Geotechnical projects are successful when there is a lot of knowledge about the soil implemented in safe sustainable solutions. Existing models of hydraulic flow in soils need to be tested and confirmed again and again to make sure it’s trustworthy. With the use of three-layered samples containing 1mm and 3mm glass bead sizes a simplified model of the fining upward (1mm top layer) and coarsening upward (3mm top layer) stratification was made. The top and bottom layers consist of a uniform glass bead size. The middle layer is a binary mixed one with different volumetric percentages to mimic the gradual increase of grain sizes like fining and coarsening upward sediment deposits. A decrease in the permeability was observed as the volume percentage of the smaller glass beads increased. The influence of a possible transition/mixed zone between layers was not clear because of the small ratios of the used glass beads. This is also the case for the effect of the porosity on the permeability. In addition, test samples were prepared to calculate the theoretical harmonic permeability to be able to compare it with the actual measured permeability. This theoretical harmonic permeability seems in the case of the coarsening upward samples smaller than the actual measured permeability as was expected from findings of another research. This study confirms the influence of the relative positioning of the layers with their specific properties on the overall permeability and the deviation from the theoretical harmonic permeability. Future prediction of the permeability’s in layered deposits is a little bit more educated with the findings of this study.

The aim of this project is to focus on the effect of mechanical contrast and surface roughness as factors influencing the shear strength of the interface of different rock samples. The shear strength of an interface is significant in experimental projects that for instance address the containment and propagation analysis of hydraulic fractures. A discontinuity can be defined as any type of interruption in mechanical and structural properties of a rock layer. The samples used in this project are mechanically discontinuous at the interface. These samples consist of 3 different sandstones, one granite and one monzodiorite samples. These samples were prepared to fit a certain casket that was specially designed for this project. The mechanical contrast between pairings of these samples were obtained through calculations for difference in unconfined compressive strength between the rock types. The samples were then placed in a direct shear box and sheared against each other to obtain shear force and vertical displacement profiles while under a specific normal load. In three different sets of experiments, specific pairings of samples were analysed and processed. Each pairing showed a unique set of results which were then compared with one another. Each experiment set focused on a certain aspect. The first set of experiments focused on the effect of mechanical contrast. The second experiment set focused on the change in surface roughness caused by shearing at higher loads. The third set focused on the effect of predetermined changes on surface roughnesses and how this would affect the shear stress profiles. The values obtained through these experiments were then mathematically processed and shear stresses and normal stresses were plotted against each other. From these plots the friction coefficients and angles of friction were calculated. The results show that mechanical contrast has a direct effect on the shear stress profiles. A constant mechanical contrast of two different pairings of samples results in the same trend no matter what rock types were used. In other words, if two different pairs are sheared against each other with each pair having the same mechanical contrast, the shear stress profiles will have the same friction coefficient. The surface roughness also directly effects the shear stress profiles. The results showed that the higher the measure of surface roughness, the higher the shear stress will be. The predetermined surface roughnesses of the samples were 125 and 75 μm.

