Browsing by Subject "Eagle Ford"
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Item Applying Decline Curve Analysis in the Liquid-rich Shales: Eagle Ford Shale Study(2014-01-09) Indras, PurviWith the emergence of liquid rich shale (LRS) plays like Eagle Ford and Northern Barnett, the petroleum industry needs a simple, easily applied technique that provides reliable estimates of future production rates in this kind of reservoir. There is no guarantee that methodology that has proved to work in gas reservoirs will necessarily be appropriate in LRS reservoirs. In this work, we found that without corrections of early data, the Stretched Exponential Production Decline (SEPD) model, designed for transient flow, usually produces pessimistic forecasts of future production. The Duong method, another transient model, may be reasonable during long term transient linear flow, but notably optimistic after boundary-dominated flow (BDF) appears. For wells in BDF, the Arps model provides reasonable forecasts, but the Arps model may not be accurate when applied to transient data. A hybrid of early transient and later BDF models proves to be a reasonable solution to the forecasting problem in LRS. In addition, use of diagnostic plots (like log-log rate-time and log-log rate-material balance time plots) improves confidence in flow regime identification and production forecasting. In some LRS?s, BDF is observed within 12 months. In any case, it is essential to identify or to estimate the time to reach BDF and to discontinue use of transient flow models after BDF appears or is expected. We validated our methodology using ?hindcast analysis?; that is, matching the first half of production history to determine model parameters, then forecasting the second half of history and comparing to observed production data. We also found that application of pressure-corrected rates in decline curve analysis (DCA) may substantially improve the interpretation of data from unconventional oil wells flowing under unstable operating conditions. Fetkovich (hydraulically fractured well) type curve analysis can be added to improve confidence in flow regime identification from diagnostic plots and to estimate the Arps hyperbolic exponent b from the matching b stem on the type curve, which can then be extrapolated to determine estimated ultimate recovery.Item Assessment of Eagle Ford Shale Oil and Gas Resources(2013-07-30) Gong, XinglaiThe Eagle Ford play in south Texas is currently one of the hottest plays in the United States. In 2012, the average Eagle Ford rig count (269 rigs) was 15% of the total US rig count. Assessment of the oil and gas resources and their associated uncertainties in the early stages is critical for optimal development. The objectives of my research were to develop a probabilistic methodology that can reliably quantify the reserves and resources uncertainties in unconventional oil and gas plays, and to assess Eagle Ford shale oil and gas reserves, contingent resources, and prospective resources. I first developed a Bayesian methodology to generate probabilistic decline curves using Markov Chain Monte Carlo (MCMC) that can quantify the reserves and resources uncertainties in unconventional oil and gas plays. I then divided the Eagle Ford play from the Sligo Shelf Margin to the San Macros Arch into 8 different production regions based on fluid type, performance and geology. I used a combination of the Duong model switching to the Arps model with b = 0.3 at the minimum decline rate to model the linear flow to boundary-dominated flow behavior often observed in shale plays. Cumulative production after 20 years predicted from Monte Carlo simulation combined with reservoir simulation was used as prior information in the Bayesian decline-curve methodology. Probabilistic type decline curves for oil and gas were then generated for all production regions. The wells were aggregated probabilistically within each production region and arithmetically between production regions. The total oil reserves and resources range from a P_(90) of 5.3 to P_(10) of 28.7 billion barrels of oil (BBO), with a P_(50) of 11.7 BBO; the total gas reserves and resources range from a P_(90) of 53.4 to P_(10) of 313.5 trillion cubic feet (TCF), with a P_(50) of 121.7 TCF. These reserves and resources estimates are much higher than the U.S. Energy Information Administration?s 2011 recoverable resource estimates of 3.35 BBO and 21 TCF. The results of this study provide a critical update on the reserves and resources estimates and their associated uncertainties for the Eagle Ford shale formation of South Texas.Item Centrifuge testing of an expansive clay(2009-08) Plaisted, Michael D.; Zornberg, Jorge G.; Gilbert, Robert B.Expansive clays are located world wide and cause billions of dollars in damage each year. Currently, the expansion is usually estimated using correlations instead of direct testing as direct testing is expensive and often takes over a month to complete. The purpose of this study was to determine if centrifuge technology could be used to characterize expansive clays