Thesis (Ph. D.)--University of New South Wales, 2004. / Also available online.

Thesis (Ph.D.)--University of Alberta, 2010. / Title from PDF file main screen (viewed on Apr. 13, 2010). A thesis submitted to the Faculty of Graduate Studies and Research in partial fulfillment of the requirements for the degree of Doctor of Philosophy in Petroleum Engineering, [Department of] Civil and Environmental Engineering, University of Alberta. Includes bibliographical references.

Thesis (Ph. D.)--University of Texas at Austin, 2005. / Supervisor: Carlos Torres-Verdín. Vita. Includes bibliographical references.

No description available.

Key petrophysical properties of reservoir sequences are determined by their individual mineral compositions, and are routinely evaluated through the analysis of cores and geophysical well logs. However, mineralogical studies are seldom incorporated in reservoir assessment. The objectives of the study were to investigate the influence of mineralogy on petrophysical properties of petroleum reservoir beds and the application of mineralogical studies in reservoir evaluation. Mineralogical analyses were performed on core samples from the Plover Formation, the principal reservoir sequence in the Northwest Shelf area of Australia, intersected in two separate wells in the Laminaria petroleum field. The techniques used included X-ray powder and oriented-aggregate analysis, optical microscopy and whole rock geochemistry. Quantification of each mineral phase based on whole-rock powder data was performed using the Rietveld-based Siroquant technique. Results from the Siroquant assay were used as an indicator of mineralogy for the individual samples and were compared with core plug and geophysical log data. X-ray micro-tomography analysis of selected samples was also performed. The reservoir sequences in both wells were sand-dominated, consisted mostly of quartz, clay mineral matrix and cement of silica, pyrite or calcite. The abundance of clay minerals increased in the shale and shaly sandstone intervals. Comparison of mineralogical and core plug analyses of samples from the same depths showed that the down-hole variations in porosity, permeability, grain density and radioactivity were accompanied by changes in mineralogy. Higher proportion of clay minerals in shales was indicated by higher gamma log signals. The gamma log may be taken as an indicator of shaliness only in intervals where kaolinite is proportional to the quantity of illitic clays. Sonic log and neutron log porosity values are comparable with core plug porosity data in sandstone intervals. However, clay minerals increase the sonic log response, thereby increasing porosity in shaly intervals. Clay minerals tend to decrease the neutron log response causing higher porosity indication in shales, similar to that expected in sandstones. Routine density log analysis underestimated porosity values because of the contribution of dense minerals to the bulk density of the formation. Use of laboratory determined grain and fluid densities resulted in improved density log porosity compared to core porosity. X-ray tomography analysis revealed an overall positive correlation between mineralogy and porosity data. Routine geophysical log evaluation revealed inconsistent results when compared to core analysis data because of the influence of minerals on various logs. It is essential that mineralogical studies be included in reservoir assessment. X-ray tomography may provide an alternative approach in evaluating porosity and mineralogy.

Thesis (Ph. D.)--University of Texas at Austin, 2004. / Supervisor: Roger T. Bonnecaze. Vita. Includes bibliographical references.

Thesis (Ph. D.)--University of Texas at Austin, 2007. / Vita. Includes bibliographical references.

Thesis (Ph. D.)--University of Texas at Austin, 2002. / Vita. Includes bibliographical references.

Quick evaluation of reservoir performance is a main concern in decision making. Time-consuming input data preparation and computing, along with data uncertainty tend to inhibit the use of numerical reservoir simulators. New analytical solutions are developed for capacitance-resistive models (CRMs) as fast predictive techniques, and their application in history-matching, optimization, and evaluating reservoir uncertainty for water/CO₂ floods are demonstrated. Because the CRM circumvents reservoir geologic modeling and saturation-matching issues, and only uses injection/production rate and bottomhole pressure data, it lends itself to rapid and frequent reservoir performance evaluation. This study presents analytical solutions for the continuity equation using superposition in time and space for three different reservoir-control volumes: 1) entire field volume, 2) volume drained by each producer, and 3) drainage volume between an injector/producer pair. These analytical solutions allow rapid estimation of the CRM unknown parameters: the interwell connectivity and production response time constant. The calibrated model is then combined with oil fractional-flow models for water/CO₂ floods to match the oil production history. Thereafter, the CRM is used for prediction, optimization, flood performance evaluation, and reservoir uncertainty quantification. Reservoir uncertainty quantification is directly obtained from several equiprobable history-matched solutions (EPHMS) of the CRM. We validated CRM's capabilities with numerical flow-simulation results and tested its applicability in several field case studies involving water/CO₂ floods. Development and application of fast, simple and yet powerful analytic tools, like CRMs that only rely on injection and production data, enable rapid reservoir performance evaluation with an acceptable accuracy. Field engineers can quickly obtain significant insights about flood efficiency by estimating interwell connectivities and use the CRM to manage and optimize real time reservoir performance. Frequent usage of the CRM enables evaluation of numerous sets of the EPHMS and consequently quantification of reservoir uncertainty. The EPHMS sets provide good sampling domains and reasonable guidelines for selecting appropriate input data for full-field numerical modeling by evaluating the range and proper combination of uncertain reservoir parameters. Significant engineering and computing time can be saved by limiting numerical simulation input data to the EPHMS sets obtained from the CRMs. / text

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