Rapid injectivity decline is frequently observed during injection in unconsolidated sand reservoirs. Field data suggests that hydraulic fracture processes are directly or indirectly related to this injectivity decline. Conventional fracture theories do not apply to unconsolidated sand since this material has little to no cohesion and tensile strength. The main fracture mechanism hypotheses are shear failure of the zone ahead of the fracture tip and fluidization. For both mechanisms, a fluid pressure high enough to initiate and propagate the fracture is required. The fluid pressure is dependent on the injection rate, fluid viscosity and permeability of the formation. Unconsolidated sands have a high permeability, thus under normal waterflood conditions a high injection pressure is not expected. Three main impairment mechanisms leading to the injectivity decline have been identified based on field evidence and previous work: -Plugging -Wellbore fill -Resorting of grains and finer particles Plugging results from the infiltration of fines originating from the injection fluid, crossflow or drilling mud. The external and/or internal filter cake can locally reduce the permeability of the formation. During surface shut-ins, backflow and/or crossflow can occur leading to the infiltration of solid particles and fluids into the wellbore. This reduces the leak-off area of the well. Lastly, resorting of grains and finer particles can result in a denser packing of the reservoir. The dynamically mixing of particles can lead to lower permeability regions. Research goal The main goal of this research is to develop a better qualitative and quantitative description of the fracturing process and the impairment mechanisms causing the observed injectivity decline. This thesis comprises of the first phase of this research, focusing on the capabilities of the equipment to create and detect fractures under waterflooding conditions. What makes this research unique is the use of low viscosity fluids, to mimic field conditions. Other work often involves the use of efficient fracturing fluids that have a high viscosity and/or good filter cake building capabilities to minimalize the leak-off. Next to that, injection of fluids is performed live in a CT scanner. This allows the visualization of fractures or low-density regions through density distributions in three dimensions over time. Equipment Injection takes place in a high-strength aluminium vessel with a sample volume of 3.84 dm3. See images 2.1 and 2.2 of an overview of the setup and pressure vessel. Axial and radial pressure can be controlled independently up to 20 MPa. A pore fluid system records the outflow mass and provides a fluid pressure on the sample. The sample consists of a very fine, very well sorted sand with a permeability around 5 Darcy. The main injection fluids are water and Fluorinert FC-770. This is a high density, low viscosity fluid that is used to visualize the preferential flow path of the injection fluid in the CT scanner. Results Fractures have been successfully created using a high viscosity fluid during the first experiment. The goal of that experiment was to test the setup and the equipment. The fractures were created at an injection pressure of 38 MPa and were up to 1 cm long and 2 mm wide. Experiments 2 and 3 were performed in the CT scanner with the use of Fluorinert as the injection fluid. The infiltration zone of this fluid was clearly visible but no fractures were created. Sand infiltration in the injection tube leaded to a number of problems during the experiments. Experiments 4 and 5 added fines to the injection water. Quartz powder was used in experiment 4 and bone meal in experiment 5. The fines leaded to a gradual increase in injection pressure, but did not lead to a higher density in the CT scans. No fractures were observed but low-density regions in front of the perforations were created during both experiments as a result of backflow. Experiment 6 introduced the use of internal pressure sensors in the sample and used a sample created with two sands and Kaolinite, a non-swelling clay. During two high flowrate injection cycles, the clays migrated away from the near wellbore region, leaving behind lower density regions. Conclusion & future work Creating fractures with low viscosity fluids in a laboratory environment has proven to be difficult. No fractures have been created throughout the low viscosity experiments. Several impairment mechanisms that were identified in the field have also been observed in the experiments. This thesis forms a solid basis for the next research phase to investigate these impairment mechanisms more closely. By lowering the confining stresses, increasing the flow rates and decreasing the sample permeability, there is a good probability that fractures can be created with this equipment in future work.

The main objective of this study is to quantify interference effects between production and injection wells for geothermal projects that operate within the same reservoir. The secondary objective is to study the time it takes for the reservoir unit to thermally recharge after production has stopped. Two reservoir simulators are benchmarked to decide which one to use for reaching these objectives. The Ammerlaan, Duijvestijn and DAP doublets, all targeting the the Delft Sandstone Member in the West Netherlands Basin, serve as a case study. A literature review is presented to gain a better understanding of the geological history and the structural setting. A box-model of the study area is created and used to benchmark the two reservoir simulators. A static reservoir model is developed in Petrel through seismic interpretation, structural modelling, facies modelling and petrophysical modelling. Populating this static model with dynamic properties allows us to perform reservoir simulations in Eclipse100 and study the propagation of pressure and temperature. A discrete parameter analysis aims to capture the uncertainties that are associated with reservoir modelling and simulation. In this study, data is used from seismic surveys, wireline logs, core studies, a cuttings study and the monthly production volumes of the Ammerlaan and Duijvestijn doublets. It is shown that interference on temperature has a long term (20-30 years) effect on the Duijvestijn (positively) and the Ammerlaan and DAP doublets (negatively). The combined total energy production of the three doublets over 100 years is small with a decrease of 3% due to temperature interference, compared to when running the doublets in stand-alone configuration. Interference on pressure has a short term (days) effect on the achieved flow rate when the injection well cannot reach its target injection rate and is constraint on the maximum allowable pressure at which it is allowed to inject. This occurs under the low permeability scenarios and can be observed when the pressure wave arrives at the neighbouring injector. The Duijvestijn, Ammerlaan and DAP doublets all benefit from this through a combined increase in energy production of 8% over 100 years of production, averaged over all scenarios. During thermal recharge after production, the average reservoir temperature increases asymptotically. Temperature recharges to 96.1% to 97.4% of the initial reservoir temperature after 1000 years of recharging under different thickness and conductivity scenarios. The absence of a thermal influx at the bottom of the reservoir model is limiting the capacity of the reservoir to recharge to its initial average temperature. Interviews are conducted to investigate the implications that the findings of this research have on the policy measures for geothermal projects. Suggestions for changes in policy are made to optimize the recovery of heat in the subsurface.

