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The Columbus Basin, offshore Trinidad, is a mature gas producing basin with a number of major fields now in decline. Focus for infield exploration and production is shifting, with thin bedded sandstones as a secondary pay target. This basin is exceptional as age equivalent analogues to the subsurface reservoirs are exposed along the south east coast of Trinidad at Mayaro Bay (16 – 25 m sections). This research utilizes these outcrops and integrates findings with subsurface core data to present an improved understanding of thin bedded sandstones in three significant areas: 1) depositional setting on a wave dominated delta through description and interpretation of their large scale architecture and facies associations, 2) reservoir quality and connectivity of the facies and microfacies that comprise these heterolithic units through petrography and pore system characterization and 3) pore scale reservoir quality and connectivity through micro CT imaging and 3D modelling of their pore system morphology. Detailed sedimentological analysis has revealed that thin beds are highly interbedded units with thicknesses of 0.1 – 10 cm and have a lenticular geometry. Their lateral extent, controlled by their exposure, varies from 3 to 10s m in some areas. Field sampling and microfacies analysis, revealed five distinct lithofacies types and five microfacies types that make up two principal facies associations (FA): (FA1) axial distal delta front facies and (FA2) lateral distal delta front facies. The reservoir quality poroperm data achieved for the thin sandstones of these two facies associations are consistent with routine core analysis data from basin core and industry assigned values for conventional thicker bedded sandstones, inferring their secondary reservoir potential. Utilizing new techniques such as X-Ray tomography, a high resolution 3D model of the thin sandstone pore systems has been created for qualitative and quantitative reservoir characterization, especially vertical and lateral connectivity within the thin bedded units. This detailed dataset of 3D pore dimensions that can be used as conditioning data for other reservoir models. The observations and conclusions of this research give an insight into the depositional architecture and thin bedded sandstones on a distal delta front and their associated reservoir properties and connectivity mechanisms that facilitate an effective reservoir. These findings may inform and guide future exploration and appraisal, development and production and well completion and configuration programmes for thin bedded reservoirs as explained by the implications and recommendations at the end of this thesis.

>Magister Scientiae - MSc / This study investigates the viability of the sedimentary deposits in the Northern Orange basin for carbon storage and sequestration. A combination of geological modelling, petrographic and geochemical techniques are used to investigate this scenario after an initial seismic-well tie had been performed to match the formation tops in Well AF-1 with the 3D seismic volume acquired in this basin in 2009. Core description of well AF-1 assisted in identifying different facies and samples taken at specific depths for petrographic and geochemical analyses, while different geological formations were mapped from the calibrated positions of seismic-well tie throughout the seismic volume. The well data and geophysical logs were utilized to generate petrophysical properties and used to calibrate observations made from seismic interpretations. The facies log used in this study was generated using the Python’s script on Petrel 2014 Gamma Ray, while the density log was used to generate the porosity log. The generated facies and porosity logs were upscaled and used to populate a 3D grid using faults and surfaces identified in the seismic volume. The sedimentological properties of the subsurface were identified utilizing petrographic descriptions including measurements of sorting, colour and grain sizes. While the mineralogical properties of the record was verified through XRD analyses and thin section. The facies and porosity modelling revealed the dominance of siltstones and sandstones as the main sedimentary facies throughout the sequence. Sandstones are extensive and prominent within the Cenozoic and Mastrichtian, while the unit dated to the Barremian is identified as having the best potential for CO2 storage based on the overlaying capping unit. Quartz, Plagioclase feldspar (Albite), Biotite and Kaolinite are the major minerals identified in all four samples. Each of these minerals has an implication for which may influence the long term storage of CO2 with the potential to form as they may form part of the inra-porous post-depositional cementation and hence change the porosity and permeability properties. The presence of Albite as observed on the XRD may predict possible mineralisation of CO2 to form Dawsonite when reservoir is injected with CO2. The Barremian sandstone which straddles the Aptian shale at the top and the Hauterivian Shale and Siltsone deposit at the bottom holds a good promise for a potential CO2 storage. An estimated volume of CO2 that could be stored in the reservoir of the Barremian sandstone in zone 8 is limited to the lateral seal of shale above the reservoir in zone 7 of the Aptian age. The method used to determine the potential storage capacity of CO2 was performed by Alexandros Tasianas and Nikolaos Koukouzas (2016). The Equation used to determine CO2 storage capacity is: mCO2 = RV * Ø * Sg * δ(CO2) . / 2021-09-01

<p> This study describes the analysis of orientation of elongate quartz grains in massive turbidite sandstones from the Chetco Formation (Jurassic) of southwestern Oregon. Inferences on depositional fabric of this resedimented facies are made.</p> <p> Grain orientation in the plane parallel to bedding is generally not highly significant statistically, and current direction, supplied by imbrication, is not persistent vertically through the beds. However, a rotation pattern of current direction in each bed is detected.</p> <p> Variations in orientation distribution could represent variations in sediment concentration of the flow and in the rate of deposition.</p> / Thesis / Bachelor of Science (BSc)

