Energy plays a fundamental role in societies impacting everything from basic human needs like lighting, cooling and heating to complex industrial processes that significantly influence social development, economic growth, and national security particularly in terms of access and affordability for all citizens. The world’s electricity demand grew by 2.2% in 2023 and is expected to rise at a faster rate by an average of 3.4% in 2026 (IEA, 2024). With the global climate warming, it is important to reduce our societal impact on Earth by using clean energy sources. One of the clean sources is geothermal energy which has a great potential to reduce dependency on the fossil fuels. Geothermal energy sources can deliver both, heat and electricity. Tanzania has a huge geothermal potential that has not yet been used and has only been explored to a limited extent. This thesis attempts to identify the geothermal potential of southwest Tanzania with appropriate drilling zones by assessing the main components of a geothermal system reservoir which are temperature, permeability and fluid flow at Songwe Tanzania. It is one of the identified potential development areas with very little information available.
The work flow begins with chapter 2 where a geological and thermal numerical model is set up to simulate the temperature at depth. The thermal model considers pure conductive heat flow to achieve a first idea of the temperature distribution in the different geological layers.
Chapter 3 describes the conducted field study at the thermal spring areas as well as the laboratory analysis of the samples in order to understand the geothermal fluid source by using geochemical modelling, obtain the reservoir temperature through geothermometer calculation and locate the up-flow and the outflow zones of the geothermal field.
In chapter 4 numerical simulations of fluid and convective heat flow are performed to allow understanding the heat transport by fluids and the hydrogeological behaviour of the geothermal reservoir by varying thermal and physical parameters.
Chapter 5 shows possible drilling locations for a first geothermal well in the study area, whereby areas of different productivity are distinguished.

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Capturing CO2 directly at industrial complexes and safely storing it in the subsurface is one of the proposed mitigation measures of climate change. One of these challenges is identifying suitable reservoirs that ensure the safe and permanent storage of CO2. Therefore, detailed integrity assessments should be performed on the caprock to accurately determine and manage the risks involved in the permanent storage of CO2 (Kaldi et al., 2013). This should include leakage risk quantification of (sub-seismic) fault zones in the primary seal (Zappone et al., 2021). This thesis aims to understand and predict the probability of caprock leakage through a fault-related fracture network. It specifically focuses on the network organisation of fault damage zone (FDZ) fracture networks and the impact of their topology on the connectivity of the fracture network. Topology, in the form of fracture node classification, has been used to determine the connectivity of fracture networks (Sævik and Nixon, 2017). However, this research points out that the connectivity of a fracture network cannot be solely determined by a linear relationship between the fracture node ratio and the connectivity. This methodology does not effectively succeed in capturing connectivity differences of different fracture networks. To research these differences, a measure of connectivity is introduced based on the graph theory concept of the giant component. In this concept, networks are connected by a certain amount depending on their  node type. By using the total length of the giant component we find the largest component ratio (LCR). This measure of connectivity and its relationship with percolation was tested using a DFN simulator. The concept of the giant component allows us to study the connectivity of various fracture networks. This is done by developing an algorithm that is based on the concept of robustness that removes fracture segments from a fracture network, which in turn enables us to find a relationship between the topology and the connectivity of the network and assess its uncertainty. From the DFN simulations and the robustness algorithm, it is found that the relationship between connectivity and topology is unique for different fracture networks. However, it was concluded that in general a fracture network significantly starts to increase in its connectivity when the average node has 1.6 edges connected to it (k). It also showed that the highest uncertainity of fracture network connectivity is present at 1.9<k<2.2.

The aim of this study is to reduce the risk of the ongoing Geothermal exploration effort in Geneva Basin by estimating the influence of the natural fracture on the reservoir properties. A Discrete Fracture Network (DFN) was generated to resemble the fracture network in the Lower Cretaceous carbonate reservoir. The DFN modelling approach is using a novel workflow that is based on a geomechanical forward modelling simulation approach. Two 2D seismic lines and well data, including interpreted fractures using Borehole Image (BHI) log, were used to prepare the model inputs. Some results were derived from the fracture data that were also used to prepare the model inputs. In general, the fracture data have fairly constant orientation along the Lower Cretaceous interval. In this study the fractures are assumed to be formed under a single tectonic regime. However, when partitioning the fractures in different stratigraphic formations, a change in the direction of the fractures with depth is observed. This observation could be explained by the variation in rock's stiffness between different stratigraphic formations.
Two techniques were used to model the subsurface fracture network: paleo-tectonic stress inversion and fracture network forward modelling techniques. The modelled DFN resembles the fractures geometry at the well location whereas away from the well the model is constrained by the subsurface fault geometry and far-field tectonic stress. Moreover, the modelled DFN consists of multiple 2 meters thick layers where each layer include a layer-bound fracture network. One of the main limitations of this approach is that it can not consider multiple tectonic regimes to simulate the fracture network. In addition, this approach requires large computational power.