Geothermal energy is a relatively sustainable energy source of which the essence is to extract heat from hot subsurface rocks. Circulating fluids serve as the transport agent of heat. The contact area between the fluids and the rocks is where the relevant heat transfer occurs, i.e., where the water is heated up. In some geothermal reservoirs, this circulation occurs naturally through porous matrix (mainly sediments) or through heavily fractured formations. Enhanced geothermal systems (EGS) are potentially favorable reservoirs where subsurface permeability is increased by means of artificial stimulation techniques. These stimulation techniques often involve hydraulic fracturing where a limited existing fracture network is expanded or “enhanced” by injecting fluids under high pressure conditions. While the geometry of the generated fractures influences permeability, the effect on heat exchange has received less attention. This thesis discusses the effects of fracture geometry on the heat transfer between solid and fluid. Along with laboratory experiments, numerical simulations were conducted. All investigations were performed on igneous granite rocks. Tensile fractures were generated to allow a fluid flow along the otherwise impermeable rock samples. Several parameters were varied throughout the experiments and simulations including volumetric flow rate, fracture aperture, rock temperature and fracture geometry and surface area in order to investigate their impact on heat transfer processes. Flow rate variations in the experiments have shown that higher flow rates cause the fluid to absorb less heat per unit volume and cause the rock to cool down more extensively, therefore thermal depletion of the reservoir is likely to occur within a shorter time frame. The dependency of exchanged heat on fracture aperture variations (in the range of 0.05 to 0.5 mm) did not yield a clear trend within the experiments, but does so in numerical simulations. Aperture variations in the numerical simulations did not cause notable differences in transferred heat as long as the volumetric flow rate is kept constant. However, as the fluid velocity is kept constant the amount of fluid flushed along the fracture per unit time is affected by varying apertures. This causes a difference in heat transfer as well. Increased fracture surface areas alone (more extensive topology/roughness) have shown a minimal impact on the heat production while a more extensive fracture network (additional branches) has shown notable enhancement in the amount of heat produced. Cooling behavior of the rock has shown correlations with Newton’s law of cooling and suggests a limitation of heat production by the heat conduction occurring within the rock. Experimental findings cannot directly be compared with natural reservoir conditions. The reason for this is a thermal equilibrium that is achieved at each flow experiment, i.e., the heat withdrawn equals the heat resupplied by a heater. In natural reservoirs this is often not the case where a cold front propagates towards the production well and determines the lifetime of how long heat can efficiently be produced from a certain rock mass. This results in an unsteady heat conduction where the heat withdrawn does not equal the heat resupplied.

The Southern Chotts and Jeffara Basins are situated within the Saharan Domain of Central Tunisia, North Africa. The Southern Chotts Basin hosts reservoirs within the Triassic, Permian and Ordovician units that contain significant hydrocarbon accumulations whilst the Jeffara Basin contains outcrop analogues of the same hydrocarbon­bearing formations. The basins experienced a late Hercynian shortening phase which involved the uplift of a major topographic high (Tebaga de Medenine). This high, in conjunction with a older regional high, the Telemzane Arch influenced the deposition and geometry of the Permian and Triassic units across both basins. This shortening event is characterised at the scale of hundreds of meters by E­W striking folds into which the mid­late Triassic and early Jurassic units are deposited. The folding is also observed at field scale (10’s meters) through small fault­related folds in the Permian deposits of the Tebaga de Medenine. This late Hercynian phase occurs between the late Permian and early Jurassic in the basins. Fracture data collected from the upper Permian and lower Triassic units (Jeffara Basin) provides an analogue to the fracture networks at depth (Southern Chotts Basin) in the Paleozoic reservoirs. A conjugate fracture system observed in the field (from fracture pavements) corroborates with the interpretation of regional shortening in the basins. Seismic attribute analysis on depth slices in the Paleozoic reservoirs also shows the conjugate system at depth. This analysis is integrated with outcrop fracture data and FMI data from wells to create an open fold distributed fracture model of the system in the basins. This model indicates the main driver for fracture generation in the region is folding and is used to predict the fracture networks at depth. This is undertaken using discrete fracture network (DFN) modelling of the subsurface. This model is integrated with a deterministic model from the seismic time slices to create a hybrid predictive fracture model of the early Paleozoic reservoirs. Analytical aperture modelling of the fracture model demonstrates the fractures varied in openness depending on orientation and fracture length. The conjugate set orientated at 240∘and longer joints detected from seismic attributes presented the widest aperture size. These fractures in the subsurface at implications on the transmissibility of the reservoirs, especially Permian units which have low bulk rock permeability and the lower Triassic (TAGI) sequences which are susceptible to compartmentalisation.

