Browsing by Author "Gilliland, Ellen"

Now showing 1 - 8 of 8
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    An Assessment of Hypocenter Errors Associated with the Seismic Monitoring of Induced Hydro-fracturing in Hydrocarbon Reservoirs
    Gilliland, Ellen (Virginia Tech, 2009-10-14)
    Expanding the standard, single-well recording geometry used to monitor seismicity during hydro-fracture treatments could provide more accurate hypocenter locations and seismic velocities, improving general reservoir characterization. However, for the real, two-well data set obtained for this project, only S-wave picks were available, and testing resulted in anomalous hypocenter location behavior. This study uses a hypocenter location algorithm and both real and synthetic data sets to investigate how the accuracy of the velocity model, starting hypocenter location, recording geometry, and arrival-time picking error affect final hypocenter locations. Hypocenter locations improved using a velocity model that closely matched the observed sonic log rather than a smoothed version of this model. The starting hypocenter location did not affect the final location solution if both starting and final locations were between the wells. Two solutions were possible when the true solution was not directly between the wells. Adding realistic random picking errors to synthetic data closely modeled the dispersed hypocenter error pattern observed in the real data results. Adding data from a third well to synthetic tests dramatically reduced location error and removed horizontal geometric bias observed in the two-well case. Seismic event data recorded during hydro-fracture treatments could potentially be used for three-dimensional joint hypocenter-velocity tomography. This would require observation wells close enough to earthquakes to record P- and S-wave arrivals or wells at orientations sufficient to properly triangulate hypocenter locations. Simulating results with synthetic tests before drilling could optimize survey design to collect data more effectively and make analysis more useful.
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    Assessment of the Geological Storage Potential of Carbon Dioxide in the Mid-Atlantic Seaboard: Focus on the Outer Continental Shelf of North Carolina
    Mullendore, Marina Anita Jacqueline (Virginia Tech, 2019-05-02)
    In an effort to mitigate carbon dioxide (CO2) emissions in the atmosphere, the Southeast Offshore Storage Resource Assessment (SOSRA) project has for objective to identify geological targets for CO2 storage in two main areas: the eastern part of the Gulf of Mexico and the Atlantic Ocean subsurface. SOSRA's second objective is to estimate the geological targets' capacity to store up to 30 million metric tons of CO2 each year with an error margin of ±30%. As part of this project, the research presented here focuses on the outer continental shelf of North Carolina and its potential for the deployment of large-scale offshore carbon storage in the near future. To identify geological targets, workflow followed typical early oil and gas exploration protocols: collecting existing datasets, selecting the most applicable datasets for reservoir exploration, and interpreting datasets to build a comprehensive regional geological framework of the subsurface of the outer continental shelf. The geomodel obtained can then be used to conduct static volumetric calculations estimating the storage capacity of each identified target. Numerous uncertainties regarding the geomodel were attributed to the variable coverage and quality of the geological and geophysical data. To address these uncertainties and quantify their potential impact on the storage capacity estimations, dynamic volumetric calculations (reservoir simulations) were conducted. Results have shown that, in this area, both Upper and Lower Cretaceous Formations have the potential to store large amounts of CO2 (in the gigatons range). However, sensitivity analysis highlighted the need to collect more data to refine the geomodel and thereby reduce the uncertainties related to the presence, dimensions and characteristics of potential reservoirs and seals. Reducing these uncertainties could lead to more accurate storage capacity estimations. Adequate injection strategies could then be developed based on robust knowledge of this area, thus increasing the probability of success for carbon capture and storage (CCS) offshore projects in North Carolina's outer continental shelf.
