No description available.

No description available.

No description available.

The Jurassic sediments of the Minch Basin were deposited in a series of small interconnected basins that became the centre of extensive igneous activity during the Lower Tertiary. Outcrop samples have been collected from throughout the Minch area, particularly from the islands of Skye and Raasay, and aliphatic and aromatic hydrocarbon fractions analysed for biomarker compounds by GC-MS. Sample suites collected from the margins of Tertiary igneous dykes of varying sizes have shown that the dykes matured the immature sediments in a manner analogous to burial. Biomarker reactions however occurred later relative to kerogen breakdown reactions, so that the hopane isomer ratio does not reach completion until the peak of oil generation. Steroid aromatisation occurs at a similar rate to isomerisation, suggesting heating rate is not the only control on relative rates of reaction. The sills seen in the youngest Jurassic sediments have not had the same effect, but show anomalous η-alkane distributions with heavy preference in the most heated samples. The biomarker isomer ratios are not at equilibrium values, possibly due to high temperature cracking. These unusual effects are interpreted as the result of intrusion into wet unconsolidated sediments. The central intrusive complexes have also had the effect of maturing the country rock sediments, with the oil window seen on Raasay between about 5km and 8km from the complex margin. No thermal effect is seen beyond about 15km. Maturity appears to decrease radially away from the complex, and no anomalies can be definitely ascribed to postulated hydrothermal circulation systems. The temperature of the peak of oil generation is estimated as 130°C. Biomarker assemblages in immature sediments from all Jurassic formations have been considered in relation to proposed depositional environment and palynofacies. A number of unusual features have been noted including abundant heavy anteisoalkanes in shales associated with corals, very abundant 4-methyl steranes in the Cullaidh Shale, and unusual assemblages in the lagoonal Duntulm Formation. A dark brackish marine shale contained virtually nothing other than C_25 and C_27 η-alkanes and C₂₇ steranes, yet the palynomorphs consisted almost entirely of a monotypic dinoflagellate assemblage. A cryptic algal source is suggested for the η-alkanes. 4-methyl sterane distributions in all formations have been plotted on triangular diagrams and separate into distinct fields. This may be due to different dinoflagellate input. Finally, the petroleum potential of the Jurassic sediments in the basin has been assessed. Although potential source rocks occur, it seems unlikely that they can have been matured by burial in the Minch, and the Central Intrusive Complexes can not have matured a significant volume of source rock. It is possible however that large sills concordant with bedding could have matured source rocks over a wider area, and it is suggested that this has occurred at Invertote, where the black sandstone beneath the Cullaidh Shale is believed to be an exhumed reservoir.

<p> <b>Petrophysical evaluation of lithology and mineral distribution with an emphasis on feldspars and clays, middle and upper Williams Fork Formations, Piceance Basin, Colorado.</b> Understanding accessory mineralogy occurrence and distribution is critical to evaluating the reservoir quality and economic success of tight&ndash;gas reservoirs, since the occurrence of iron&ndash;rich chlorites can decrease resistivity measurements and the occurrence of potassium feldspar increases gamma&ndash;ray measurements, resulting in inaccurate water saturation and net&ndash;to&ndash;gross calculations, respectively. This study was undertaken to understand the occurrence and distribution of chlorite and potassium feldspar in the middle and upper Williams Fork Formations of the Piceance Basin at Grand Valley Field. </p><p> Eight lithofacies are identified in core based on grain&ndash;size, internal geometry, and sedimentary structures. Four architectural elements (channel fill, crevasse splay, floodplain, and coal) were determined from lithofacies relationships, and then associated with well&ndash;log responses. Logs and models were used to determine the occurrence and distribution of lithology, architectural elements, chlorite and potassium feldspar, as well as the relationships between minerals and lithology and architectural elements. Net&ndash;to&ndash;gross ratios vary stratigraphically, from 8% to 88%, with a higher average in the middle Williams Fork Formation (58.3%) than in the upper Williams Fork Formation (48.5%). Volumetric proportions vary stratigraphically for both channel fills (18&ndash; 75%) and crevasse splays (1&ndash;7%). </p><p> The average volume percent of chlorite and potassium feldspars are both &lt;1%, with P ₅₀ values of 1.3% and 7%, respectively. Chlorite is pervasive at the base of the middle Williams Fork Formation: almost 90% of the sandstones in sand&ndash;rich intervals contain chlorite. The distribution of chlorite did not vary between reservoir architectural elements, with 70% of both crevasse splays and channel fills containing chlorite. The results of this study show that, for the middle and upper Williams Fork Formations at Grand Valley Field, 1) there are eight lithofacies and four architectural&ndash;element types identified from core; 2) the occurrence and distribution of accessory minerals (&lt;10%) of chlorite and potassium feldspar can be accurately estimated from limited core and well&ndash;log data; 3) chlorite occurrence does not vary significantly between reservoir architectural elements; 4) the abundance of chlorite near completion intervals and the occurrence of potassium feldspar in calculated mudstone lithologies indicate a need to re&ndash;evaluate the utilization of saturation models and lithology calculations in reservoir&ndash;quality evaluations.</p>

