstacles with the principal objective of reducing the exploration risks by selecting the best geological reservoirs.

One of the most important geological factors causing uncertainty is the quality of the reservoirs and their ability to produce the expected volume of warm geothermal brine. Thus, great emphasis has been placed on investigating and understanding the relationships between reservoir sandstone, porosity, permeability, petrography, diagenetic processes and alterations related to variable sediment sources, basin entry points, depositional systems and climate, burial and thermal history. Mesozoic sandstones comprise the most important geothermal reservoirs in Denmark. Details concerning the reservoir quality are compiled and compared for the Lower Triassic Bunter Sandstone, Triassic Skagerrak, Upper Triassic – Lower Jurassic Gassum and Middle Jurassic Haldager Sand formations. The Bunter Sandstone Formation contains extensive aeolian and more confined fluvial sandstones with high porosity and permeability. However, highly saline formation water could be unfavourable. The Skagerrak Formation comprises well-sorted braided stream sandstones in the centre of the basin, and is otherwise characterised by muddy sandstones and alluvial fan conglomerates. An immature mineralogical composition has caused intensive diagenetic changes in the deepest buried parts of the basin. The Gassum Formation consists of shoreface, fluvial and estuarine sandstones interbedded with marine and lacustrine mudstones. In the upper part of the formation, the sandstone beds pinch out into mudstones towards the basin centre. Pervasive siderite- and calcite cement occurs locally in shallowly buried sandstones, and with burial depth the maximum abundances of quartz and ankerite cement increase. Sandstones of shallow burial represent excellent reservoirs. The relatively coarse grain size of the Haldager Sand Formation results in high porosity and permeability even at deep burial, so the formation comprises a high-quality geothermal reservoir.

Substantial progress has been made, and a well-established regional geological model combined with reservoir quality is now available for areas with cored wells. This has enabled an improved estimation of reservoir quality between wells for exploration of geothermal reservoirs.

Over the past decade in the Netherlands, most operators have only developed a single doublet. The learning effect from these single events is suboptimal, and operators have only been capable of developing doublets in areas with relatively low exploration risk. This ‘stand-alone’ approach can be significantly improved by a collective approach to derisk regions with similar subsurface characteristics. Such a play-based portfolio approach, which is common in the oil and gas industry, can help to accelerate the development of the geothermal industry through unlocking resource potential in areas marked by high upfront geological risk, effectively helping reduce costs for the development. The basis of the methodology is to deploy new information to the play portfolio by trading off with the risk of the first wells, resulting in a strong geological risk reduction.

The added value of the portfolio approach is demonstrated for the Netherlands in this paper through a comparison with a ‘stand-alone’ development. In the stand-alone approach, each new project will be equally risky, and therefore relatively unprofitable. In the case of a portfolio approach, all experience about the play is used optimally for derisking. In case of success, subsequent projects will have a higher chance of being successful, due to the experience gained in previous projects. Even if a project fails, this may help in increasing the probability of success for subsequent projects. For plays that are initially considered too risky for the market to start developing, the value of information (VoI) of a play-based portfolio approach will help by derisking the play to such an extent that it becomes attractive for the market to develop, even at high initial risk. It can be demonstrated for several geothermal plays in the Netherlands that by adopting the portfolio approach, the probability of a play being developed becomes higher, the number of successfully developed projects increases and the average profitability of the project will also be higher. Five more advantages are: (1) continuous improvement by integrated project development, (2) cost reduction through synergy, efficiency and standardisation, (3) optimisation of the surface heat demand and infrastructure, (4) the possibility of structural research and development (R&D) and innovation, and (5) financing advantages. The advantages reinforce each other.

A preliminary estimate of the geothermal potential of the Netherlands adopting the portfolio approach is between 90 and 275 Petajoules (PJ). For about 350 doublets being developed, producing about 70 PJ, the value of the advantage of the play-based portfolio approach is €2 billion for the three main plays: Rotliegend, Triassic and Jurassic/Cretaceous. The learning effects of synergy, efficiency and standardisation are expected to be significant.