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    Determining Coalbed Methane Production and Composition from Individual Stacked Coal Seams in a Multi-Zone Completed Gas Well
    Ripepi, Nino; Louk, Kyle; Amante, Joseph; Schlosser, Charlies; Tang, Xu; Gilliland, Ellen (MDPI, 2017-10-02)
    This work proposes a novel and cost-effective approach to determine coalbed methane (CBM) production and composition from individual coal seams in a multi-zone completed CBM well. The novel method uses water to cover individual coal seams in a low pressure CBM well followed by an Echometer fluid level survey to determine the water level. Corresponding gas flow measurements and natural gas chromatography analysis are used to determine gas production and composition from unique zones. A field test using this technology is conducted in Central Appalachia for a multi-zone CBM well containing 18 coal seams. Test results show that the shallow coal seams contribute the majority of the total CBM production in this multi-zone well, and the deeper coal seams contain more heavy hydrocarbons like ethane and propane.
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    Field Laboratory for Emerging Stacked Unconventional Plays (ESUP): Project No. DE-FE0031576
    Ripepi, Nino; Karmis, Michael E.; Chen, Cheng; Gilliland, Ellen; Nojabaei, Bahareh (Virginia Tech, 2018-08-24)
    The objective for this project is to investigate and characterize the resource potential for multi-play production of emerging unconventional reservoirs in Central Appalachia. The project team includes Virginia Tech; Virginia Center for Coal & Energy Research; Enervest Operating, LCC; Pashin Geoscience, LLC; and Gerald R. Hill, PhD, Inc. The anticipated duration of the project is April 1, 2018 - March 31, 2023.
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    Integrated Experimental Characterization of the Lower Huron Shale in the Central Appalachian Basin
    Tan, Xinyu (Virginia Tech, 2020-06-04)
    Reservoir characterization is an essential step in the oil/gas exploration process and is of great significance in the evaluation of oil/gas resources. To evaluate the production potential of the Lower Huron shale in the central Appalachian Basin, matrix permeability, Raman spectroscopy, Fourier Transform infrared spectroscopy (FTIR), and atomic force microscopy (AFM) were used in this study. According to the experimental results, matrix permeability is relatively high for a shale gas formation, suggesting great production potential of shale gas resources in this region. Additionally, four shale samples with varying thermal maturity were characterized by the complementary Raman and FTIR spectroscopy, and curve-fitting results successfully demonstrated the change of chemical structures with the evolution of thermal maturity. Raman spectroscopy results show that the curve fitted G band position and the band separation between the G band and D1 band tend to increase with the rise of thermal maturity level. Results of FTIR spectroscopy show that the aromaticity level and the condensation extent of aromatic rings show an increasing tendency with the increase of maturation level. Moreover, mechanical properties of these four shale samples were characterized by AFM. Results show that Young's modulus is in the range of 8.20 GPa - 12.94 GPa, which is in the normal range compared with the results from other shale formations. Additionally, scanned results show an increasing tendency for Young's modulus of the organic components with the rise of thermal maturity level in these shale samples. The potential reason for this phenomenon was also explored, specifically, the growth of aromatic groups and the decrease of the CH2/CH3 ratio may be possible reasons for the rise of Young's modulus of organic components in these shale samples. This work is meaningful for the evaluation of shale gas resources, especially emerging plays, in the central Appalachian Basin, and it also provides a valuable database for relevant research on shale matrix permeability, Raman, FTIR and AFM.
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    Integrative Geophysical and Environmental Monitoring of a CO2 Sequestration and Enhanced Coalbed Methane Recovery Test in Central Appalachia
    Gilliland, Ellen (Virginia Tech, 2016-12-02)
    A storage and enhanced coalbed methane (CO2-ECBM) test will store up to 20,000 tons of carbon dioxide in a stacked coal reservoir in southwest Virginia. The test involves two phases of CO2 injection operations. Phase I was conducted from July 2, 2015 to April 15, 2016, and injected a total of 10, 601 tons of CO2. After a reservoir soaking period of seven months, Phase II is scheduled to begin Fall 2016. The design of the monitoring program for the test considered several site-specific factors, including a unique reservoir geometry, challenging surface terrain, simultaneous CBM production activities which complicate the ability to attribute signals to sources. A multi-scale approach to the monitoring design incorporated technologies deployed over different, overlapping spatial and temporal scales selected for the monitoring program include dedicated observation wells, CO2 injection operations monitoring, reservoir pressure and temperature monitoring, gas and formation water composition from offset wells tracer studies, borehole liquid level measurement, microseismic monitoring, surface deformation measurement, and various well logs and tests. Integrated interpretations of monitoring results from Phase I of the test have characterized enhanced permeability, geomechanical variation with depth, and dynamic reservoir injectivity. Results have also led to the development of recommended injection strategy for CO2-ECBM operations. The work presented here describes the development of the monitoring program, including design considerations and rationales for selected technologies, and presents monitoring results and interpretations from Phase I of the test.