through direct testing. Testing was performed in an centrifuge permeameter on compacted specimens of Eagle Ford clay. A framework was developed to analyze effective stresses in centrifuge samples and methods were proposed to determine the swell-stress curve of a soil from centrifuge tests. Standard free swell test were also performed for comparison. The swell-stress curve determined by centrifuge testing was found to match with the curve found from free swell tests after correcting for differences in testing procedures. The centrifuge tests were found to be repeatable and required several days for testing rather than weeks.Item Eagle Ford shale : evaluation of companies and well productivity(2016-08) Chavez Urbina, Grecia Alexandra; King, Carey Wayne, 1974-; Lake, Larry W.Unconventional resources, particularly shale reservoirs, are a significant component in oil and gas production in the United States as they represent (as of May 2015) 48 and 58 percent, respectively, of the total oil and gas produced. However, there has been a deceleration on oil and gas production in general because of low market prices. The drastic decline in oil and gas prices that started in 2014 has companies struggling to continue their operations, resulting in negative financial outcomes for 2015 for most companies. The present work examines the financial results of three companies, EOG Resources, Pioneer Natural Resources, and Chesapeake Energy, along with their particular well productivity using the Logistic Growth model to forecast production in one of the most prolific shale plays in the United States, the Eagle Ford. This work also examines the economic feasibility of drilling new wells when oil prices are low using a discounted cash flow model for each company. The financial analysis shows that from the three companies, Pioneer Natural Resources has the best financial results; its high cash-flow-to-debt ratio, and low debt and debt-to-equity ratios make it an attractive company to invest in. In contrast, Chesapeake has the worst results which represents high risk for investors, and EOG has moderate results that still make it a good company to invest in. The discounted cash flow model demonstrate that under the cost assumptions and estimated production used in this work, EOG gets the best results from their wells located in the Eagle Ford with break-even prices bordering the 40 $/bbl compared to the other companies with break-even prices above 87 $/bbl for Pioneer and 89 $/bbl for Chesapeake. From the discounted cash flow model, it can also be concluded that none of the companies in the analysis is expected to gain revenue from drilling new wells if oil prices are under 40 $/bbl, and that companies that are quick to respond to the low prices by reducing their drilling and completion costs can significantly improve their well economics.Item Facies characterization and stratigraphic architecture of organic-rich mudrocks, Upper Cretaceous Eagle Ford Formation, South Texas(2011-08) Harbor, Ryan Lee; Ruppel, Stephen C.; Fisher, W. L. (William Lawrence), 1932-; Steel, Ronald J.The Eagle Ford is a well-known source rock for both sandstone (Woodbine) and carbonate (Austin and Buda) hydrocarbon reservoirs in East and South Texas. Recent discoveries have demonstrated that source rocks, such as the Eagle Ford, are capable of producing significant volumes of gas and oil. At the same time, variations in well producibility indicate that these rocks, like conventional reservoirs, display considerable geological heterogeneity. Yet, only limited research has been published on the subsurface stratigraphy and character of Eagle Ford facies. Understanding the types, controls, and distribution of these heterogeneities requires in-depth rock-based studies. In order to characterize Eagle Ford facies, 27 cores from 13 counties were investigated for rock textures, fabrics, sedimentary structures, and fossil assemblages. These studies were supported by light and electron microscopy as well as analysis of elemental chemistry and mineralogy. Regional subsurface stratigraphic correlations and facies distributions were defined using wireline logs calibrated from core studies. In South Texas, the Eagle Ford Formation was deposited during a second-order transgressive/regressive cycle on the flooded, oxygen-restricted Comanche Shelf. Nine depositional facies consisting predominately of organic-rich, fine-grained (5.0 % TOC) to coarser-grained (3.05 % TOC) fabrics were identified. Facies developed in low-energy environments episodically interrupted by higher-energy, event sedimentation (current winnowing, cohesive and non-cohesive density flows, and turbidity flows). Locally, these rocks show evidence of early diagenetic recrystallization of calcite. Concurrent water anoxia and organic matter preservation persisted locally into later Austin deposition, resulting in formation of a three-fold division of the Cenomanian-Coniacian Eagle Ford Formation. Common facies of lower and upper Eagle Ford members include (1) unlaminated, fissile, clay- and silica-rich, organic-rich