Conference Agenda

The transition towards a zero carbon footprint energy system will greatly impact the energy mix we will use. Globally, a significant increase is expected in the contribution of electrical power (supplied by renewable sources such as solar and wind), bioenergy, nuclear energy and other sources such as hydro power and geothermal energy. However it is expected that the energy mix still contains a significant component of fossil fuels to enable processes for which the use of renewable energies is not yet technically or economically viable. In order to achieve the desired net zero emission balance, the emissions associate with these fossil fuels and part of the bioenergy will need to be offset by CO2 Capture and Storage.

How will this change in the energy mix impact the role and prospects for geoscientists and petroleum engineers?

The work of petroleum geoscientists and engineers in the energy industry today can be split in three key areas: producing energy (eg oil and gas), storing and buffering of energy to guarantee security of supply (eg underground gas storages) and storing of by-products (eg produced water).

Going forward it is expected that those key focus areas will remain. The nature and portfolio of applications that require our subsurface capabilities and expertise however will likely be expanded.

On the production side we expect a much stronger focus on finding and developing hydrocarbons that are competitive in terms of economics as well as CO₂ intensity (incl CO2 assisted EOR) and the addition of other energy production activities such as geothermal energy.

In order to maintain security of supply, (seasonal) energy buffering and storage will likely remain essential. The underground gas storages may be augmented with or replaced by for instance Compressed Air Storage (Salt Caverns), Hydrogen Storage (Salt Caverns, depleted gas fields) or Aquifer Thermal Energy Storage.

On the storage of by-products side, we expect Carbon Capture and Storage (CCS) to become a key activity.

All of the above developments will continue to require our subsurface skills and capabilities: to identify and characterise suitable subsurface reservoirs and resources, make and realise development plans, operate safely and optimise through well, reservoir and field management. This will be illustrated using examples form the Dutch Upstream energy landscape.

Anhydrites Carbonates of the Leine formation, the third evaporitic cycle of the Zechstein group, are widely distributed in the Southern Permian basin. These strata are often drilled through by wells targeting underlying Rotliegend gas prospects. The ZEZ3C/A members constitute brittle rocks sandwiched by the ductile halites from the underlying ZEZ2H and the overlying ZEZ3H. The brittle sheet is frequently rifted (boudinage) and the resulting fragments are often referred to as stringers. In many areas ZEZ3 stringers (consisting of Haupt Anhydrite/ Platten Dolomite), show a fairly constant thickness of around 50 meters. Deviations from these general observations, in particular anomalously thick stringers, were known from wells but their origin was unclear. This poor understanding was also related to limitations in seismic quality, which generally did not allow detailed stringer mapping. With the arrival of new 3D seismic from the dutch offshore G/H blocks (adjacent to the German sector), the stringer interval could be studied in great detail. Seismic-to-well ties in this area, show that thickened zones consist of a locally thickened Zechstein III anhydrite member. Isopach mapping of the stringers resulted in new insights of the thickened zones distribution which tend to have a characteristic appearance consisting of linear, branching and closing segments. Based on these observations the gypsum dome structure model is proposed in this research, which is largely based on comparable observations described from the Harz mountains. In this model recently deposited water-rich gypsum behaves ductile and creates doming features comparable to halite salt domes, albeit on a smaller scale. Subsequent dewatering of gypsum bodies after some burial, causes the transition to anhydrite which has a higher specific density and is more brittle. Also, the associated volumetric shrinkage creates new accommodation space which effect can be observed in the overlying strata. In addition, the dewatering process might create fluid pathways to the surface and result in the leak-off of over pressures in these zones. Planning and drilling new well trajectories might benefit from the improved understanding of stringer thickness variability based on this research.

The transnational EU-Interreg-funded “Roll-out of Deep Geothermal Energy in North-West Europe” (DGE-ROLLOUT) project aims to reduce CO₂ emissions following a multi-disciplinary geoscientific approach, and promotes the use of hydrothermal energy as a future-oriented, climate and environmentally friendly resource.

During mid-Palaeozoic times, marine transgressive-regressive cycles enabled the development of extensive reef complexes on the southerly continental shelf of the Laurussian palaeocontinent, whose remainders now make up large parts of the Rhenohercynian Basin. Amongst others, the up to several hundred meters thick Dinantian Kohlenkalk Group was formed.

