This thesis attempts to evaluate the extent to which UAV imagery can complement traditional geological fieldwork and to assess the behaviour of natural fracture networks across multiple scales. By conducting detailed field surveys and capturing high-resolution UAV images, the study provides a comprehensive comparison of the data, particularly in terms of fracture orientations, lengths, density, intensity and topology. The Parmelan plateau in France has been studied as a potential geothermal reservoir analogue. This study utilises an integrated approach combining fieldwork, high-resolution Unmanned Aerial Vehicle (UAV) imagery, and satellite imagery.

Field data collected using field scanlines were compared with data obtained from UAV imagery to evaluate the efficacy of each approach. The results indicate that UAV imagery, while advantageous for covering large and inaccessible areas, faces significant limitations in accurately identifying fracture types and orientations without supplementary field data. This discrepancy is primarily attributed to factors such as image resolution - limited visibility of small-scale fracture-type indicators.

The multi-scale analysis performed in this study shows that natural fracture networks exhibit similar behaviour across different scales, though some scale-dependent variations are evident. The findings highlight the importance of integrating UAV data with traditional field methods to achieve a better understanding of fracture networks. This integration is particularly important for optimizing outcrop analogue data used in modelling subsurface geothermal reservoirs, which can significantly enhance the efficiency of geothermal energy extraction.

Natural fractures play a crucial role in many sustainable subsurface applications, particularly in reservoirs with low primary porosity and permeability. Therefore, fracture analysis has become a fundamental aspect of geosciences, often starting with fracture interpretation from borehole image logs. It has been widely recognized that interpretations come with uncertainties; nevertheless, there is a current lack of both quantitative and qualitative understanding regarding differences among interpretations. This study aims to address this gap, by performing a statistical analysis on five interpretations of the same well, highlighting their differences and similarities. Based on the results from the analysis, a workflow was created to reduce uncertainties in fracture interpretations from image logs.

The created workflow was then applied to two wells in the Geneva Basin, Switzerland; associated with a geothermal project aiming to produce heat and electricity from the Upper Cretaceous limestone rocks. Research has shown that these rocks form a tight reservoir, and fluid flow will rely on the presence of fracture networks. In the two wells, a total of eight fracture sets were defined based on movement and relative chronology, and used to reconstruct the fracture history of the basin. This led to the identification of four Mesozoic to Cenozoic stress regimes: 1) a normal or strike-slip regime, 2) a NE-SW reverse regime, 3) a normal regime, and 4) a NW-SE reverse regime. The latter is considered the main deformation event of the region: the Late Miocene fold-and-thrust tectonics. In the Geneva Basin, this event is represented by a pair of NE-SW striking conjugates, which forms the majority of observed fractures. The fifth fracture set is believed to be fault-related and was only observed in one of the wells.

Beyond the regional implications, this study emphasizes the importance of uncertainty reduction in the early stages of fracture analysis, and its effects on establishing a reliable fracture history.

In the geothermal exploration well, NLW-GT-01, in the West Netherlands Basin, a very tight reservoir with low porosity (≤5.0%) and matrix permeability (≤ 0.1mD) has been encountered in the Main Buntsandstein Subgroup. The impact of natural fractures, which can significantly impact fluid flow in tight reservoirs, has been studied. However, there is a lack of consensus in different studies on the fracture classification.

In this study, a re-evaluation is performed of the well data of the NLW-GT-01 and VAL-01 wells. An analysis comparing core, geophysical, and image logs is performed to document the drivers and characteristics of natural fracture distribution in the WNB and investigate the geological and geomechanical parameters influencing the development of fractures in the Main Buntsandstein Subgroup.

On the core of NLW-GT-01 and VAL-01, five types of fractures are classified veins, joints, Mode II fractures, stylolites and drilling-induced fractures. The natural fractures have a dominant NW-SE strike orientation. The drilling-induced fractures and the borehole breakouts indicate a NE-SW oriented in-situ minimum stress and an NW-SE oriented maximum stress. The natural fractures are favourably oriented to be open based on their orientation compared to the in-situ stress orientation.