mudrocks, (2) laminated, calcareous, organic-rich mudrocks, and (3) laminated, foraminifera- and peloid-rich, organic-rich packstones. The transitional Eagle Ford member consists of highly-cyclic (1) ripple-laminated, organic-rich wackestone (cycle base) and (2) burrowed, organic-lean lime wackestones (cycle top). Transitional Eagle Ford facies developed in oxygen-restricted, basinal depositional environments as distal equivalents to burrowed, foraminiferal lime wackestones of the Austin Formation. Facies complexities in the Eagle Ford stem from complicated and interrelated processes of sediment production and distribution, diagenesis, and water column chemistry. Integrated core studies shed light on both controls of facies formation and their spatial distribution. These findings provide a framework for upscaling the fine-scale, heterogeneous character of shelfal Eagle Ford mudrocks; thus allowing development of predictive models into the distribution of key reservoir properties in the subsurface.Item Feasibility of isotropic inversion in orthorhombic media : the Barrett unconventional model(2016-05) Yanke, Andrew James; Spikes, Kyle; Sen, Mrinal K; Fomel, Sergey BGeophysicists often relegate shale reservoirs as having higher symmetries (e.g., transversely isotropic (TI) or isotropic) than what reality demonstrates. Routine application of TI (or even isotropic) algorithms to orthorhombic media neglects the associated errors because we never know the true model in practice. This thesis evaluates the viability of isotropic post-stack and pre-stack seismic inversion to orthorhombic media using the SEAM Barrett Unconventional Model, the most realistic depositional model to date. The Barrett Model contains buried topography, simulated stratigraphy, and designated reservoir zones with orthorhombic anisotropy. I inverted the Barrett data volume for isotropic elastic property cubes, which I compared to the model volume in each symmetry-plane of an orthorhombic medium. If the stacked seismic data contained only the near offsets, post-stack inversion resolved acoustic impedances that closely matched the true model both within and outside of the reservoir zones at all well locations. Anisotropy most affected the far offsets, so muting them predictably enhanced the post-stack inversion. I maintained all offsets for pre-stack inversion, but a parabolic radon filter eliminated nonhyperbolic behavior (rather than nonhyperbolic moveout analysis) at far offsets. The pre-stack impedance attributes adequately described the vertical heterogeneity of the true model at a cross-validation well, but the inverted values increasingly relied on the initial model with depth. The inverted density estimates experienced notable oscillations relative to the initial model, particularly where steep contrasts in elastic properties occurred. Mismatch of the inverted elastic properties at the well locations can be attributed to noise, thin layering effects, band limitation, steep contrasts in elastic properties, AVO behavior stacked into the data, an inaccurate starting model, and the effects of anisotropy. The most significant sources of error include small-scale reflectivity and comprehensive filtering of nonhyperbolic phenomena. Away from the well locations, the isotropic inversion gave no visual indication of reservoir geobodies, but it sufficiently described the elastic property variations near reservoir mid-sections. Moreover, I showed that the inverted elastic properties differ from their orthorhombic models by no more than 35%. The greatest misfits occurred near reservoir contacts and geobody locations. The computed impedance models in each symmetry-plane have distinctive differences, but isotropic inversion dismisses these variations entirely. I conclude that isotropic inversion should not be a surrogate for orthorhombic methods in data preconditioning and quantitative reservoir characterization.Item Fresh water reduction technologies and strategies for hydraulic fracturing : case study of the Eagle Ford shale play, Texas(2013-12) Leseberg, Megan Patrice; Fisher, W. L. (William Lawrence), 1932-; Nicot, Jean-Philippe, 1958-Hydraulic fracturing has unlocked a tremendous resource across the United States and around the world—shale. However, these processes have also come with a myriad of potential environmental effects, including a substantial demand for water. Hydraulic fracturing can require anywhere between two and four million gallons per well. The need for such large quantities of water can produce severe stresses on local water resources. In response to this issue, operators have developed several ways to alleviate some of the stresses brought on by the extensive water use such as alternative sourcing and reuse technologies. Companies are driven to exercise these options and decrease their fresh water usage for hydraulic fracturing processes for multiple reasons, including changes in regulation, to gain support of local communities, and to increase efficiencies of operations. Whatever the motivation may be, there are a variety of options companies have at their disposal to reduce