The main objective of this paper is to give an overview of the risks seen in the exploration and production of geothermal energy from the viewpoint of the regulator. The risks are categorised as conventional risks, ultra-deep risks and enhancing factors. These risks are similar to those seen in the oil and gas industry, but the maturity of the geothermal sector in terms of managing such risks is much lower.

Another objective of this paper is to discuss how these risks are managed and mitigated by the sector and the supervisor, State Supervision of Mines (SodM). Portfolio operators developing multiple projects, using skilled employees and embracing continuous improvement are seen as the way forward for the sector to grow safely and sustainably.

This paper concludes that positive developments have started, but a lot of work still needs to be done to ensure safe growth of the geothermal energy sector.

This article attempts to identify the main ‘above-ground’ factors which impact on the contribution that geothermal energy can make to the Dutch Energy Transition, and to draw conclusions about these factors. Recent literature sources are used to illustrate the size of Dutch heating demand, and the part of this which can be provided by geothermal energy. Consideration is given to the impact of off-take variability over time, showing that the base-load nature of geothermal doublets acts as a restraint on the share which they can take in the energy supply. The characteristics of district heating grids are discussed. Other potential sources of heat are considered and compared.

The conclusion is that geothermal energy can provide a material contribution to the energy transition. This depends to a large extent on the existence of and design choices made for the development of district heating networks. Large size and standardisation, and the development of seasonal heat storage, are beneficial.

Unlike most other renewable sources of heat, which have alternative ‘premium’ applications such as the provision of ‘peak capacity’ or molecules for feedstock, geothermal energy is not suitable for other uses. The emission savings that it can provide will be lost if other heat sources are chosen in preference as supply for district heating, so that it makes sense that district heating infrastructure should be designed to encourage the use of geothermal energy where possible.

Recently drilled geothermal boreholes in Mol, northern Belgium, provide new information on the Lower Carboniferous carbonates in the Campine–Brabant Basin. Because of low primary porosity, fractures in these limestones and dolostones are of major importance for reservoir permeability. The Fullbore Formation MicroImager (FMI) log of the MOL-GT-01 borehole enabled interpretation of bed boundaries and fractures in the subsurface. Relationships between the frequency of these fractures and bed thickness, lithology variations and the presence of faults were explored. The results show that thick beds contain relatively few fractures and thin beds relatively many. Except for lower values in shaly intervals, the fracture frequency (number per metre) is largely independent of lithology. Zones with substantial changes in the structural dip (called a cusp) and/or azimuth of bed boundaries were identified. The clearest cusp is present at a depth of 3284 m. Since the presence of a normal fault is most likely regarding the local and regional geology, this cusp likely resembles a fault-tip fold of a WSW-ward dipping normal fault with an inclination of at least 54°. It is uncertain whether the borehole crossed the fault itself or only a monocline on top of it. Fracture frequency is increased in the vicinity of the interpreted possible faults. Up to a vertical distance of c.45 m from the faults, the mean fracture frequency is higher than in a non-faulted zone with similar lithology. However, frequency differences between these faulted and non-faulted zones are mostly insignificant, so no clear damage zones are present.

The Pannonian basin in Central Europe is well known for its rich geothermal resources. Although geothermal energy has been utilised, mainly for direct use purposes, for a long time, there are still a lot of untapped resources. This paper presents novel methods for outlining and assessing the theoretical and technical potential of partly still unknown geothermal reservoirs, based on a case study from the Dráva basin, one of the sub-basins of the Pannonian basin along the Hungarian–Croatian border. The presented methods include reservoir delineation based on combining geological bounding surfaces of the Upper Pannonian basin-fill units with a set of isotherms deriving from a conductive geothermal model. The geothermal potential of each identified reservoir was calculated by a Monte Carlo method, which was considered as being represented by the heat content of the fluids stored in the effective pore space (‘moveable fluid’). The results underline the great untapped geothermal potential of the Dráva basin, especially that of the reservoir storing thermal water of 50–75°C, which has the largest volume and the greatest stored heat content.

