Petrographic and Petrophysical Characterization of the Eagle Ford Shale in La Salle and Gonzales Counties, Gulf Coast Region, Texas PDF Download
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Author: Sebastian Ramiro-Ramirez
Publisher:
ISBN:
Category : Facies (Geology)
Languages : en
Pages : 126
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Author: Sebastian Ramiro-Ramirez
Publisher:
ISBN:
Category : Facies (Geology)
Languages : en
Pages : 126
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Author: Namrita Sondhi
Publisher:
ISBN:
Category : Gas reservoirs
Languages : en
Pages : 352
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Author: Chad Larsen
Publisher:
ISBN:
Category :
Languages : en
Pages : 89
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Eagle Ford Shale and the overlying Austin Chalk are the main producing plays throughout Central Texas. Due to the high clastic nature of Eagle Ford Shale and its ability to produce and maintain fractures from hydraulic fracturing, this formation quickly became the favored target over Austin Chalk for unconventional hydrocarbon production. The purpose of this study is to gain an understanding of nano-petrophysical properties of Eagle Ford Shale,which is still lacking.Drilling cores from three wells within the oil window of Eagle Ford Shale were examined at the Bureau of Economic Geology in Austin, TX. Multiple plug samples were taken of three wells and analyzed using various tests of XRD, pyrolysis, TOC, mercury intrusion porosimetry (MIP), pycnometry, (DI water and n-decane) vacuum saturation, low-pressure nitrogen gas physisorption, and fluid (DI water and n-decane) imbibition. These experiments will shed light on the nano-petrophysical properties of the reservoir regarding porosity, pore throat distribution, permeability, and flow patterns. MIP results from this study show that Eagle Ford Shale has a wide range of pore structure parameters with porosity values varying from 0.11 to 7.25% and permeability from 0.005 to 11.6 mD; all samples are dominated by two pore types: micro fractures (1-50 μm) and inter-granular(0.01-1 uμ) pores. TOC % showed an increase when quartz % increased as minerology has a direct influence on TOC %. Bulk density averages 2.54% while the grain density is slightly increased with an average of 2.64%. Kerogen values plot between group II and III indicating a hydrocarbon potential. Based on the nano-petrophysical analysis of Eagle Ford Shale, the results of this thesis are beneficial to further the understanding of the pore structure and fluid migration within the shale, and to better facilitate increased production.
Author: Jon Paul Pierre
Publisher:
ISBN:
Category :
Languages : en
Pages : 0
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Expanded 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.
Author: Railroad Commission of Texas. Eagle Ford Shale Task Force
Publisher:
ISBN:
Category : Eagle Ford Shale
Languages : en
Pages : 147
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Author: Silas O'Silas
Publisher:
ISBN:
Category :
Languages : en
Pages : 80
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In recent years, the Haynesville shale has become a target for natural gas exploitation, especially with the advent of horizontal drilling and hydraulicfracturing. Located in East Texas and Northwest Louisiana, it is believed to be one of the largest producing natural gas plays in the U.S., with estimated recoverable reserves of around 75 TCF according to the Energy Information Administration (EIA, 2011). Current total daily production for the entire play is around 5.4 Bcf/d. The economic potential of the Haynesville shale gas play is propelled by recent gradual rebounds in natural gas prices, increased industrial utilization of gas, and expansion of LNG export terminals along the gulf coast due to the lifting of the decades-old ban on exporting petroleum products. Consequently, it is imperative to properly evaluate the petrophysical attributes of the shale in order to understand the reservoir characteristics that may ultimately influence production. This study focused on the petrophysical evaluation of wells in East Texas and Northwest Louisiana. Wireline logs and core data were integrated to provide a predictive template for targeting and landing lateral wellbores within the shale in order to provide useful insight for hydraulic fracture stimulation with the view of optimizing production. The critical factors determined to influence the target zones include geomechanical properties such as brittleness, and geochemical properties such as the mineral volumes in the rock. These were calculated from logs using equations previously published in literature and correlated to nearby core measurements for verification. Already drilled and completed laterals were also evaluated to identify potential refracturing opportunities that could remedy production decline. The stimulation techniques and production outcomes of these laterals were examined in an attempt to identify possible trends and contrasts accordingly. The results show that the geomechanical properties vary across the shale play area. The geomechanical and geochemical properties can be useful in target selection for landing horizontal wells and effective fracture treatments, but they cannot by themselves guarantee productivity as other factors have to be taken into consideration such as completions method. The various operational constraints and development patterns such as different lateral lengths and age/style of completions make it difficult to do effective well-to-well production comparison; however the results points to trends such as longer lateral lengths with greater fracture stages to boost production. Additionally, in some areas, it has been established via the petrophysical analysis that there may be additional intervals in which to land a second horizontal well. This will surely lead to better exploitation and increased production from the reservoir.