fresh water demands—dependent on specific formation characteristics, the qualities and quantities of available water, among others. The Eagle Ford shale is one of the most rapidly growing shale plays in the country. However, this formation is located in a fairly arid part of the country. Because of meager average rainfall totals, water availability to meet demand is an issue of great concern. Due to nearly exponential increases in shale production, stresses on local water supplies have dramatically increased as well. The objectives of this thesis are as follows: 1) to establish the enormous resource that has become available; while still recognizing the environmental impacts associated with development processes, focusing primarily on water requirements and associated wastewater production; 2) to break down current water demand for shale development, as well as wastewater management practices in the Eagle Ford, with a brief comparison to other shale plays across the country; 3) to obtain an understanding of operator motivation—what factors affect wastewater management strategies; and 4) to analyze techniques operators presently have at their disposal to reduce fresh water demands, specifically through the use of brackish waters and recycling/reuse efforts, and finally to quantify these efforts to evaluate potential fresh water savings.Item High resolution stratigraphy and facies architecture of the Upper Cretaceous (Cenomanian-Turonian) Eagle Ford group, Central Texas(2012-08) Fairbanks, Michael Douglas; Fisher, W. L. (William Lawrence), 1932-; Ruppel, Stephen C.Heightened industry focus on the Upper Cretaceous (Cenomanian-Turonian) Eagle Ford has resulted from recent discoveries of producible unconventional petroleum resource in this emerging play. However, little has been published on the facies and facies variabilities within this mixed carbonate-clastic mudrock system. This rock-based study is fundamental to understanding the controls, types, and scales of inherent facies variabilities, which have implications for enhanced comprehension of the Eagle Ford and other mixed carbonate-clastic mudrock systems worldwide. This study utilizes 8 cores and 2 outcrops with a total interval equaling 480 feet and is enhanced by synthesis of thin section, XRD, XRF, isotope, rock eval/TOC, and wireline log data. Central Texas Eagle Ford facies include 1) massive argillaceous mudrock, 2) massive argillaceous foraminiferal mudrock, 3) laminated argillaceous foraminiferal mudrock, 4) laminated foraminiferal wackestone, 5) cross-laminated foraminiferal packstone/grainstone, 6) massive bentonitic claystone, and 7) nodular foraminiferal packstone/grainstone. High degrees of facies variability are observed even at small scales (50 ft) within the Eagle Ford system and are characterized by pinching and swelling of units, lateral facies changes, truncations, and locally restricted units. Facies variability is attributed to erosional scouring, productivity blooms, bottom current reworking, and bioturbation. At the 10-mile well spacing scale and greater, the data significantly overestimates intra-formational facies continuity but is successful in defining the following four-fold stratigraphy: The basal Pepper Shale is an argillaceous, moderate TOC, high CGR and GR mudrock. The Waller Member is a newly designated name used in this study for an argillaceous and foraminiferal, high TOC, massive mudrock with a generally moderate CGR and GR profile. The Bouldin Member is a high energy, carbonate-rich (foraminiferal), low TOC, low and variable CGR but high GR zone. Finally, the South Bosque Formation is an argillaceous and foraminiferal, moderate TOC, massive and laminated mudrock with a moderate CGR and GR signature. GR logs alone are inadequate for determination of facies, TOC content, depositional environment, and sequence stratigraphic implications. Using integrated lithologic, isotopic, and wireline log data, cored wells in the study area are correlated across the San Marcos Arch. Geochemical proxies (enrichment in Mo, Mn, U, and V/Cr) indicate that maximum basin restriction occurred during deposition of the Bouldin Member. Bottom current activity influenced depositional processes and carbonate sediment input was driven by water column productivity. These primary controls on Eagle Ford stratigraphy and character are independent from eustatic fluctuation, rendering classical sequence stratigraphy unreliable.Item Hydraulic fracturing sand resource development in the Llano uplift region, central Texas : resource calculation, favorability analysis, and transportation economics(2016-05) Verma, Rahul; Elliott, Brent Alan; Kyle, James Richard; Gutierrez, GenaroUse of naturally occurring sand, one of the most commonly used proppants for hydraulic fracturing, has grown tremendously as a commodity in the past decade as hydraulically wells for petroleum production from unconventional reservoirs increased significantly. USGS estimates that the United States produced more than 94 million metric tons of industrial sand in 2015, almost 52 percent of the global