Browsing by Subject "Shale"
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Item The Black Shale Basin of West Texas(1939-08) Cole, Charles Taylor, 1913-; Bybee, Halbert Pleasant, 1888-1957The Black Shale Basin of West Texas covers an area in excess of 21,000 square miles and includes the region from Terrell and Pecos Counties eastward to Menard and Kimble Counties. It extends from Real, Edwards, and Val Verde northward beyond Glasscock and Upton Counties. This basin includes such local basins as the "Midland Basin," and "Val Verde Basin," of Frank E. Lewis, the "Sheffield Channel," and the "Kerr Basin." Reasons are given for the belief that the black shale sediments in this basin were derived from rocks south of this area. The shale ranges in age from Bend (lower Pennsylvanian) through Clear Fork (middle Permian). The shale of the Midland Basin has been divided into three distinct zones. Pre-Cretaceous erosion has removed the offlapping Permian shale in the extreme southern portion of the area leaving Pennsylvanian directly beneath the Trinity. The problem of stratigraphy is complicated by gradation and lack of diagnostic fossils. There is a great divergence of opinion as to correlative formational units derived from a study of the well cuttings.Item Complex electrical properties of shale as a function of frequency and water content(Texas Tech University, 1999-05) Adisoemarta, Paulus S.An experimental research program has been initiated to investigate the electrical properties of swelling shales (shales that have been exposed to water and are therefore expanding) across a wide frequency range, 5 Hz to 1.3 GHz. This range spans the spectrum of the commonly used downhole logging measurements, from the deep laterologs to the microwave dielectric tools. Three different methods of varying the sample's water content have been used: desiccator, electro-osmosis and air exposure methods. Two distinct measurement techniques have been used to span the frequency range: four-electrode setup for the low frequencies (5 Hz -13 MHz), and open-ended coaxial probe with network analyzer at the high end (20 MHz - 1,3 GHz), The probe technique is simple to use, potentially enabling field measurements of complex permittivity to be taken, although some accuracy is sacrificed. The effects of swelling in shale are most pronounced at the lowest frequencies. This investigation discovered a phenomenon of shale; shale will generate a direct electrical current under stress that has potential for a wellbore diagnostic tool. Also, the best fluid for shale preservation was found to be Isopar M™ (a mineral oil), saturated with deionized water.Item Determination of the Controls on Permeability and Transport in Shale by Use of Percolation Models(2012-10-19) Chapman, IanA proper understanding of reservoir connectivity is essential to understanding the relationship between the porosity and the permeability within it. Additionally, the construction of an accurate reservoir model cannot be accomplished without this information. While a great deal is known about the connectivity in conventional sandstone systems, little is understood about the connectivity and its resultant properties within shale systems. Percolation theory is a method to describe the global properties of the shale system by understanding the nanometer scale interaction of pore space. In this study we use both analytical and empirical techniques to further understand shale pore scale interactions as well as global phenomena of the shale system. Construction of pore scale connectivity simulations on lattice and in the continuum allow for understanding relationships between pore topology, system porosity and system permeability. Additionally, questions regarding the role of Total Organic Carbon as well as natural fractures in contributing to shale permeability will be discussed. Analytical techniques are used to validate simulation results regarding the onset of percolation and related pore topology. Finally, time of flight simulation is used to further understand pressure transient behavior in the resulting topological models. High aspect ratio pores are shown to be the driver of shale permeability as opposed to the low aspect ratio pore space associated with organic matrix. Additionally, systems below the percolation threshold are likely able to produce because the wellbore will often encounter near infinite clusters. Finally, a characteristic volume growth profile is shown for a multi-porosity system whereby each level of porosity displays a corresponding stair step of volume growth in time.Item Discrete element modeling of rock fracture behavior: fracture toughness and time-dependent fracture growth(2006) Park, Namsu; Olson, Jon E.Item Elemental geochemistry and micropaleontology of an upper Pennsylvanian black shale: the Haskell-Cass