An inter-laboratory study of high-pressure gas sorption measurements on two carbonaceous shales has been conducted to assess the reproducibility of sorption isotherms on shale and identify possible sources of error. The measurements were carried out by 7 different international research laboratories on either in-house or commercial sorption equipment using manometric as well as gravimetric methods. Excess sorption isotherms for methane, carbon dioxide and ethane were measured at 65°C and at pressures up to 25 MPa on two organic-rich shales at dry conditions. The inter-laboratory reproducibility of the methane excess sorption isotherms was better for the high-maturity shale (within 0.02 – 0.03 mmol g-1) than for the low-maturity sample (up to 0.1 mmol g-1), which is in agreement with results of earlier studies on coals. The procedures for sample conditioning prior to the measurement, the measurement procedures and the data reduction approach must be optimized to achieve higher accuracy. Unknown systematic errors in the measured quantities must be minimized first by applying standard calibration methods. Furthermore, the adsorption of methane on a dry, organic-rich, high-maturity Alum shale sample was studied at a wide temperature range (300 – 473 K) and pressures up to 14 MPa. These conditions are relevant to gas storage under geological conditions. Maximum methane excess uptake is 0.176 – 0.042 mmol g-1 (125 - 30 scf t-1) at 300 - 473 K. Supercritical adsorption was parameterized using the modified Dubinin-Radushkevich and the Langmuir equations. Gas in shales is stored in three different states: adsorbed, compressed (free) and dissolved; quantifying each underpins calculations of gas storage capacity and also the mechanisms by which gas must be transported from pore (surfaces), to fracture, to the well. While compressed gas dominates in meso- and macropores, it is often assumed that (a) sorbed gas occurs mainly in micropores (< 2nm) and (b) micropores are mainly associated with organic matter. In the third part of this thesis, those ideas are tested by characterising the porous structure of six shales and isolated kerogens from the Posidonia Formation in combination with high pressure methane sorption isotherms at 45, 65 and 85°C. Together, these data help us to understand the extent to which (a) small pores control CH4 sorption and (b) whether “sorption” pores are associated with the organic and inorganic phases within shales. Samples were selected with vitrinite reflectance of 0.6, 0.9 and 1.45%. Pore volumes – named sorption pore volumes here - were determined on dry shales and isolated kerogens by CO2 isotherms measured at -78°C and up to 0.1 MPa. These volumes include micropores (pore II width < 2nm) and narrow mesopores; according to the Gurvitch Rule this is the volume available for sorption of most gases. Sorption pore volumes of Posidoniashales range from 0.008 to 0.016 cm3 g-1, accounting for 21 - 66% of total porosity. Whilst sorption pore volumes of isolated kerogen are much higher, between 0.095 – 0.147 cm3 g-1, normalization by TOC shows that only half the sorption pore volume of the shales is located within the kerogen. Excess uptakes on dry Posidonia shales at 65°C and 11.5MPa range from 0.056−0.110 mmol g-1 (40−78 scf t-1) on dry shale, and from 0.36−0.70 mmol g-1 (253−499 scf t-1) on dry kerogen. Enthalpies of adsorption show no variation with TOC and maturity, respectively. The correlation between maximum CH4 sorption and CO2 sorption pore volume at 195 K is very strong and goes through the origin, suggesting that the vast majority of sorbed CH4 occurs in pores smaller than 6 nm. Approximately half the sorption pore volume and thus CH4 sorption potential of these dry shales is in organic matter, with the rest likely to be associated with clay minerals. Sorption mass balances using isotherms for kerogen and clay minerals do not always account for the total measured sorbed CH4 on dry shales, suggesting that some sorption may occur at interfaces between minerals and organic matter.