As the world’s population continues to increase, the demand for energy also increases. However, the use of fossil fuel energy has resulted in disadvantageous impacts for humans and the Earth. This condition becomes a good momentum to find a clean and more sustainable energy resources, given the fact that fossil fuel energy is a non-renewable resource that someday, in the future, its availability becomes scarce. Additionally, environmental awareness concerning energy-mix use and combating climate change also increases globally. Geothermal energy is one of the better alternatives for energy sources, as it is renewable as well as clean and green. A study from the Netherlands Organization for Applied Scientific Research (TNO) says that deeper Triassic sandstones, with possibly higher temperatures, could also potentially contain geothermal reservoirs. Therefore, this condition has paved the way for the exploration of the deep reservoir. The assessment of geothermal production usually faces considerable uncertainty due to, among other things, lack a comprehensive geomechanical model. Therefore, knowledge of the current state of stress is essential to address a wide range of problems that might arise during geothermal exploration and production—those problems such as wellbore stability, fault reactivation, induced seismicity, and deformation in depleting reservoirs. This study aims to construct a 3D geomechanical model in the Lower Germanic Triassic group, in De Lier field. By using the effective stress ratio concept, a 3D geomechanical model is constructed to describe the principal stresses distribution. The principal stresses distribution determines how the faulting stress regime will be formed. The vertical stress, as one of the principal stresses, is controlled by depth and density. On the other hand, the minimum horizontal stress is controlled by Poisson’s ratio. Four models are constructed based on several assumptions. In the model where gravity is the only source of stress, the maximum principal stress σ1 is always vertical. Whereas, in the models where tectonic stress is included, three depth intervals related to the faulting stress regime are observed. Imposing greater tectonic stress to the model will shift the depth of transition downward. Cross-section analysis shows that the local principal stresses variation due to the presence of different stratigraphic units and geological structures (faults and fractures). Fractures and faults at particular depth are inactive under the current stress field. Furthermore, pore pressure and friction coefficient have a significant impact on faults and fractures stability.

This report contains the results of the two thesis studies that finalise a combined MSc--programs of Reservoir Geology and Science Communication. The first part of the report comprises the multi-scale data (kilometers to meters scale) analysis of a) the large--scale architecture of the subsurface Daly Waters Arch which was obtained from seismic data interpretation; and b) fracture pattern characterisation by outcrop measurements and drone imagery in the Tomkinson Province. Both the Daly Waters Arch and the Tomkinson Province are located in the largely undeformed Palaeo-- to Meso--Proterozoic Greater McArthur Basin in the Northern Territory, Australia. In July 2019, a geological fieldwork was conducted in the Tomkinson Province to collect the fracture data with the drone. In this research, the Daly Waters Arch and the Tomkinson Province have been geologically linked based on seismic and fracture data. By discussing analog cases of far-field deformation, these results have been placed in a larger context of large--scale basin deformation.

The second part of the report focuses on the Netherlands, where ambitious goals have been set for the implementation of geothermal energy in the energy transition. During the gas production in Groningen, a negative social perspective towards mining operations, in general, was developed. For the implementation of geothermal energy, an approach for the communication of technical uncertainties between the initiators and the local public of a geothermal project is designed in this study. Technical uncertainties that are present in geothermal energy implementation in the Netherlands have been identified during semi-structured expert-interviews with different stakeholders in the spectrum of geothermal energy. The approach addresses guidelines for the communication of the context, the goal, the technical uncertainties present in the geothermal project, the main communicating actors, their reference frames, and the situation in which the communication process takes place.