cycle (Douglas group), southeastern Kansas(Texas Tech University, 1995-08) Baker, Terri LynnMajor and trace element concentrations and microfaunal distributions were determined for a detailed section of the Haskell-Cass cycle (upper Vinland Shale, Haskell Limestone, and lower Robbins Shale) near Peru, Kansas. Total organic carbon (TOC), loss on ignition (LOI), detrital elements, carbonate elements, trace and minor metals, and rare earth elements were analyzed and compared to the abundances of conodont elements and holothurian sclerites. The lower Robbins Shale is a low organic carbon (< 2.0 wt. percent) gray shale. This offshore shale is atypically thick due to moderate influx of fine terrigenous elastics. A geochemically anomalous interval occurs in the lower Robbins Shale. This interval has the highest TOC, limited siliceous detritus, and when normalized to aluminum, moderate peaks of vanadium, nickel, chromium, and copper. This geochemical pattern suggests that a brief period of high marine productivity ultimately caused reduced conditions. Vanadium is more concentrated higher in the section, unlike Ni, Cr, and Cu, and is a geochemical indicator of open marine conditions. Conodont abundance is unusually low and sclerites are absent in the anomalous interval, but conodonts return to the expected "core shale" levels higher in the section. Gondolella appears higher in the section where vanadium levels are greater.Item Evaluation of Membrane Treatment Technology to Optimize and Reduce Hypersalinity Content of Produced Brine for Reuse in Unconventional Gas Wells(2012-10-19) Eboagwu, UcheOver 18 billion barrels of waste fluids are generated annually from oil and gas production in the United States. As a large amount of water is used for oilfield operations, treating and reusing produced water can cut the consumption of fresh water in well sites. This research has helped to develop a membrane process train for a mobile produced water treatment unit for treating oilfield produced brine for reuse. To design the process train, over 30 sets of combination tests at pilot laboratory scale were performed using pretreatment, microfiltration and nanofiltration processes. Membrane performance was selected based on high flux separation efficiency, high tolerance for solids and fluid treatments. Over 95 % solids rejection and greater than 80 % oil removal efficiency were obtained in all these tests. Process train (pre-treatment and membrane) performance was monitored by chemical analysis of permeate and models fitting experimental data for the process. From the results, hydrocarbon rejection was analyzed; total organic carbon rejection was 47.9 %, total carbon content averaged 37.3 % rejection and total inorganic carbon rejection was at 3.66 %. BTEX removal efficiency ranged from 0.98 % to 52.7 % with the progressive pretreatment methods of using cartridge filters. The nanofiltration membrane showed significant reduction in total dissolved solids and in both anionic and cationic species. The process train is seen to follow a sequence of treatment from cartridge and oil removal filter treatment to microfiltration treatment to ultrafiltration, followed by nanofiltration for the purpose of this research. Further research still needs to be done on to determine the kind of analytical test which will give real time feedback on effectiveness of filters. In summary, the process train developed by TAMU-GPRI possesses distinct advantages in treating oilfield produced brine using membrane technology. These advantages include high quality of permeate, reduced sludge and the possibility of total recycle water systems. The small space requirement, moderate capital costs and ease of operation associated with the use of the mobile unit membrane technology also makes it a very competitive alternative to conventional technologies.Item Evaluation of natural pozzolans as replacements for Class F fly ash in portland cement concrete(2013-12) Cano, Rachel Irene; Juenger, Maria C. G.Most concrete produced today utilizes pozzolans or supplementary cementitious materials (SCMs) to promote better long term durability and resistance to deleterious chemical reactions. While other pozzolans and SCMs are available and provide many of the same benefits, Class F fly ash has become the industry standard for producing quality, durable concrete because of its low cost and wide-spread availability. With impending environmental and safety regulations threatening the availability and quality of Class F fly ash, it is becoming increasing important to find viable alternatives. This research aims to find natural, lightly processed, alternatives to fly ash that perform similarly to Class F fly ash with regards to pozzolanic reactivity and provide comparable compressive strength, workability, drying shrinkage, thermal expansion