Master of Science / Department of Geology / Matthew W. Totten / The Woodford Shale has received significant research interest as the number of productive wells has increased. The Woodford is productive over a wide range of thermal maturity (based upon vitrinite reflectance), yet most clay mineral studies report primarily illite (Caldwell, 2011 & Whittington, 2009). A previous report contrasts this behavior to other late Paleozoic shales in Oklahoma (Kowal, 2016). The major difference between these units is the amount of organic matter, which is much higher in most Woodford samples. In this study, Woodford shale samples were analyzed for several different characteristics, and combined with organic fraction data from previous work on the same samples (Lambert, 1993). Clay mineralogy was determined using an X-ray diffractometer (XRD) with the goal of finding the amount, and the degree of crystallinity of illite in a suite of samples. X-ray fluorescence (XRF) analysis was conducted to determine the variability of elemental concentrations within the samples. The bulk powder XRD data were combined with the major element concentrations to calculate mineral percentages. These data were compared to thermal maturity based upon vitrinite reflectance and Tmax values to determine the role of burial diagenesis on the clay mineralogy within Woodford Shale. The predominant clay mineral found within the samples was illite, with no recognizable mixed-layer smectite present, suggesting illitization is occurring early in the diagenetic process. A positive correlation between K/Rb ratios and TOC was found, supporting the control of organic matter on potassium in shales. No correlation between amount illite and thermal maturity was found, providing more evidence for the theory that high amounts of organics are driving illitization rather than thermal maturity.

Master of Science / Department of Geology / Sambhudas Chaudhuri / The exploration and development of unconventional shale plays provide an opportunity to study the hydrocarbon generation process. These unconventional plays allow one to investigate the interactions between the fluid, mineral, and organic material that occur in a hydrocarbon-generating source bed, before any changes in composition that may occur during secondary migration or post migration processes. Previous studies have determined the chemical constituents of formation waters collected from conventional reservoirs after secondary migration has occurred. This investigation targets formation waters collected from the Woodford shale that acts as both source and reservoir, therefore samples have yet to experience any changes in composition that occur during secondary migration. This investigation focuses on the major element and trace element chemistry of the formation water (Cl, Br, Na, K, Rb, Mg, Ca, Sr, and Rare Earth Elements), which has been compared to chemical constituents of the associated crude oil and kerogens. Analytical data for this investigation were determined by the following methods; Ion Chromatography, Inductively Coupled Plasma Mass Spectrometry (ICP-MS), and Inductively Coupled Plasma Atomic Emission Spectroscopy (ICP-AES). The information is used to assess the presence of different sources of water that constitute the formation water, and also to investigate interaction between different minerals and formation waters within the source beds. The formation water data also yields new insights into compartmentalization of oil-gas rich zones within the source beds.

