Shale has proven to be a major unconventional natural gas play. However, due to its complex bedding orientations, comparatively high clay content and its complex heterogeneity, producing and optimising production is often hindered by its challenging complexities. It is now imperative to critically understand the complexities surrounding the geology of Shale reservoirs and its characterization. The overall aim of this study is to understand and characterise the Marcellus shale with the view of enhancing our knowledge of the geometry and topology of the tight shale rock. This study presents a simplified workflow in the study of the heterogeneity of shale rock sample by the combination of Nano CT imaging and Scanning Electron Microscopy imaging methodologies. The key components involve the uses of an appropriate sample preparation technique and application of complex imaging algorithm in digitising the shale sample and 3dimension image analysis for improved gas recovery. Full networks with parameterised topology have been generated on the scanned images. In this study the measured porosity is 4.73% and calculated porosity is 4.92%. Therefore the average porosity of the Marcellus shale derived in is study is 4.83% .The network predicted absolute permeability at cross points of the correlations; both correlation combinations gave a similar water saturation value of 0.533 while the relative permeability using the Corey/Skjaeveland was 0.044 and Sigmund Mccaffery/Benstine Anli was 0.047. The Nano CT scans were used for both determination of the static petro physical properties-porosity and visualisation of the sample. The SEM was used to discretise the morphology. The integration of Nano CT reconstruction and SEM imaging modalities presented in this study is a new technique in the characterisation of tight formations at a core scale. This technique carried out in the discretization of unconventional/shale reservoirs will not only help in providing understanding onto the complex geometry of tight reservoirs but also provide intricate insight into understanding adaptable optimum production techniques through flow behavioural analysis and characterisation.

Carbon Capture and Storage (CCS) is considered as an important solution for CO₂ emission reduction, yet, the CO₂ capture process is highly costly. Thus, combining Enhanced Gas Recovery (EGR) with CCS could potentially offset the costs via additional production of natural gas. Therefore, the objective of this P.hD. is to build a numerical model to simulate CO₂-EGR in partially-depleted gas reservoirs; in particular Centrica Plc's North Morecame gas field. Our numerical model is based on the so-called Method of Lines (MOL) approach. MOL requires selecting a set of persistent Primary Dependent Variables (PDVs) to solve for. In this case, we chose to solve for pressure, temperature and component mass fractions. Additionally, MOL requires recasting of the governing equations in terms of the PDVs, which often requires the evaluation of partial derivative terms of the flow properties with respect to the PDVs. In this work, a method of analytical evaluation of these partial derivative terms is introduced. Furthermore, in a new approach, the mutual solubility correlations for mixtures of CO₂-H₂O and CH₄-H₂O, available in the literature, are joined together using straight lines as a ternary diagram, to form a ternary CO₂-CH₄-H₂O equilibrium model; the equilibrium-model's predictions matched well with the available experimental solubility data. 1D and 2D numerical simulations of CO₂-EGR were carried out. Overall, the 1D results were found to match very well with an existing analytical solution, predicting accumulation of a CH₄ bank ahead of the CO₂ plume and accurately locating the associated shock fronts while considering the partial miscibility of both CO₂ and CH₄ in H₂O. Based on the subsequent model predictions, in the North Morecambe field without drilling any additional wells, 0.6 out 2.3 BSCM, i.e., 26% of the remaining gas can potentially be recovered using CO₂-EGR.