properties and resistance to alkali-silica reaction, sulfate attack, and chloride ion penetration. Eight fly ash alternatives from the US were tested for compatibility with the governing standard for pozzolans used in portland cement concrete and various fresh and hardened mortar and concrete properties. The results of this research indicate that six materials meet the requirements for natural pozzolans set by the American Society for Testing and Materials and many are comparable to Class F fly ash in durability tests. The primary concern when using these materials in concrete is the increase in water demand. The spherical particle shape of fly ash provides improved workability even at relatively low water-to-cement ratios; however, all of the materials tested for this research required grinding to achieve the appropriate particle size, resulting in an angular and rough surface area that requires more lubrication to achieve a workable consistency. So long as an appropriate water reducing admixture is used, six of the eight materials tested in this study are appropriate and beneficial for use in portland cement concrete.Item Experimental investigation of geomechanical aspects of hydraulic fracturing unconventional formations(2014-08) Alabbad, Emad Abbad; Olson, Jon E.Understanding the mechanisms that govern hydraulic fracturing applications in unconventional formations, such as gas-bearing shales, is of increasing interest to the petroleum upstream industry. Among such mechanisms, the geomechanical interactions between hydraulic fractures and pre-existing fractures on one hand, and simultaneous multiple hydraulic fractures on the other hand are seen of high importance. Although the petroleum engineering and related literature contains a number of studies that discusses such topics of hydraulic fracture interactions, there still remain some aspects that require answers, validations, or further supporting data. Particularly, experimental evidence is fairly scarce and keenly needed to solidify the understanding of such complex applications. In this work, the investigation methodology uses a series of hydraulic fracturing laboratory tests performed on synthetic rocks made of gypsum-based cements such as hydrostone and plaster in various experimental set ups. Those laboratory tests aim to closely investigate hydraulic fracture intersection with pre-existing fractures by assessing some factors that govern its outcomes. Specifically, the roles of the pre-existing fracture cementation, aperture, and relative height on the intersection mode are examined. The results show dominant effect of the cement-fill type relative to the host-rock matrix in determining whether hydraulic fracture crossing the pre-existing interface may occur. Similarly, hydraulic fracture height relative to the height of the pre-existing fracture may dictate the intersection results. However, the intersection mode seems to be insensitive of the pre-existing fracture aperture. Moreover, simultaneous multi-fracture propagation is examined and found to be impacted by the interference of the stresses induced from each fracturing source on neighboring fracturing sources. Such stress interference increases as the number of the propagating hydraulic fractures increase. While hydraulic fractures initiating from fracturing sources located in the middle of the fracturing stage seem to have inhibited propagation, outer hydraulic fractures may continue propagating with outward curvatures. Overall, the experimental results and analyses offer more insights for understanding hydraulic fracture complexity in unconventional formations.Item Exploring hydrocarbon-bearing shale formations with multi-component seismic technology and evaluating direct shear modes produced by vertical-force sources(2012-12) Alkan, Engin, 1979-; Hardage, Bob Adrian, 1939-; Hardage, Bob Adrian, 1939-; WAGNER, DON; FOMEL, SERGEY B; WILSON, CLARK R; FISHER, WILLIAM LIt is essential to understand natural fracture systems embedded in shale-gas reservoirs and the stress fields that influence how induced fractures form in targeted shale units. Multicomponent seismic technology and elastic seismic stratigraphy allow geologic formations to be better images through analysis of different S-wave modes as well as the P-wave mode. Significant amounts of energy produced by P-wave sources radiate through the Earth as downgoing SV-wave energy. A vertical-force source is an effective source for direct SV radiation and provides a pure shear-wave mode (SV-SV) that should reveal crucial information about geologic surfaces located in anisotropic media. SV-SV shear wave modes should carry important information about petrophysical characteristics of hydrocarbon systems that cannot be obtained using other elastic-wave modes. Regardless of the difficulties of extracting good-quality