Coal-bed methane (CBM), also referred to as Coal seam gas (CSG), relates to the production of methane from coal beds by drilling wells, hence lowering formation pressure, and triggering methane release. While the potential of this resource is significant, the assessment of the quantity and the producibility of methane from coal seams is highly variable. For this reason the objective of this work is to investigate the assessment of gas content, gas-in-place and coal permeability through petrophysical of analysis and by gaining a better understanding of coal bulk properties,. In this study 17 cored production wells were analysed from the Walloon Sub-group coal seams fairway in the Surat Basin in Queensland Australia, which is today the most ambitious investment in CSG worldwide. A total of 2374 coal beds were investigated to understand how the nature of the different coal lithotypes are reflected in core analysis, wireline logs measurements and DST test results, and how they affect coal quality, and control gas content, fracture development and reservoir permeability. High-resolution studies involving fine scale are required to estimate volumes and CSG formation evaluation turns to the interpretation of standard wireline tools readings in hundreds of coal seam wells. Nevertheless, the heterogeneous thin-bedded nature of coal seams, together with the fact that methane within coal is mainly stored by adsorption, create several difficulties in wireline log petrophysical analysis. Consequently core description is used to validate the combination of the density log with the shallow focused electric and induction resistivity measurements, benefitting the recognition and thickness estimation of thin coal beds and coal laminae rich mudstones. This observation, and a refined coal quality and gas content estimation methodology, are presented and tested against previously published workflows and provide an improved and tested strategy for petrophysical analysis of CSG.

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In petroleum industry, highly stable water-in-oil (w/o) emulsions are formed during extraction process and these emulsions are stabilized by the indigenous surface active species in the oil. The recovery of crude oil through emulsion breakdown and subsequent separation (demulsification) should be carried out at source in order to avoid costly pumping and cooling of emulsion which enhances emulsion stability. Although conventional methods available for emulsion breakdown using demulsifiers and electric field separation, in the case of viscous crude oils with large amounts of indigenous surfactants, such methods are not satisfactory to achieve on-site oil-water separation. Therefore, such emulsions may have to be chemically treated. It was previously shown that when hydrophilic micro-porous polymers, known as PolyHIPE Polymers (PHPs) were added to the emulsion, it caused emulsion to separate as a result of selective removal of surfactants. This separation process was further enhanced in the presence of electric field. This current study focuses on cross-flow microfiltration of w/o emulsions through a sulphonated hydrophilic microporous polymeric material in the absence or presence of electric field. However, sulphonated PHPs used in the experiments do not have an active membrane layer with pores at micron- or nano- scale. The thickness of the separation layer is ca. 4 mm and pore size is in 10 micrometer range. We used either 50 or 70 vol. % oil phase in the w/o emulsions. Effect of: pore size, crossflow velocity and electric field strength on permeate flux rate decay and separation efficiency of emulsions which are stable for more than 70 days otherwise was investigated. It was found that the permeate flux rate decayed rapidly with crossflow filtration time before the flux reached steady state. The application of electric field enhanced the permeate flux rate. Under steady state conditions, permeate flux rate was not significantly affected by the PHP pore size. Permeate from the crossflow filtration was collected in glass cylinders and allowed to separate under gravity as a function of time. It was found that the demulsification time was affected primarily by the applied electric field, emulsion water content, crossflow velocity and PHP pore size. Demulsification rate increased with increasing electric field and water fraction of emulsion and with decreasing pore size of PHP. Demulsification was achieved within 6-7 hr. The results were interpreted in terms of ‘confinement phenomenon’ in which it was postulated that the PHP filtration media selectively retained the surface active agents and; thus, causing the demulsification of the emulsions. The surface active agents were deposited within the pores of the separation media and; thus, causing flux decay. Although the deposits of surface active agents could break-up due to permeate flow through the separation media, they could not be re-distributed at the oil-water interface to re-stabilize the emulsion. However, some water can be trapped within the oil as oil-in-water-in-oil multiple emulsion which would be more resistant to demulsification.

