<p> Despite an increased interest in exploitation of hydrocarbon source rock resource plays, there remains an incomplete understanding of organic and inorganic component interaction within source rocks. Few studies have been conducted concerning the associations between organic and inorganic geochemistry for the purposes of understanding kerogen type, thermal maturity influence, and paleoredox setting. This investigation&rsquo;s goal was evaluating these relationships with samples from the Eagle Ford Formation using organic data, obtained by Rock-Eval pyrolysis and oxidation, and inorganic data, obtained using high-temperature and pressure leaching experiments. The study additionally tested various parameters for whole rock batch leaching, including time, temperature of leaching, and use of acids. The most successful leaching technique was applied to samples that (1) had first been subjected to Rock-Eval pyrolysis, at three different maximum temperatures (450&deg;C, 550&deg;C, and 650&deg;C), as well as (2) samples that had not been subjected to pyrolysis. As different kerogen fractions were destroyed at these different temperatures, variances in elemental concentrations leached from these samples could be attributed, at least partially, to these fractions. Using this approach, the lower molecular weight kerogen fraction contained most of the elements likely attributable to carbonates and sulfides associated with the kerogen (e.g., Ca, Mg, Mn, Mo, P, S, Sr, Zn). The higher molecular weight portion contained more elements probably attributable to clays, quartz, and other clastic minerals (e.g., Al, Fe, K, Si). An evaluation of the overall element chemistry of the rock paired with Rock-Eval parameters showed (1) major/trace elements varied according to amount and type of organic carbon in the Eagle Ford samples, (2) relative abundances of certain major/trace elements were useful proxies for bulk mineralogy and depositional environment, and (3) relationships between certain clay-related major and trace elements and T_max values suggesting clays and trace elements acted to catalyze the cracking of the kerogen.</p>

<p> Two hydrothermal experiments were performed using sandstone core material from the Norwegian North Sea with synthetic brines reacted at approximately 150&deg;C and 450 bars, temperature and pressure calculated to simulate a depth of burial of approximately 4 km. The results of the experiments were analyzed with geochemical modeling and with chemical and petrographic analyses. Geochemical modeling with several computer programs indicated that the experimental fluid was undersaturated with respect to K-feldspar, kaolinite, and illite, but supersaturated with respect to muscovite. Chemical analysis with inductively-coupled plasma mass spectrometry indicated that the fluid reached saturation with respect to K-feldspar. Petrographic analysis with scanning electron microscopy and energy-dispersive scanning indicated that changes took place over the course of the experiments in both the clay and non-clay mineral fractions, and this result was verified by X-ray diffraction analysis that indicated dissolution of both K-feldspar and illite and formation of muscovite. These converging lines of evidence indicate that significant changes took place in the clay mineral fraction of the experimental sandstone core material, reacted at realistic basin temperature, pressure and geochemical conditions, over the course of several weeks.</p>

<p>Prolific amounts of oil and gas have been produced from the San Joaquin Basin in many different oil and gas fields. In many cases, the petroleum system is easily identifiable, and the path hydrocarbons take from source area to trap are known. This study aims to identify secondary migration pathways of hydrocarbons from the source to the trap in an oil field near Fresno, California, where the source is about 35 miles from the trap. To create an accurate subsurface interpretation of the study area, 3D seismic data and more than 300 well logs were used. From subsurface structure maps, net sand maps, an Allan profile, and regional research, it was found that there are two possible migration scenarios that reasonably describe the secondary migration of hydrocarbons into the study area. Six normal faults within the field play large roles as seals and/or migration pathways, and to better understand hydrocarbon migration in the study area, further work must be done on the sealing/leaking behavior of the faults within the field.

<p>The Denver-Julesburg Basin (DJ Basin) has been a productive oil and gas field since 1970 where operators began targeting the J sandstone (Sonnenberg 2013). Within the DJ Basin, the Wattenberg field has been the ?hot spot? for the past several years due to its high gas to oil ratio. The Niobrara Formation has added new value to this area as the use of horizontal drilling and hydraulic fracturing has become common practice for operators in the Wattenberg since 2009 (Sonnenberg 2013). This formation is a ?tight? rock that has very little connectivity making the hydraulic fracturing technique a necessity for economical wells. There are a large number of faults seen in the Wattenberg field that can have just a few feet of displacement to very large faults with 100+ feet of displacement. These faults are likely part of a polygonal fault system that has been linked to dewatering events that occurred prelithification in the Wattenberg Field (Underwood 2013). Along some of these major faults we see sections of Niobrara Formation that are missing, and these fault planes provide a pathway for the expulsion of this sediment. Understanding the pre-lithification faulting and missing section in the Niobrara Formation could result in added economic value as this could lead to finding optimal well placement for maximizing oil recovery. This study was driven by the hypothesis that the missing section of Niobrara Formation could be linked to the Pierre Shale?s Tepee Buttes. To determine the origin of the Tepee Buttes seismic data, well logs, thin sections, and XRF data was used to further investigate the Tepee Buttes, Niobrara Formation Chalks and Marls, Fort Hays Limestone, and Pierre Shale.