SV-SV signal, direct shear waves as well as direct P and converted S energy should be accounted for in 3C seismic studies. Acquisition of full-azimuth seismic data and sampling data at small intervals over long offsets are required for detailed anisotropy analysis. If 3C3D data can be acquired with improved signal-to-noise ratio, more uniform illumination of targets, increased lateral resolution, more accurate amplitude attributes, and better multiple attenuation, such data will have strong interest by the industry. The objectives of this research are: (1) determine the feasibility of extracting direct SV-SV common-mid-point sections from 3-C seismic surveys, (2) improve the exploration for stratigraphic traps by developing systematic relationship between petrophysical properties and combinations of P and S wave modes, (3) create compelling examples illustrating how hydrocarbon-bearing reservoirs in low-permeable rocks (particularly anisotropic shale formations) can be better characterized using different S-wave modes (P-SV, SV-SV) in addition to the conventional P-P modes, and (4) analyze P and S radiation patterns produced by a variety of seismic sources. The research done in this study has contributed to understanding the physics involved in direct-S radiation from vertical-force source stations. A U.S. Patent issued to the Board of Regents of the University of Texas System now protects the intellectual property the Exploration Geophysics Laboratory has developed related to S-wave generation by vertical-force sources. The University’s Office of Technology Commercialization is actively engaged in commercializing this new S-wave reflection seismic technology on behalf of the Board of Regents.Item A general poro-elastic model for pad-scale fracturing of horizontal wells(2015-12) Manchanda, Ripudaman; Sharma, Mukul M.; Espinoza, David N; McClure, Mark W; Olson, Jon E; Roussel, Nicolas PEconomic production of oil and gas from tight rocks requires horizontal well drilling with multiple hydraulic fractures along the length of the horizontal wells. Multiple horizontal wells are drilled and fractured close to each other to increase the recovery of oil and gas from a single location or pad. Interference between fractures in a horizontal well pad is commonly observed in the field. There is no clear understanding of the impact of various operational and reservoir parameters on the observed interference. This inter-well interference can occur through the creation of complex fracture networks and/or poro-elastic stress changes. In this research, the development of a poro-elastic numerical simulator was undertaken to evaluate hydraulic fracturing practices in pad-scale scenarios. The primary motivation was to assess the impact of various operational parameters such as fracture spacing, well spacing and fracture sequencing on the geometry of the created fractures. Two approaches were used to understand the problem at hand. In the first approach, static fractures were simulated in 3-D and the impact of their stress shadow on subsequent fractures was studied. It was observed that fracture spacing, injection volume, and time between successive fractures were the most important parameters that could be used to optimize the creation of fractures in a well. Formation properties such as Young’s modulus and horizontal stress contrast modified the magnitude and spatial extent of the stress shadow and the extent of stress reorientation. It was shown that stage spacing, well spacing and fracture sequencing together with fracture designs (volume of sand pumped and fluids used) can be adjusted to obtain non-intersecting, transverse fractures that efficiently drain the reservoir. A hypothesis, time dependent closure of induced unpropped fractures, was presented to explain why zipper fracturing often outperforms conventional sequential fracturing. The hypothesis was tested and confirmed with a field data set made available to us by Shell from the Eagle Ford shale. In the second approach, a novel finite volume based 3-D, geomechanical, field-scale numerical simulator was developed to simulate propagation of multiple fractures simultaneously in a poro-elastic reservoir. This provided a more realistic model of the pad-scale fracturing process. The ability of the model to perform realistic pad-scale simulations was demonstrated for a variety of field situations such as multi-cluster multi-stage fracturing, infill-well fracturing, re-fracturing, mini-frac analysis and fracture network simulations. The inclusion of poro-elastic effects and reservoir heterogeneity in the model allowed us to examine the effects of reservoir depletion on fracture geometry in refraced and infill wells.Item Geologically-based permeability anisotropy estimates for tidally-influenced reservoir analogs using