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This thesis describes a detailed geochemical evaluation of the hydrocarbon potential of source rocks and the origins of the crude oils in the western and central parts of the Sirt Basin in Libya. The Sirt Basin is one of North Africa's richest and most prolific oil-bearing basins, with most of the oil being considered to be derived from the Campanian Sirte Shale and other local source rocks such as Rachmat, Etel and Hagfa Shale formations. The primary aims of this research were to determine the main source rocks that generated petroleum, determine the number of genetically distinct oil families in the basin and compare them with their parent source rocks, and to assess the regional migration and the filling directions of the reservoirs, since this information can exert a profound influence on current and future exploration activities across the study area. A study was undertaken on these source rocks and crude oils using 269 rock cuttings and 51 crude oil samples from several boreholes and oilfields in the Sirt Basin. Routine geochemical analysis in addition to biomarker analysis by gas chromatography-mass spectrometry, compound specific carbon isotopic analysis on n-alkanes and diamondoid analyse were carried out on selected source rock samples and on all of the crude oil samples. The geochemical results demonstrated the presence of various organic-rich zones within the Upper Cretaceous Sirte Shale and Rachmat source rocks. The Sirte Shale Formation is considered to have variable fair, good to very good source potential, and has good hydrocarbon generation in the study area. The Rachmat Formation shale is considered as the second potential source rock in the basin. Vitrinite reflectance, Spore Colour Index, and pyrolysis Tmax data indicate that the Upper Cretaceous shale samples are early to mid-mature in the west of the basin, and middle to late mature in the north central of the basin. Optical analysis of palynofacies slides showed that structureless, amorphous organic matter is dominant, along with the presence of some phytoclasts and reveals moderate to well preserved, fluorescent Type II marine kerogen and Type II-III kerogen. A number of biomarker and other organic facies and maturity indicating molecular marker parameters, as well as isotopic data, show that the crude oils in the western and v central parts of the Sirt Basin are genetically related and only minor variations are present between them, likely due to minor organic facies variations in the Sirt Shale and Rachmat source rocks. The biomarker parameters show dissimilarities between the crude oils in eastern part relative to the western and central part of the basin, due to variations in the organic facies and depositional environments setting of the source rocks or due to higher maturity. Based on molecular marker characteristics, oil-oil correlation identified nine oil families, plus two subfamilies in the study area: Oils from families 1A, 1B, 2, 3 and 4 are situated in the western and central parts of the Sirt Basin, while oil families 5, 6, 7, 8 and 9 are located in the eastern part of the basin. Crude oils of families 1A, 1B, 2, and 3 were interpreted as having been generated from a suboxic to anoxic marine, clay-rich and early to middle maturity source rock. Molecular and other compositional variation between oil families were attributed to organic facies and subtle maturation variations. Age-related biomarker parameters in the oils suggested that their source was Upper Cretaceous. Migration of the generated and expelled oil and gas from the Sirte Shale and Rachmat source rocks to the reservoirs of the Upper Cretaceous-Tertiary petroleum system was interpreted to have occurred along both vertical and lateral pathways along the faults, in the Oligocene to Miocene, while oil carbazole data indicated that this migration was generally likely to have been over relatively short distances.

The work presented in this thesis is an effort to help petrophysicists and reservoir engineers in improving reservoir characterization. Magnetic susceptibility techniques were used for prediction of important reservoir parameters in hydrocarbon sedimentary sequences. For the first time ever I have shown that the grain lining hematite cement surrounding quartz grains has significant control on permeability in hydrocarbon bearing reservoir rock samples. This work also shows that it is not only the dispersed hematite and clay minerals in a reservoir rock matrix that control permeability, but also that the grain lining hematite has additional and dominant control on permeability. In addition, for the first time ever, magnetic susceptibility techniques have been applied on core samples from relatively tight gas sandstone reservoirs. Such techniques were previously known to have been used in only conventional clastic reservoirs. Magnetic hysteresis measurements were used to show that the permeability is dependent on hematite content and independent of hematite particle size. Identifying and Evaluating faults and fluid contact in hydrocarbon bearing reservoir rocks are challenging tasks. The work presented in this thesis has shown for the first time that raw magnetic susceptibility measurements performed on drill cuttings can be used to detect faults and fluid contacts in sedimentary sequences. Such measurements can be performed at well site, thereby enabling companies to make important field development decisions quickly. Additionally, a series of novel crossplots have been developed between magnetic susceptibility and various wireline log data for determination of mineralogy, mixture porosity and mineral quantification. These crossplots are similar in format to standard industry charts, which provide a further tool for improved petrophysical characterization using rapid, non-destructive magnetic susceptibility measurements.