A pilot for a large scale, fully integrated chain of CO2 capture, transport and storage (CCS) has been initiated in the port of Rotterdam. The initiative aims to demonstrate the technical and economic feasibility of CCS and show that it can be deployed on a large scale for power plants and energy-intensive industries that emit large volumes of CO2. The partially-depleted Q16-Maas gas condensate field could potentially be used to permanently store the captured greenhouse gas (CO2). The case study shows the potential that this field has for CO2 storage and also examines other options for life-cycle extension. The case study is based on macroscopic scale reservoir behaviour and simulated in the fully compositional simulator, Eclipse 300. Gas reservoirs have a proven track record for safely trapping gaseous phases in the subsurface over long geological timescales. As long as initial reservoir conditions, mainly pressure (=296,5 bar), are not exceeded, CO2 in supercritical phase should be safely stored. According to literature, with increasing storage time, the CO2 is even trapped more securely, although this process may take hundreds to thousands of years. The results of the case study show that approximately 1.1 million tonnes of pure CO2 can be stored in Q16-Maas field. By side-tracking the original well and producing the attic gas in the reservoir, 160 million cubic meters of additional gas can be recovered, along with condensate. If the side-tracked well is then converted to a CO2-injection well, the CO2 storage capacity is increased to 1.4 million tonnes. This injectable CO2 volume is less than the two million tonnes originally estimated and this is due to the influx of water from a strong aquifer that has partially filled the void left by depleting the gas field. The possibility of enhanced gas and condensate recovery using CO2 has also been investigated in this case study, as the use of CO2 for miscible floods in hydrocarbon reservoirs has been proven and used successfully as a tertiary recovery method. The reservoir simulation of the Q16-Maas field shows that there is no additional hydrocarbon recovery by CO2 flooding. Sidetracking to and producing from an updip location in the reservoir is equally as productive. The reason for this is attributed to presence of a strong water aquifer, together with the varying reservoir quality and thickness prevents the successful application of CO2 enhanced hydrocarbon recovery. The total cost of transport and storage (OPEX and CAPEX) was estimated to be 71.5 million euro. Assuming CO2 storage volume of 1.4 million tonnes, the project would need to receive roughly 50 euro/tonne in order to breakeven for storing and transporting the CO2, the capturing is not included.

Hydrocarbon or geothermal reservoir often consists of several rock layers from different lithology. The various lithologies have their own number of mechanical properties and the layering effect introduced the term of mechanical contrast, which represents the ratio of rock strength between adjacent layers. Mechanical contrast and confining pressure highly influence the fracture behavior in the layered rocks. In this study, fractures in layered rocks are investigated, starting with its geometry and also the stress field contributed to the fracture generation and development. The fracture geometry such as fracture length, average aperture, aperture distribution and orientation are quantified in a two dimension slice image. The study focused on comparing the fracture behavior when (a) the layered rock compositions are the same between samples with increasing confining pressure or (b) the different compositions of layered rocks (different mechanical contrast) between samples in the same confining pressure. The results show that fracture tends to propagate through layer interface when the mechanical contrast between adjacent layers and the confining pressure are low. The fracture in the weak layer developed at a gentler dip (shear fracture) with higher fracture aperture compared to the ones in the strong layer which almost vertical (tensile fracture). In addition, the shear fracture in the weak layer usually accompanied by the zone of cataclastic flow while the tensile fracture has a more clear pathway for fluid flow. However, mode I opening/tensile fractures are less likely to affect fluid flow in the reservoir because their aperture is insignificant at depth. While in mode II sliding/shear fractures, only several parts along the fracture that can provide the open space, which depend on the presence of jogs and irregularities on the fracture surfaces. The results from fracture measurements show that in the weak layer, average aperture and aperture distribution will reduce with the increasing of confining pressure, but increased with the increasing of mechanical contrast. Average fracture aperture and distribution have a significant role in capillary pressure. The higher average aperture will reduce the amount of pressure needed to flow the fluid, while a higher number of aperture standard deviation (aperture distribution) has a contrasting effect. The average aperture has a bigger impact on capillary pressure compare to aperture distribution. Thus, by increasing the confining pressure or decreasing the mechanical contrast, the required pressure for fluid to flow is increasing. Furthermore, the numerical modeling is performed by imitating the rock mechanical properties and the fracturing conditions from the laboratory experiment. The results show that under compressive stresses, the layered rocks still generate tensile stresses around the interface within the strong layer. The tensile stresses occur because of the stress transfer between adjacent stiff and soft layer with a bonded interface. The presence of tensile stress and the crack-tip stress are responsible for the generation of the tensile fracture in the strong layer for all samples. The effect of varying the number of confining pressure, Poisson’s ratio and Young’s modulus on the tensile stresses distribution are also performed. The sensitivity study shows that Poisson’s ratio has a more significant impact compared to Young’s modulus on both maximum tensile stress and thickness of tensile region. Higher Poisson’s ratio resulting in higher tensile stresses, while on Young’s modulus it depends on the contrast between adjacent layers rather than the magnitudes. Understanding the fracture behavior in layered rocks is beneficial for reservoir characterization, as fractures can enhance the permeability and providing vertical connectivity between isolated reservoirs. Accurately interpret 3D natural fracture distribution can help the estimation of the resource and recoverable potential early in field life. It will also contribute to optimizing the well placement and completion design for efficient production planning.