lidar-derived, quantitative shale character data(2011-05) Burton, Darrin; Wood, Lesli J.; Steel, Ronald; Mohrig, David; Kim, Wonsuck; Hesse, Marc; Janson, XavierThe principle source of heterogeneity affecting flow behavior in conventional clastic reservoirs is discontinuous, low-permeability mudstone beds and laminae (shales). Simple ‘streamline’ models have been developed which relate permeability anisotropy (kv/kh ) at the reservoir scale to shale geometry, fraction, and vertical frequency. A limitation of these models, especially for tidally-influenced reservoirs, is the lack of quantitative geologic inputs. While qualitative models exist that predict shale character in tidally-influenced environments (with the largest shales being deposited near the turbidity maximum in estuaries, and in the prodelta-delta front), little quantitative shale character data is available. The purpose of this dissertation is to collect quantitative data to test hypothetical relationships between depositional environment and shale character and to use this data to make geologically-based estimates of for different reservoir elements. For this study, high-resolution, lidar point-clouds were used to measure shale length, thickness, and frequency. This dissertation reports a novel method for using distance-corrected lidar intensity returns to distinguish sandstone and mudstone lithology. Lidar spectral and spatial data, photo panels, and outcrop measurements were used to map and quantify shale character. Detailed shale characteristics were measured from four different tidally-influenced reservoir analogs: estuarine point bar (McMurray Formation, Alberta, Canada), tidal sand ridge (Tocito Sandstone, New Mexico), and unconfined and confined tidal bars (Sego Sandstone, Utah). Estuarine point bars have long (l=67.8 m) shales that are thick and frequent relative to the other units. Tidal sand ridges have short (l=8.6 m dip orientation) shales that are thin and frequent. Confined tidal bars contain shales that are thin, infrequent, and anisotropic, averaging 16.3 m in length (dip orientation). Unconfined tidal bars contain nearly equidimensional (l=18.6 m dip orientation) shales with moderate thicknesses and vertical frequency. The observed shale geometries agree well with conceptual models for tidal environments. The unique shale character of each unit results in a different distribution of estimated . The average estimated kv/kh values for each reservoir element are: 8.2*10^4 for estuarine point bars, 0.038 for confined tidal bars, 0.004 for unconfined tidal bars, and 0.011 for tidal sand ridges.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 The impact of shale properties on wellbore stability(2005) Zhang, Jianguo; Chenevert, Martin E.; Sharma, Mukul M.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 Measurement of fluid properties in organic-rich shales(2015-12) Jung, Chang Min; Sharma, Mukul M.; Chenevert, Martin E.; van Oort, Eric; Balhoff, Matthew; El Mohtar , ChadiThe primary objective of this study is to develop and improve water-based drilling fluids and fracturing fluids for organic rich shale reservoirs by using nanoparticles and to gain fundamental insight into water and oil flow in shales. This dissertation presents results for several shale formations in the US, namely the Barnett shale, the Eagle Ford shale, the Utica shale, and the Bakken shale. The research discussed here presents new methods for studying the interaction between various fluids and organic-rich shale and the development of proper methods to measure apparent and relative permeability of shale. First of all, we show how the petrophysical properties of shales are changed when they are poorly preserved. Experiments were performed to measure important petrophysical properties such as porosity, density, weight change, hardness, wave velocity and permeability before and after shale samples dried-out. The large differences in shale properties between preserved and un-preserved samples as reported herein, clearly indicate that shales should be preserved at the well site and tested with a standard procedure ensuring minimum alteration of fluids from the shale. Failure to follow a standard procedure leads to measurements that do not reflect the “true” or in-situ properties of the shale. Instead, the measurements can be a factor of 2 or 3 different from the “true” value. The shale handling, preservation and measurement techniques and procedures presented here can be used as a standard protocol for studying organic rich shales. Next, we discuss how fracturing fluid can change the petrophysical properties of shale. Among the various petrophysical properties, the fluid permeability is chosen to determine the effect of the fracturing fluid on the shale. Experimental procedures are presented to suggest how to measure the shale