The fractures are associated with large-scale tectonic events. During the burial of the formation related to the extensional phase of the WNB during the Mesozoic, veins, joints, conjugate fractures, and stylolites could be formed. During the inversion of the basin in the Late Mesozoic-Cenozoic, tectonic stylolites could have been formed, and the previously formed conjugate fractures could have been reactivated.

Natural fractures are concentrated in more heterolithic intervals of the VAL-01 and NLW-GT-01 wells in both image logs and cores. These heterolithic sections display alternations of medium sandstones with silt- and claystones. The identification of more fractures in VAL-01 compared to NLW-GT-01 can be explained by the difference in basin location. VAL-01 is located in the centre of the basin where distal playa environments produced more fine-grained material alternating with coarser sands. The more proximal NLW-GT-01 is dominated by fluvial sands. The lithological variability produces Young’s and Shear modulus variability that seems to be driving increased fracture density rather than the
absolute value of the Young’s modulus causes this.

Permian deposits are found in outcrops and in the subsurface of Southern Tunisia, in the Jeffara Basin. Their stratigraphic and tectonic evolution is not yet fully understood and represents the main focus of this work. Aspects of the Permian system such as, lateral extend of formations, dating and paleo environments are not well constrained. Answering these questions will impact future hydrocarbon exploration and also improve the geological understanding of Tunisia. To achieve this, seismic lines and well data of the Jeffara Basin have been re-interpreted and re-correlated.

The results of the study indicate a lagoon depositional environment for the Early Permian, a carbonate self environment for the Middle-Upper Permian successions, with dimensions of 80 square kilometers and a general east-west orientation. The thickness of the carbonate deposits reaches a maximum of 2500 kilometers to the north of the reconstituted paleoshore. A Sabkha environment has been interpreted for the Upper Permian with significant deposits of anhydrite. Structurally, it was observed that the Permian is not affected by major normal faults.

Conversely, significant folds have been identified at the seismic data, with a general east-west strike and a northwards dip. Based on the displacement of seismic reflectors, two tectonic episodes have been identified. The first is dated to the Upper Carboniferous - Early Permian and the second to the Early-Middle Triassic. Decompaction calculations indicate low subsidence rates and general stability during the Early Permian. This was followed by significantly increased subsidence rates during the Middle and Upper Permian.

A novel 2D finite element method (FEM) on unstructured grid for nonlinear time-dependent deformation of materials is developed. The objective is to model the complex deformation behavior of the rock salt, inside which caverns are mined to store green fuels (such as hydrogen). The analyses and the developments of the present work allow for quantification of the state of the stress of the cavern, and assess the safety and reliability of the storage structure over time. The novelty of the approach is in using minimization of the potential energy principle in conjunction with nonlinear creep deformation physics. While the available FEM-based simulators offer tools only for solving linear and non-linear elastic models, the developed simulator takes into account cyclic loading and material’s damage evolution in time with possibility to predict the material’s failure. Apart from that, the stored product (hydrogen) density is taken into account, which affects cavern’s pressure variation with depth. Impurities,causing heterogeneous rock salt properties, are also considered in the developed model. Multivariate Gaussian distribution is utilized to generate distribution of the heterogeneous mechanical properties. Eulerian strains are introduced in the model to take into account deformation of the mesh. As such,the computational grid changes its geometry according to the deformation. Several numerical test cases are studied. Firstly, a consistency (verification) study is performed, to validate the linear elastic model. Remark that the linear elastic deformation model casts the basis of the non-linear model with creep physics. Then, several studies have been performed to analyze, quantify and approximate the deformation of the salt cavern under the gas pressure change, including the time-dependent creep physics.