Master of Science / Department of Geology / Matthew Totten / The REE distribution patterns and total concentrations of the organic matter of the Woodford shale reveal a potential avenue to investigate hydrocarbon maturation processes in a source rock. Ten samples of the organic matter fraction and 10 samples of the silicate-carbonate fraction of the Woodford shale from north central Oklahoma were analyzed by methods developed at KSU. Thirteen oil samples from Woodford Devonian oil and Mississippian oil samples were analyzed for REE also. REE concentration levels in an average shale range from 170 ppm to 185 ppm, and concentration levels in modern day plants occur in the ppb levels. The REE concentrations in the organic matter of the Woodford Shale samples analyzed ranged from 300 to 800 ppm. The high concentrations of the REEs in the Woodford Shale, as compared to the modern-day plants, are reflections of the transformations of buried Woodford Shale organic materials in post-depositional environmental conditions with potential contributions of exchanges of REE coming from associated sediments. The distribution patterns of REEs in the organic materials normalized to PAAS (post-Archean Australian Shale) had the following significant features: (1) all but two out of the ten samples had a La-Lu trend with HREE enrichment in general, (2) all but two samples showed Ho and Tm positive enrichments, (3) only one sample had positive Eu anomalies, (4) three samples had Ce negative anomalies, although one was with a positive Ce anomaly, (5) all but three out of ten had MREE enrichment by varied degrees. It is hypothesized that Ho and Tm positive anomalies in the organic materials of the Woodford Shale are reflections of enzymic influence related to the plant physiology. Similar arguments may be made for the Eu and the Ce anomalies in the Woodford Shale organic materials. The varied MREE enrichments are likely to have been related to some phosphate mineralization events, as the Woodford Shale is well known for having abundant presence of phosphate nodules. The trend of HREE enrichment in general for the Woodford Shale organic materials can be related to inheritance from sources with REE-complexes stabilized by interaction between the metals and carbonate ligands or carboxylate ligands or both. Therefore, a reasonable suggestion about the history of the REEs in the organic materials would be that both source and burial transformation effects of the deposited organic materials in association with the inorganic constituents had an influence on the general trend and the specific trends in the distribution patterns of the REEs. This study provides a valuable insight into the understandings of the REE landscapes in the organic fraction of the Woodford Shale in northern Oklahoma, linking these understandings to the REE analysis of an oil generated from the same source bed and comparing it to oil produced from younger Mississippian oil. The information gathered from this study may ultimately prove useful to trace the chemical history of oils generated from the Woodford Shale source beds.

Master of Science / Department of Geology / Matthew W. Totten / Shales are generally regarded as organic rich source and seal rocks that are unworthy of the amount of research that has been given to their coarser-grained counterparts, even though shales comprise nearly two-thirds of Earth’s sedimentary record (Potter et al., 1980). The Woodford Shale is acknowledged as a prolific source rock across much of Oklahoma and the midcontinent (Lambert, 1990). Up to 8% world's original hydrocarbon reserves are estimated to have been sourced by the Woodford and its equivalents (Fritz et al., 1991). Study of the heavy-mineral fraction in sedimentary rocks is important because it can indicate provenance and some of the diagenetic changes that occur in sedimentary rocks. This goal of this study is to describe the heavy-mineral fraction of eight Woodford Shale samples from the Greater Anadarko Basin of Oklahoma, and determine whether or not the constituents that make up the heavy-mineral fraction have any impact on the process of thermal maturity within source rocks. This study utilizes a method designed to efficiently separate the heavy-mineral fraction of shale samples. Scanning electron microscope (SEM) and Energy Dispersive X-ray Spectroscopy (EDS) are used in this study to identify mineralogy, grain size, composition and shape. Mineral distributions in the samples have been determined from point counting. The weight percent of the heavy mineral fraction was calculated for each of the samples. This was then compared to their location within the basin, depth, vitrinite reflectance and total organic carbon (TOC). We found that as the thermal maturity increase, the weight percent of heavy minerals also increases. Pyrite (FeS₂) was the most abundant heavy mineral found in the Woodford samples used in this study. From analyzing the different forms of pyrite, it was found that as thermal maturity increases, framboidal pyrite alters to euhedral pyrite.

