The storage of carbon dioxide is now regarded as a critical industrial application aimed at mitigating its accumulation in the atmosphere. Reservoirs and aquifers have been identified as viable alternative locations. This report seeks to examine the impact of sedimentological heterogeneity on the development and migration of CO2 plumes over time. The study uses the Roda Sandstone Formation as a case study, primarily due to the presence of carbonate-cemented layers within the Gilbert-delta lobes, which contribute to reservoir heterogeneity commonly observed in subsurface formations. The utilization of a sketch-based modeling approach was employed in constructing the geo-models represented by Rapid Reservoir Modeling (RRM) software since the Roda Sandstone is an exposed section in Isabena Valley in Spain. Furthermore, various realizations are constructed using different parameters of the cemented layers to comprehensively comprehend all potential scenarios. The aforementioned observations pertain to variations in the thickness and lateral continuity of the cemented layers. Additionally, dynamic modeling is also performed by injecting CO2 into the reservoir for 50 years. The simulator utilized for dynamic modeling is the Delft Advanced Research Terra Simulator (DARTS). The findings demonstrate that reservoirs with moderate sedimentological heterogeneity are actually better sites to store CO2 due to the capacity and effectiveness of the storage.

Alluvial stratigraphy is influenced by both allogenic and autogenic factors, which are difficult to be distinguished from each other because they operate at overlapping spatial and temporal scales. Moreover, it remains uncertain whether autogenic dynamics can result in sedimentary cyclicity that resembles allogenically-driven stratigraphic products. In order to undertake this challenge and address the uncertainty, we first test what sedimentary processes can produce the alluvial cyclicity observed in outcrops by designing comparable scenarios in the process-based numerical modelling. In the meantime, we systematically characterize floodplain aggradation cycles by tracing them in a UAV-based photogrammetric model. Moreover, we comprehensively describe channelized sandstone bodies in the field and the model to reconstruct the paleogeography. Lastly, we configure the relationships between floodplain aggradation cycles and sandstone bodies of different river styles, based on which we identify the link between orbital forcing and alluvial stratigraphic response.@en

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.

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.

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.

Fluvial reservoirs are difficult to model due to the high permeability contrast between the sandstone bodies and the overbank deposits and the complex geometry of the permeable (sandstone bodies) and impermeable zones (overbank deposits). A set of fluvial meandering models has been generated using FLUMY. The models represent a range of Net-to-Gross ratios and sandstone body geometries. In order to quantify the effect of sample size on effective properties, the models are evaluated based on the statistical moments of the probability distributions of porosity and single-phase permeability as a function of sample size. The porosity and permeability show a high spread at small sample volumes, but the spread reduces as the sample size increases. A normalized standard deviation, the coefficient of variation, has been used as a criterion for the variability of the probability distributions. The coefficient of variation of the porosity and the horizontal permeability show a monotonic decline as a function of sample size. The coefficient of variation of the vertical permeability does not show a monotonic decline. This is caused by a drastic decrease of the mean of the vertical permeability with increasing sample volume. The mean of the horizontal permeability also decreases with increasing sample size, but to a lesser extent. The mean of the probability distributions of permeability as a function of sample size converges much earlier than the standard deviation. This convergence indicates that we can determine the effective properties at the Representative Elementary Volume (REV), without reaching REV. The convergence of the mean could potentially be used as a criterion for the relevant spatial scale of upscaling from the fine scale static model to the coarse scale model. Furthermore, if cells are uncorrelated at a scale where the mean of the permeability is not a function of sample volume anymore, random attribution of properties can be used to populate dynamic grid cells.

This study documents and attempts to describe the processes leading to the formation and preservation of exposed oil, water, and paleo-gas contacts at the McMurray Formation type section, Alberta, Canada. The McMurray Formation type section, a part of the Athabasca Oil Sands Deposit (AOSD), the largest exhumed oil reservoir on Earth, is unparralled, still underutilized, natural laboratory for veryfing and refining existing, and developing new concepts, for oil migration and post oil-emplacement fluid diffusion and biodegradation processes in a sedimentologically complex reservoir setting. Exposures, coupled with adjacent borehole data, provide a three-dimensional insight into reservoir heterogeneities and their influence on oil migration, entrapment, post-emplacement fluid mixing, and biodegradation processes and products, in a hierarchical and chronological order from early charge to present-day conditions. The principles of oil above water and of horizontal or tilted oil/water contacts are challenged by outstanding examples of: (i) centimetre to decimetre scale inter-fingering oil-water stringers/contacts, created by capillary pressure differences and partial charge; (ii) irregular oil-water contacts in both clean and heterogeneous reservoirs characterized by gravitational effects caused by severe biodegradation that caused the formation of extra heavy-oil commonly referred to as “bitumen” that sank through the water column; (iii) occurrences of multiple metre-scale intervals with less than 50% oil saturation, commonly referred to as lean zones that formed during microbial gas generation following oil entrapment. Studied contacts provided excellent opportunity to study oil migration and charging mechanisms from pore and sedimentary bed to reservoir scale at various stages of oil migration into the reservoir, as well as oil, water, and gas re-migration within the reservoir (trap). Described exposures can play an additional role in advancing geoscience education, petroleum exploration, reservoir characterization, field development, and production optimization studies.

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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.

An understanding of the paleoenvironment and the main sedimentary processes behind preserved deposits is crucial to correctly interpret and represent lithofacies and facies associations in geomodels that are used in the hydrocarbon industry, particularly when a limited dataset of cores is available. In this paper a fairly common facies association is discussed containing massive sands - here defined as thick (>0.5 m) structureless sand beds devoid of primary sedimentary structures, or with some faint lamination - deposited by mass failures of channel banks in deep fluvial and estuarine channels. Amongst geologists it is generally accepted that liquefaction is the main trigger of large bank failures in sandy subaqueous slopes. However, evidence is mounting that for sand deposits a slow, retrogressive failure mechanism of a steep subaqueous slope, known as breaching, is the dominant process. A model of breaching-induced turbidity current erosion and sedimentation is presented that explains the presence of sheet-like massive sands and channel-like massive sands and the sedimentary structures of the related deposits. Sheet-like packages of spaced planar lamination that are found together with massive sand bodies in deposits of these environments are identified as proximal depositional elements of breach failure events. The model, acquired from sedimentary structures in deposits in the Eocene estuarine Vlierzele Sands, Belgium, is applied to outcrops of the Dinantian fluvial Fell Sandstone, England, and cores of the Tilje and Nansen fms (Lower Jurassic, Norwegian Continental Shelf). The possible breach failure origin of some other massive sands described in literature from various ancient shallow water environments is discussed. Breach failure generated massive sands possibly also form in deep marine settings. The potentially thick and homogeneous, well-sorted sand deposits bear good properties for hydrocarbon flow when found in such an environment. However, in case of deposition in an estuarine or fluvial channel, these sand bodies are spatially constricted and careful facies interpretation is key to identifying this. When constructing a static reservoir model, this needs to be considered both for in-place volume calculations as well as drainage strategies.

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