A transition towards more renewable energy sources such as wind- and solar energy is underway. These sources can be unpredictable with regard to energy production and therefore energy storage has become a major concern. A promising technique, Underground Hydrogen Storage (UHS), converts excess energy into hydrogen and stores it underground, after which, by reversing the process, the stored energy can be used when the imbalance between supply and demand is great. Hydrogen storage in salt caverns is particularly attractive because of their high sealing capacity, low amount of cushion required, the inert nature of rock salt and high possible injection and withdrawal rates. For energy storage purposes, these salt caverns are exposed to different cyclic loading conditions during operation, resulting in variations in stress in and around the cavern. Investigation of the mechanical response of rock salt under cyclic loading conditions is essential for the safety assessment and usability of the cavern. The response of the system to varying loading conditions can be mainly divided into two groups, either time-dependent or stress-dependent. The main focus of this thesis is to record the stress-dependent behaviour of rock salt under varying loading conditions. More specifically, it focuses on nonlinearity that occurs due to viscoplasticity. This phenomenon can be described as the rate dependent
behaviour of a material that occurs when a material exceeds a certain stress level, after which irreversible deformation occurs. This thesis describes the development of a 2D FEM (finite element method) simulator on an unstructured grid that captures the mechanical response. To model the stress-dependent behaviour, the viscoplastic model proposed by Desai is used. This model is
based on the non-associated flow rule and takes into account material dilatancy and compressibility. In addition, the model allows for hardening, the tensile strength of rock salt and variation in yield behaviour with pressure variation. Sonar data from cavern EPE S43 is utilised to test the simulator. This case showed that irreversible deformation occurs as a result of the stress-dependent behaviour of rock salt. For this specific cavern, the total working volume of the cavern decreased roughly by 0.0003% over three operating cycles, indicating that viscoplastic deformation itself does not pose significant risks to the cyclic storage of hydrogen in salt caverns.

Geological surveying is a common practice performed by geologists nowadays. Determining layer orientation parameters and identifying folds are examples of features needed in order to create a geological map or model of the (sub) surface. Surveying is expensive and time consuming, therefore such survey is recently being investigated and implemented in 3D point clouds. This thesis provides a method to quickly obtain geological information such as orientation parameters and fold information in a semi-automated manner. Obtaining this parameters is currently still a difficult problem because of data density and calculation complexity.
Fast and reliable are terms important for the created method. Large point clouds can easily jam a system and reliability is important for usability and compatibility of the created results. A method is designed which can handle bulk data, performing operations such as filtering and noise reduction assisting in data handling. Next to general calculations such as roughness filtering, intensity filtering and directional filtering of generated normals, the use of a Graphical User Interface (GUI) greatly improves the reliability of the feature calculations. The user selects areas which are potentially interesting for acquiring layer orientation information, which are then analyzed by the method itself creating a base for determining the layer orientation parameters. This base is then used to attempt the reconstruction of the bedding layers of the geological outcrop resulting in the desired geological features.
The method has been tested on the “La Charce” dataset and the “Meso-scaled fold” dataset for method validation and on the “Pradelle 2” dataset for compatibility checking. Average calculation time is with approximately 10 minutes reasonable fast. The acquired dip direction of approximately 156 degrees is very similar to that of Prentice (2017), Bisschop (2017) and the fieldwork teams of 2016. The dip angle of 52 degrees is on the other hand off compared to validation results. The layer thickness calculations are comparable, all theses show that the bulk thicknesses between ~30 and ~70 cm. The fold dataset has no validation results but the images look good. It has to be mentioned that all results obtain commission and omission errors but these are in no comparison to the results which are correct.

In the northern part of the Netherlands, the exploitation of gas fields has been inducing small earthquakes, causing damage to existing buildings.
With the aim of preventing consequences to people and structures, the VIIA Groningen project deals with CC2 and CC3 buildings retrofit and provides reinforcement measures when necessary.
As part of the structural response assessment, after the NPR 9998 (2015), and eventual special cases from the latest NPR 9998 (2017), non-linear time history analyses (NLTH) are executed, comprising seismic ground response analysis (SRA).
The propagation of seismic waves through a 1D soil column is highly dependent on the characteristics of the materials constituting the soil deposits. Hence, it is essential to correctly interpret the soil properties, in order to achieve realistic representations of the in-situ conditions.