The interest in carbonate lithologies has risen in the last few decades, due to discoveries of giant and supergiant carbonate reservoirs. While studying the properties of this lithology, the existence of cave systems at great depths was highlighted, since their presence can lead to drilling related problems, as well as change the flow direction of fluids in the subsurface. The possibility of predicting their orien- tations, dimensions and mechanical stability in the subsurface would therefore be of great help in the hydrocarbon business, which is why in this study, thanks to data provided by a Lidar laser scanner, a dimensional analysis of caves’ conduits related to their position within the karst system is performed. The origin of caves can be hypogenic or epigenic and they can present different patterns of distribution of conduits. When deformation events cause the generation of orthogonal sets of joints in the rock layers and fractures intersect with each other and with bedding planes, the fluid flow in the subsurface becomes channelized into these features. The combination of this and speleogenetic processes leads to the development of maze caves, whose conduits’ dimensions vary within a system as a consequence of differences of continuity and connectivity along a fracture network. Variations in the shapes of caves’ conduits can be observed as well, depending on the supply of sediment and the position relative to the water table during dissolution. Mechanical deformation of karst systems can be simulated by using the linear elastic deformation mathematical model. In this way it is possible to study the influence that mechanical properties such as Young’s modulus and Poisson’s ratio have on the mechanical stability of caves in the subsurface.

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.

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.

This paper investigates surfactant flooding using a microfluidic device. Its purpose is to validate the results obtained in recent core experiments reported by Janssen et al. (2019) and provide mechanistic interpretation. In these experiments authors injected a surfactant slug into sandstone cores, initially brought to residual oil saturation. Low oil/water IFT leads to oil mobilization and the formation of emulsions. Furthermore, authors found that oil is more effectively mobilized when the injected surfactant is at optimum salinity. In this study the following experiments are subsequently conducted in a microfluidic device to validate this optimum surfactant slug: primary drainage, waterflooding and surfactant flooding. In case of the surfactant flooding experiment, the micro-emulsion formation was observed at 1.5 PV and 1.25 PV for the under-optimum and optimum conditions respectively. In both conditions, an increased oil mobilization was obtained, compared to the waterflooding experiment. However, the optimum condition, with a slug salinity of 2.0 wt% NaCl outperformed the under-optimum condition with a slug salinity of 0.4 wt% NaCl in terms of oil recovery. The increased salinity in case of the optimum condition results in an lower IFT compared to the under-optimum condition, which in turn results in an higher capillary number. The obtained results indicate a dependency between the capillary number and the amount of oil droplets. The optimum capillary number can be found at the lowest oil saturation with the largest amount of droplets. Based on the results obtained from the conducted experiments on this microfluidic device, upscaling is considered to be a viable and educated recommendation.

More than 30% of the world’s hydrocarbon reserves are located in carbonate reservoirs, and this percentage is likely to increase, as a result of discoveries of new giant oil fields in carbonate rocks, generically named “Pre-salt layers”. However, there are still some problems in understanding karst systems that still unresolved. The karst caves are one of the suitable analogs for karstic reservoirs that also spread all over the world. In this study, the mobile LIDAR (Light Detection and Ranging) data is used to characterize the geometries and to analyze the stability of tunnels under several depths from 5 caves in Bahia, Brazil. The studied caves are representing both of the karstification mechanism (Epigene & Hypogene). In general, there are two tunnel shapes among the caves: horizontal ellipse & Vertical ellipse shapes. Several factors could be controlled the shape origin of the tunnels, but from this study mainly caused by lithology or the geology structure factor. By comparing with the structural data, the conduit orientation generally shows the same trend. Therefore, these conditions suggest a geometrical correlation between the fractures and the caves, and that the observed fractures almost certainly acted as conduits for fluid flow. The stability analysis showed that the vertical ellipse tunnels are more stable compared to the horizontal ellipse. However, all of the tunnels are already unstable in shallow depth (on average less than 2 km depth). The sensitivity tests show several parameters that would affect the stability: Rock Properties (Rock Mass strength, Rock mass elastic, density), number of tunnels in the system and the distances between multiple tunnels.

