<p> A 6012-foot Monterey Formation succession at Chico Martinez Creek, San Joaquin basin, is characterized at high spatial resolution by spectral gamma-ray data in 2- foot increments, 5-foot lithologic descriptions, and qualitative XRD and FTIR analysis. Based on these data, the 4 Monterey members&ndash;the Gould, Devilwater, McDonald and Antelope shales&ndash;are subdivided into 7 distinctive lithofacies. New paleomagnetic data, combined with industry-provided biostratigraphy establishes a chronostratigraphic framework and allows determination of linear sediment accumulation rates. Condensed sedimentation at the onset of McDonald deposition (~14 Ma) is also observed in correlative members in the Pismo, Santa Maria and Santa Barbara basins. This regional event is associated with eustatic regression from the Mid-Miocene highstand related to formation of the East Antarctic Ice Sheet and ongoing thermotectonic basin subsidence. A surge in linear sediment accumulation rates in the siliceous upper McDonald and Antelope (~10.4 Ma) is attributed to a regional increase in diatom productivity. </p>

<p> Among the most important properties controlling the production from conventional oil and gas reservoirs is the distribution of porosity and permeability within the producing geologic formation. The geometry of the pore space within these reservoirs, and the permeability associated with this pore space geometry, impacts not only where production can occur and at what flow rates but can also have significant influence on many other rock properties. Zones of high matrix porosity can result in an isotropic response for certain reservoir properties whereas aligned porosity/permeability, such as open, natural fracture trends, have been shown to result in reservoirs being anisotropic in many properties.</p><p> The ability to identify zones within a subsurface reservoir where porosity/permeability is significantly higher and to characterize them according to their geometries would be of great significance when planning where new boreholes, particularly horizontal boreholes, should be drilled. The detection and characterization of these high porosity/permeability zones using their isotropic and anisotropic responses may be possible through the analysis of azimuthal (also referred to as azimuth-limited) 3D seismic volumes.</p><p> During this study the porosity/permeability systems of a carbonate, pinnacle reef within the northern Michigan Basin undergoing enhanced oil recovery were investigated using selected seismic attributes extracted from azimuthal 3D seismic volumes. Based on the response of these seismic attributes an interpretation of the geometry of the porosity/permeability system within the reef was made. This interpretation was supported by well data that had been obtained during the primary production phase of the field. Additionally, 4D seismic data, obtained as part of the CO₂ based EOR project, supported reservoir simulation results that were based on the porosity/permeability interpretation.</p>

<p> Detection of Morrow A sandstones is a major problem in the exploration of new fields and the characterization of existing fields because they are very thin and laterally discontinuous. The present research shows the advantages of S-wave data in detecting and characterizing the Morrow A sandstone. Full-waveform modeling is done to understand the sandstone signature in P-, PS- and S-wave gathers. The sandstone shows a distinct high-amplitude event in pure S-wave reflections as compared to the weaker P- and PS-wave events. Modeling also helps in understanding the effect of changing sandstone thickness, interbed multiples (generated by shallow high-velocity anhydrite layers) and sidelobe interference effect (due to Morrow shale) at the Morrow A level. </p><p> Multicomponent data need proper care while processing, especially the S-wave data which are aected by the near-surface complexity. Cross-spread geometry and 3D FK filtering are effective in removing the low-velocity noise trends. The S-wave data obtained after stripping the S-wave splitting in the overburden show improvement for imaging and reservoir property determination. Individual P- and S-wave attributes as well as their combinations have been analyzed to predict the A sandstone thickness. A multi-attribute map and collocated cokriging procedure is used to derive the seismic-guided isopach of the A sandstone. </p><p> Postle Field is undergoing CO₂ flooding and it is important to understand the characteristics of the reservoir for successful flood management. Density can play an important role in finding and monitoring high-quality reservoirs, and to predict reservoir porosity. prestack P- and S-wave AVO inversion and joint P- and S-wave inversion provide density estimates along with the P- and S-impedance for better characterization of the Morrow A sandstone. The research provides a detailed multicomponent processing, inversion and interpretation work flow for reservoir characterization, which can be used for exploration in other parts of the world as well.</p>

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> This thesis describes the advantages of investigating gas shales reservoir description on a nanoscale by using petrographic analysis and core plug petrophysics to characterize the Barnett, Marcellus and Mancos shale plays. The results from this analysis now indicate their effects on the reservoir quality. Helium porosity measurements at confining pressure were carried out on core plugs from this shale plays. SEM (Scanning Electron Microscopy) imaging was done on freshly fractured gold-coated surfaces to indicate pore structure and grain sizes. Electron Dispersive X-ray Spectroscopy was done on freshly fractured carbon-coated surfaces to tell the mineralogy. Extra-thin sections were made to view pore spaces, natural fractures and grain distribution. </p><p> The results of this study show that confining pressure helium porosity values to be 9.6%, 5.3% and 1.7% in decreasing order for the samples from the Barnett, Mancos and Marcellus shale respectively. EDS X-ray spectroscopy indicates that the Barnett and Mancos have a high concentration of quartz (silica-content); while the Mancos and Marcellus contain calcite. Thin section analysis reveals obvious fractures in the Barnett, while Mancos and Marcellus have micro-fractures. </p><p> Based on porosity, petrographic analysis and mineralogy measurements on the all the samples, the Barnett shale seem to exhibit the best reservoir quality.</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.

<p> The recent and rapid growth of horizontal drilling in the Anadarko basin necessitates newer studies to characterize reservoir and source rock quality in the region. Most oil production in the basin comes from the Granite Wash reservoirs, which are composed of stacked tight sandstones and conglomerates that range from Virgillian (305&ndash;299 Ma) to Atokan (311&ndash;309.4 Ma) in age. By utilizing geophysical well logging data available in raster format, the Granite Wash reservoirs and their respective marine flooding surfaces were stratigraphically mapped across the regional fault systems. Additionally, well log trends were calibrated with coincident core data to minimize uncertainty regarding facies variability and lateral continuity of these intervals. In this thesis, inferred lithofacies were grouped into medium submarine fan lobe, distal fan lobe, and offshore facies (the interpreted depositional environments). By creating isopach and net sand maps in Petra, faulting in the Missourian was determined to have occurred syndepositionally at the fifth order scale of stratigraphic hierarchy.</p><p>

Includes folded maps.