In the course of the Variscan Orogeny, this Palaeozoic carbonate horizon was covered by voluminous paralic sedimentary rocks and deformed to large-scale, generally northeast-southwest-trending, syncline-anticline structures within the Rhenohercynian Zone. Alpine (post-)orogenic processes further induced faulting, resulting in fault-block tectonics in the Lower Rhine Embayment area of tectonic subsidence.

Nowadays, the Dinantian Kohlenkalk Group, which occurs in large parts of the northwest European subsurface, may represent a potentially favourable deep geothermal reservoir, also considering significant multiphase karstification and dolomitisation which can be observed in samples obtained from exploration boreholes and in nearby exposed counterparts.

Therefore, one major aim of the DGE-ROLLOUT project revolves around the hydrothermal characterization of the Kohlenkalk Group. Using lithostratigraphic and structural data obtained from drilling operations, geological mapping, and the interpretation of seismic profiles, it is aimed to provide a comprehensive 3D-subsurface model of the carbonate reservoir within the transnational area comprising Belgium, France, Germany and the Netherlands. 3D-modelling is carried out using the commercial software MOVE [v2019.1.0; Petroleum Experts Ltd].

Geothermal power plants require reservoirs of high temperature, high flow rates and sustainable recharge. Typically, there is a trade-off between increasing temperatures and decreasing fluid availability (due to pore space limitations) with depth. Predictions of the working conditions in reservoir formations at greater depth are challenging due to uncertainties in the underlying geology and because of the complex interaction of heat and fluid transport processes. We use new 3D geological models of Hesse (Germany) for a series of thermo-hydraulic simulations (BMWi-funded project “Hessen 3D 2.0”, FKZ: 0325944A+B). By quantifying the respective influences of conductive, advective and convective heat transport, we are able to subdivide the subsurface of Hesse into model domains of characteristic thermo-hydraulic regimes, and to obtain insights into reservoir temperatures and the hydraulic characteristics that control exploitable thermal energy resources. We further discuss these models in terms of their implications for the assessment of geothermal potentials represented by the application case of simplified hydrothermal doublets. The area of the northernmost part of the Upper Rhine Graben is identified as the most promising in terms of available geothermal energy. Convective heat transport within a sequence of thick and permeable graben filling sediments, favoured by low hydraulic gradients and a high heat input from the basement, result in a predicted geothermal potential between 1.7 and 2.5 MW per doublet. These results can assist to delineate where further exploration and future development for renewable heat supply should be encouraged.

Multiphase mass and heat transfer are ubiquitous in the subsurface within manifold applications. The presence of fractures magnifies the uncertainty of the heat transfer process, which will significantly impact the dynamic transport process. However, accurate modeling methodologies for thermal high-enthalpy multiphase flow within fractured reservoirs are quite limited. In this work, the geothermal multiphase flow in the high-resolution fractured reservoir is numerically investigated. The discrete-fracture model is utilized to describe the fractured system with discretization of optimized resolution. A synthetic fracture model is selected to run on different levels of discretization with different initial thermodynamic conditions. A set of comprehensive analysis is conducted to compare the convergence and computational efficiency of simulation results. The numerical scheme is implemented within the Delft Advanced Research Terra Simulator (DARTS), which can provide fast and robust simulation to energy applications in the subsurface. Based on the converged numerical solution, a thermal Peclet number is defined to characterize the interplay between thermal convection and conduction. Different heat transfer stages are recognized on the Peclet curve in conjunction with production regimes in synthetic fractured reservoir. Afterward, a realistic fracture network, sketched and scaled up from a digital map of a realistic outcrop, is utilized to perform sensitivity analysis on the key parameters influencing the heat and mass transfer. The thermal propagation and Peclet number are found to be sensitive to flow rate and thermal parameters. The findings provide insights for the multiphase mass and heat transport in the fractured high-enthalpy geothermal reservoirs, which can be taken as guidance for the practical geothermal developments with uncertainties.

