<p> The informally known &ldquo;Mississippian Limestone&rdquo; stratigraphic interval in north-central Oklahoma, U.S.A. bears no chronostratigraphic markers and has no formally established biostratigraphic framework to date. Conodonts collected from four &ldquo;Mississippian Limestone&rdquo; cores in Logan, Payne, and Lincoln Counties provide the means for better constraining the stratigraphic age of the interval over the area studied. Conodont extraction was conducted by acid digestion of whole-rock samples and heavy liquid density separation after which conodont genera and species types were identified from scanning electron microscopy. Biostratigraphically significant conodonts recovered in combination with chemostratigraphic work by Dupont (2016) and earlier studies by Thornton (1958), Curtis and Chaplin (1959), McDuffie (1959), Rowland (1964), Selk and Ciriacks (1968), and Harris (1975) indicate the &ldquo;Mississippian Limestone&rdquo; ranges from middle Osagean to late Chesterian in age. In general, conodont element recoveries were too low in quantity and too poor of quality for use as biostratigraphic markers. The relatively low recovery and poor preservation quality of the conodont elements are attributed primarily to the elements being reworked soon after deposition by frequent storms on a mid- to outer-ramp environment in a low-latitude carbonate ramp setting. The results of this investigation are most significant in that they help place Mississippian deposition over the area studied within the context of a global Carboniferous stratigraphy. The results also allow for the Mississippian interval in the study area to be more accurately related to time-correlative strata with similar or better age constraint for constructing more temporally meaningful depositional models of the Oklahoma basin.</p><p>

<p> CO₂ flooding has proven to be an effective technique for enhanced oil recovery. However, the application of CO₂ flooding in the recovery process of asphaltenic crude systems is often avoided, as high asphaltene precipitation rates may occur. While the effects of asphaltene concetration and CO₂ injection pressure on asphaltene precipitation rate have been the focus of many studies, asphaltene precipitation rate is not a reliable factor to predict the magnitude of asphaltene-induced formation damage. Wettability alteration is only caused by the immobile asphaltene deposits on the rock surface. The enternmaint of flocs may occur at high fluid velocity. Morover, the effective permeability reduction is only caused by the flocs, which have become large enough to block the pore throats. The dissociation of the flocs may occur under certain flow conditions. In this study, a compositional reservoir simulation was conducted using Eclipse 300 to investigate the injection practice, which avoids asphaltene-induced formation damage during both immiscible and miscible CO₂ flooding in asphaltenic crude system. Without injection, at pressure above bubble point, slight precipitation occurred in the zone of the lowest pressure near the producing well. As pressure approached the bubble point, precipitation increased due to the change in the hydrocarbon composition, which suggested that the potential of asphaltene-induced formation damage is determined by the overall fluid composition. At very low pressure, precipitation decreased due to the increase in the density. </p><p> As CO₂ was injected below the minimum miscibility pressure, a slight precipitation occurred in the transition zone at the gas-oil interface due to the microscopic diffusion of the volatile hydrocarbon components caused by the local concentration gradients. The increase in CO₂ injection rate did not significantly increase the precipitation rate. </p><p> As CO₂ was injected at pressure above the minimum miscibility pressure, precipitation occurred throughout the entire reservoir due to the vaporizing drive miscibility process. While precipitation increased with the injection rate, further increase in the injection rate slightly decreased the deposition due to shear. The pressure drop in the water phase caused by the pore throat increased the local water velocity, resulting in a more effective removal of the clogging asphaltene material.</p><p>