Hydraulic fracturing is a long-established method of stimulating a well to improve the inflow or outflow potential. Hydraulic fracturing is the most successful stimulation method used by the oil and gas industry, and is also used for water injection and production wells around the world, even for drinking-water wells. Hydraulic fracturing creates a crack in the earth that is then filled with a highly conductive material (proppant). This fracture has a large inflow area compared to an unstimulated wellbore and provides a high-permeability path for the fluid to flow in or out of the reservoir.

Hydraulic fracturing has a long history of being used in hot dry rock (HDR) geothermal applications since the 1980s (Murphy & Fehler, 1986). In those often very tight reservoirs, the aim is to create fracture networks that generate the reservoir flow capacity. In high-permeability formations, fracturing can potentially double the productivity of a well. In low-permeability formations, well performance can be increased by a factor of 5–10 in most cases.

In this paper, we focus on two different scenarios of geothermal stimulation. The first is for permeable, porous formations where the heat exchange happens through the perfect contact between the fluid and the porous reservoir. Stimulation may then be necessary to create a small fracture if the pressure drop near the well is too large due to insufficient reservoir permeability. The other scenario is a formation at great depth, where the formation permeability is so extremely small that very long propped fractures would be needed to obtain sufficient flow or even where the porous system does not provide sufficient heat exchange but the heat exchange has to be facilitated by an artificial or stimulated fracture network: a so-called Enhanced Geothermal System.

For porous, permeable formations we will present examples of fracture treatments that can increase the flow rate so that the economics of the project is improved. In some formations, stimulation is then a contingency in case of poorer than expected reservoir quality. A worst-case well with a large skin value of 20 can perform with stimulation like a base-case unstimulated well. In other formations, stimulation will be integral to well design in order to optimise the project performance. For those cases the Coefficient of Performance can be improved from 7 to 25 with the aid of stimulation.

In Ultra-Deep Geothermal (UDG) recovery, the targets are reservoirs below 4000 m, because industrial heat demand requires a minimum temperature of 120°C up to 250°C. For an economic business case, the rate over a period of 15 to 25 years should be from 150 to 450 m3 h−1, depending on the boundary conditions.

Shallower reservoirs in the Netherlands often show very high permeability, but at great depth the target layers could have very low permeability (Veldkamp et al., 2018). Several stimulation methods can be used, of which hydraulic fracture stimulation with water (proppantless) is the primary candidate. Other stimulation methods are propped fracturing in sandstone, acid fracturing in carbonates and thermal stimulation.

For a geological play that is attractive for UDG in the Netherlands, the most likely stimulation method is with water fracturing, because propped fracturing would require a huge amount of proppant that is very costly. Based on analogues and conceptual designs, the expected flow rate is estimated under selected boundary conditions.

The decline of domestic natural gas production, increasing dependency on gas imports and lagging development of renewable energy production may pose serious challenges to the current high standards of secure energy supply in the Netherlands. This paper examines synergy between hydrocarbon- and geothermal exploitation as a means to reinforce energy security. The Roden gas field is used as an example to demonstrate potential delay of water breakthrough in the gas well and a resulting increase of recovered gas (up to 19%), by positioning of a geothermal doublet in the water leg of the gas field. The reservoir simulations show that the total increase of gas production primarily depends on the amount of aquifer support. An optimal configuration of gas- and geothermal wells is key to maximise gas recovery and strongly depends on the distribution of reservoir properties. The study also reveals that this option can still be beneficial for gas fields in a late stage of production.