Carbonate reservoirs are of significant importance as they host a high percentage of the world’s oil and gas reserves. They are however subject to dissolution and may be heavily karstified often resulting in large cavities which may impose major hazards in drilling and production. In many cases, difficulty remains due to poor understanding of karst geometry and how it is distributed. This research presents a geometry and stability analysis using LIDAR (Light Detection and Ranging) data on cave systems in Brazil that can serve as direct analogues to subsurface carbonate reservoirs and therefore enhance our ability to predict them. Our study area lies in the state of Bahia in Brazil and consists of five caves: Diva De Maura, Torrinha, Ioiô, Lapinha, and Paixáo. These cave systems occur in Neoproterozoic carbonates of the Salitre Formation in the Irecê basin of the São Francisco Craton. Analysis of the geometry shows existing preferential karstic developments and tunnel shape patterns mainly classified in two, horizontal ellipse and vertical ellipse. Analysis of geologic structures and orientations of cave passages show that these caves exhibit marked structural guidance with two main orientations N-S and E-W. This aligns with the regional phases of deformation corresponding to collisional events that occurred on the margin of the São Francisco Craton. Stability analysis shows that tunnels aspect ratio is a major parameter controlling the stability, whereas the dimension of a tunnel has a much less effect on stability. Tunnels with aspect ratios less than 1 show a collapse depth greater than 1000 m and are more stable than tunnels with aspect ratios greater than 1. Results show that almost all tunnels with a horizontal ellipse geometry are supported with rock that is already undergoing severe deformation at a depth of 500m. Sensitivity tests show that overburden and rock mass strength parameters namely cohesion have the largest effect on the stability results.

Despite recent drop in the growth of global oil demand, the trend is expected to gradually pick up and continue increasing. Industrial and transportation sectors are still considered the highest consumers of oil. The petrochemicals sector’s demand for oil is increasing sharply and expected to continue in that fashion for the upcoming years. As oil fields age and mature, extraction of oil via primary and secondary techniques becomes, to an extent, inefficient. That encourages more research and development in enhance oil recovery (EOR) methods. In EOR, the aim is to either change a physical or chemical property of reservoir fluid in order to improve the oil recovery factor. The techniques can be categorized as thermal, physical, chemical or gaseous. In this experimental study, the lessons learned from gas flooding methods and surfactant flooding methods are taken into account in order to come up with a novel Foam-Assisted Chemical Flooding (FACF) procedure that aims to enhance the oil recovery factor to its maximum. In this approach, a surfactant slug solution is injected into a core at residual oil after water flooding conditions to mobilize trapped oil by capillary pressure. Then, a surfactant drive solution is co-injected with N2 for foam generation to serve as mobility buffer displacing the accumulated mobilized oil. The experimental study is performed under reservoir conditions of 90 ±1oC temperature and 20 bar of back pressure. In this study, surfactant stability is tested in synthetic formation brine. Then, phase behaviour tests are conducted to identify the capability of the surfactant to reduce o/w interfacial tension (IFT) to ultra-low values. The resulting solutions are categorized into their associated Winsor Types and classified based on salinity as under-optimum, optimum and over-optimum. A final surfactant slug solution is formulated based on these tests. Afterwards, bulk foam tests are performed in absence and presence of crude oil to test surfactant foaming ability and the resulting from stability and strength. Core-flood experiments are carried out to assess the possibility of generating foam in porous media in absence of crude oil and at residual oil to waterflooding. Full EOR FACF experiments are conducted, two at under-optimum and two at optimum salinity conditions. Two FACF experiments are performed with the assistance of medical CT scanner. In one FACF experiment, the foam is pre-generated utilizing a mixing tee and then injected into the Bentheimer sandstone. The study reported here showed that surfactants are not stable in synthetic seawater injection brine, as it tends to form complexes in presence of divalent ions, and subsequently generate precipitations. Stability was achieved by removing the divalent ions from the synthetic brine. In addition, phase behaviour study yielded that surfactant (A) is a better o/w IFT reduction agent than surfactant (B). A distinct layer of micro-emulsion was observed in excess of water and oil phases. On the other hand, surfactant (B) displayed better foaming abilities than surfactant (A) in absence of crude oil. Using surfactant (B), foam was generated in multiple qualities in a Bentheimer sandstone core-flood experiments in absence of crude oil. The critical foam gas fraction was found to be 75%. However, attempts to generate foam in porous media at residual oil to water flooding conditions were not successful. In three FACF core-flooding experiments, weak and unstable foam was generated during the surfactant drive co-injection phase. Whereas, in the last FACF experiment where a mixing tee was utilized, pressure drop and gas breakthrough data show that stable foam was generated. The CT images from two FACF experiments, one at optimum and the other at under-optimum salinity conditions displayed unstable water front in waterflooding phase, and unfavourable mobility conditions, during the surfactant slug injection. However, the effect of salinity conditions was seen in the different oil bank shapes in both experiments. The one at under-optimum salinity condition showed more unstable front. The study reported here showed that the FACF technology yields improving oil recovery of 70±5%, 77±5% and 73±5% for the FACF experiments where it was very challenging to generate foam in-situ and reached up to 80±5% of oil initially in place in the case where foam was pre-generated outside the core (55%, 61%, 59% and 46% are the oil recovery factors after waterflooding, respectively). The study revealed that drive foam strength has a bigger impact than its surfactant slug salinity.