Heterogeneous fine-grained sediments at shallow burial (< 1000m) below the seafloor can often experience large strain of mechanical compaction and variable degrees of overpressure in their pore space as a result of disequilibrium dissipation of pore fluid. Shallow overpressure can pose significant risks to economics and safety of hydrocarbon production and may impact on hydrocarbon generation deep in a basin and hydrocarbon migration to traps during basin evolution. However, when basin modelling ignores the heterogeneity of sediments, large strain deformation and fluid flow conditions at smaller length- and/or time-scales than those at basin scales, it can lead to incorrect prediction of sediment compaction, and hence the mass of the sediment column, the magnitude of pore pressure and its distribution at shallow burials, and consequently can impact on the simulation of basin evolution. In this thesis, the necessity of considering large-strain consolidation in modelling shallow compaction is demonstrated, and a one-dimensional large-strain numerical simulator, based on one of Gibson’s consolidation models and suitable for basin modelling, is developed and verified. An analytical upscaling technique is also developed for determining the effective compressible parameters and permeability for horizontally layered systems of certain compaction characteristics. They are used subsequently to analyse parametrically the compaction behaviours of the layered systems and to calculate effective coefficients for the systems, with results showing that fine-scale simulation is required when considering the effect of fluid-structure interaction. However, the large strain model over-predicts the pressure of the Ursa region, Gulf of Mexico, based on information from the Integrated Ocean Drilling Program (IODP). An analysis indicates that horizontal fluid flow, or lateral motion of mass transport processes, may explain the over prediction. The limitation of a 1D model is further discussed thereafter both in fluid flow and mechanical deformation. With strong applicability and fundamentality, the Modified Cam Clay model is adopted in 2D research, and related verification is provided. Modified Cam Clay can show elastic and elastic-plastic properties in basin evolution. Heterogeneous Modified Cam Clay materials can be upscaled to a homogenous anisotropic elastic material in elastic deformation and a homogenous Modified Cam Clay material in elastic-plastic deformation, however, the upscaled parameters vary with the effective stress. The value of the upscaling is demonstrated by modelling the evolution of a simplified North Africa basin model.

In this thesis, novel workflows involving high resolution near-wellbore modelling (NWM) are illustrated, which allow integration of multi-scale geological and petrophysical data from highly heterogeneous reservoirs in field-scale reservoir simulations. When applied to a clastic reservoir with high variance at small scale, NWM significantly improved reservoir characterisation and calibration of reservoir model with well test data. Results show that using NWM tools for reservoir modelling yields more precise flow calculations and improves our fundamental understanding of the interactions between the reservoir and the wellbore. Furthermore, this thesis employs an integrated NWM workflow to identify and evaluate the geological heterogeneities that enhanced reservoir permeability in a giant carbonate reservoir with a long production history. Key among these heterogeneities are mechanically weak zones of solution-enhanced porosity, leached stylolites and associated tension gashes, which were developed during late stage diagenetic corrosion. The results of this investigation confirmed the critical role of diagenetic corrosion in enhancing the permeability of the reservoir. One of the key aims of this thesis is to develop a novel near-wellbore upscaling (NWU) workflow that addresses the challenges associated with conventional carbonate modelling workflows. The NWU workflow developed in this thesis provides a systematic geostatistical approach to obtain more realistic representation of the above multi-scale geological-petrophysical heterogeneities in the reservoir simulation model of the carbonate field. The NWU results were used to generate global porosity-permeability and vertical-horizontal permeability relationships for reservoir simulation. Instead of applying artificial permeability multipliers that do not necessarily capture the impacts of geological heterogeneities, the NWU workflow incorporates representations of fine-scale heterogeneities in the reservoir simulation model. Another aim of this thesis is to develop a new near-wellbore rock-typing and upscaling approach to improve the integration of reservoir rock-typing and simulation in carbonate reservoirs. The rock-typing and upscaling methodology described in this work involves the geological-petrophysical classification of the reservoir heterogeneities through systematic evaluation of the key diagenetic events, including the key associations between the depositional and diagenetic features, and their impact on reservoir flow properties. The near-wellbore rock-typing and upscaling workflow yielded consistent initialisation of the reservoir simulation model and therefore improved the calculation of volumes of fluids-in-place. Subsequently, the cumulative production curves computed by the reservoir simulation model agreed well with the historic production data. The revised simulation model is now much better constrained to the reservoir geology and provides an improved geological-prior for history matching. This thesis therefore provides valuable insights to the means by which a geologically consistent field-level history match can be achieved for complex carbonate reservoirs.