methane and other higher order hydrocarbons, through C4, with interest in further developing reactions important to methane- and ethane-related chemistry. With the increased demand for energy and the declining conventional hydrocarbons worldwide, energy companies, both majors and independents, are turning to unconventional resources to produce the hydrocarbons required to meet market demand. From coalbed methane to low permeability (tight) gas reservoirs and gas shales, energy companies are making substantial progress in developing the technologies required to bring these unconventional reserves to the market. A common misconception is that there are not enough domestic oil and gas reserves to fuel our economy. The United States imports most of the oil used for transportation fuel and several TCF of natural gas annually. However, there is a very large resource of natural gas in unconventional reservoirs, with over 2,200 TCF of gas in place in just the gas shale formations that have been identified in the energy arena (Navigant Study 2008). There are still major gas shale plays and basins that have not been explored and are waiting to be evaluated and developed. The natural gas in shales and other unconventional reservoirs can be used to generate electricity, or it can be turned into liquids and used by the transportation industry. It is also misconstrued that gas shales are relatively new in our industry and something of the future. The first commercially viable gas shale well was drilled in the early 1920s in Pennsylvania, before the famous oil well drilled by Colonel Drake. The objectives of this study are to (1) complete literature review to establish which geologic parameters affect completion techniques in five emerging gas shales: the Antrium, the Barnett, the Haynesville, the Marcellus, and the Woodford; (2) identify the different completion methods; (3) create an economic model for the completion techniques discussed; (4) develop a sensitivity analysis on various economic parameters to determine optimal completion strategy; and (5) create completion flowcharts. Based on the literature review I have done for several gas shale basins, I have identified seven pertinent geologic parameters that influence completion practices. These are depositional environment, total organic content (TOC), average gas content, shale mineralogy, shale thickness, and reservoir pressure. Next, I identified different completion and simulation trends in the industry for the different shale plays. The results from this study show that although there are some stark differences between depths (i.e. the Antrim Shale and the Haynesville Shale), shale plays are very similar in all other geologic properties. Interestingly, even with a large range for the different geological parameters, the completion methods did not drastically differ indicating that even if the properties do not fall within the range presented in this paper does not automatically rule them out for further evaluation in other plays. In addition to the evaluation of geologic properties, this study looked at drilling cost and the production profile for each play. Due to the volatility of the energy industry, economic sensitivity was completed on the price, capital, and operating cost to see what affect it would have on the play. From the analysis done, it is concluded that horizontal drilling in almost any economic environment is economic except for one scenario for the Woodford Shale. Therefore, gas shales plays should still be invested in even in lower price environments and companies should try to take advantage of the lower cost environments that occur during these times. With continual development of new drilling and completion techniques, these plays will become more competitive and can light the path for exploration of new shale plays worldwide.

The Woodford Shale is an important unconventional oil and gas resource. It can act as a source rock, seal and reservoir, and may have significant elastic anisotropy, which would greatly affect seismic response. Understanding how anisotropy may affect the seismic response of the Woodford Shale is important in processing and interpreting surface reflection seismic data. The objective of this study is to identify the differences between isotropic and anisotropic seismic responses in the Woodford Shale, and to understand how these anisotropy parameters and physical properties influence the resultant synthetic seismograms. I divide the Woodford Shale into three different units based on the data from the Pioneer Reliance Triple Crown #1 (RTC #1) borehole, which includes density, gamma ray, resistivity, sonic, dipole sonic logs, part of imaging (FMI) logs, elemental capture spectroscopy (ECS) and X-ray diffraction (XRD) data from core samples. Different elastic parameters based on the well log data are used as input models to generate synthetic seismograms. I use a vertical impulsive source, which generates P-P, P-SV and SV-SV waves, and three component receivers for synthetic modeling. Sensitivity study is performed by assuming different anisotropic scenarios in the Woodford Shale, including vertical transverse isotropy (VTI), horizontal transverse isotropy (HTI) and orthorhombic anisotropy. Through the simulation, I demonstrate that there are notable differences in the seismic response between isotropic and anisotropic models. Three different types of elastic waves, i.e., P-P, P-SV and SV-SV waves respond differently to anisotropy parameter changes. Results suggest that multicomponent data might be useful in analyzing the anisotropy for the surface seismic data. Results also indicate the sensitivity offset range might be helpful in determining the location for prestack seismic amplitude analysis. All these findings demonstrate the potentially useful sensitivity parameters to the seismic data. The paucity of data resources limits the evaluation of the anisotropy in the Woodford. However, the seismic modeling with different type of anisotropy assumptions leads to understand what type of anisotropy and how this anisotropy affects the change of seismic data. / text