To interpret the soil layering at a particular site, the Cone Penetration Test (CPT) is commonly used in Groningen. It offers a quick, economical and reliable measurement of ground conditions. However, the CPT-based correlations used to estimate soil properties can constitute a source of uncertainty if not coupled with full-scale testing and laboratory measurements.
The present thesis, thus, deals with the verification and the improvement of two CPT-based correlations used for soil interpretation in Gronigen specifically. The research study focuses on the mathematical models related to the plasticity index (PI) and the undrained shear strength (Su) of soft soils present in Groningen.

A comprehensive database of factual data was compiled in order to group various test types and provide a best-estimate of soil properties for different soil types using geotechnical and stratigraphic considerations. Secondly, a statistical characterisation of data-sets was performed to obtain insight on the correlations performance in relation to the in-situ and laboratory measurements. Based on the outcomes of the statistical comparison, analytical and regression analyses were carried out with the scope of improving the correlation that was deemed to be inadequate. Additionally, a sensitivity analysis was executed to investigate the influence of three relevant soil properties on the seismic ground response from a typical soil profile from Groningen. The parameters assessed are: plasticity index (PI), undrained shear strength (Su), and shear wave velocity (Vs).

Results indicate that, among the considered CPT-based correlations, the equation for PI from Cetin and Ozan (2009) is adequate in some cases. The geotechnical units sandy Clay and Loam show good correspondence with the factual data. On the other hand, the PI predicted with such relation tends to be lower than the laboratory measurements for the remaining soil units (e.g. clean Clay, silty Clay, OC Clay). Conversely, the PI behind the models implemented in the NPR 9998 (Bommer et al., 2017a) are in closer agreement to the factual data, however, the
PI from some soil units can be further improved with the findings from the present research.

For the interpretation of Su, the SHANSEP model from Ladd and Foott (1974) is frequently used. The available factual data showed a poor correspondence with the predicted Su values. Therefore, the SHANSEP model was further studied to calibrate its parameters for different soil types. From the available triaxial consolidated undrained laboratory tests, best-estimate of SHANSEP coefficients were obtained for the main soil types (clean, sandy, and silty Clay). New Su values were validated with the in-situ and laboratory measurements. In this context, it is confirmed that the dependency of Su on the overconsolidation ratio (OCR) is crucial. Moreover, the estimation of OCR from CPT measurements (following the Mayne, 2014, procedure) is found to be partially inaccurate within the SHANSEP framework and needs to be studied in more detail.

Engineering aspects related to the topics of the research are discussed and considerations regarding the applicability of the new correlations are provided. Furthermore, the present study gives indications about the usefulness of a number of test types, suggesting direction for future soil investigations. In addition, look-uptables for PI and Su, based on the outcomes of the present research, are provided as part of the recommendations for implementation in the soil parameter interpretation for the Groningen region.

The subsurface of Groningen gas field composed of several faults. The continuous production has been resulting in several micro-seismicity activities, particularly for the past decades. One of the reasons for the production-induced-seismicity is fault reactivation at depth. The fault that initially in the non-active state becomes active and starts slipping due to pore fluid extraction. The modelling of fault reactivation induced by production can be simulated by coupling of flow and geomechanics.

The project studies the coupling of flow and geomechanics for an idealistic subsurface model with fault. The flow occurs due to pore pressure depletion and is predicted by solving mass conservation. The corresponding deformation is estimated by momentum balance equation.

The observation will be limited to rock deformation that is quantified by effective stress and displacement on the fault due to a pressure change in the subsurface. The simulation is performed using Stanford's Automatic Differentiation General Purpose Reservoir Simulator (ADGPRS).

In the proposed model, the flow equation is discretised using finite volume method, and poromechanics is discretised by finite-element Galerkin's approach. Both problems share the same grid model, and there is no error associated with the information exchange. The coupled problem is being solved fully implicitly where flow and mechanics formulation are solved simultaneously.

