ABSTRACT An evaluation of an integrated data set collected over the past 12 years designed to identify the parameters controlling reservoir quality and production properties in organic, siliceous mudrocks reveals the key diagenetic processes affecting the development of brittleness in siliceous mudrocks. This work was motivated by the failure of early efforts to correlate brittleness to x-ray diffraction (XRD) mineralogy. The outcome of this analysis has been the recognition of two, often overlapping, pathways to brittleness that are determined at the time of deposition by the relative proportions of clay, detrital quartz, and biogenic silica present in the original sediment and are later affected by burial history. One pathway begins with a phyllosilicate–mud-dominated sediment, and the other begins with a sediment containing common or abundant biogenic silica (opal-A). Both pathways are characterized by compactional porosity loss and both eventually include the generation of authigenic quartz cement; however, the source of that authigenic quartz is different between the two pathways. The authigenic quartz that characterizes the first pathway is developed from the illitization of smectite and is precipitated as a cement within the argillaceous matrix. This authigenic quartz is detectable along with the detrital quartz by XRD analysis. All other factors being equal, the volume of brittle, authigenic quartz cement derived from the alteration of smectite is proportional to the volume of original clay. As a result, the effectiveness of this cement to increase the brittleness of the rock may be impacted by the presence of the ductile clays. In the alternate pathway, authigenic quartz is derived from the transformation of biogenic opal-A and is independent of the amount of clay. Much of the XRD quartz volume in rocks derived from biogenic–silica-rich sediment that contained little or no detrital quartz will comprise a brittle, authigenic cement.

ABSTRACT The Devonian Woodford Shale and Cretaceous Mowry Shale consist of relatively deep (below storm wave base) intracratonic basin deposits commonly referred to as “shales” because of their dark gray to nearly black color, very fine-grained nature, pelagic fossils such as radiolarians, and common amorphous marine kerogen. These shales typically contain less than 30% detrital clay by weight and more than 50% quartz (locally up to 80%). The quartz is a mix of biogenic grains, mainly radiolarians, and authigenic silica along with some detrital quartz silt of extrabasinal origin. The authigenic silica is dominantly microcrystalline (< 1 micron) and forms a major component of the matrix in these formations, but the rocks also contain authigenic pyrite, commonly as framboids, minor carbonates including magnesite, and quartz overgrowths, but together these authigenic minerals form less than 10% of the rock. Authigenic quartz in the Woodford and Mowry samples commonly takes the form of silica nanospheres, a type of microquartz less than a half micron in diameter. Textures of this microquartz are best observed directly with a high-resolution electron microscope. In many Woodford and Mowry samples, the silica nanospheres, which tend to be associated with organic matter, form more than 50% of the rock. The large volume of the authigenic quartz, together with “floating” detrital components and the close association with pyrite framboids, indicates that the silica nanospheres formed very early, perhaps in association with microbial activity on or in the seafloor sediments. These early silica nanospheres, which are only weakly luminescent, helped create a lithified sediment during or soon after deposition. Where the silicification process ceased prior to complete silica cementation, the early silica nanospheres are associated with up to 15% interparticle microporosity. This gives the Woodford and Mowry good potential reservoir quality, at least locally. The authigenic silica nanospheres also enhance the mechanical properties and brittleness of these siliceous mudrocks to a degree much greater than the presence of the detrital quartz particles alone.

ABSTRACT Scanning electron microscopy (SEM) has revolutionized our understanding of shale petroleum systems through microstructural characterization of dispersed organic matter (OM). However, as a result of the low atomic weight of carbon, all OM appears black in SEM (BSE [backscattered electron] image) regardless of differences in thermal maturity or OM type (kerogen types or solid bitumen). Traditional petrographic identification of OM uses optical microscopy, where reflectance (%R o ), form, relief, and fluorescence can be used to discern OM types and thermal maturation stage. Unfortunately, most SEM studies of shale OM do not employ correlative optical techniques, leading to misidentifications or to the conclusion that all OM (i.e., kerogen and solid bitumen) is the same. To improve the accuracy of SEM identifications of dispersed OM in shale, correlative light and electron microscopy (CLEM) was used during this study to create optical and SEM images of OM in the same fields of view (500× magnification) under white light, blue light, secondary electron (SE), and BSE conditions. Samples ( n = 8) of varying thermal maturities and typical of the North American shale petroleum systems were used, including the Green River Mahogany Zone, Bakken Formation, Ohio Shale, Eagle Ford Formation, Barnett Formation, Haynesville Formation, and Woodford Shale. The CLEM image sets demonstrate the importance of correlative microscopy by showing how easily OM can be misidentified when viewed by SEM alone. Without CLEM techniques, petrographic data from SEM such as observations of organic nanoporosity may be misinterpreted, resulting in false or ambiguous results and impairing an improved understanding of organic diagenesis and catagenesis.

ABSTRACT Exploration for hydrocarbons in Mississippian strata in Kansas and Oklahoma began in the 1900s. Early production came from open-hole completions in vertical wellbores at the apex of structural and stratigraphic traps. In the mid-20th century, cased-hole completions and hydraulic fracture stimulation allowed development of lower permeability zones. Recently operators began to explore and develop transition zones and low-permeability facies with horizontal drilling. The petroleum system that includes these accumulations consists of two hydrocarbon kitchens in the Arkoma and Anadarko basins, which have been generating oil and gas from the Woodford Shale since the beginning of the Pennsylvanian. Hydrocarbons charged out of the basins and along the fractured terrain of the Cherokee platform into reservoirs from Kinderhookian to Chesterian age across the carbonate facies belt. The distribution of these reservoirs, including limestones, dolomites, and cherts, along with structural configuration, governs the relative abundance and location of oil, gas, and water in each trap. The past decade saw over four thousand laterals targeting Mississippian reservoirs, including shales in unconventional traps, and the greatest rise in oil production in the region since the 1920s. High associated water volumes have created escalating operational costs and are correlative with earthquake activity.

ABSTRACT Mississippian carbonates of northern Oklahoma were deposited on the Anadarko shelf (ramp) as several shallowing-upward sequences. In Woods County, Oklahoma, the Mississippian ranges in thickness from 350 ft (105 m) to the south to as little as 100 ft (30 m) to the north due to uplift and erosion. Lithologies observed in core are chert conglomerate, tripolitic chert (tripolite), dense chert, chert-rich limestone, dense limestone, and shale-rich limestone. To evaluate the spatial distribution of Mississippian lithologies and petrophysical properties, and to explore the controls on production, this study integrates 3-D seismic with core and well-log data. As a constraint for 3-D lithology modeling, lithology logs were estimated using a neural-network approach with core and log data resulting in 65.1% accuracy. A P-impedance volume from seismic inversion was used to constrain the spatial distribution of tripolite in the model, the main reservoir lithology. Lithology-constrained 3-D porosity and water saturation models show that tripolite is the most porous and heterogeneous lithology. Comparing lithology, porosity, and water saturation models to production data illustrates that production from vertical wells is primarily controlled by porous tripolite distribution, whereas horizontal wells produce from both tripolite and chert-rich limestones and are most sensitive to water saturation variations.