production. About 71 percent the total industrial sand was used for hydraulic fracturing and well packing in 2015. With the recent decline in oil and gas price and exploration drilling, it becomes all the more relevant to develop low cost, locally extracted sand for hydraulic fracturing. The Hickory sandstone unit of the Riley formation in central Texas is one such resource. The region is already one of the largest sand producers in the US and is conveniently located within 200–300 miles of major shale basins in Texas. Barnes and Schofield (1964), and Kyle and McBride (2014) present geological studies of the region and its potential for hydraulic fracturing sand. This study builds on this experience, to calculate for the first time, the total resource volume in the region. Benson et al. (2015) considers high friability, near surface access and proximity to transportation facilities as the three most important qualities of sand resource. As the sand in the Llano uplift region was never buried more than 1,500 feet, it remains friable (Kyle and McBride, 2014). This study estimates the sand resource in the Llano Uplift region to be more than 24 billion metric tons, of which, 20 billion metric tons is characterized by near surface access and proximity to transportation facilities. Several favorable sites for extraction are identified in Mason County, McCulloch County, San Saba County, Barnet County, and Llano County. Several hydraulic fracturing sites in the Barnett, Eagle Ford, and Permian basin, with fracture closure stress less than 6,000 psi, are identified as potential markets for the sand extracted in the Llano Uplift. A transportation cost optimization between using railways and highways, to transport sand from favorable extraction sites to hydraulic fracturing sites, finds that using highways is most cost effective means for transporting to all the sites in the Permian basin, most sites in the Barnett basin, and a few in the Eagle Ford basin. A combination of railways and highways is found to be more cost effective on a few routes to the Barnett and Eagle Ford basin.Item Impacts from above-ground activities in the Eagle Ford Shale play on landscapes and hydrologic flows, La Salle County, Texas(2014-08) Pierre, Jon Paul; Young, Michael H.; Kyle, J. RichardExpanded production of hydrocarbons by means of horizontal drilling and hydraulic fracturing of shale formations has become one of the most important changes in the North American petroleum industry in decades, and the Eagle Ford (EF) Shale play in South Texas is currently one of the largest producers of oil and gas in the United States. Since 2008, more than 5000 wells have been drilled in the EF. To date, little research has focused on landscape impacts (e.g., fragmentation and soil erosion) from the construction of drilling pads, roads, pipelines, and other infrastructure. The goal of this study was to assess the spatial fragmentation from the recent EF shale boom, focusing on La Salle County, Texas. To achieve this goal, a database of wells and pipelines was overlain onto base maps of land cover, soil type, vegetation assemblages, and hydrologic units. Changes to the continuity of different ecoregions and supporting landscapes were then assessed using the Landscape Fragmentation Tool as quantified by land area and continuity of core landscape areas (those degraded by “edge effects”). Results show an increase in ecosystem fragmentation with a reduction in core areas of 8.7% (~333 km²) and an increase in landscape patches (0.2%; 6.4 km²), edges (1.8%; ~69 km²), and perforated areas (4.2%; ~162 km²) within the county. Pipeline construction dominates sources of landscape disturbance, followed by drilling and injection pads (85%, 15%, and 0.03% of disturbed area, respectively). This analysis indicates an increase in the potential for soil loss, with 51% (~58 km²) of all disturbance regimes occurring on soils with low water-transmission rates and a high runoff potential (hydrologic soil group D). Additionally, 88% (~100 km²) of all disturbances occurred on soils with a wind erodibility index of approximately 19 kt/km²/yr or higher, resulting in an estimated potential of 2 million tonnes of soil loss per year. Depending on the placement of infrastructure relative to surface drainage patterns and erodible soil, these results show that small changes in placement may significantly reduce ecological and hydrological impacts as they relate to surface runoff. Furthermore, rapid site reclamation of drilling pads and pipeline right-of-ways could substantially mitigate potential impacts.Item Lessons learned in the Eagle Ford play and applicability to Mexico(2015-12) Meneses-Scherrer, Eduardo Javier; Tinker, Scott W. (Scott Wheeler); Gülen, Gürcan; Hammes, UrsulaMexico’s oil and gas production decline from conventional reservoirs calls for the assessment of their Late Cenomanian-Turonian shale resources. However, a geological screening of the Texas Gulf coast and east and northeast Mexico indicates that their distinct paleogeographic and tectonic development preclude a straightforward correlation between