The case study for the simulation is a simplified Groningen subsurface model with a fault zone. The impact of variability in production dynamic on fault reactivation is studied. The variations in production rate and production strategy are applied in different formation configurations. It is found that the correlation between the production rates and the stress state in the subsurface depends on the formation offset. However, the stress field does not depend on continuity of the production scheme. Several aspects including the presence of Gas-Water contact in the model was studied in this project as well.

A rock fracture is a mechanical break or discontinuity that separates a rock body into two or more parts. The continuity or cohesion of the rock body is lost across a fracture. Fractures are formed in response to stress on a rock. A rock breaks and forms a fracture when the applied stress reaches the rock strength. Vertical fractures improve connectivity between multiple layers, and can aid the production of geothermal and petroleum reservoirs.
The heterogeneity of layered reservoirs leads to significant variation in mechanical properties, which in turn influence fracture nucleation, fracture growth and fracture geometry. This variation in rock mechanical properties, combined with layer thickness, is called mechanical stratigraphy. Natural fractures are subject to controls imposed by mechanical stratigraphy. Focusing on the mechanisms that control natural fracture development can improve fracture characterization. As rock strength is an important part of mechanical stratigraphy, the term mechanical contrast is introduced to examine the effect of contrasts in rock strength of adjacent layers.

This study examines the effect of the mechanical contrast and confining pressure on fracture behaviour in layered rocks in the laboratory. The focus of this study is threefold, it examines the effect of mechanical contrast and confining pressure on fracture propagation, fracture orientation and fracture aperture in layered rocks.
Unconfined and confined compressive strength tests have been performed on layered samples with varying mechanical contrasts at different confining pressures. A total of 169 tests have been performed which include confined and unconfined compressive strength tests on layered and monophase samples and brazilian tensile strength tests and velocity measurements on monophase samples.

The results show that fractures initiate in the weakest layer and propagate through the layer interface or are contained within the weakest layer. Unconfined compressive strength tests showed that differences in rock strength do not always act as a containment barrier.
The combination of mechanical contrast and confining pressure does control the containment of fractures within a layer. Lower horizontal compressive stresses are required to contain fractures when the mechanical contrast increases.
Mechanical contrast does not seem to influence fracture aperture. Confining pressure however greatly influences fracture aperture as it limits the ability of fractures to dilate.
Results show that fracture orientation is controlled by mechanical contrast. Fractures refract at layer interfaces when the mechanical contrast is sufficiently high. Confining pressure does not seem to affect the refraction of fractures.

The experimental results can improve the understanding of fracture containment, fracture aperture and fracture orientation in layered rocks at subsurface conditions. The mechanical contrast of the layered rocks, combined with the stress conditions need to be considered when characterizing subsurface fractures.
Vertical connectivity between layers is of importance when predicting fluid flow through reservoirs. As frac tures often serve as preferential fluid flow paths, correctly interpreting fracture characteristics is important for successful development of layered reservoirs.

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.