Organic rich shales are an important source of natural gas, where significant amounts of gas can be stored in the pore system of shales. The pore systems of organic rich shales are both highly variable and poorly understood, and within this context, the overall research aim is to characterise and investigate the pore system of organic rich shales and isolated kerogens, and to examine the relationship between shale pore structure and gas storage. The research focussed on two case studies: 1) the Draupne Formation (DF) of the North Sea, and 2) the Colorado Group (CG) of the Western Canada Sedimentary Basin of Canada. The DF shales have a range of thermal maturities, from immature to late oil window, allowing the effect of maturity on pore structure to be examined. The CG group shales are both immature and isomature, allowing the pore structure of pre-oil window kerogen and shale to be investigated. The geochemistry of the shales and isolated kerogen samples was characterised using TOC, Rock-Eval, Pyrolysis GC-MS, FT-IR, 13C-NMR, Elemental Analysis. The pore structure of the isolated kerogens and shales was investigated using 1) Electron microscopy, 2) Mercury intrusion porosimetry, and 3) low pressure gas adsorption methods, including nitrogen at - 78oC and CO2 at 0oC. The gas storage capacity of the shales was determined using high pressure methane at 30oC and up to 1 MPa. In the Draupne Formation sample suite, thermal maturity has a significant influence on the pore structure, with organic matter content and mineralogy having a secondary role. Mercury intrusion porosimetry indicates that the pore size distribution of the shales is dominated by pores < than 100 nm in size, and that the proportion of mesopores increases with maturity, at the expense of micropore content. The gas sorption pore volumes of both the isolated kerogens and shales exhibit a strong negative correlation to maturity, with the TOC normalised pore volumes strongly decreasing with increasing maturity. The negative correlation with maturity is also repeated with the Dubinin-Radushkevic (D-R) micropore volumes and the BET surface areas of the kerogens and shales. The absence of shale minerals in the kerogen concentrates indicates that the negative correlation between pore structure and maturity is controlled by the organic matter, and shale matrix mineralogy is a secondary influence on pore structure in this sample suite. In the Colorado Group case study, mineralogy is the primary influence on the pore structure of the shales, with organic matter content having a secondary role. The mercury intrusion porosimetry of the shale indicates that the pore size distribution is dominated by sub-100 nm pores, and the pore size distribution is constant, with no change across the sample suite. The gas sorption pore volumes of the isolated CG kerogens are almost identical to the isolated DF kerogens, suggesting that Type II algal kerogens have similar gas sorption pore volumes. For the CG shales, the sorption pore volume correlates strongly with illite content. The correlation is positive, with a correlation coefficient of R2 = 0.97. This indicates pore volume is primarily located in the shale mineral matrix, and organic matter content is secondary in the CG sample suite. This strong positive illite content is also observed in the D-R micropore volumes of the shales, indicating that illite is microporous. The N2 BET surface area also reflects this strong positive correlation to illite, with a R2 = 0.90.

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Shallow-marine reservoirs are typically complex, containing hierarchically arranged heterogeneity in inter-well volumes, at scales that are challenging to represent in reservoir models. Permeability contrasts associated with clinoforms are one such heterogeneity, but at present there are no modelling tools available to automate the generation of multiple three-dimensional (3D) clinoform surfaces. Consequently, clinoforms are rarely incorporated in models of shallow-marine reservoirs, even when their potential impact on flow is recognized. A numerical algorithm that generates multiple 3D clinoforms is presented. The algorithm is validated via construction of 3D, surface-based reservoir models of: (1) fluvial-dominated delta-lobe deposits exposed at outcrop (Cretaceous Ferron Sandstone Member, Utah, USA); and (2) a deltaic reservoir using a sparse subsurface dataset (Jurassic Sognefjord Formation, Troll Field, Norwegian North Sea). We use a suite of 3D reservoir models constructed with the clinoform-modelling algorithm and outcrop-analogue data (Cretaceous Ferron Sandstone Member, Utah) to quantify the impact of clinoforms on fluid flow in the context of: (1) other uncertainties in reservoir characterisation, such as the impact of bed-scale heterogeneity on vertical permeability; and (2) reservoir engineering decisions, including oil production rate. Clinoforms are difficult to identify using production data, but our results indicate that they can significantly influence hydrocarbon recovery and their impact can be larger than that of other geological heterogeneities and of reservoir engineering decisions. Vertical permeability within distal delta-front facies comprising interbedded sandstones and shales is found to be an important influence on sweep within clinothems. However, it is difficult to characterize these intervals from subsurface datasets. A digital outcrop modelling method is presented and applied to capture the geometry and architecture of sandbodies in such deposits in an outcrop analogue (G2 parasequence, Grassy Member, Blackhawk Formation, Utah, USA). We use the resulting digital outcrop model to make a preliminary interpretation of 3D gutter cast geometry.