The geological history of the McArthur Basin (NT Australia) is poorly understood. It consists of five onshore Paleo- to Mesoproterozoic packages with mainly siliciclastic and carbonate rocks, with cumulative thicknesses up to 15km. The basin contains the world’s oldest hydrocarbons, principally hosted in unconventional reservoirs in the Wilton Package. Fluid flow in these reservoirs is related to natural, reactivated or induced fractures. Characterizing the fracture network is an important part of predicting fluid flow. This study tries to link the geological history to the generation of fractures.

The geological history needs to be better understood to characterize the fracture network. In this study seismic, well, outcrop and geophysical data are integrated to construct a cross section that links outcrops (Batten Fault Zone and Broadmere Complex) with the subsurface (Beetaloo Sub-basin). The literature in combination with the cross section is used to revise the geological history.

A fieldwork is conducted to study fracture geometries on outcrops of the Wilton Package that are analogues to subsurface fracture networks. A drone is used to image fracture pavements at an order (10²m) that is normally missed by geologists (10¹m) and satellite images (10³m). The Tanumbirini-1 well, located in the sub-basin, provides a FMI log for interpreting fractures in the subsurface. A key objective is to differentiate fractures associated with fracture drivers like regional stress, folds and faults.

This study identified two unconformities in the seismic data, corresponding to two deformation events. The Carpenteria Event between the Wilton Package and the Inacumba Group is associated with a dominantly N-S oriented stress field and the Borroloola Event within the Inacumba Group corresponds to a mainly E-W oriented stress field. Both events created their own fracture sets and are observed on outcrops and in the subsurface. The tectonic stress is σ₁ at the surface but σ_H,max in the Beetaloo Sub-basin. Fracture generation in the sub-basin happened at another stress regime than the surface outcrop analogues, making any direct comparison less reliable. Hence this study gives a prediction of the fracture density and permeability trends in the sub-basin. A conceptual model of the subsurface permeability is proposed where the permeability trend is mainly E-W oriented.

In the context of the energy transition, rapid development of the geothermal sector in the Netherlands has to take place. The first steps have been taken by establishing the Green Deal UDG between multiple industrial consortia, which agree to share knowledge on the research and use of ultra-deep geothermal energy . The Dinantian carbonates are of interest for the deep geothermal wells, because of their high geothermal potential. This research project provides a case study of the Californië geothermal doublets in Limburg (NL), which are currently the only geothermal wells in the Netherlands producing from the Dinantian carbonates. However, the static and dynamic model prove that the Devonian Bosscheveld formation and Condroz group are also part of the reservoir formation. Due to the tight matrix of the reservoir rocks, the permeability is believed to be fracture and karst (meteoric and hydrothermal) driven. The goal of this Thesis is to create a static and dynamic model of the reservoir that confirms the current production data (history match) and that explores the development of the geothermal potential of the reservoir in space and time. The static and dynamic reservoir model are based on a limited amount of well and seismic data, which forms the main challenge in this project. A framework of assumptions has been created to construct the model and a scenario- based approach has been applied to construct a best case scenario that matches the production data. A key element in the static reservoir model is the Tegelen fault. To estimate the impact of the Tegelen fault on the permeability distribution in the reservoir, a fieldwork in an analogue carbonate quarry has been executed. The results are applied in the static model. The dynamic results in this study show that the permeability configuration applied in the best case scenario results in BHP, flow rate and temperature values that are of the correct order of magnitude and within an acceptable error margin of the production data. Multiple sensitivities have been simulated to determine the range of parameters that may cause an inaccuracy in the results. Additional data acquisition is necessary to validate and optimize the static model, which will result in a dynamic model with an improved history match and a larger predictive power for future production and reservoir management.