Many laboratory tests of samples where the rock fractures are based on meso-scale (cm) characterization of effective ‘intact’ strength parameters neglecting the microstructure effects. Understanding fracturing processes at micro-scale (mm) will require models with microstructure data. However, data is lacking on micro-scale. Stylolites are natural rock-rock interlocked interfaces which form by a localized dissolution process and their interface contains minerals and material different from that in the surrounding host rock. Microstructures such as stylolites influence the tensile stress behaviour in a rock formation. We are interested in stylolites because they can act as drains or as barriers to flow. Therefore, we introduce a study where we investigate on micro-scale failure mechanisms of limestone samples with stylolites in diverse orientations. In preceding study (Pluymakers et al., pers. comm.) a series of Brazilian Disc Tests was performed on eleven samples all including stylolites of microscale carbonate samples from the ”Treuchtlinger Marmor” formation from the Molasse Basin (Munich, Germany). All experiments were filmed using a DSLR camera. In this study we aim to develop the use of the Particle Image Velocimetry method to analyze such type of movies. We use the developed Particle Image Velocimetry method to analyze three of the movies of the preceding study, which contained samples where the stylolite is at different angles to the horizontal axis of the sample, so to s3. Two samples has an angle of 90° between the stylolite and s3 and one with an angle of 40°. In this open-source software the pixel displacement is analyzed in frames (i.e. consecutive images, ’before’ and ’after’ image) and it calculates the velocity distribution within the framepairs, but it is also used to derive, display and export multiple parameters of the flow pattern. In this study we derived and displayed the strain rate on the image pairs. The results show that the strain field of the two limestone samples of a 90° stylolite behaves identical in the two major stress drops (i.e. DStress) from the stress-displacement curve. However, the sample with a stylolite of 40° behaves differently. For the two 90° oriented stylolites random extension and compression takes place at the first highest negative stress drop and symmetric extension takes place at the second highest negative stress drop from the stress-displacement curve. However, for the 40° oriented stylolites asymmetric extension takes place at the first highest negative stress drop from the stress-displacement curve. And random extension at the second drop. Another result of this study is that the strain rate obtained from PIVlab, the strain rate per stress drop (MPa) (i.e. in the stress displacement-curve) in both the two 90 ° stylolite samples and the 40 ° sample were different. To put this work in the broader context of the energy transition, we consider the rapid development of the geothermal sector. Nowadays geothermal energy is considered as one of many alternative sources of energy using the hot water in the Earth’s surface to generate electricity and power heating/ cooling systems. The Dinantian carbonates in the Netherlands and the ”Treuchtlinger Marmor” carbonates from Germany are of interest for Ultra Deep Geothermal wells, because of their high geothermal potential. To enhance the porosity/permeability in a formation where hot water needs to be extracted hydraulic fracturing can be an option and this study gives insight about how the rock formations on micro-scale behave when tensile failure occurs. Tensile is one of the most important properties to be evaluated for any textile material (i.e. rocks). Tensile failure is important because it occurs when the stress on a component exceeds the strength of the material thus it determines the strength of a rock and consequently is influenced by single plane of weakness such as stylolites.