Net Present Value calculations show that the added value from the geothermal doublet on total gas production could lead to an early repayment of initial investments in the geothermal project, thereby reducing the overall financial risk. If no subsidies are taken into account, the additional profits can also be used to finance the geothermal project up to break-even level within 15 years. However, this comes with a cost as the additional profits from improved gas recovery are significantly reduced.

Geothermal energy is a viable alternative to gas for the heating of buildings, industrial areas and greenhouses, and can thus play an important role in making the transition to sustainable energy in the Netherlands. Heat is currently produced from the Dutch subsurface through circulation of water between two wells in deep (1.5–3 km) geothermal formations with temperature of up to ∼100 °C. As the number of these so-called doublets is expected to increase significantly over the next decades, and targeted depths and temperatures increase, it is important to assess potential show-stoppers related to geothermal operations. One of these potential hazards is the possibility of the occurrence of felt seismic events, which could potentially damage infrastructure and housing, and affect public support. Such events have been observed in several geothermal systems in other countries. Here we review the occurrence (or the lack) of felt seismic events in geothermal systems worldwide and identify key factors influencing the occurrence and magnitude of these events. Based on this review, we project the findings for seismicity in geothermal systems to typical geothermal formations and future geothermal developments in the Netherlands. The case study review shows that doublets that circulate fluids through relatively shallow, porous, sedimentary aquifers far from the crystalline basement are unlikely to generate felt seismic events. On the other hand, stimulations or circulations in or near competent, fractured, basement rocks and production and reinjection operations in high-temperature geothermal fields are more prone to induce felt events, occasionally with magnitudes of M > 5.0. Many of these operations are situated in tectonically active areas, and stress and temperature changes may be large. The presence of large, optimally oriented and critically stressed faults increases the potential for induced seismicity. The insights from the case study review suggest that the potential for the occurrence of M > 2.0 seismicity for geothermal operations in several of the sandstone target formations in the Netherlands is low, especially if faults can be avoided. The potential for induced seismicity may be moderate for operations in faulted carbonate rocks. Induced seismicity always remains a complex and site-specific process with large unknowns, and can never be excluded entirely. However, assessing the potential for inducing felt seismic events can be improved by considering the relevant (site-specific) geological and operational key factors discussed in this article.

The majority of running geothermal plants worldwide are located in geological settings with convection- or advection-dominant heat transport. In Germany as in most regions in Europe, conduction is the dominating heat transport mechanism, with a resulting average geothermal gradient. The geothermal play type concept is a modern methodology to group geothermal resources according to their geological setting, and characteristic heat transport mechanisms. In particular, the quantity of heat transport is related to fluid flow in natural or engineered geothermal reservoirs. Hence, the permeability structure is a key element for geothermal play typing. Following the existing geothermal play type catalogue, four major geothermal play types can be identified for Germany: intracratonic basins, foreland basins and basement/crystalline rock provinces as conduction-dominated play types, and extensional terrains as the convection-dominated play type. The installed capacity of geothermal facilities sums up to 397.1 MWth by the end of 2018. District heating plants accounted for the largest portion, with about 337.0 MWth. The majority of these installations are located in the play type ‘foreland basin’, namely the Molasse Basin in southern Germany. The stratigraphic unit for geothermal use is the Upper Jurassic, also known as ‘Malm’ formation, a carbonate reservoir with high variability in porosity and permeability. Recently drilled wells in the southernmost Molasse Basin indicate the Upper Jurassic as a tight, fracture-controlled reservoir, not usable for conventional hydrothermal well doublets. Our new data compilation including the recently drilled deep geothermal well Geretsried reveals the relation of porosity and permeability to depth. The results suggest that obviously diagenetic processes control permeability with depth in carbonate rock, diminishing the predictability of reservoir porosity and permeability. The play type concept helps to delineate these property variations in play type levels because it is based on geological constraints, common for exploration geology. Following the general idea of play typing, the results from this play analysis can be transferred to geological analogues as carbonate rock play levels in varying depth.