Faults can both improve producibility and fluid flow in hydrocarbon reservoirs, and cause leakage and instabilities in sealing layers. For this reason it is of importance to create a multiscale understanding of the drivers behind deformation, and how deformation is accommodated. Carbonates have always been of interest to the oil and gas industry as carbonates house some of the world’s largest oil and gas reserves. Understanding, and maybe predicting the geometries and fracture types could therefore be of integral importance to the E&P industry. For that reason two seismic datasets were provided for analysis on both a Fault Network Scale (faults over >1km in length) and a Small Seismic Scale (faults <1km in length). For the Fault Network Scale Petrel was used for seismic interpretation of the faults, as only the largest faults were interpreted in both seismic datasets. For the Small Seismic Scale OpendTect was used for enhanced seismic interpretation. OpendTect’s fracture enhancing attributes and filters provide seismic images with a high level of detail. These attributes were applied to 5 generated steering-cubes, to display even the smallest faults. The results on the Fault Network Scale show that most faults are caused by regional tectonics. However in areas where salt is underlying the chalks of the Chalk Group, halokinesis is the main driver of deformation. On the Small Seismic Scale drivers behind deformation differ more, fluid expulsion drives polygonal faulting patterns in areas where salt tectonics or far field extensional tectonics are absent. Towards halokinesis structures salt tectonics will be the main driver behind deformation. In areas where salt is absent, far field tectonics can still influence chalks forming fractures either parallel or perpendicular to the major surrounding faults.

A seismic survey acquired by the petroleum company Wintershall has been used for this study in order to characterize the fault and fractures present in the area using the latest seismic attribute techniques. With the use of the software OpendTect from dGB Earth Sciences and a methodology developed by (Jaglan Hardeep, 2016) and (Qayyum F, 2015) is used in order to apply the latest seismic attributes to enhance the detailed characterization of fault and fractures from a seismic survey acquired by the petroleum company Wintershall over the F10 block in the Dutch North Sea, offshore The Netherlands.
The methodology to enhance faults and fracture is divided in three phases based on their objective. The first section of the methodology focuses on conditioning the data, to generate a volume that honors the dip and azimuth of the overall geological structures. This volume is defined as the Steering cube and is the framework for the application of the latest seismic attributes. The second phase is the application of the seismic attributes to enhance the faults and fractures encountered in the targeted horizons belonging to the lithostratigraphic groups. The third and last section is to manually interpret the faults and fractures to obtain length scales and orientation of the geologic structures characterized. Allowing to obtain fault and fracture network characteristics in terms of frequency, orientation and length scale. Finally, this study aims to provide recommendations on how seismic attributes can provide indications of sub seismic fractures.

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.

Steam injection is an EOR method, which is mostly used for heavy oil production. This viable method is based on increasing the pore pressure in the reservoir and reducing the viscosity of the heavy oil. In particular cases, the increase in pore pressure and thermal expansion related to the steam injection leads to surface deformation – heave. The results show that the level of heave increases when the reservoir thickness is larger. For a 100 m thick reservoir, with a pressure increase of 5 MPa and temperature increase to 570 K, the heave is 80 mm. Increasing the reservoir thickness by a factor of two (200 m) results in an increase of heave by a factor of 1.6 (130 mm). A similar increase in heave results when we increase the pressure increment in the reservoir. In our experiments, pressure and heave are linearly related. Results depends on rock properties, most noticeably the elastic property, Young’s modulus, and thermal expansion factor. An increase in Young’s modulus leads to decrease in level of heave. An increase of thermal expansion factor leads to increase in heave.
When the water required for the steam is extracted from a shallow aquifer, producing this aquifer leads to a reduction of the level of heave that is caused by steam injection. This reduction depends on the pressure reduction in the aquifer and on its thickness. For realistic dimensions and rock properties of the aquifer, this effect appears to be insignificant. Only with very low Young’s modulus (7 GPa) and very thick aquifer, the subsidence due to water depletion can compensate the expansion caused by steam injection.