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With the continued growth of world population comes the need for more energy resources to quench the thirst of the energy insatiable world we live in. Geothermal energy is green and is a sustainable way of providing our energy needs. Formation water at depths greater than 3,000m in the Netherlands is a potential source of energy to generate electricity. Over the study area observed formations are buried deep enough to reach water temperatures in excess of 1000C, and this could conceivably be used for the generation of electricity with very low CO2 emissions. Four seismic surveys L3NAM1985P (146.6km2), L3NAM1991A (414.5km2), Z3NAM1990D (762.2km2) and Z3AMC1989A (544.6km2) were interpreted and integrated with well data including well tops to help in this evaluation. The Detfurth and Volpriehausen (Triassic) of the West Netherlands Basin in the Zuid Holland area are established to be potentially good reservoirs for geothermal development. This is due to the fact that stratigraphically, they are the deepest sandstones and consequently most likely to reach sufficient depths. These objectives are too deep to be visible and adequately interpretable on seismic due to the low impedance contrast and because it is overlain by the strong reflectors of the evaporates of the Upper Germanic Triassic. Therefore, surfaces for these objectives were generated based on formation markers in the wells that intersected the Triassic using 3D gridding in Jewel Suite. Generally, the reservoir interval from the top of the Detfurth to the base of the Volpriehausen contains enough thick sequences of porous sands. The gross thickness ranges from 95m in well VAL-01 to 163m in P15-14. Two porosity/permeability relationships have been used for calculating N/G at various permeability cut-offs of 0.1mD, 1mD, 10mD and 100mD. Net sand ranges from 0.14m to 58.04m for 10mD and 0.1mD permeability cut-offs respectively. The zone in and around Wells MON-03, P18-A-02, P15-01 and P15-14 show the best reservoir intervals based on average porosity and N/G values. Based on different scenarios the average porosity ranges from 6.5% to 16.2% and N/G ranges from 0.6% to 30.8%. Primary porosity and permeability are generally low in the mapped area, but it is expected that permeability and connectivity are enhanced locally through fracturing. The objective is highly faulted, and hence this will serve as conduit for water leading to a higher level of connectivity and water production. Heterogeneity remains an issue of concern due the high level of Vcl is some of the intervals. But it is believed that they will generally not serve as a barrier or baffle to flow, i.e. it will reduce the vertical permeability but not the important horizontal permeability. The objectives in the mapped area suggest that aeolian and fluvial facies occupy more than 50% of the rock unit. Aeolian sandstones are known for their excellent reservoir qualities. They are well sorted with good porosity and permeability. This means that a larger part of the rock unit within the mapped area is of good reservoir quality. The focus of the oil industry is on the structural highs. Prospective areas for geothermal exploitation occur in lows. The lows have no well penetrations and are usually considerably deeper than the much shallower oil fields. It is, however, suspected that structuration and formation of highs and lows is relatively late and that diagenesis predates structuration. This would imply that the shallow oil fields have porosities representative of much greater depths. This is borne out by the fact that there is hardly any relationship of porosity against depth. When this proves to be accurate it would have a very positive effect on the development of geothermal energy, since this reduces the uncertainties involved in a project like this.

Gas hydrates are significant resource of natural gas existing both on-shore buried under the permafrost and off-shore buried under oceanic and deep lake sediments. Earlier studies have demonstrated that large volumes of gas can be produced from gas hydrate accumulations by means of depressurization-induced dissociation using vertical wells. In this study gas hydrate production from a class-3-hydrate reservoir is investigated, on how the production results change if a homogeneous or a heterogeneous reservoir is used for the simulations. The production is by means of a vertical well drilled at the edge of the reservoir. Additionally, it has been studied how the placement of a vertical well and the number of vertical wells and their spacing influences the production. Also the efficiency of producing from a single horizontal well is studied and compared to the results of simulations with vertical wells. It was observed that the permeability of the reservoir has a strong impact on how the methane hydrates dissociate in the reservoir. Comparing the production data and how the reservoir has been swept of gas hydrates for the different scenarios employing various kind and amounts of well, it can be concluded that the scenario with two vertical wells is the most efficient scenario studied giving the most efficient production, low water production also because unwanted gravity segregation could be avoided.