Master of Science / Department of Geology / Matthew W. Totten / The Woodford Shale (Oklahoma, U.S.A.) is a prolific unconventional hydrocarbon resource. The Woodford has been shown to be heterogeneous in many geochemical, mineralogical, and rock mechanic properties across the state of Oklahoma, which presents a challenge to successful exploitation of this resource (Caldwell, 2014; Turner et al., 2015; Wiley, 2015; Zhang et al., 2017). Most prior studies of the Woodford Shale report properties from a single sample collected from a vertical well, which reports these values as a single point source on a distribution map. Studies using outcrop localities report lateral variations in several rock properties of the Woodford, but are limited to the short distances an outcrop provides (Turner et al., 2015). The main focus of this research is to determine whether rock properties important to the productivity of the Woodford Shale vary across a lateral well bore within the Woodford shale. Measurements of chemical and mineralogical compositions were performed on rock cutting samples from a single horizontal well path of the Carleigh 6H-32 across approximately one mile. The mineral makeup was determined by use of X-ray diffraction (XRD) and elemental concentrations were determined by hand-held X-ray fluorescence (HHXRF). What was found is that the Upper and Middle Woodford Shale are relatively homogeneous laterally. The lack of variation means that it’s possible to determine from which subgroup samples may have been taken. The geochemical data were used to calculate a mineral-based brittleness index (Wang and Gale, 2009), which was compared to the measured frack gradient across perforations of the Carleigh 6H-32 well. In addition, the total organic matter content (TOC) was approximated in the same samples using loss on ignition (LOI) methods. The calculated mineralogy within samples assigned to the Middle Woodford show some variability throughout the horizontal well, which leads to an associated variation in mineral brittleness index when using the Wang and Gale (2009) formula. The mineral based brittleness index correlates with observed fracture gradient during well completion. This suggests that the tendency to fracture is also variable along the well path, which should be considered during design of the well completion.

Master of Science / Department of Geology / Matthew Totten / Oil production in Kansas has a long history with plays being found on all sides of the state. The source of Kansas’s hydrocarbons has been traditionally thought to be outside the state due to low thermal maturity and the shallow burial of potential source rocks within Kansas. This research addresses the question regarding the source of the oil in Kansas, at least within a small geographic area of roughly 146mi[superscript]2. The Spivey-Grabs-Basil Field has been one of the more successful fields within the state of Kansas since the 1960’s. This field is compartmentalized and offers a natural laboratory in which to conduct the field’s first formal oil-source rock correlation since oils are locked into place. While the main focus of this research relies heavily on pyrolysis and GCMS for biomarker analysis, it also investigates the possibility of using rare earth element (REE) concentrations as a possible fingerprint of organic matter within a source bed. TOC values of the Chattanooga shale samples from the Spivey-Grabs-Basil filed range from 0.75 and 3.95 wt. %, well within productive capacity. Pyrograms show both the potential for additional production, and the likely previous expulsion of hydrocarbons. Biomarker concentration percentages between C[subscript]27, C[subscript]28, and C[subscript]29 steranes, as well as pentacyclic terpane ratios compared between crude oil from the Spivey-Grabs-Basil and the Chattanooga shale show a definite genetic relationship. REE values of the organic fraction of the Chattanooga inversely correlate with those of the crude oils, suggesting fractionation during oil generation. After comparison of results with the Woodford shale in Oklahoma, the conclusion of this study is that the Chattanooga shale which underlies the Spivey-Grabs-Basil oil field of southern Kansas is the probable source rock which generated the oil now being produced.