Heat production from low permeability reservoirs is believed to be significantly aided by the presence of open natural fractures (e.g. Upper Rhine Graben). However, in hot sedimentary aquifer studies these structural features are rarely included when estimating their economic viability. Therefore, we present a case study which assesses the impact of natural fractures on heat extraction from the tight Main Buntsandstein Subgroup targeted by the recently drilled NLW-GT-01 well (West Netherlands Basin (WNB)). We integrate: 1) reservoir property characterisation using petrophysical-analysis and geostatistical-inversion, 2) image log- and core interpretation, 3) large-scale seismic fault extraction and characterisation, 4) Discrete Fracture Network (DFN) modelling and permeability upscaling, and 5) fluid-flow and temperature modelling. First, the results of the petrophysical analysis and geostatistical inversion indicate that the Triassic reservoir layers have almost no intrinsic porosity or permeability. Second, the image-log interpretation shows predominately NW-SE orientated fractures having log-normal length - and negative-power-law aperture behaviour, respectively. Third, the seismic fault analysis depicts pattern which is to be expected from the structural setting of WNB. Fourth, inspection of the reservoir scale 2D DFN’s and upscaled permeability models suggest that if open, natural fractures significantly enhance the effective permeability (up to 500 mD). Finally, the performed 2D fluid-flow/temperature simulations indicate that open natural fractures significantly increase in the geothermal heat extracted from the normally tight reservoir rock. However, while the presented results are positive, it should be noted that the prediction and characterisation of natural fractures in the sub-surface is a relatively uncertain process.

In most hydrocarbon and geothermal reservoirs (“fluid reservoirs”), fluid flow is largely controlled by the permeability of the fracture system in the host rock. In such “fractured reservoirs sensu latu”, however, only interconnected fracture systems reach the percolation threshold necessary for fluid flow. For “fractured reservoirs sensu strictu”, i.e., those reaching economic potential, significant permeability is necessary. This permeability may be entirely provided by the existing fracture system and the host rock matrix or enhanced by reservoir stimulation. Both for the direct use of reservoirs, as well as for effective stimulation, the geometry of the existing fracture system in relation to the current stress field and its likely future development need to be known as accurately as possible. This is particularly important for reservoirs in fault zones.

Here I present manifold elements of multidisciplinary approaches, altogether aiming at reliable estimations of potential fluid flow in fluid reservoirs. Focus is on parameters and methods useful for fluid-flow estimations. Also, the interdependencies of parameters are important. The emphasis of this presentation is 1) on field studies in fracture-controlled paleogeothermal reservoirs in fault zones in Great Britain and in outcrop analogues of Mesozoic rocks in Germany and 2) on numerical models of local stress fields that provide the basis for numerical models of fracture propagation and fluid flow in fluid reservoirs.

These studies increase our understanding of fluid flow in reservoirs. Thus, they contribute to maximise the success of wells and help to improve the planning of well paths and reservoir stimulation.

Carbon capture and storage (CCS) is a key climate mitigation technology available to meet the Paris Agreement goal for limiting global warning. The goal of CCS projects is to separate, capture and permanently store CO₂, thereby reducing greenhouse gas emissions from existing industrial facilities. The main components of a CCS project are the capture infrastructure, the transport of the CO₂ to the storage site and the injection of the CO₂ deep underground. Site selection, characterization and engineering design are the prime means to ensure CO₂ risks are as low as possible. In addition, Shell uses a risk-based measurement, monitoring and verification (MMV) framework to evaluate the storage performance by monitoring conformance and containment. Shell is currently involved in several CCS projects as a partner (Gorgon in Australia, Northern Lights in Norway) and as the operator for Quest, a commercial-scale facility in Alberta, Canada.

At Quest, CO₂ is captured from the Scotford oil sands upgrader and transported by pipeline to the storage site. Since 2015, more than 5 million tons of CO₂ have been injected into a saline aquifer located at a depth of about 2 km below ground surface. A comprehensive MMV plan is in place and incorporates several monitoring techniques including microseismicity monitoring. Even though Quest is in a quiet tectonic area, induced seismicity is recognized as a potential risk in all large-scale fields undergoing injection. We will discuss how microseismic monitoring is an important element of the MMV plan to evaluate the induced seismicity risk and to possibly provide early notice of anomalies.