permeability. To measure the fluid permeability, the Pressure Penetration Technique (PPT) was developed and used. The reference permeability with sea water brine was measured and then fracturing fluid was injected into the shale. The brine permeability was re-measured to see the effect of exposure to the fracturing fluid, and experimental data show the permeability change due to fracturing fluid plugging the shale. Next, we focus on the development of a Water Based Mud (WBM) system for organic-rich shale. Drilling through a shale formation can result in borehole instability problems, and this is known to add substantial costs to the operation. This is because conventional drilling fluids tend to interact with clay minerals in shales, and the mechanical properties of rock are changed by clay swelling. To reduce the interaction between water-based muds and shales, we need to reduce water invasion into the shale. The addition of nanoparticle additives to water-based drilling fluids can significantly reduce the invasion. We report results for shale permeability and pressure penetration though shales using different fluids: brine, base mud and nanoparticle based muds. To better define the effect of nanoparticles, we used different concentrations of nanoparticles in the mud. From the large reduction in permeability and the pressure response results, we clearly show that nanoparticles act as good shale inhibitors to ensure wellbore stability during drilling. Experimental studies used to measure the relative permeability of shale. Such measurements have never been done before. Due to the extremely low permeability of shale, it is very difficult to measure the relative permeability of shale directly. We propose a method of relative permeability measurement using NMR (Nuclear Magnetic Resonance) spectroscopy to measure fluid saturations and a RPC (relative permeability measurements under a confining pressure) set-up to conduct the displacement. RPC set-up is a newly developed forced injection set-up using the unsteady-state method. The in-situ fluid saturation was successfully measured with NMR, and the set-up was also useful for measuring the relative permeability of shale. It yielded continuous results from the Bakken shale tests.Item Natural fracture characterization of the New Albany Shale, Illinois Basin, United States(2011-12) Fidler, Lucas Jared; Gale, Julia F. W.; Laubach, Stephen E. (Stephen Ernest), 1955-; Fisher, William L.; Flemings, Peter B.; Fomel, Sergey B.; Olson, Jon E.The New Albany Shale is an Upper Devonian organic-rich gas shale located in the Illinois Basin. A factor influencing gas production from the shale is the natural fracture system. I test the hypothesis that a combination of outcrop and core observations, rock property tests, and geomechanical modeling can yield an accurate representation of essential natural fracture attributes that cannot be obtained from any of the methods alone. Field study shows that New Albany Shale outcrops contain barren (free of cement) joints, commonly oriented in orthogonal sets. The dominant set strikes NE-SW, with a secondary set oriented NNW-SSE. I conclude that the joints were likely created by near-surface processes, and thus are unreliable for use as analogs for fractures in the reservoir. However, the height, spacing, and abundance of the joints may still be useful as guides to the fracture stratigraphy of the New Albany Shale at depth. The Clegg Creek and Blocher members contain the highest fracture abundance. Fractures observed in four New Albany Shale cores are narrow, steeply-dipping, commonly completely sealed with calcite and are oriented ENE-WSW. The Clegg Creek and Blocher members contain the highest fracture abundance, which is consistent with outcrop observations. Fractures commonly split apart along the wall rock-cement interface, indicating they may be weak planes in the rock mass, making them susceptible to reactivation during hydraulic fracturing. Geomechanical testing of six core samples was performed to provide values of Young’s modulus, subcritical index, and fracture toughness as input parameters for a fracture growth simulator. Of these inputs, subcritical index is shown to be the most influential on the spatial organization of fractures. The models predict the Camp Run and Blocher members to have the most clustered fractures, the Selmier to have more evenly-spaced fractures, and the Morgan Trail and Clegg Creek to have a mixture of even spacing and clustering. The multi-faceted approach of field study, core work, and geomechanical modeling I used to address the problem of fracture characterization in the New Albany Shale was effective. Field study in the New Albany presents an opportunity to gather a large amount of data on the characteristics and spatial organization of fractures quickly and at relatively