<p> Stress-shortening data and the micro- and macro-fabrics or experimentally deformed calcite-cemented graywacke were analyzed in order to understand the nature of deformation in calcite-cemented rocks. Forty four room temperature triaxial experiments were conducted on the Blairmore sandstone in the range of 2.1 - 19.8 percent shortening, 1 - 2600 bars confining pressure, at strain rates on the order of lo-4/second. Under these condition, the normal transition from longitudinal fracture, at low confining pressure, to limited homogeneous flow, at high confining pressure is observed. The strength ( σ1, - σ3 ) increases from 2. 3 kilobars (kb) at 1 kb confining pressure (op), to 5.9 kb at 2.6 kb cp. At low confining pressures, deformation takes place primarily by brittle fracture of the calcitee At high confining pressures, the calcite deforms primarily by twinning, and the sand grains deform by fracturing parallel to σ1. The transition in deformational behavior of this rock is similar to the transition observed in orthooalcite rocks. However, in contrast to orthocalcite rocks, (1) strength is enhanced, (2) ductility is markedly reduced, end (3) the brittle-ductile transition is suppressed to much higher confining pressures. The behavior of this rock is analyzed by considering a two-phase model material consisting of a dispersion of strong, brittle particles within a weak and/or ductile matrix. Principles developed through the study of particulate reinforced composite engineering materials indicate that the mechanical behavior of these materials is dependent upon the mechanical interaction of the two phases. The sand grains act to constrain flow of the ductile matrix. Concurrently, plastic deformation within the matrix results in the development of stress concentrations within the nearly rigid sand grains. These enhanced stresses may result in the initiation and propagation of fractures within the sand grains. Propagation of the fractures is parallel to the maximum principal stress and the fractures characteristicly develop in this manner. Although the inherent physical properties of the individual phases determine the strain development within the individual phases, it is the interaction of the two phases which determines the unique behavior of the composite material. This behavior in turn controls the strength of the material and exerts an important influence on the development of the deformation fabric. The two-phase model not only provides insight into the behavior of calcite-cemented sandstones and other analogous rocks, but also makes it possible to predict how these rocks will behave when factors such as temperature and strain rate are permitted to vary. </p> / Thesis / Doctor of Philosophy (PhD)

Diagenetic and structural aspects of tight gas sandstones must be addressed concurrently in order to fully understand low-permeability sandstones and to better predict their reservoir quality attributes that arise from a combination of pore-scale and fracture distribution characteristics. This dissertation focuses on aspects of rock evolution that are germane to concurrent structural and diagenetic evolution, such as loading and thermal history, rock mechanical property evolution, and fracture timing. I tested the hypothesis that the cement precipitation step, governed by thermal exposure and grain surface attributes, governs how sandstone attributes evolve using observations from the Late Cretaceous Williams Fork sandstones from the Piceance Basin, Colorado. My research shows that essential information for predicting and understanding fracture patterns in sandstone can be obtained by unraveling cement precipitation (diagenetic) history. Fractures depend on the mechanical properties existing during fracture growth. I show that key rock mechanical properties (subcritical crack index, Young's modulus and Poisson's ratio), petrophysical behavior, and reservoir quality depend in a systematic way on time-temperature history and the intrinsic grain surface attributes of these sandstones. I classified the Williams Fork lithofacies petrographically and correlated those with log responses to create a model that can be used to predict reservoir quality and diagenesis directly from well logs. I determined rock mechanical characteristics by measuring the subcritical crack index (SCI), a mechanical property that influences fracture distribution characteristics, and by examining log-derived bulk mechanical properties. To quantify the influence of quartz cementation on the SCI and to determine the range of SCI values for sandstone of given framework composition at different diagenetic stages, I measured SCI on Williams Fork core samples and their outcrop equivalents. Diagenetic modeling is applied to determine the sandstone characteristics during fracturing. / text