the Upper Cretaceous Eagle Ford Group of Texas and equivalent formations in Mexico. In Texas, east of the Frio River Line, extensional tectonics prevailed during the Mesozoic-Cenozoic; while in Mexico compressional tectonics influenced sedimentation from the late Cenomanian through the Eocene. Late Cenomanian compression led to paleobathymetry variations that may have influenced the lithology, distribution, and thickness of the lower organic-rich interval of the Eagle Ford Group, as well as the uplift of a western landmass that was a source of detrital argillaceous sediments. Laramide orogeny produced the exhumation of the late Cenomanian-Turonian section in most of the eastern part of Mexico, and its burial in foreland basins below Cenozoic sediments with contrasting thickness. Therefore, uplift and loading burial impacted critical depth-dependent factors such as thermal maturation, pore pressure, and viscosity. Hence, in east and northeast Mexico four areas have geological and geotechnical characteristics to be potential sweet spots in the Eagle Ford trend. The areas are the Sabinas Coal Basin, the western part of the Burgos Basin, the southwestern part of the Maverick Basin, and the southwestern part of the Tampico-Misantla Basin. Each area may be an opportunity to ensure Mexico´s energy mix and offset the declining production; nevertheless, these areas present significant technical, operational, and public challenges such as water shortage or mismanagement, insufficient road and pipeline infrastructure, and the ability to deal with people with strong cultures and social roots. Once the geologic and engineering data extracted from the appraisal wells permit the understanding of the economic potential of the sweet spots, supply chains may develop around a Northeastern Hub embracing the Burgos, Maverick, and Sabinas Coal Basins, and an Eastern Hub, including the Tampico-Misantla Basin. High-quality project management and decision-making process based on economic and scientific facts may permit a fruitful learning curve.Item Multi-frac treatments in tight oil and shale gas reservoirs : effect of hydraulic fracture geometry on production and rate transient(2013-05) Khan, Abdul Muqtadir; Olson, Jon E.The vast shale gas and tight oil reservoirs in North America cannot be economically developed without multi-stage hydraulic fracture treatments. Owing to the disparity in the density of natural fractures in addition to the disparate in-situ stress conditions in these kinds of formations, microseismic fracture mapping has shown that hydraulic fracture treatments develop a range of large-scale fracture networks in the shale plays. In this thesis, an approach is presented, where the fracture networks approximated with microseismic mapping are integrated with a commercial numerical production simulator that discretely models the network structure in both vertical and horizontal wells. A novel approach for reservoir simulation is used, where porosity (instead of permeability) is used as a scaling parameter for the fracture width. Two different fracture geometries have been broadly proposed for a multi stage horizontal well, orthogonal and transverse. The orthogonal pattern represents a complex network with cross cutting fractures orthogonal to each other; whereas transverse pattern maps uninterrupted fractures achieving maximum depth of penetration into the reservoir. The response for a vii single-stage fracture is further investigated by comparing the propagation of the stage to be dendritic versus planar. A dendritic propagation is bifurcation of the hydraulic fracture due to intersection with the natural fracture (failure along the plane of weakness). The impact of fracture spacing to optimize these fracture geometries is studied. A systematic optimization for designing the fracture length and width is also presented. The simulation is motivated by the oil window of Eagle Ford shale formation and the results of this work illustrate how different fracture network geometries impact well performance, which is critical for improving future horizontal well completions and fracturing strategies in low permeability shale and tight oil reservoirs. A rate transient analysis (RTA) technique employing a rate normalized pressure (RNP) vs. superposition time function (STF) plot is used for the linear flow analysis. The parameters that influence linear flow are analytically derived. It is found that picking a straight line on this curve can lead to erroneous results because multiple solutions exist. A new technique for linear flow analysis is used. The ratio of derivative of inverse production and derivative of square root time is plotted against square root time and the constant derivative region is seen to be indicative of linear flow. The analysis is found to be robust because different simulation cases are modeled and permeability and fracture half-length are estimated.Item Paleoenvrironmental Controls on Diagenesis of Organich-Rich Shales in the Eagle Ford Group(2014-08-27) Kruse, KendraCarbonate precipitation can be either promoted or inhibited