Master of Science / Department of Geology / Matthew Totten / The Woodford shale is recognized as an abundant source rock across Oklahoma and much of the midcontinent (Lambert, 1990), and up to 8% of the world’s hydrocarbon reserves are estimated to have been sourced by the Woodford and its equivalents (Fritz et al, 1991). The Woodford shale is far more complex than other Devonian black shales found in North America due to the presence of alternating bands of chert-like amorphous silica and silica-rich shale. Analysis of chert and its possible role in gas generation and storage in shales has been largely overlooked. The goal of this study is to determine if chert size, amounts, or polycrystallinity can be indicators of thermal maturity within the Woodford shale. Handheld XRF analysis was conducted on the whole rock samples, and a mudrock specific sodium bisulfate fusion was used to separate the non-clay fraction. SEM was performed on the resulting separates to study and observe changes in chert fabric, grain-size, and amount. No correlations were observed to indicate that chert is an indicator of thermal maturity within the Woodford shale. Increase in chert growth and amount was also not detected within the size fractions as thermal maturity increases. Handheld XRF proved to be a good proxy for quick, onsite analysis of silica concentrations, as well as the amount of organic matter within drill core. This could be beneficial as hydraulic fracking produces best results in areas of higher silica content, and the wells with the highest organic matter have the highest potential for petroleum accumulations.

Newly available industry well data and seismic attribute analysis reveal that late Ordovician-early Devonian Hunton Group strata are more widespread (i.e., not removed by mid-Devonian erosion) in the central and southern portions of the Arkoma Basin in eastern Oklahoma than previously thought. This study demonstrates the value of applying seismic attribute analysis to problems of quantifying and mapping stratigraphic features caused by erosions and/or karstification. Well and seismic isochron data in the Red Oak petroleum field for the Viola-Woodford interval (the units that lie stratigraphically beneath and above, respectively, the Huton Group) show isolated ~40-m thick lenses of Hunton rocks, on average measuring 3 km in diameter, with a surrounding halo of karsted rock. This distribution can be explained in two different ways: 1) Hunton occurrences could represent isolated erosional remnants reflecting incomplete removal of the Hunton Group during Middle Devonian time (pre-Woodford unconformity) or 2) due to karsting and collapse of stratigraphically lower units (Viola or Bromide carbonates), lenses of Hunton rocks would have sagged into sinkholes where they were preserved beneath regional base level. Using formation tops from a well data set correlated with attribute and structure maps from a proprietary 3-D seismic data set, we identify three seismic characteristics in the middle Paleozoic interval that correlate well with: 1) absent Hunton seismic markers, indicating that Hunton rocks were completely removed, 2) the Hunton contacts, indicating where a seismically visible section of Hunton rocks remains, 3) absent Hunton but with a thin horizon included within lower carbonate strata that is interpreted to be an incipient karst zone, which is consistently adjacent to areas containing Hunton rocks. The base of the Sylvan Shale and the top of the Woodford Shale, the respective lower and upper adjoining units, form significant chronostratigraphic surfaces. As such, anomalous thicknesses of these units are depositionally related; thick Woodford sections often correlate to thin or absent Hunton rocks, possibly indicating back-filled pre-Woodford channels eroded into or through the Hunton Group. Conversely, when there is little or no Woodford thickening over Hunton lenses and when adjacent areas show thinning and partially karsted Viola rocks, we propose that karstic collapse of Viola strata was responsible for the Hunton rocks preservation. A combination of these models may be necessary to account for areas where we see thinning both in the Woodford and Viola, suggesting that a Hunton lens is structurally lowered due to karsting, but due to its erosionally resistive nature, the lens forms a depositional high, causing the Woodford to thin over it. The 3-D approach is absolutely necessary to reveal the subtle waveform details that illustrate the karstic and erosional processes involved in the preservation of the Hunton wedges. These findings were interpolated, constrained by well data, over the entire Oklahoma portion of the Arkoma basin in order to produce a new Hunton isopach map and 20 separate cross-sections (two shown herein). These show a broad linear region of absent Hunton. Eustatic sea levels rose throughout the middle and late Devonian, so this large area of eroded Hunton is interpreted as a post-Hunton, pre-Woodford structural uplift. Other Hunton wedges, similar in size and extant to that seismically imaged in this study, were also found in the well data. The karstic collapse of the Viola and subsequent preservation of Hunton rocks occurred on both limbs of the arch.