The primary reservoirs present in the Southern Chotts Basin, Central Tunisia, are located within Triassic, Permian and Ordovician units. They are mainly sourced by the Silurian -- Lower Devonian Fegaguira formation and its Hot Shale member. Late Paleozoic exhumation has eroded part of the Palaeozoic package, removing the Early Devonian -- Carboniferous and most of the Permian deposits in the Southern Chotts Basin. This resulted in a diachronous unconformity in the present-day stratigraphy and represents significant uncertainties. This study presents a reconstruction of the tectonic and thermal history of the Southern Chotts Basin and the subsequent impact on source rock thermal maturation, with an emphasis on the Hercynian exhumation. Implications on the petroleum systems in the basin are evaluated by means of a migration study. Investigation of adjacent analogue basins allows estimation of the amount of initially deposited sediment in the Early Devonian -- Permian. Calibration with vitrinite reflectance data minimizes exhumation uncertainties in the basin history and indicates ca. $2300$ m sediment eroded during the Hercynian phase. Subsidence analysis shows similar subsidence patterns throughout the area of interest since the Mesozoic. This argued to use a single set of high and low case initial deposition estimates, calibrated with vitrinite reflectance, in source rock maturation modelling. Source rock maturation modelling in the kitchen area indicates hydrocarbon generation occurs in two phases separated by a phase of stable maturity during Hercynian exhumation. Maturation in the kitchen area is found to currently be in the condensate -- wet gas zone. Migration modelling shows that Paleozoic generation in the northern and northeastern portion of the basin primarily sourced the present-day hydrocarbon discoveries. High capillary entry pressures in overlying Fegaguira shales forced hydrocarbons generated in the Hot Shale member to migrate downward into porous Ordovician units. Subsequently, hydrocarbons laterally migrate up-dip into local traps, where they remain trapped wherever the overlying source rock is preserved during Hercynian exhumation. The Ordovician units acts as a reservoir, and as a carrier bed to source present-day accumulation in the Triassic TAGI unit. A newly identified petroleum system primarily hosts accumulations in lower shoreface Ordovician El Atchane deposits, overlain by the Fegaguira and Hot Shales. Simulated hydrocarbon accumulations and projection of shoreface deposits throughout the area of interest mark a sweet spot area with significant reservoir potential in structural traps. Recommendations are given to further investigate the potential of this system.

This research describes how thermal fractures impact the near-wellbore (NWB) region of a depleted gasfield in a carbon sequestration project. As CO2 is usually injected in its supercritical phase, the injection fluid is injected on high pressures and low temperatures. This is in high contrast with the depleted gasfields, which have a low reservoir pressure. The increase in pressure and decrease in temperature causes a thermoporoelastic response, resulting in a reduction of stress inside the reservoir. Once the fracture initiation stress, the so-called fracture stress, is reached, thermal fractures form. Thermal fractures form only due to extensive cooling of the reservoir. The fractures impact the NWB region; due to opening of fractures there is a drop in pressure in the bottomhole pressure (BHP). This increases the reservoir's injectivity. This research uses CMG GEM to model this. The simulation uses a homogeneous box dual permeability model with the model being initialized as a generalized depleted gas reservoir in the North Sea. To model the fractures, the Barton Bandis model is used. This model changes the permeability in a fracture cell once fracture conditions are met. From this model, the moment of fracturing (fracture time), the fracture halflength and the injectivity of the reservoir is researched by performing a sensitivity analysis on key parameters. It is found that the thermal fractures propagate conform to the propagation of the coldest part of the thermal front. The thermal front propagates further once the fracture conditions are met sooner due to fluid highways or when the pressure build up in the reservoir is slower. The sensitivity on the geomechanical parameters showed that only the stress conditions in the reservoir changed, causing the injection constant to change and thus a different fracture time. The way the reservoir reacted to the initiation of fractures was the same; the injectivity was improved similarly for each parameter. The effective permeability (thickness and permeability) determines, together with the injection rate, the way the pressure builds up in the reservoir changes the increase of injectivity due to fracturing slightly. Increasing the reservoir volume causes a slower pressure build-up inside of the reservoir, allowing the thermal front to propagate further and thus longer fracture lengths. Lastly, the sensitivity on the thermal effects showed that a higher difference between the reservoir and injection temperature causes the fracture to be less dependent on the increase of pressure to fracture, resulting in earlier fracturing and longer fracture halflength. The pressure build-up is not changed, so the injectivity remains similar to the basecase scenario. All in all, this thesis gives an insight on how key parameters impact thermal fracture behavior. It also shows what range of parameters can be expected. Combining these two gives an insight on what parameters the focus should be on to better describe the behavior of thermal fractures, to economize the operation by leaving out or including extensive data collection on key parameters. This helps to improve the injection strategy with CO2 injection projects in depleted gasfields.