2D and 3D basin models have been constructed of the southern and central parts of the Vulcan Sub-Basin, which is located in the Timor Sea, north-western Australia. This work was carried out in order to better elucidate the petroleum migration and accumulation histories and exploration potential of the region. The study area extended from the southern limit of the Swan Graben in the south-west to the northern part of the Cartier Trough in the north-east. The results from the basin modelling have been compared with the seafloor bathymetry and physiography, the spatial distributions of hydrocarbon related diagenetic zones (HRDZs) in the region, as well as the distribution of other leakage and seepage indicators. A new method for identifying potential HRDZs using seismic data has also been developed. The 2D/3D modeling results from the Swan Graben indicate that horizontal and downward oil expulsion from the source rocks of the Late Jurassic Lower Vulcan Formation into the upper Plover Formation sandstones was active from the Early Cretaceous to the present day. Oil migration from the Lower Vulcan Formation into the Late Cretaceous Puffin Formation sands in the Puffin Field was simulated via lateral migration along the bottom of an Upper Vulcan Formation seal and by vertical migration above the seal edge. Modelling also indicates that Late Jurassic sequences over the Montara Terrace are thermally immature and did not contribute to the hydrocarbon accumulations in the region. On the other hand, 3D modelling results indicate that the Middle Jurassic Plover Formation in the Montara Terrace became thermally mature after the Pliocene and hence it could have contributed to both the specific hydrocarbon accumulations and the overall hydrocarbon inventory in the area. In the southern Cartier Trough, the Lower Vulcan Formation is typically at a lower thermal maturity than that seen in the Swan Graben, due to a combination of a relatively recent (Pliocene) increased burial and a thinner Lower Vulcan Formation. Here, horizontal and downward oil/gas expulsion from the Lower Vulcan Formation into the Plover Formation sandstone was active from the Late Tertiary to the present day, which is significantly later than the timing of the expulsion in the Swan Graben. In the central Cartier Trough, the areal extent of both generation and expulsion increased as a result of rapid subsidence and deposition from about 5.7 Ma to the present day. This Pliocene loading has resulted in the rapid maturation of the Early to Middle and Late Jurassic source system and expulsion of oil very recently. Oil migration from the Lower Vulcan Formation into the Jabiru structure, via the Plover Formation carrier bed, was simulated in both the 2D and the 3D modelling. In particular, the 3D modelling simulated oil migration into the Jabiru structure, both from the southern Cartier Trough (after the Miocene) and also from the northern Swan Graben (in the Early Cretaceous). Early gas migration, and the attendant formation of a gas cap, was also simulated. Importantly, this result provides a potential alternative interpretation for the formation of at least some of the residual zones in the Timor Sea, as well as in other areas. Traditionally, most of the residual zones within the Timor Sea have been attributed to fault seal reactivation and failure. However, the simulated early gas cap in the Jabiru structure has formed as a result of gas exsolution as the migrating hydrocarbons entered the Jabiru trap (and its shallow flanks), which was then only located a few hundred metres below the surface. The rapidly decreasing pressure allowed the gas to form a separate phase, with the result that in the Early Cretaceous, in the 3D model, the Jabiru trap was composed of a relatively large gas cap with a thinner (“black oil”) oil leg. Progressive burial through the Tertiary, and the attendant increase in pressure, resulted in the gas going back into solution. The associated decrease in the bulk volume of the hydrocarbon accumulation produced a “residual” oil zone at the base of the column, purely through a change in phase, rather than through loss of hydrocarbons from fault seal failure, for example. The processes outlined in this scenario would be essentially indistinguishable from those produced by fault seal failure when assessing traps using fluid history tools such as GOI. Such a process could be critically important in the case of shallow, low-relief traps, where only the exsolved gas could be trapped, with the “black oil” component displaced below the spill of the trap. Small, sub-commercial gas fields would thus be located around the periphery of the source depocentres - though these would be the result of an early, rather than late, gas charge. Small black oil accumulations could be developed inboard from such gas fields. A new method to extract HRDZs from 3D seismic data has predicted the location of new HRDZs in the northern Vulcan Sub-basin. Further investigation is needed to confirm/refine the method but it has the potential to significantly aid HRDZ mapping (and seal assessment and hydrocarbon migration studies). A workflow for future studies is proposed which includes inputs from basin modelling, leakage and seepage mapping, and fault seal and fault reactivation studies. Implementation of this workflow should ultimately allow a more reliable estimation of GOR prior to drilling. / http://proxy.library.adelaide.edu.au/login?url= http://library.adelaide.edu.au/cgi-bin/Pwebrecon.cgi?BBID=1277632 / Thesis(M.Sc.)-- Australian School of Petroleum, 2007.

Thesis (Ph. D.)--University of Texas at Austin, 1999. / Vita. Includes bibliographical references (leaves 177-191). Available also in a digital version from Dissertation Abstracts.

Thesis (Ph. D.)--Oregon State University, 1995. / System requirements for computer disk: IBM-compatible PC. Typescript (photocopy). Includes plates in pocket. Includes bibliographical references. Also available on the World Wide Web.

