Browsing by Subject "Eagle Ford Shale"
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Item Anisotropic seismic characterization of the Eagle Ford Shale: rock-physics modeling, stochastic seismic inversion, and geostatistics(2016-05) Ren, Qi; Sen, Mrinal K.; Spikes, Kyle; Srinivasan, Sanjay; Fomel, SergeyQuantitative reservoir characterization using integrated seismic data and well log data is important in sweet spot identification, well planning, and reservoir development. The process includes building up the relations between rock properties and elastic properties through rock physics modeling, inverting for elastic properties from seismic data, and inverting for rock properties from both seismic data and rock physics models. Many quantitative reservoir characterization techniques have been developed for conventional reservoirs. However, challenges remain when extending these methods to unconventional reservoirs because of their complexity, such as anisotropy, micro-scale fabric, and thin beds issues. This dissertation focuses on developing anisotropic rock physics modeling method and seismic inversion method that are appliable for unconventional reservoir characterization. The micro-scale fabric, including the complex composition, shape and alignment of clay minerals, pore space, and kerogen, significantly influences the anisotropic elastic properties. I developed a comprehensive three-step rock-physics approach to model the anisotropic elastic properties, accounting for the micro-scale fabric. In addition, my method accounts for the different pressure-dependent behaviors of P-waves and S-waves. The modeling provides anisotropic stiffnesses and pseudo logs of anisotropy parameters. The application of this method on the Upper Eagle Ford Shale shows that the clay content kerogen content and porosity decrease the rock stiffness. The anisotropy increases with kerogen content, but the influence of clay content is more complex. Comparing the anisotropy parameter pseudo logs with clay content shows that clay content increases the anisotropy at small concentrations; however, the anisotropy stays constant, or even slightly decreases, as clay content continues to increase. Thin beds and anisotropy are two important limitation of the application of seismic characterization on unconventional reservoirs. I introduced the geostatistics into stochastic seismic inversion. The geostatistical models, based on well log data, simulate small-scale vertical variations that are beyond seismic resolution. This additional information compensates the seismic data for its band-limited nature. I applied this method on the Eagle Ford Shale, using greedy annealing importance sampling as inversion algorithm. The thin Lower Eagle Ford Formation, which cannot be resolved by conventional inversion method, is clearly resolved in the inverted impedance volume using my method. In addition, because anisotropy is accounted for in the forward modeling, the accuracy of inverted S-impedance is significantly improved.Item The Eagle Ford formation of Travis County, Texas(1925-06) Green, Guy EmmettItem Fracture Conductivity of the Eagle Ford Shale(2014-07-25) Guzek, James JHydraulic fracturing is a well completions technique that induces a network of flow channels in a reservoir. These channels are characterized by fracture conductivity, a measure of how easily a liquid or gas flows through the fracture. Fracture conductivity is influenced by several variables including fracture surface roughness, fracture closure stress, proppant size, and proppant concentration. The proppant concentration within a fracture can significantly affect the magnitude of fracture conductivity, which enhances the productivity of a hydraulically fractured well. Therefore, understanding the relationship between proppant concentration and fracture conductivity is critical to the successful development of unconventional reservoirs such as the Eagle Ford Shale. This work investigates the fracture conductivities of seven Eagle Ford Shale samples collected from an outcrop of facies B. Rough fractures were induced in the samples and laboratory experiments that closely followed the API RP-61 procedure were conducted on the samples to measure the unpropped and propped conductivities. Propped experiments were performed with 30/50 mesh white sand at two different areal concentrations within the fracture, 0.1 lb/ft^(2) and 0.2 lb/ft^(2). Assuming a cubical packing arrangement, the proppant pack is calculated to be a partial monolayer of 0.8 layers at 0.1 lb/ft^(2) and a pack of 1.6 layers at 0.2 lb/ft^(2). The results show that when the fractures are propped with 0.1 lb/ft^(2) or 0.2 lb/ft^(2), fracture conductivity values are approximately two orders of magnitude greater than unpropped conductivity values. Therefore, even low areal concentrations of proppant in a fracture can significantly enhance conductivity in the Eagle