Gas injection processes suffer from poor volumetric sweep efficiency due to phenomena such as viscous fingering caused by density contrast between the injected gas and the displaced fluid, channeling due to heterogeneities in the reservoir and gravity override due to the inherent lower density of gas. One possible way to overcome these negative effects is by foaming the gas. Foam can be defined as a dispersion of gas separated by lamellae in a continuous liquid phase. Lamellae stability is enhanced by adding surfactants to the aqueous phase (Lake, 2014). The underlying idea is that the pitfalls of gas injection can be overcome by trapping the gas and therefore reducing its mobility. The benefits of foam flooding have been reported by several authors (Almaqbali et al., 2017, Li et al., 2009, Chalbaud et al., 2002, Patil et al., 2018 ) however, to implement field scale projects, an accurate representation of foams in models that can be applied to reservoir simulators is of paramount importance. In this sense, two main families of foam modelling exist today. One family referred as population balance models, treat foam texture and bubble size explicitly and another family, that treats foam texture implicitly by applying a mobility reduction factor to gas mobility.
In the first part of this document, a model that treats foam texture implicitly will be used to evaluate foam performance in a heterogenous reservoir consisting of two layers with different permeabilities. The model known as STARS (Computer Modelling Group, 2010) reduces gas mobility using semiempirical functions that represent the physics governing foam texture. One of the functions used by the model is the dryout function, which represents the effects of water saturation on foam coalescence. This function is tuned by a couple parameters, namely, fmdry and epdry that control the water saturation at which foam dries out and how fast it dries out, in other words, how abrupt its collapse is. Farajzadeh et. al, (2015) found that these parameters were permeability dependent.
Inspired by these findings, in the modelling section of this project, foam performance in a two layer reservoir with different permeabilities under varying injection conditions is assessed. Each layer will have its unique set of parameters, namely, fmmob, epdry and fmdry. We are interested in seeing the effects that epdry has on foam performance and the effects of having vastly contrasting foam strengths between layers (large fmmob contrast). The results suggest that epdry can have significant impact on foam performance in the high quality regime. Interestingly, it was found that large fmmob contrast reduce vertical conformance and can reduce recovery efficiency in the high quality regime.
It is known that oil can have negative impact on foam stability, however most studies treat gas and oil as different phases. Under miscible conditions, oil and gas become one phase and the extent to how oil destabilizes foam is not clearly understood. Kahrobaei et. al (2017) found in core flood experiments a unique rheological behavior in foams with miscible mixtures of Carbon Dioxide – Decane. Their experiments showed three distinguishable apparent viscosity regimes depending on Carbon dioxide fraction. Regime 1, in which apparent viscosity increased with increasing CO2 fraction; Regime 2 in which apparent viscosity decreased with increasing CO2 fraction; and Regime 3 in which apparent viscosity is constant independently of the CO2 molar composition.
Inspired by Kahrobaei et. al, (2017) findings, the second part of the project attempts to investigate, using microfluidics, the effects in foam texture caused by compositional changes in an AOS surfactant solution and a miscible Carbon Dioxide – Decane mixture. Unfortunately, due to set-up limitations and inability to reliably mix the components, the experiments were inconclusive. Nonetheless, valuable lessons learnt are presented that will facilitate the experimental approach if someone decides to continue with this line of investigation.

The production and injection of fluids from and in reservoirs leads to changes in the in-situ stress in the subsurface. This can cause reservoir compaction, subsidence, fault reactivation and / or seismicity. As these effects may greatly influence society it is of importance to find accurate methods to describe them so they can be predicted or even better, mitigated.

This thesis discusses a new analytical approach to calculate stress in the subsurface which incorporates the effects of differential compaction on the initiation of fault reactivation. This new approach is named Differential Compaction Loading (DCL) and the reason for its development is due to discrepancies observed between calculations using the Mohr-Coulomb failure criterion, also known as Poro-elastic Loading (PEL), and field observations.

Geomechanical modelling was performed to assess fault failure sensitivity to a range of geometrical aspects as well as reservoir and fault properties. From this analysis, focusing on the reactivation pressure at which failure first occurs, an empirical sense of sensitivity was established. It was found that for the examined variations in the geometry the fault dip angle resulted in the largest spread in reactivation pressure. For the examined reservoir and fault properties, the friction angle was found to have the largest sensitivity.

With these results it was possible to improve the estimates of essential parameters within the analytical approach, yielding a better fit between analytical and modelled solutions. These solutions lie closer to field observations. Hence, the new method of DCL shows a great improvement in calculation of stresses in the subsurface, compared to the method of PEL. This calibrated analytical approach allows for a quick assessment of the fault stability within a reservoir. Additionally, through the results from the geomechanical model new insights were obtained into the way stresses change and behave when a reservoir is depleted. The rotation of the principal stresses for each level of depletion was quantified and a new definition of the critical fault angle, the dip angle which will fail first, was derived. This links the depletion pressure and related rotation angle directly to a value of the new critical fault angle when DCL is present.