<p> The objective of this study is threefold: 1) Build a dual-porosity, geological reservoir model of Niobrara formation in the Wishbone Section of the DJ Basin. 2) Use the geologic static model to construct a compositional model to assess performance of Well 1N in the Wishbone Section. 3) Compare the modeling results of this study with the result from an eleven-well modeling study (Ning, 2017) of the same formation which included the same well. The geologic model is based on discrete fracture network (DFN) model (Grechishnikova 2017) from an outcrop study of Niobrara formation.</p><p> This study is part of a broader program sponsored by Anadarko and conducted by the Reservoir Characterization Project (RCP) at Colorado School of Mines. The study area is the Wishbone Section (one square mile area), which has eleven horizontal producing wells with initial production dating back to September 2013. The project also includes a nine-component time-lapse seismic. The Wishbone section is a low-permeability faulted reservoir containing liquid-rich light hydrocarbons in the Niobrara chalk and Codell sandstone.</p><p> The geologic framework was built by Grechishnikova (2017) using seismic, microseismic, petrophysical suite, core and outcrop. I used Grechishnikova&rsquo;s geologic framework and available petrophysical and core data to construct a 3D reservoir model. The 3D geologic model was used in the hydraulic fracture modeling software, GOHFER, to create a hydraulic fracture interpretation for the reservoir simulator and compared to the interpretation built by Alfataierge (2017). The reservoir numerical simulator incorporated PVT from a well within the section to create the compositional dual-porosity model in CMG with seven lumped components instead of the thirty-two individual components. History matching was completed for the numerical simulation, and rate transient analysis between field and actual production are compared; the results were similar. The history matching parameters are further compared to the input parameters, and Ning&rsquo;s (2017) history matching parameters.</p><p> The study evaluated how fracture porosity and rock compaction impacts production. The fracture porosity is a major contributor to well production and the gas oil ratio. The fracture porosity is a major sink for gathering the matrix flow contribution. The compaction numerical simulations show oil production increases with compaction because of the increased compaction drive. As rock compaction increases, permeability and porosity decreases. How the numerical model software, CMG, builds the hydraulic fracture, artificially increases the original oil-in-place and decreases the recovery factor. Furthermore, grid structure impacts run-time and accuracy to the model. Finally, outcrop adds value to the subsurface model with careful qualitative sedimentology and structural extrapolations to the subsurface by providing understanding between the wellbore and seismic data scales.</p><p>

<p> In this study, imbibition experiments are used to explain the significant fluid loss, often more than 70%, of injected water during well stimulation and flowback in the context of natural gas production from shale formations. Samples from a 180 ft. long section of a vertical well were studied via spontaneous and forced imbibition experiments, at lab-scale, on small samples with characteristic dimensions of a few cm; in order to quantify the water imbibed by the complex multi-porosity shale system. The imbibition process is, typically, characterized by a distinct transition from an initial linear rate (vs. square root of time) to a much slower imbibition rate at later times. These observations along with contact angle measurements provide an insight into the wettability characteristics of the shale surface. Using these observations, together with an assumed geometry of the fracture system, has made it possible to estimate the distance travelled by the injected water into the formation at field scale. </p><p> Shale characterization experiments including permeability measurements, total organic carbon (TOC) analysis, pore size distribution (PSD) and contact angle measurements were also performed and were combined with XRD measurements in order to better understand the mass transfer properties of shale. The experimental permeabilities measured in the direction along the bedding plane (10^&ndash;1&ndash;10^&ndash;2 mD) and in the vertical direction (~10^&ndash;4 mD) are orders of magnitude higher than the matrix permeabilities of these shale sample (10^&ndash;5 to 10^&ndash;8 mD). This implies that the fastest flow in a formation is likely to occur in the horizontal direction, and indicates that the flow of fluids through the formation occurs predominantly through the fracture and micro-fracture network, and hence that these are the main conduits for gas recovery. The permeability differences among samples from various depths can be attributed to different organic matter content and mineralogical characteristics, likely attributed to varying depositional environments. The study of these properties can help ascertain the ideal depth for well placement and perforation. </p><p> Forced imbibition experiments have been carried out to better understand the phenomena that take place during well stimulation under realistic reservoir conditions. Imbibition experiments have been performed with real and simulated frac fluids, including deionized (DI) water, to establish a baseline, in order to study the impact on imbibition rates resulting from the presence of ions/additives in the imbibing fluid. Ion interactions with shales are studied using ion chromatography (IC) to ascertain their effect on imbibition induced porosity and permeability change of the samples. It has been found that divalent cations such as calcium and anions such as sulfates (for concentrations in excess of 600 ppm) can significantly reduce the permeability of the samples. It is concluded, therefore, that their presence in stimulating fluids can affect the capillarity and fluid flow after stimulation. We have also studied the impact of using fluoro-surfactant additives during spontaneous and forced imbibition experiments. A number of these additives have been shown to increase the measured contact angles of the shale samples and the fluid recovery from them, thus making them an ideal candidate for additives to use. Their interactions with the shale are further characterized using the Dynamic Light Scattering (DLS) technique in order to measure their hydrodynamic radius to compare it with the pore size of the shale sample.</p><p>