low cost, but with questionable reliability. Core study allows accurate observation of fracture attributes, but has limited coverage. Geomechanical modeling is a good tool for analysis of fracture patterns over a larger area than core, but results are difficult to corroborate and require input from outcrop and core studies.Item Organic maturation, primary migration, and clay mineralogy of selected Permian Basin shales(Texas Tech University, 1990-05) Landis, Charles R.The organic composition and maturity, and clay mineralogy of Woodford, Atoka, Canyon, and Wolfcamp shales of the Permian Basin were investigated with conventional and fluorescence microscopy, x-ray diffraction, and laser fluorescence spectroscopy. These shales were found to be mature source rocks with respect to the generation of liquid hydrocarbons and were of organic facies B and BC (oil and oil/gas prone, respectively) at the onset of catagenesis. An important exception is immature Woodford Shale in the northern region of the Midland Basin. Remaining hydrocarbon potential in mamre shale is gas or oil/gas. Maceral compositions favor the liptinites, mainly Tasmanales alginite and liptodetrinite. The clay mineral assemblages of Woodford and Canyon shales consist predominandy of discrete illite and accessory iUitic I/S and chlorite. In Canyon shales, kaolinite may be locally abundant. Discrete smectíte and smectite-dominated l/S are not observed in either shale sequence. Analytical electron microscopy reveals tíie detrital origin of the iUite and chlorite. These clays are interpreted to represent the influx of material firom weathered basement rocks in their respective hinterlands. Primary hydrocarbon migration from these shales is complex. In Canyon clastics, primordial oUs diffuse to sand laminae from adjacent shale. In thickly bedded shales, the continuous hydrocarbon phase is more conspicuous. An iinusual variety of exsudatinite was found to accumulate along bedding plane fracmres and exhibit a strong blue to blue-green fluorescence. Time-resolved fluorescence data indicate that several microenvironments, each characterized by unique ranges of fluorescence Ufetimes, may be detected.Item Paleoclimate and geochemical variation of the Stark Shale Member, Dennis Formation (Missourian), Mid-continent North America(2008-08) Akanbi, Oluwatosin T.; Holterhoff, Peter; Asquith, George B.; Barnes, Calvin G.The Upper Pennsylvanian Stark Shale is the core shale of the Dennis cyclothem. Bottom-water oxygenation is an important control on the preservation and quality of sedimentary organic matter and may influence the enrichments of trace elements (TEs). Detailed sample intervals were collected from four cores of the Stark Shale from Nemaha Uplift in Kansas (uplift cores) to the Forest City Basin in Missouri (basin cores). The samples were analyzed for major and trace elements, organic carbon and clay mineralogy. X-ray diffraction showed that illite, quartz and pyrite are the predominant minerals. Detrital elements (Si, Al, Zr and Ti) showed higher abundances of clay in the basin compared to the uplift. The weathering index and chemical index of alteration both indicate that source minerals of the shale were highly weathered. The basin core showed a more mature source compared to the uplift cores. Core shales were deposited during maximum transgression and may have high or low TOC depending on bottom-water oxygen levels. In high TOC cores (TOC > 10 %), abundances of V, Zn, Cr, Ni and Mo showed a moderate to strong correlation with TOC in the basin cores. The Heinen core (uplift) showed no significant correlation with the above elements at high TOCs. Low TOC shale (Emery core) showed no significant correlation with all trace elements (TEs). TEs enrichments were classified into TEs of euxinic affinity (V, Mo) and TEs associated with organic matter (Cu, Ni, Zn). Covariation of TEs of strong euxinic affinity with TOC were observed to be stronger in the basin core. Redox geochemical ratios V/Cr, TEs, V/ (V+Ni) and V-Mo covariation indicate euxinic conditions in the basin. Anoxic ¡V oxic conditions seem dominant in the uplift cores. Rock eval data showed a mixture of type I and II kerogen indicating terrestrial and marine organic matter. These data suggest that the controlling factors in the distribution of elements regionally and stratigraphically within the Stark Shale are: -Degree of weathering before deposition -Paleoredox conditions in the depositional environment -The composition of the organic -Settling time of detrital influx -Paleoclimate and paleogeographic conditions during deposition.Item Pore structure characterization of shale at the micro- and macro-scale(2016-12) Jiang, Chunbi; Daigle, Hugh; Bryant, Steven L.; Olson, Jon E.; Prodanovic, Masa; Flemings, Peter BPore structures within two Barnett shale samples