Shale gas became an important source of natural gas in the United States and is expected to contribute significantly to worldwide energy supply. This has been the main motivation for the research and development on shale gas. Shale gas is found in extremely low permeable organic rich formations that are either a source rock or a reservoir. Such formations are porous and contain gas, but have almost no matrix permeability. Shale gas reservoirs from different places have significant differences in structural environment, mineralogical composition, in depth of deposition and in the thickness of the productive layer. Besides, each of the shale gas properties vary substantially within the same producing area. The variability of shale gas properties greatly influences the well performance that should be taken into account for optimizing gas production. The focus of this thesis is to investigate the main factors influencing well performance in shale gas reservoirs: the complexity and conductivity of the fracture network, the proppant distribution within the complex fracture network, the impact of closure stress on un-propped and partially propped fracture conductivity, and finally the factor which is intrinsic to shale gas reservoirs -adsorbed gas. Based on a literature survey, the most important factors prioritized and numerical simulation models constructed for further investigation of prioritized factors. The main challenge in development of shale reservoirs is that in order to reach economically viable production it is indispensible to implement stimulation treatment, such as artificial hydraulic fractures to connect the natural fractures within the shale rock and to create pathway for gas to flow into the wellbore. Shale gas reservoirs are typically comprised of two distinct porous media: the shale matrix containing the majority of gas storage in the formation but with a very low permeability, and the fracture network with a higher permeability but low storage capacity. The gas in the fractures is produced immediately, the adsorbed gas is released as the formation pressure is drawn down by the well. The aim of this thesis work is to conduct theoretical research of the influence of above mentioned factors on well productivity, to prioritize the most crucial factors, and then numerically model them for two different real cases from shale gas reservoirs of North America, in order to investigate the effect of specific parameters on well performance, with the further prospective to model European shale gas reservoirs, as found in the Vienna basin, Northern Germany, Poland, Southern Sweden , the UK, Brabant, Netherlands.

The Permian Skoorsteenberg Formation in the Tanqua-Karoo basin in South Africa provides excellent exposure of submarine basin-floor fans. Because of this, the European Union sponsored various outcrop studies, drilling as well as the data acquisition of the research boreholes in the NOMAD project. It was a unique opportunity to study a submarine fan system by combining widely exposed outcrop and research borehole data. Because both data sets are available, this MSc. project aims to acquire bed thickness data from core and borehole image (Fullbore Formation Micro Imager) analysis and to extrapolate these data to 3D in a variety of methods based on the results of first objective. Analysis has been done on the turbidites of Fan 3 in wells NB-4, NB-3, NB-2, and NS-2. The cumulative distributions of turbidite bed thicknesses in the studied wells were found to follow a power law. Therefore, the cumulative bed thicknesses plot can be used for the following purposes: (i) to derive certain parameters for the bed geometries and distributions; (ii) to calculate turbidite volume connected to the well; (iii) to suggest accommodation space degree of confinement; and (iv) to derive qualitative information on the extent of erosion and bed amalgamation (thus, may suggest depositional setting). The change of slope (the change of exponent) in the cumulative bed thicknesses can be interpreted due to confinement or alternatively, due to the variation of the flow rheology. The clustering of data in the cumulative bed thicknesses plot may suggest the flow rheology affecting the turbidite deposition in particular time or location, which may represent a shift in the lobe depocenter. The turbidites volume connected to the wellbore can be calculated using three different methods, these are: using the mathematical model developed by Malinverno (1997) (volume is calculated from the bed thickness distribution); using the facies model developed utilizing Petrel 2010.1 software; and using the discrete convolution method (volume is calculated by relating the experimental data and the well data). The application of each method has to be done with care, taking into consideration the data availability and the limitation of each method. Moreover, information of the lobe internal geometries is needed in the volume calculation.