by microbial processes in different redox zones. It is therefore possible for basin redox evolution to indirectly control early carbonate diagenesis and modify reservoir properties of corresponding shale units. The goals of this study were to analyze geochemical characteristics of the Late Cretaceous Eagle Ford Group in McMullen County, Texas to test the hypotheses that (1) the redox state of the water column controlled carbonate cement abundance and (2) carbonate cement lowered organic matter content by volumetric dilution. An x-ray analytical microscope was used to map elemental compositions of fresh core samples within the Eagle Ford Group. Resultant maps were used to characterize carbonate cements and to estimate the redox state of the overlying water column during deposition, as indicated by the relative abundances of the trace metals Mo, V, and Cr. Results indicate that cementation occurred early relative to compaction. Ti Kal normalized Mo Kal and CaKal fluorescence intensities are positively correlated throughout the unit, suggesting that carbonate cementation was related to the redox state. Total organic carbon is negatively correlated in the upper Lower Eagle Ford with (Ca Kal)/(Ti Kal) fluorescence ratio, consistent with volumetric dilution of organic matter by diagenetic cementation prior to compaction. In contrast, there is no significant correlation between total organic carbon and carbonate content in the more organic-rich Lower Eagle Ford.Item Shale Oil Production Performance from a Stimulated Reservoir Volume(2011-10-21) Chaudhary, Anish SinghThe horizontal well with multiple transverse fractures has proven to be an effective strategy for shale gas reservoir exploitation. Some operators are successfully producing shale oil using the same strategy. Due to its higher viscosity and eventual 2-phase flow conditions when the formation pressure drops below the oil bubble point pressure, shale oil is likely to be limited to lower recovery efficiency than shale gas. However, the recently discovered Eagle Ford shale formations is significantly over pressured, and initial formation pressure is well above the bubble point pressure in the oil window. This, coupled with successful hydraulic fracturing methodologies, is leading to commercial wells. This study evaluates the recovery potential for oil produced both above and below the bubble point pressure from very low permeability unconventional shale oil formations. We explain how the Eagle Ford shale is different from other shales such as the Barnett and others. Although, Eagle Ford shale produces oil, condensate and dry gas in different areas, our study focuses in the oil window of the Eagle Ford shale. We used the logarithmically gridded locally refined gridding scheme to properly model the flow in the hydraulic fracture, the flow from the fracture to the matrix and the flow in the matrix. The steep pressure and saturation changes near the hydraulic fractures are captured using this gridding scheme. We compare the modeled production of shale oil from the very low permeability reservoir to conventional reservoir flow behavior. We show how production behavior and recovery of oil from the low permeability shale formation is a function of the rock properties, formation fluid properties and the fracturing operations. The sensitivity studies illustrate the important parameters affecting shale oil production performance from the stimulated reservoir volume. The parameters studied in our work includes fracture spacing, fracture half-length, rock compressibility, critical gas saturation (for 2 phase flow below the bubble point of oil), flowing bottom-hole pressure, hydraulic fracture conductivity, and matrix permeability. The sensitivity studies show that placing fractures closely, increasing the fracture half-length, making higher conductive fractures leads to higher recovery of oil. Also, the thesis stresses the need to carry out the core analysis and other reservoir studies to capture the important rock and fluid parameters like the rock permeability and the critical gas saturation.Item Stratigraphy and Depositional Controls on Source Rock Formation within the Upper Cretaceous (Lower Cemomanian) Maness Shale, Central Texas(2014-11-26) Hudson, AnnWith the success of the prolific Eagle Ford Shale play in South Texas, there is increasing interest in the resource potential of its equivalent source rock on the northeast side of the San Marcos Arch. The ?Eagle Ford Shale? northeast of the San Marcos arch is composed of the transgressive lower Cenomanian Maness Shale, which unconformably overlies the Buda Limestone, and the regressive upper Cenomanian Pepper Shale of the Woodbine Group which unconformably underlies the Austin Chalk. This succession has sourced multiple reservoirs within the western portion of the East Texas Basin and is now being evaluated as a potential self-sourced reservoir. In this study we will attempt to determine the depositional controls on the formation of organic-rich source rock within the Maness Shale and divide the interval into chemostratigraphic packages