at the microscale and macroscale were constructed based on conventional core analysis techniques (mercury intrusion capillary pressure (MICP), nitrogen sorption, and helium porosimetry). Measurements were performed on both bulk samples (core 2 and core 6) and organic matter isolated from bulk samples. Pore size distributions obtained from both core 2 and core 6 contain a large volume of micropores, while pore size distributions obtained from isolated organic matter do not, indicating that organic matter-associated pores are mesopores and most of the micropores are within the matrix. The organic matter-associated pore volume of core 2 is about 22% of the total pore volume, and the organic matter-associated pore volume of core 6 is about 41% of the total pore volume. A bundle of short conduits model with constraints can explain the measured nitrogen desorption isotherm on organic matter, and this model was used to represent the microscale pore structure within organic matter. Fragment size effect was observed on both MICP curves and nitrogen sorption isotherms measured on bulk Barnett samples: smaller fragment size results in larger mercury intrusion or nitrogen gas sorption. Fragment size effect does not appear in helium porosity measurement on bulk samples. A multiscale pore structure consisting of connected clusters of organic particles was constructed. The clusters have a characteristic length that controls the accessibility of the pore system, and the clusters are superimposed upon a background of intergranular voids not associated with organic matter. Within the individual organic particles, the pore structure consists of discrete, short pore conduits. The concept of characteristic length of the connected clusters can explain the fragment size effect, and the pore system can be fully accessible if the fragment size is close to this characteristic length. The modeled characteristic lengths for both core 2 and core 6 are in the micrometer range. To estimate permeability, the pore structure within organic matter is assumed to be a collection of dead ends which do not contribute to throughgoing fluid transport. Assuming further that the organic matter clusters are connected onto a network within the inorganic matrix, the permeability of the pore structure in micrometer scale is in 1 nanodarcy range.Item Rock-Fluid Chemistry Impacts on Shale Hydraulic Fracture and Microfracture Growth(2012-07-16) Aderibigbe, AderonkeThe role of surface chemical effects in hydraulic fracturing of shale is studied using the results of unconfined compression tests and Brazilian tests on Mancos shale- cored at depths of 20-60 ft. The rock mineralogy, total organic carbon and cation exchange capacity were determined in order to characterize the shale. Adsorption tests to study the interaction of the shale and aqueous fluid mixture were also carried out using surface tension measurements. The uniaxial compressive strengths and tensile strengths of individual shale samples after four hours exposure to water, 2.85 x 10^-3 M cationic surfactant (dodecyltrimethylammonium bromide-DTAB) and 2.81 x 10^-3 M anionic surfactant (sodium dodecylbenzenesulfonate-SDBS) were analyzed using ANOVA and Bonferroni tests. These mechanical strengths were largely reduced on exposure to the aqueous environments studied, despite the relatively low clay and low swelling clay content of the Mancos shale. Further comparison of the uniaxial compressive strengths and tensile strengths of the shale on exposure to water, to the strengths when exposed to the surfactant solutions showed that their difference was not statistically significant indicating that exposure to water had the greatest effect on strength loss. The surface tension measurement of 2.85 x 10^-4 M DTAB and 2.81 x 10^-4 M SDBS solutions before and after equilibration with shale showed about 80% increase in surface tension in the DTAB solution and 10% increase in surface tension in the SDBS solution. The probable sorption mechanism is electrostatic attraction with negatively charged sites of the shale as shown by significant loss of the cationic surfactant (DTAB) to the shale surface, and the relatively minor adsorption capacity of the anionic surfactant (SDBS). Although these adsorption tests indicate interaction between the shale and surfactant solutions, within the number of tests carried out and the surfactant concentration used, the interaction does not translate into a significant statistical difference for impacts of surfactants on mechanical strength of this shale compared to the impact of water alone. The relevance of this work is to facilitate the understanding of how the strength of rock can be reduced by the composition of hydraulic fracturing fluids, to achieve improved fracture performance and higher recovery of natural gas from shale reservoirs.