Ultimately, these new insights into fault failure behaviour of boundary faults could be a useful tool in the step towards prediction and mitigation of production or injection related seismicity.

The fluid flow in a reservoir largely depends on faults, as faults can act like conduits or barriers. The influence of three fault parameters (permeability, thickness and angle) on the temperature and pressure behaviour of a geothermal reservoir, has been investigated by modelling a faulted reservoir in 2D in MATLAB, based on the Finite Element Method. The reservoir is assumed to be sandstone with a permeability of 40*10-14 m2. The fault has been modelled with a permeability ranging from 10-11 m2 to 10-17 m2, a thickness ranging from 10 cm to 150 m and an angle ranging from 0 to 90 degrees. While varying one parameter, the other two stayed fixed. The base values for the fault permeability, thickness and angle were 10-14 m2, 20 m and 0 degrees respectively. Both a finite and infinite fault have been modelled in the reservoir. Decreasing the permeability led to a higher production temperature, especially at a finite fault, where the fluid is able to bypass the fault and thus sweep the warmth of a larger part of the reservoir. At a fault permeability of 10-14 m2 the fluid has seemed to have extracted the maximum amount of heat in the reservoir, further decrease in permeability did not lead to a higher production temperature. At an infinite fault there is only a small increase in temperature at a fault permeability of 10-16 m2. The impedance at a finite fault is not much affected, as the fluid is able to flow around the fault. The impedance at an infinite fault, however, rapidly builds up with decreasing permeability. A thickness of 20 m, at the base permeability value of 10-14 m2, results in the highest production temperature. Larger thicknesses cause larger amounts of unrecoverable area and consequently less heat can be extracted. At a finite fault the impedance climbs only to a value of 4 MPa at a thickness of 150 m, but at an infinite fault the impedance already reaches 10 MPa at a thickness of 80 m. The fault has its largest influence at a perpendicular position to the flow. At a parallel position, the results are the same as a reservoir without fault, as the fluid will not have to dodge a lot to reach the production well. All three fault parameters have a significant influence on the temperature and pressure behaviour of the geothermal reservoir. They are all able to enlarge and eliminate the influence of the fault. A finite fault can cause a favourable higher production temperature without a large impedance, as the fluid is able to bypass the fault. An infinite fault has less effect on the temperature and causes the impedance to build up rapidly, which requires an unrealistic high pumping power and consequently an unprofitable geothermal system.

There is an increased need for modelling the Dutch overburden to improve the prediction of earthquakes and subsidence due to the extraction of hydrocarbons. Depending on the surface location, the subsidence model of the NAM can under or over predict the amount of subsidence by 4 to 5 cm. This is around 15 % of the current maximum subsidence of 30 cm. The underlying assumption of the NAM subsidence model is that the reservoir, and the overburden above it, behave the same and thus have the same elastic parameters. The purpose of this research is to obtain a better understanding of the role overburden heterogeneities play in man induced subsidence. The main research question is: To what extent do overburden heterogeneities affect subsidence caused by reservoir depletion? Followed by the hypothesis: The heterogeneities of the overburden affect subsidence and should therefore be incorporated.
The results show that modelling the overburden as multi-layered, rather than as one homogeneous layer, leads to a difference of 0.75 cm. This is greater than the measurement error of the InSAR data, which is used to determine the subsidence of the Groningen field, and is significant when compared to the current discrepancy of 4 to 5 cm. Elastic parameters have been calculated from acoustic well data for geological units around the Groningen area. The calculated values differ from the values used by the NAM. When the calculated values are used for the Upper North Sea and Lower North Sea groups, the difference with the reference model is up to 2 cm for a reservoir radius of 3 km and 0.87 cm for a Groningen scale reservoir. The results suggest that the heterogeneities of the overburden affect subsidence significantly enough to warrant further investigation. Due to the fact that the obtained results are for horizontal layers, there is much potential for more complex overburden geology e.g. salt structures and non-horizontal layers.