based on whole rock elemental data. The main goals are 1) to build a depositional model within a sequence stratigraphic framework that can be used as a predictive tool to locate the richest source rocks within the basin, and 2) to determine the distribution of source rock facies vertically and laterally across the basin. The Maness Shale is a mixed carbonate and siliciclastic mudrock which contains overall high TOC and was deposited in an anoxic, low-energy environment. Maximum TOC and carbonate content are found within a condensed section located in the upper portion of the Maness Shale in association with a maximum flooding surface. Paleo-redox elements (Cu, Ni, V, Mo, and U) indicate that maximum levels of anoxia were reached within the condensed section. Carbonate content is thought to be biogenic in origin and is a result of increased productivity within the basin. Increases in productivity also lead to a high amount of organic material being deposited and preserved.Item The Effect of Rock Properties on Hydraulic Fracture Conductivity in the Eagle Ford and Fayetteville Shales(2014-09-05) Jansen, Timothy AHydraulic fracture treatments are used in low permeability shale reservoirs in order to provide highly conductive pathways from the reservoir to the wellbore. The success of these treatments is highly reliant on the created fracture conductivity. Optimizing fracture designs to improve well performance requires knowledge of how fracture conductivity is affected by rock and proppant characteristics. This study investigates the relationship between rock characteristics and laboratory measurements of propped and unpropped fracture conductivity of outcrop samples. These samples are from the Eagle Ford shale and the Fayetteville shale. Triaxial compression tests were performed on core specimens in order to determine the Young?s Modulus and Poisson?s Ratio of the outcrop samples. A combination of X-ray diffraction and Fourier transform infrared spectroscopy was used to determine the mineralogy. Profilometer surface scans were also performed to characterize the fracture topography. The results from this study show that the main factors affecting fracture conductivity are closure stress and proppant characteristics (concentration, size, and strength). For unpropped fractures, the fracture topography is the main factor in determining fracture conductivity. The topography interaction of the two surfaces determines the fracture width. A higher Young?s Modulus helps maintain this fracture width by resisting deformation as closure stress increases. For propped fractures, the most influential factor in determining fracture conductivity is proppant characteristics (concentration, size, and strength). At a proppant monolayer placement, the major mechanism for conductivity loss is proppant embedment, leading to decreased fracture width. A higher Young?s Modulus reduces the proppant embedment and better maintains fracture conductivity as closure stress increases. For a multilayer proppant pack concentration, the effect of rock characteristics is negligible compared to the effect of proppant pack characteristics.Item U-Pb geochronology of the Late Cretaceous Eagle Ford Shale, Texas; defining chronostratigraphic boundaries and volcanic ash source(2014-08) Pierce, John Donald; Fisher, W. L. (William Lawrence), 1932-; Ruppel, Stephen C.The Eagle Ford Shale and equivalent Boquillas Formation (Late Cretaceous) contain abundant volcanic ash beds of varying thickness. These ash beds represent a unique facies that displays a range of sedimentary structures, bed continuity, and diagenetic alteration. They are prominent not only in West Texas outcrops, but also in the subsurface of South Texas where hydrocarbon production is actively occurring. The ash beds have the potential to be used for stratigraphic correlation for understanding early diagenesis and — most importantly — for obtaining high-resolution geochronology, which can then be used for defining depositional rates and chronostratigraphy. Study of the ash beds was conducted at outcrops along U.S. 90, west of Comstock, Texas, the subsurface in Atascosa and Karnes County, and at a construction site in South Austin. Bed thicknesses range from 0.1–33 cm and were collected throughout the entirety of the Eagle Ford succession. Mineral separation yielded abundant non-detrital zircons for U-Pb dating. Dating was conducted using LA-ICP-MS at The University of Texas at Austin, to attain a base level understanding of the age range for the Eagle Ford. High-resolution ages for the base and top of the Eagle Ford were obtained, in addition to radioisotopically defining the Cenomanian-Turonian boundary within the section. U-Pb ages for the Eagle Ford Shale range from Early Cenomanian to Late-Coniacian near Comstock, Mid-Cenomanian to the Turonian-Coniacian boundary in the subsurface, and Early Cenomanian to Late Turonian in Austin area. These findings contrast with many of the regional biostratigraphic studies across the Eagle Ford and indicate a more prolonged period of Eagle Ford deposition than previously observed.