Knowledge of the state of stress is of significant importance to have a thorough understanding of subsurface geomechanics. The World Stress Map (WSM) is the main source of present-day stress data in Western Europe and indicates a regional NW-SE maximum horizontal stress (SH) trend for the Netherlands. However, for more local studies the WSM lacks the required resolution. Therefore, the first objective of this research is to expand the Dutch Stress Map (DSM) database in which SH orientations are collected. As such, a better understanding can be obtained of the horizontal stress field with depth and the SH orientations that deviate from the regional trend. In addition, this research aims to characterize the in-situ stress regimes with depth in the Groningen field, using different one-dimensional stress models. This research first highlights the importance of the stress state and indicates which in-situ stress information is currently lacking in the Netherlands. Moreover, it is shown how stress-induced borehole features serve as basis for the determination of horizontal stress directions. The datasets used to expand the DSM database are presented, after which an extensive analysis is performed on the collected SH orientations. Subsequently, the stress magnitudes are quantified by studying the sensitivity of the in-situ stress regime to different 1D stress models. Moreover, the workflow is described for developing a 3D geomechanical model, which can serve as basis for future studies. The research shows that the DSM database is expanded with 86 new boreholes across the Dutch on- and offshore regions. The analysis of the database indicates a dominant NW-SE SH orientation, both spatially and with depth. In most stratigraphic groups, the SH direction falls within the range of 315° ±22.5°, although a larger degree of variation is observed in the post-salt stratigraphies. On a local scale, two case studies show that SH orientations, which deviate from the regional NW-SE trend, can be related to the presence of a salt structure and a normal fault. The 1D in-situ stress models all indicate a normal faulting stress regime at reservoir depth (Rotliegend) and deeper. In the interval between the reservoir and Earth’s surface, no unambiguous stress regime is identified as the regime is more sensitive to the different boundary conditions applied.

With an increase in the demand for heat energy, and the growing conscience of the world to reduce CO2 emissions, the transition to cleaner energy alternatives has gained momentum. In the Netherlands, the potential for cost-effective geothermal heat extraction from sedimentary aquifers has led to the exploration of siliciclastic Triassic reservoirs in the West Netherlands Basin and Roer Valley Graben for their suitability. This thesis primarily focuses on two geothermal target wells namely NDW-01 and NLW-GT-01. These wells lie in the Nederweert and Westland areas respectively.NDW-01 comprises of 292m thick sandstone package which is scarcely studied. While the NLW-GT-01 well was drilled tapping depths of over 4000 meters and encountering temperatures of about 100°C. In contradiction to the pre-drill expectations of having appreciable porosity and permeability values between 10-500mD, the Upper Volpriehausen sandstones in NLW-GT-01 exhibited porosity and permeabilities ranging between 1.4% to 3.9% and ≤0.02mD respectively. The sandstones were highly compacted and severely cemented by dolomite and quartz. These cements blocked all the macropores leaving no visible porosity in the thin sections. Although, the cored interval was extensively fractured the measured permeability values were negligible. This thesis presents the results of an assessment of the factors leading to the deterioration of intrinsic porosity and permeability of Triassic aquifers lying in the Westland and Nederweert regions. In this project, grain-size analysis using core plugs, thin-section study, petrophysical data analysis, and FMI log interpretation were conducted to understand the depositional environment of the Lower Germanic Trias Group precisely the cored sections of the Nederweert Sandstone Member in NDW-01 well and the Volpriehausen sandstones in NLW-GT-01 borehole. Due to the complex tectonic history coupled with locally different paleoenvironments, the current depths of the Triassic deposits in the investigated area did not correlate with the reservoir quality of the adjacent shallower wells. In addition to the local depositional conditions in the basin, the variable precipitation in the source area, and the distance of sediment transport have defined the rock characteristics. The primary grain-textures, such as roundness, sorting, packing, as well as the detrital framework and authigenic minerals, were found to influence the sandstone porosity. The tightness of the reservoir was due to significant mechanical compaction and cementation described by a diagenetic reconstruction explaining the evolution of porosity with depth with a negligible generation of secondary porosity. The deterioration of the reservoir quality is correlatable to the burial history and its resulting consequences, namely mechanical and chemical compaction endured by the rock during periods of basin subsidence and uplift. These analyses have put the deviation of pre-drill results from those that were obtained through post-drill evaluations into perspective.