Ford Shale. Comparing the results of the two propped experiment types, conductivity values at 0.1 lb/ft^(2) proppant concentration are on average 49% higher than conductivity values at 0.2 lb/ft^(2). This difference is attributed to the partial monolayer pack at 0.1 lb/ft^(2) and proppant pack of 1.6 layers at 0.2 lb/ft^(2). However as closure stress increases from 1,000 psi to 6,000 psi, fracture conductivity at 0.2 lb/ft^(2) decreases more slowly than conductivity at 0.1 lb/ft^(2). These results suggest that the conductivity of the denser proppant pack at 0.2 lb/ft^(2) is more resistant to the flow inhibiting effects caused by proppant embedment and proppant crushing.Item Key Economic Drivers Impacting Eagle Ford Development from Resource to Reserves(2013-11-25) Del Busto Pinzon, Andres MauricioThe Eagle Ford shale of South Texas has become one of the most active and most important shale plays in the U.S. This success has been possible because of the unique geology and richness of the play, allowing significant production of natural gas, condensate liquids, and oil; the rapid improvement of long horizontal lateral drilling and multi-stage hydraulic fracturing completion technologies; and a long-term period of sustained high oil prices. This study develops a probabilistic before-tax economic model to estimate the reserves of the Eagle Ford shale, under different stochastic parameters and scenarios usually not considered by evaluators. The model is used to assess impact and sensitivity on reserves and economic yardsticks considering the variability and uncertainty of project inputs such as production streams, commodity prices, capital investments, and operational costs. We use existing probabilistic methodologies for production and price forecasting and use public and private sources to develop statistical distributions for additional parameters, including differentials for commodity prices, natural gas content for the different production regions, and water/gas and water/oil ratios. We consider three evaluation scenarios?single-well, 100-well, and Full-well?in each of the proposed production regions of the Eagle Ford shale, with calibrated probabilistic inputs for each region. Single-well results show how it is hard to produce complete distributions of reserves all across the play, although production regions with better productivity are identified. Results from the scenarios with multiple wells, show how the commerciality of the considered development projects is achievable in liquid-rich production regions and with moderate to high price forecasts. This study provides useful information and results to oil and gas professionals about key areas that influence the commercial development of Eagle Ford shale. The methodology to perform evaluations with probabilistic components enables better project development and investment decisions and can be applied to other shale plays.Item Occurrence of Multiple Fluid Phases Across a Basin, in the Same Shale Gas Formation ? Eagle Ford Shale Example(2014-04-29) Tian, YaoShale gas and oil are playing a significant role in US energy independence by reversing declining production trends. Successful exploration and development of the Eagle Ford Shale Play requires reservoir characterization, recognition of fluid regions, and the application of optimal operational practices in all regions. Using stratigraphic and petrophysical analyses, we evaluated key parameters, of reservoir depth and thickness, fluid composition, reservoir pressure, total organic carbon (TOC), and number of limestone and organic-rich marl interbeds of the Lower Eagle Ford Shale. Spatial statistics were used to identify key reservoir parameters affecting Eagle Ford production. We built reservoir models of various fluid regions and history matched production data. Well deliverability was modeled to optimize oil production rate by designing appropriate operational parameters. From NW to SE, Eagle Ford fluids evolve from oil, to gas condensate and, finally, to dry gas, reflecting greater depth and thermal maturity. From outcrop, the Eagle Ford Shale dips southeastward; depth exceeds 13,000 ft at the Sligo Shelf Margin. We divided Eagle Ford Shale into three layers. The Lower Eagle Ford is present throughout the study area; it is more than 275 ft thick in the Maverick Basin depocenter and thins to less than 50 ft on the northeast. In the Lower Eagle Ford Shale, a strike-elongate trend of high TOC, high average gamma ray values, and low bulk density extends from Maverick Co. northeastward through Guadalupe Co. Both limestone and organic-rich marl beds increase in number from fewer than 2 near outcrop to more than 20 at the shelf margins. Average thicknesses of Lower Eagle Ford limestone and organic-rich marl beds are low (< 5 ft.) in the La Salle ? DeWitt trend, coincident with the most productive gas and oil wells. Eagle Ford Shale was divided into 5 