<p> Extreme heterogeneity in oil saturation between closely adjacent sandstone beds reflects different timing and degree of diagenesis. Understanding the distribution and origin of such heterogeneity is critical to effectively exploiting intercalated sandstone deposits within fine-grained unconventional reservoirs and in unraveling subtleties of stratigraphic traps. Sea cliff exposures at Point Fermin, California, expose a submarine channel facies within the largely hemipelagic facies. Separated by only meters, Point Fermin Sandstone is oil-saturated, whereas Altamira Shale sandstone is not. Samples were analyzed for porosity, permeability and fluid saturation in conjunction with thinsection petrographic analysis. Sandstones are primarily schist- bearing lithic arenites and the grains are cemented mostly by rhombic dolomite. Data show that both units have the same provenance but differ in the timing and type of diagenesis with shale-hosted sandstones generally showing earlier cementation. The degree and type of cementation occluded pore spaces to prevent hydrocarbon charging in the non-saturated sandstone.</p>

<p> The submarine-fan-dominated, proximal Los Angeles basin contains interstratified hemipelagic strata coeval with the widespread Miocene Monterey Formation that accumulated in other California margin basins. Although more detritalrich and containing greater abundance of plagioclase and muscovite than more distal, outboard basins, a four-part compositional zonation is recognized in the fine-grained facies, similar to the stratigraphic succession of the Santa Barbara coastal area. In ascending stratigraphic order, these include a basal interbedded calcareous-siliceous zone, a phosphatic zone, a calcareous-siliceous zone, and an uppermost siliceous zone. To establish these zonations, 125 samples from five wells in a north-south transect across the western basin from East and West Beverly Hills, Inglewood, and Wilmington oil fields were analyzed for bulk chemical composition by XRF and quantitative mineralogy by XRD and FTIR. The mineralogic composition of the fine-grained detrital fraction makes use of geochemical equations for sedimentary components developed elsewhere unsuitable to the Los Angeles basin.</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>

<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>

Stratigraphy and source rock analyses of the Heath Formation in Fergus, Garfield, Golden Valley, Musselshell, Petroleum, and Rosebud counties, central Montana

<p> The Spraberry Formation is a Leonardian age submarine fan deposit restricted to the Midland Basin. The formation consists of very fine-grained sandstone, medium to coarse grain size siltstones, organic shales and carbonate mudstones. These rocks show variability in sedimentary structures and bedding types varied from thinly laminated to convolute laminations. Bioturbations were present in some samples and soft sediment deformation, such as water escape features, sediment loading and flame structures. </p><p> The Spraberry Formation is a naturally fractured reservoir with low porosity and low matrix permeability. Porosity measured varied from 2% in rocks with poor reservoir quality such as the argillaceous siltstone and mudstone while good reservoir rocks had an average porosity of 9%. Seven lithofacies were identified based on sedimentary structures, grain size and rock fabrics. Petrographic analysis showed four porosity types: (1) intragraular porosity; (2) dissolution porosity; (3) fracture porosity and (4) intergranular porosity. Fractured porosity was only observed in the argillaceous siltstone lithofacies. </p><p> The prominent diagenetic influences on the Spraberry Formation are: quartz cementation, quartz overgrowth, illtization of smectite, feldspar dissolution, clay precipitation, carbonate cementation, formation of framboidal pyrite and fracture formation. These diagenetic features were observed using scanning electron microscope (SEM) and in thin sections. Generally, petrophysical properties, such as porosity and permeability, vary gradually from reservoir rocks to non-reservoir rock. Observed trends where: 1) increasing organic and argillaceous content with decreasing porosity and 2) increasing carbonate sediments and calcite cements with decreasing porosity. Mineralogical analysis from FTIR showed an abundance of quartz and calcite, while illite is the prominent clay mineral observed in all samples.</p>