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The tectonic evolution of rift basins can strongly influence the petrophysical properties of its sedimentary infills at various scales and, therefore, influence the characteristics of present resources. Understanding the tectonic evolution of a rift basin is therefore decisive, as it can have consequences for the parameters that influence the planning of geothermal doublets. In this framework, this study gives a detailed interpretation of the syn- and post-rift episodes in the West Netherlands Basin, since Jurassic times. Despite multiple studies on the geotectonic setting of the West Netherlands Basin, a detailed understanding of its syn- and post-rift phases in the context of geothermal exploration is still fundamentally lacking. With a renewed interpretation of a seismic 3D cube, covering a large portion of the onshore section of the basin, we identified two important Jurassic rifting episodes and one Cretaceous inversion event. Rifting caused compartmentalisation of the main producing geothermal target in the area; the Late Jurassic Nieuwerkerk Formation. Yet, the central portions of the half-grabens show good potential for geothermal exploration. Subsequent inversion could have caused local breaching of the aquifer, forming a potential risk. Therefore, only non to moderately inverted areas should be considered for geothermal exploration. This study provides a better understanding of the multi-phase rifting history in the West Netherlands Basin, providing important constraints on the reservoir-seal integrity and with that, the amount of heat that can be safely produced from a geothermal reservoir rock. Aiming to contribute to the energy transition, this study provides an integrated picture of the West Netherlands Basin and shows how a basin’s geological history can affect its geothermal resources.

A geothermal area with only bicarbonate thermal water discharges at medium temperature requires a more integrated analysis than used in classical geochemical exploration. This signature is typical for steam-heated water, which commonly occurs at the margins of a geothermal system. However, these waters can also rise from carbonate rich layers in the central part of the field. Our study shows that fluid flow modeling can identify the exact source, flow pathways and temperatures of reservoir fluids based on water-rock interaction. For the first time, we present a conceptual geothermal fluid flow model based on geochemical data for the Songwe geothermal system in Tanzania. Thermal springs discharge along NW-SE fracture zones in two separate areas: the central Songwe graben (Iyola, Main springs, Rambo and Kaguri) and eastern Songwe graben (Ikumbi). The discharge temperatures of springs range between 37 and 85 oC with Na-HCO3 type, and carbonate deposits surrounding most of the springs. We estimated fluid temperatures for a depth of 2.5km by applying K-Mg and Na-K-Ca (Mg correction) geothermometers, suggesting that reservoir fluids reach temperatures between 125 and 148 oC. We reconstructed reservoir fluid characteristics for that temperatures and propose oversaturated minerals (volcanics, clays, carbonates, apatites, weathered metamophics and hydrothermal minerals) as a model result of interaction between the deep fluids and certain lithologies. Comparison between the modeled oversaturated minerals with minerals in the springs (calcite, aragonite, analcime, muscovite, and smectite) suggests that Kaguri spring water is a result of interaction between deep reservoir fluids with all lithologies, passed on the way to the surface (Metamorphics, Karoo group and Red Sandstone). The fluid signature of Kaguri springs suggest an upflow zone of the geothermal system. Further, our model with oversaturated minerals shows that the thermal water from the reservoir flows laterally along the Red Sandstone layer to the eastern part of study area. It appears as Rambo springs, south of Kaguri springs, and as Main springs and Iyola to the west. The outflow zone might be continuing towards Ikumbi springs, where the fluids also interact with volcanic units. The proposed model shows that carbonate dissolution from the Red sandstone layer is the most common water-rock interaction. The carbonate is embedded in pores and fractures and occurs as matrix in the sandstone. The water-rock interaction is dominated by HCO3- and Na and seen in carbonate depositions at all springs., EGUsphere

Permian deposits are found in outcrops and in the subsurface of Central Tunisia. Their sedimentary and stratigraphic characteristics and origin are not fully understood and represents the main focus of this work. Base level changes, location of the palaeo-coastline and stratigraphic architecture and sandstone connectivity of formations are insufficiently known. Answering these questions will impact future hydrocarbon exploration and improve the geological understanding of Tunisia. Seismic lines and well data of the Jeffara Basin have been re-interpreted and seismic data converted to depth domain. The results indicate a shallow marine rimmed shelf depositional environment, with dimensions of 100 square kilometers and a general east-west orientation. Seventy kilometers to the north of the reconstructed paleoshore line twelve stacked reef complexes up to 3000 meters thick were identified. Literature study of the area indicates a tropical climate. Structurally, it was observed that the Permian is not affected by major normal faults and appears at large scale gently folded. Wells and outcrop investigations provide lithological information, which is composed of limestone and dolomite, with intervals of sand and shale. The thickness gradually increases northwards, reaching 4000 meter maximum. Using DionisosFlow, 3D stratigraphic models are constructed. They provide a number of equiprobable scenarios of facies distribution through the basin matching the available data. This modelling approach highlighted the impact of base level changes on reef geometry and in the lateral connectivity of clastic deposits. It also indicates depocenters shifting, shoreline evolution and feeder systems position and importance over time.

The sedimentary architecture of the Essaouira-Agadir Basin in Morocco is strongly influenced by development of Atlasic and Atlantic early Mesozoic riftings. The basin is now part of the Western High Atlas after Alpine exhumation and exposes several salt-cored anticlines perpendicular to the NW Africa coast. We study two of these salt-cored anticlines to understand how their tectonic evolution influence seaward sediment pathways during Mesozoic exhumation of long-lived sedimentary sources in the hinterlands. We gather structural data in Google Earth and use it in Move 2D to derive the thickness of sedimentary units in both E-W salt-cored anticlines. Results show salt mobilisation and topographic growth of these anticlines diverge the sedimentary routing of paleodrainages during the Early to Middle Jurassic exhumation of the Moroccan hinterland, and thus suggest a causal relationship.

Crustal rheology and surface processes strongly influence strain distribution and shape of orogenic wedges at their front but how they influence the wedge rear is still unclear. Here, we analyze the coupled control of viscosity and sedimentation on forearc high growth during advanced stages of subduction accretion. We use 2D thermo-mechanical finite element models constrained with data of the south Anatolian margin. Our simulations show that forearc highs grow as a thermally-activated viscosity drop in the lower crust induces ductile deformation and viscous flow. Initial viscosity and the amount of sediments in the forearc basin control non-linearly the occurrence and timing of the thermally-activated viscosity drop, and thus of the growth of the forearc high. High sedimentation rates result in thicker forearc basins that stabilize the subduction wedge and delay the onset of uplift in the forearc high. Low viscosities promote earlier onset of forearc high uplift and lead to larger morphological variability along the subduction margin. Increasing either sedimentation rate or viscosity may prevent forearc high formation entirely. The thermo-viscous forearc highs grow at an age set by wedge thermal state as a function of accretionary flux, wedge viscosity, and synorogenic sedimentation. Our models explain vertical motions in south Anatolia and potentially in other accretionary margins, like the Lesser Antilles or Cascadia, during the formation of their broad forearc highs.

TNO Applied Geosciences (1); TNO Advisory Group for Economic Affairs (2); TNO Geomodelling (3); TNO Geo Data and IT (4); TNO Monitoring and Control Services (5); TNO Data Science (6) 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.

Delft University of Technology, The Netherlands (1); PanTerra Geoconsultans (2); CGG The Hague (3) 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.