>Magister Scientiae - MSc / Clay diagenesis phenomenon and their effects on some petrophysical properties of lower cretaceous silliciclastic sandstones, offshore Orange basin have been established. Previous studies on Orange basin revealed that chlorite and quartz cements have significantly compromised the reservoir quality in this basin but it is expected that the reservoirs shows better improvement basinward, an analogy of this is displayed by tertiary sandstones deposit, offshore Angola. The main goal of this thesis is to perform reservoir quality evaluation by intergrating geological, geochemical and geophysical tools to substantiate the effects of clay minerals distribution and its subsequent diagenesis on the intrinsic properties (porosity, permeability and saturation) of reservoir intervals encountered within three wells in block 3A (deeper waters), offshore Orange basin. Five lithofacies were identified based on detailed core description from wells KF-1, KH-1 and AU-1 in this block. The facies were grouped based on colour and grain sizes, they are named : A1 (shale), A2 (sandstone), A3 (siltstone), A4 (dark coloured sandstone) and A5 (conglomerates).Depositional environment is predominantly marine, specifically, marine delta front detached bars and deepwater turbiditic sandstone deposit. Geophysical wire line logs of gamma ray, resistivity logs combo and porosity logs were interpreted, parameters and properties such as VCL, porosity, permeability and saturation were estimated from these logs and the values obtained were compared with values from conventional core analysis data, the values agreed well with each other. Detailed petrographic studies (SEM, XRD and thinsection) plus geochemical studies (CEC, EDS, pH, Ec) were carried out on twenty two core samples to establish if these clay minerals and other cements have pervasive effects on the reservoir quality or otherwise.

<p> Lower Cretaceous Mannville Group sandstones of Alberta were deposited in non-marine and marginal environments. A shallow sea transgressed several times over the study area and left evidence of tidal action. The proportion of rock fragments increases from Lower Mannville to Upper Mannville sandstones due to the uplifting of strata to the west. </p> <p> Observed petrographic and SEM textures indicate that authigenic pyrite, quartz and calcite cements were precipitated in that order followed by the dissolution of carbonate material and feldspar grains with the simultaneous precipitation of kaolinite and quartz. The secondary (or dissolution) porosity is the result of an influx of acidic pore waters. This secondary porosity is best developed in the Ellerslie Sandstone because its remnant intergranular porosity and permeability are superior to the porosity and permeability in the overlying sandstones. The present degree of diagenesis in the sandstones is largely controlled by the permeability of the rock. </p> / Thesis / Bachelor of Science (BSc)

<p> A detailed section of the Duck Cove Member (Nadon, 1981) of the Triassic Lepreau Formation of Southern New Brunswick is measured.</p> <p> The section consists of a complex sequence of conglomerates and sandstones with a minor occurrence of mudstones and breccia. A description of the facies is provided and an interpretation is based on observations of ancient and marine braided stream deposits of Miall (1978) and Allen (1983). The Markov chain analysis is used to describe the vertical succession of facies.</p> <p> Paleoflow indicators suggest a flow towards the south or southeast. However this conclusion is based on limited availability of data.</p> / Thesis / Bachelor of Science (BSc)

Fractures can increase the permeability and producability of reservoirs by acting as fluid and gas conduits to wells. Networks of fractures are most important in reservoirs where little to no matrix permeability exists such as tight gas sandstones. Two significant variables, fracture length and the abundance of fractures, are not readily measurable from subsurface observations such as those obtained from cores or well logs. Numerical models suggest natural fracture apertures and lengths follow systematic power-law (Marrett, 1996; Olson, 2007) and negative exponential distributions (Olson, 2004); fracture trace lengths are interrogated. This study tests those propositions through study of fractures in outcrop. Outcrops of the Cretaceous Frontier Formation at Oyster Ridge in southwest Wyoming and Oil Mountain near Casper, in central Wyoming provide evidence of reservoir scale fracture networks in sandstones. In the subsurface the Frontier Formation sandstones are reservoirs that produce gas and oil in several Wyoming basins. I mapped fracture patterns at twenty locations at Oyster Ridge and Oil Mountain and measured fracture trace length distributions and abundance (intensity). Fracture cumulative length distribution plots illustrate systematic length distributions. Trace length distributions of every fracture network follow negative exponential distributions regardless of the number of fractures (N = 39 to N = 394) or the size of the outcrop (1.3 to 710 m²). Results show that the fractures follow a negative exponential distribution over a range of lengths of a few centimeters to tens of meters. These trace length distributions are consistent with geomechanical model fracture pattern simulation results by Olson (2004) that suggests negative exponential trace length distribution result from fracture to fracture interaction during fracture formation. Length distributions from my field study are inconsistent with pattern simulation results by Marrett (1996) and Olson (2007) and others that produce power-law length distributions. This inconsistency suggests that the model assumptions of Olson (2004) best account for the patterns I observed. Two dimensional fracture intensity, defined as the total fracture trace length divided by the map area, was measured for each outcrop to determine how structural position affects fracture abundance patterns. Two-dimensional fracture intensity measurements collected at thirteen structural locations around Oil Mountain show higher values of fracture intensity near the fold-axial-trace compared to fold limbs. The difference is as much as 7.4 fractures per meter near fold hinges compared to 0.63 fractures per meter in fold limbs. Outcrops near small faults, with displacement of a few meters, show an increase in fracture intensity from background values around 4.8 fractures per meter to values nearly three times as high (13 fractures per meter) near faults. Values of fracture intensity that are more elevated near small tear faults imply that faulting has a greater influence on fracture intensity than folding. / text