The upper reservoir intervals of the Lower Jurassic Åre Formation in the Heidrun Field (Offshore mid-Norway) are very heterolithic and have the lowest oil recovery factor of the field despite significant amounts of remaining reserves. One of these reservoir zones is the formation Åre 6.2, which is mainly composed of tide-dominated heterolithic channel belt deposits. It contains particular layers that have excellent properties with permeabilities up to 10 Darcy. These layers are predicted to affect the production results as they can act as ‘thief zones’ within the low permeable heterolithic facies causing large quantities of water to flow through, leading to poor sweep efficiency and early water breakthrough. This study focuses on constructing conceptual depositional models of the Åre 6.2 and building detailed geological models to investigate the effect of the thief zones on overall fluid flow predictions. Conceptual depositional models were constructed by determining the characteristics of the reservoir and its depositional environment. Seven cored wells were used as the primary data to interpret lithofacies and facies associations. The study showed that Åre 6.2 mainly consisted of structured sandstones and heterolithic lithofacies with features that indicate that tidal process play an important role in the deposition. The influence of tidal process on deposition is further exemplified by the identification of two different types of channel facies associations, which are tidal and distributary channels. The thief zones were found in both facies associations, suggesting that the thief zones were formed during high freshwater discharge into the channels supplying coarse sandy material influx during a phase of high-energy deposition. To make detailed models of the tidal and distributary channels, multiscale modeling techniques were utilized to better represent the reservoir heterogeneities at the lithofacies and facies association scales. At the lithofacies scale, models were built in SBEDTM and the upscaled values of each lithofacies were obtained by applying the Representative Element Volume (REV) concept. The upscaled values were then used as input in the facies association scale models in order to represent the heterogeneities at the lithofacies scale to the next heterogeneity level. This step is essential since heterogeneities at a smaller scale may affect reservoir flow properties. Two different channel models were built in ReservoirStudioTM based on the conceptual depositional model and using outcrop analogue data from the Gule Horn Formation (Neill Klinter Group) in the Albuen area (Greenland). Flow-based upscaling was used to analyze the model uncertainties and determine a proper upscaling grid size. Finally, streamline simulations were performed to identify the effect of the thief zones. The simulation confirms that the thief zones influence fluid flow in the reservoir zone significantly as most flow was concentrated in the thief zones.

Society relies on large amounts of energy to progress and allow for a high standard of living. The recent severe climate changes require advanced technologies related to cleaner energy resources. One such technology beneficial for accelerating this current energy transition is geothermal energy. This type of energy is often found in fractured and karstified carbonate aquifers. Understanding the reservoir properties and reducing the risks of such subsurface-related activities is vital. This thesis attempts to understand the complex fractured carbonate reservoirs better and improve the numerical simulation capabilities toward large-scale uncertainty quantification.@en

The Earth’s subsurface exhibits a high potential for generating and storing energy. Engineered fractured systems, for example geothermal or carbon storage reservoirs, highly depend on the capacity of rock to conduct and store fluids. Faults and fractures create the largest contrasts in flow in these reservoirs and can enhance the reservoir potential when being generated or engineered. While the scientific focus is mainly on the effectiveness of enhancements and the risks associated with them, the sustainability of these enhancements must be better understood. In this thesis, the dependence of fracture permeability on a variety of parameters is studied. The aim is to develop a better systematic understanding of the hydro-mechanical processes controlling the potential and sustainability of fractures to conduct fluids at a variety of conditions. Several parameters that are assumed to control fracture permeability are considered in laboratory experiments. These include the rock type (clastic vs. crystalline), the fracture type (shear vs. tensile), the fracture geometry (aperture and roughness) and effective stress changes (pore and external stress). Potential geothermal rocks are considered in order to directly relate the findings to potential geothermal exploration projects. The results demonstrate the complex dependency on a variety of parameters and highlights the different physical processes depending on mainly rock and fracture type. An attempt was made to assess the potential of fractures to act as fluid conduits in reservoirs, as well their hydraulic sustainability during effective pressure changes. From these results, general implications are made concerning the ability and sustainability of fractures to conduct fluids depending on rock and fracture type. The main controlling parameters are assessed and possible mitigation strategies are developed to reduce the risk of permeability losses. Generally, only reservoir enhancement strategies resulting in a sustainable productivity increase can guarantee the scientific and political breakthrough of geothermal energy supply. @en

Responsibly using the subsurface for geo-energy extraction or storage requires an accurate understanding of the static and dynamic behaviour of the targeted reservoirs. While mostly dependent on intrinsic rock properties (e.g. porosity and permeability), this behaviour is also believed to be significantly impacted by the presence of natural fractures. For example, depending on their opening, connectivity, intensity or cement infill, natural fractures can both channel or inhibit fluid flow, thereby causing significant local flow heterogeneities which can both increase or decrease geo-energy production values. Therefore, assessing the possible characteristics of natural fractures has become an integral component in complex reservoir studies. @en