Author: East Texas Geological Society
Publisher:
ISBN:
Category : Petroleum industry and trade
Languages : en
Pages : 114
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Author: Heather Anne McGarity
Publisher:
ISBN:
Category : Geology
Languages : en
Pages :
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The Upper Cretaceous Eagle Ford Shale, in South and East Texas, consists of organic matter-rich fossiliferous marine shale. It is one of the most actively drilled targets for oil and gas in the United States, due to new technologies in drilling and completions. These low porosity and permeability reservoirs are now significant hydrocarbon producers, and therefore, it is crucial to understand the architectural elements and reservoir properties to maximize hydrocarbon production. Zones of higher clay content, variable lithology, total organic content variations, and changes in porosity and permeability can affect hydrocarbon recovery. This study focuses on building a detailed stratigraphic framework of the Eagle Ford Shale. Six wells with whole core through the Eagle Ford Formation were analyzed and interpreted to determine lithology, sedimentary structures, and parasequences. Eight separate facies along with their depositional environment were interpreted to have been deposited above storm wave base along the inner and outer shelf in a moderate energy environment episodically interrupted by higher energy events, as opposed to a deeper-water setting. Gently inclined lamina and ripple cross laminations provide evidence of significant bedload transport, probably as floccule ripples. Bioturbated horizons mark flooding surfaces that cap upward-coarsening facies successions, interpreted as parasequences. These surfaces, along with bentonites seen in core were then correlated to the corresponding wireline logs. These surfaces along with other distinct gamma ray markers were then correlated across the South Texas region using a dataset of 735 gamma ray logs. Several units show onlap and truncation that were used to document onlap and thinning adjacent to structural highs. The upper Eagle Ford Shale shows onlap and thinning of units towards the San Marcos Arch as opposed to the Maverick Basin region where the upper Eagle Ford Shale thickens significantly. The lower Eagle Ford Shale remains relatively constant throughout the South Texas region, showing only minimal areas of thickened sections. Thus, indicating deposition of this lower unit prior to subsidence of the Maverick Basin.
Author: John Albert Breyer
Publisher:
ISBN: 9780891813903
Category : Oil-shales
Languages : en
Pages : 0
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"Known as a world-class source rock for years, the Eagle Ford Shale became a world-class oil reservoir early in the second decade of the 21st century. Oil production from the Eagle Ford grew from 352 barrels of oil per day (BOPD) in 2008 to over 1.7 million BOPD in March 2015. Since then, the play has been a victim of its own success. Production from shale oil in the United States has helped contribute to a glut in world oil supply that led to a precipitous drop in oil prices beginning in the summer of 2014. As prices fell from over $100 per barrel in July 2014, to less than $30 per barrel in January 2016, production from the Eagle Ford declined over 500,000 BOPD. Anyone interested in the geology behind this remarkable play and the new ideas that reshaped the global energy supply should read this book. The hardcover book contains extended abstracts of the articles. Full articles are on the included DVD"--Publisher's website.
Author: Nefeli George Moridis
Publisher:
ISBN:
Category :
Languages : en
Pages :
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We begin this research by asking "can we better estimate reserves in unconventional reservoirs using Bayes' theorem?" To attempt to answer this question, we obtained data for 68 wells in the Greater Core of the Eagle Ford Shale, Texas. As process, we eliminated the wells that did not have enough data, that did not show a production decline and/or wells that had too much data noise (this left us with 8 wells for analysis). We next performed decline curve analysis (DCA) using the Modified Hyperbolic (MH) and Power-Law Exponential (PLE) models (the two most common DCA models), consisting in user-guided analysis software. Then, the Bayesian paradigm was implemented to calibrate the same two models on the same set of wells. The primary focus of the research was the implementation of the Bayesian paradigm on the 8 well data set. We first performed a "best fit" parameter estimation using least squares optimization, which provided an optimized set of parameters for the two decline curve models. This was followed by using the Markov Chain Monte Carlo (MCMC) integration of the Bayesian posterior function for each model, which provided a full probabilistic description of its parameters. This allowed for the simulation of a number of likely realizations of the decline curves, from which first order statistics were computed to provide a confidence metric on the calibration of each model as applied to the production data of each well. Results showed variation on the calibration of the MH and PLE models. The forward models (MH and PLE) either over- or underestimate the reserves compared with the Bayesian calibrations, proving that the Bayesian paradigm was able to capture a more accurate trend of the data and thus able to determine more accurate estimates of reserves. In industry, the same decline curve models are used for unconventional wells as for conventional wells, even though we know that the same models may not apply. Based on the proposed results, we believe that Bayesian inference yields more accurate estimates of reserves for unconventional reservoirs than deterministic DCA methods. Moreover, it provides a measure of confidence on the prediction of production as as function of varying data and varying decline curve models. The electronic version of this dissertation is accessible from http://hdl.handle.net/1969.1/155011