This thesis describes the development of a pore network model and its application to the analysis of the underlying physical mechanisms governing gas flow behaviour in porous media. The main focus of the study is CO2 and CH4 injection for EOR and storage applications as well as the evolution of solution gas following depressurization of hydrocarbon-saturated porous media. The model incorporates algorithms that dynamically track interface movements during both steady and unsteady-state flow under the coupled influence of capillary, gravity, and viscous forces. The model has been validated against laboratory experiments and the roles played by key system parameters have been identified. For injection processes, simulation results show that gravity-driven regimes fall into two broad categories of quasi-stable and migratory regimes, depending on the governing Bond number. The transition from non-dispersive to dispersive migratory flow was found to be largely independent of injection rate but a strong function of pore size distribution variance and system connectivity. CO2 and CH4 regimes in brine were found to exhibit striking similarities, suggesting that CH4-brine relative permeability curves could be used to accurately parameterize simulation models of CO2 storage in aquifers. Decreasing the interfacial tension was found to dampen viscous fingering but exacerbates gravity override which suggests that standard laboratory methods for analysing CO2 EOR processes are likely to overestimate displacement efficiency. Other sensitivity studies highlight the pore to core scale variables that control caprock sealing mechanisms, and residual and solubility trapping during CO2 injection for storage, and their implications at the reservoir scale. For depressurization, simulations performed on a pore network anchored to measured petrophysical properties of a 0.23mD fractured chalk core from a North Sea reservoir show a very weak correlation between depletion rate and critical gas saturation, contrary to conventional belief. Depressurization oil recovery efficiency was found to increase with increase in initial water saturation but the presence of fractures caused the critical saturation to decrease by approximately 60%.

This thesis examines the potential of C 60 intercalated graphite and titanium oxide 'decorated' graphite as sorbing hydrogen storage media. Initially, various types of natural flake graphite were examined and characterised with X-ray diffraction and electron microscopy techniques. Each type was assessed for suitability for modification by considering impurities, crystal structure and internal strain. Samples of increased-surface-area exfoliated graphite were then produced as an initial template for surface modification techniques, and a sample against which to compare gas-sorption characteristics. C60 intercalated graphite was produced in order to assess whether fullerenes might be used to create spacing within graphitic structures to maximise surface area and increase energies of adsorption at sites around the C60 molecule. Samples were made via a sublimation method, depositing C60 molecules onto surfaces where it was subsequently inaccessible to its solvents. Titanium oxide coated materials were created via a wet chemistry route followed by thermal decomposition, in order to examine whether this material plays a role in hydrogen uptake via 'spillover' catalysis reported to be caused by palladium/titanium oxide deposits upon surfaces. Each sample created was characterised using X-ray diffraction, electron microscopy and gas-sorption techniques; its apparent density determined by argon displacement, and then assessed for specific nitrogen BET surface area and hydrogen uptake at cryogenic temperatures. Although the methods of creating the C 60 intercalated samples proved detrimental to the material's surface area, it was found that the hydrogen surface sorption capability (uptake per unit surface area) was almost doubled. However, hydrogen uptake was effectively negated by titanium oxide surface depositions even though its surface area was increased. Future work is planned to further investigate the C 60 intercalated material.

The impact of uncertainty in the geometry of normal faults upon hydrocarbon reservoir models has been assessed at the exploration-, field- and individual fault scale. At the exploration-scale synthetic 2D seismic sections generated using mapped geometries from the Gulf of Corinth rift illustrate the uncertainty in along strike fault geometry and displacement continuity when correlating between disparate seismic lines. This uncertainty has implications for pore pressure prediction, spill point identification and calculation of hydrocarbon column heights. At the hydrocarbon field-scale, incorporation of sub-seismic structure has been quantified using reservoir production simulations. Although the inclusion of sub-seismic fault tips often leads to increased reservoir segmentation, this does not necessarily imply a detrimental impact upon hydrocarbon production. Earlier onset of oil production decline for more segmented reservoirs is offset by a lower rate of decline due to an enhanced sweep pattern as well as a lower volume of produced water when compared to less segmented cases. 3D seismic forward modelling highlights the discrepancies between realistic, outcrop-derived fault geometries and those geometries resolvable in seismic data, with seismically resolvable faults significantly simplified in comparison to those observed at outcrop. Complex geometries such as displacement partitioning across multiple slip surfaces are hence not incorporated within reservoir models leading to the area of across-fault reservoir:reservoir juxtaposition being severely underestimated. In turn faults are modelled as overly retardant to flow, with the influence of fault rock properties being overstated. Where realistic (i.e. larger) areas of across-fault juxtaposition are modelled, the fault rock properties have less impact upon acrossfault hydrocarbon flux. Juxtaposition is therefore the first order control on hydrocarbon flow across faults.