<p> Hydraulic fracturing was first carried out in the 1940s and has gained popularity in current development of unconventional resources. Flowing back the fracturing fluids is critical to a frac job, and determining well cleanup characteristics using the flowback data can help improve frac design. It has become increasingly important as a result of the unique flowback profiles observed in some shale gas plays due to the unconventional formation characteristics. </p><p> Computer simulation is an efficient and effective way to tackle the problem. History matching can help reveal some mechanisms existent in the cleanup process. The Fracturing, Acidizing, Stimulation Technology (FAST) Consortium at Colorado School of Mines previously developed a numerical model for investigating the hydraulic fracturing process, cleanup, and relevant physics. It is a three-dimensional, gas-water, coupled fracture propagation-fluid flow simulator, which has the capability to handle commonly present damage mechanisms. </p><p> The overall goal of this research effort is to validate the model on real data and to investigate the dominant physics in well cleanup for the Cana Field, which produces from the Woodford Shale in Oklahoma. </p><p> To achieve this goal, first the early time delayed gas production was explained and modeled, and a simulation framework was established that included all three relevant damage mechanisms for a slickwater fractured well. Next, a series of sensitivity analysis of well cleanup to major reservoir, fracture, and operational variables was conducted; five of the Cana wells' initial flowback data were history matched, specifically the first thirty days' gas and water producing rates. </p><p> Reservoir matrix permeability, net pressure, Young's modulus, and formation pressure gradient were found to have an impact on the gas producing curve's shape, in different ways. Some moderately good matches were achieved, with the outcome of some unknown reservoir information being proposed using the corresponding inputs from the history matching study. It was also concluded that extended shut-in durations after fracturing all the stages do not delay production in the overall situation. </p><p> The success of history matching will further knowledge of well cleanup characteristics in the Cana Field, enable the future usage of this tool in other hydraulically fractured gas wells, and help operators optimize the flowback operations. Future improvements can be achieved by further developing the current simulator so that it has the capability of optimizing its grids setting every time the user changes the inputs, which will result in better stability when the relative permeability setting is modified.</p>

<p>The depositional environment of the <i>Bigenerina humblei</i> 1, <i>Bigenerina humblei</i> 6, and <i>Amphistegina</i> &ldquo;B&rdquo; 1 sands of the Hog Bayou field in Cameron Parish, Louisiana, was investigated. To complete the investigation, analysis of well log data, along with the preparation of structure, isopach, and fault plane maps, as well as cross sections, were completed for the four sands. Paleontological data and regional literature pertaining to deposition were also utilized. </p><p> The conclusions made for this study are based on interpretation of maps generated and the comparison of these maps with maps and models of modern day and ancient depositional environments. All of the three sands studied in the Hog Bayou field are concluded to be those that are representative of varying stages in the development of a deltaic environment. All information gathered and generated for the study area indicates depositional characteristics of distributary mouth bar, distributary channel fill, and channel complex sands. The Hog Bayou field is structurally based on growth faulting that interacts with many of the strata in the field. Growth faulting and its associated rollover anticlines prove to be the primary targets of hydrocarbon accumulations. </p><p> The conclusions made from this study can put to use in the interpretation of other analogous middle Miocene depocenters found along the Gulf Coast. The understanding of the depositional environment may ultimately lead to new discoveries in yet to be explored fields. </p>

No description available.

Three immobilization matrices, Biofix (kaolinite microspheres), Drizit (polypropylene fibres) and polyester polyurethane were used as substrata for use in bioremediation. Enhanced biodegradation of petrol (Slovene diesel) and Ekofisk crude oil occurred with immobilization of Pseudomonas fluorescens to Biofix and Drizit in freshwater and saltwater systems. When compared to free bacteria, immobilization resulted in; increased growth, accelerated ability of the cells to utilize oil, and enhanced biodegradation as determined by gas chromatography. In the freshwater systems Drizit immobilized cells reduced the lag phase to one day in comparison to six in a free system and increased biodegradation of the n-alkanes by 67 %. Immobilization resulted in enhanced production of a rhamnolipid biosurfactant over the first three days of incubation in comparison to free living bacteria which showed a lag phase of two days. All three supports were compared by; scanning electron microscopy, cell loading capacity, absorption of oil, their abilities to enhance oil biodegradation and the effect of drying and storage on the immobilized cells. Biodegradation of hydrocarbons by immobilized cells was dependent on the biocarrier, with polyurethane immobilized cells failing to enhance biodegradation of Ekofisk crude oil. Drizit was the most effective biocarrier tested and the most suitable immobilization substratum for use as a bioremediation agent. Investigation into the location of the genes for alkane degradation in immobilized Pseudomonas fluorescens was undertaken. Plasmid DNA was detected using gel electrophoresis, and caesium chloride-ethidium bromide gradient was carried out to confirm the presence of the plasmid, but no plasmid band was visualized. The successful immobilization system was scaled-up, optimized by supplementation with nitrates and phosphates and applied to microcosms that modelled environmental conditions. Enhanced biodegradation of Ekofisk crude oil was demonstrated on a larger scale, in an estuarine microcosm, with the immobilized systems showing an average degradation of 41.9 % in comparison to 7.1 % in the microcosm containing free indigenous bacteria.

No description available.