production regions in South Texas that coincide with the regional, strike-elongate trends of geologic parameters, which suggests that these parameters significantly impact Eagle Ford Shale production. Eagle Ford Shale production (barrels of oil equivalent, BOE) increases consistently with depth, increases with Lower Eagle Ford thickness (up to 180-ft thickness), and increases with TOC (up to 7%). P values analyses suggest high certainty of the relationship between the production and five reservoir parameters tested in regression models. Multiple good history matches of a gas condensate well suggest significant uncertainties in reservoir parameters. Oil production rate is not sensitive to oil relative permeability for the gas condensate well model. We were unable to match the production history for the volatile oil wells, possibly because gas of lift. Reservoir modeling suggests low bottomhole flowing pressure was the key to optimize cumulative oil production. Concepts and models developed in this study may assist operators in making critical Eagle Ford Shale development decisions; they may be transferable to other shale plays.Item Production Forecast, Analysis and Simulation of Eagle Ford Shale Oil(2014-12-02) Alotaibi, Basel Z S Z JIn previous works and published literature, production forecast and production decline of unconventional reservoirs were done on a single-well basis. The main objective of previous works was to estimate the ultimate recovery of wells or to forecast the decline of wells in order to estimate how many years a well could produce and what the abandonment rate was. Other studies targeted production data analysis to evaluate the completion (hydraulic fracturing) of shale wells. The purpose of this research is to generate field-wide production forecast of the Eagle Ford Shale (EFS). This study considered oil production of the EFS only. More than 6 thousand oil wells were put online in the EFS basin between 2008 and December 2013. The method started by generating type curves of producing wells to understand their performance. Based on the type curves, a program was prepared to forecast the oil production of EFS based on different drilling schedules; drilling requirements can be calculated based on the desired production rate. To complement the research, analysis of daily production data from the basin was performed. Moreover, single-well simulations were done to compare results with the analyzed data. Findings of this study depended on the proposed drilling and developing scenario of EFS. The field showed potential of producing high oil production rate for a long period of time. The three presented forecasted cases gave and indications of the expected field-wide rate that can be witnessed in the near future in EFS. The method generated by this study is useful for predicting the performance of various unconventional reservoirs for both oil and gas. It can be used as a quick-look tool that can help if numerical reservoir simulations of the whole basin are not yet prepared. In conclusion, this tool can be used to prepare an optimized drilling schedule to reach the required rate of the whole basin.Item Sedimentary and Diagenetic Controls on Petroleum System Characteristics of the Upper Cretaceous Eagle Ford Group, South Texas(2014-04-29) Hancock, Travis AEarly diagenetic carbonate cements can affect brittleness and total organic content in shale reservoirs. Predicting these effects could potentially improve recovery efficiency and field development costs, and decrease the environmental impact of developing the field. In this study, an X-ray fluorescence spectroscopic technique was used to test for correlations between primary depositional features, diagenetic carbonate cements, and organic content and fracture distributions in core samples from the Eagle Ford Group in McMullen County, Texas. Organic content varies significantly between diagenetic facies, with the least organic matter present in coarsely mineralized shales. This result is consistent with the hypothesis that diagenetic carbonate cementation that was early relative to compaction diluted primary organic matter. In contrast, total fracture length varies significantly between depositional facies, with the lowest total fracture length per length of core present in massive shales. Carbonate diagenesis therefore likely did not exert a significant control on the formation of the bedding-parallel fractures observed in this study; instead, laminated fabrics provided planes of weakness along which stress release fractures or hydrocarbon generation-induced fractures could develop. The suggested target reservoir facies for similar Eagle Ford wells is a finely to moderately mineralized laminated shale because of the likelihood of finding high organic content and horizontal fractures that would increase the effective rock volume in communication with primary hydraulically induced fractures.