<p> To efficiently produce oil from unconventional reservoirs, it is imperative to determine and understand the geomechanical properties of the formation. But, due to the high cost of obtaining these properties from geomechanical well logs, businesses are looking for all possible ways to cut cost. The plummeting oil prices have been reflected in company spending and have driven companies to prioritize focusing attention on the rising production costs and venture all possible ways to reduce these costs. The real challenge is how to preserve these profitable gains? There is a need for an alternate and cost- effective way to obtain geomechanical properties of the rocks. </p><p> By utilizing Data Analytics, Data Mining, and ANN, patterns are observed between parameters from large amounts of data and, thus, important information regarding the formation can be understood. In this study, a relationship between conventional well logs and geomechanical well logs are established. Properties such as Young&rsquo;s Modulus, Poisson&rsquo;s Ratio, Shear Modulus, Bulk Modulus, and Minimum Horizontal Stress are determined from Conventional Logs such as Gamma Ray and Density Log utilizing ANN. Ultimately, data-driven models are developed to predict accurate geomechanical properties for future wells of the Upper and Middle Bakken Formation. Finally, the efficacy of the data-driven models achieved is tested on randomly selected new wells that were not used in the training of the model. The accurate prediction and analysis of these properties help in better reservoir characterization and efficient production from the future wells in the Bakken Formation.</p><p>

The building blocks of a sedimentary system are essential inputs into studies of reservoir character and comparisons with other sedimentary systems. Yet, our current knowledge of the building blocks of deep water slope channel deposits is still largely speculative. A quantitative approach has been utilised in order to analyse a host of lithological data and objectively identify these sedimentary components. The laterally-extensive and gently-dipping continental slope deposits of the San Fernando Channel System, Baja California, provide the required control on sub-seismic-scale temporal and lateral variations of lithofacies and 3D architecture. High resolution photo-panoramas (with better than 2mm accuracy) of the prominent conglomeratic component of the succession were collected from various key parts of the outcrop. Image analysis of segments extracted from the photo-panoramas generates key parameters for comparison of texture and fabric of conglomerates, such as clast to matrix ratio, major axis length and relative orientation. Statistical analysis of these data enabled the erection of an objective lithofacies scheme for the gravel fraction, the grouping of lithofacies into objectively-defined assemblages, and the establishment of models for the lateral and stratigraphic distributions of these assemblages. 12 lithofacies were objectively identified through hierarchical cluster analysis of 4 quantitative lithological parameters. Statistical analyses indicate significant differences in diversity in the lithofacies assemblages between the early and later parts (termed Stage 1 and Stage 2) of a channel complex set (sensu Sprague, et al., 2002), and to a lesser extent between marginal and axial parts of the system. These can be related to spatial differences and temporal changes in the nature of the turbidity currents flowing through the channel system. Gravelly units become more organised and less diverse with time in one CCS, and each successive CCS more organised at earlier stratigraphic levels than the next, except for the last CCS which is interpreted as influenced by a tectonic paroxysm. These seemingly autocyclic changes in organisation are interpreted as process-responses to changes in equilibrium profile as the nature of confinement changes with the infilling of an initial erosional confinement, to confinement by a master levee and gradual infilling through the evolution of each CCS.