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    Micrometer-scale Experimental Characterization of the Lower Huron Shale in the Central Appalachian Basin
    Tan, Xinyu; Gilliland, Ellen; Tang, Xu; Fan, Ming; Ripepi, Nino (American Geophysical Union, 2020)
    The mechanical properties of shale play an important role in hydraulic fracturing design. Although the popular nanoindentation method can be performed to evaluate some mechanical characteristics of organic matter, it is still difficult to fully characterize mechanical properties of organic components of shale due to their small scale which is usually on the order of micrometers or even nanometers. As a novel material characterization tool, Atomic Force Microscopy (AFM) has shown great potential to characterize surface properties and pore structures at micrometer- and nanometer-scale and has been applied to investigate the elastic properties of organic components in shale by multiple researchers. Raman and FTIR can detect chemical bands by utilizing molecular vibration information. Because Raman and FTIR measurements are non-destructive, high sensitivity, and short in duration, they have been used extensively to study maturation processes of organic components in coal and shale samples. To some extent, these two methods can be considered as complementary to each other, and more comprehensive understanding about maturation processes of organic components can be achieved by combining these two methods. In this work, mechanical properties and chemical characteristics of four shale samples with different thermal maturities were investigated. Generally, this study had two objectives: (1) Characterize the mechanical properties of shale samples with different maturity levels through the novel AFM method, and (2) Explore the underlying cause for the change in elastic properties of shale samples from a chemical perspective through the complementary Raman and FTIR methods.
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    Monitoring CO2 Plume Migration for a Carbon Storage-Enhanced Coalbed Methane Recovery Test in Central Appalachia
    Louk, Andrew Kyle (Virginia Tech, 2019-02-04)
    During the past decade, carbon capture, utilization, and storage (CCUS) has gained considerable recognition as a viable option to mitigate carbon dioxide (CO2) emissions. This process involves capturing CO2 at emission sources such as power plants, refineries, and processing plants, and safely and permanently storing it in underground geologic formations. Many CO2 injection tests have been successfully conducted to assess the storage potential of CO2 in saline formations, oil and natural gas reservoirs, organic-rich shales, and unmineable coal reservoirs. Coal seams are an attractive reservoir for CO2 storage due to coal's large capacity to store gas within its microporous structure, as well as its ability to preferentially adsorb CO2 over naturally occurring methane resulting in enhanced coalbed methane (ECBM) recovery. A small-scale CO2 injection test was conducted in Southwest Virginia to assess the storage and ECBM recovery potential of CO2 in a coalbed methane reservoir. The goal of this test was to inject up to 20,000 tons of CO2 into a stacked coal reservoir of approximately 15-20 coal seams. Phase I of the injection test was conducted from July 2, 2015 to April 15, 2016 when a total of 10,601 tons of CO2 were injected. Phase II of the injection was conducted from December 14, 2016 to January 30, 2017 when an additional 2,662 tons of CO2 were injected, for a total of 13,263 total tons of CO2 injected. A customized monitoring, verification, and accounting (MVA) plan was created to monitor CO2 injection activities, including surface, near-surface, and subsurface technologies. As part of this MVA plan, chemical tracers were used as a tool to help track CO2 plume migration within the reservoir and determine interwell connectivity. The work presented in this dissertation will discuss the development and implementation of chemical tracers as a monitoring tool, detail wellbore-scale tests performed to characterize CO2 breakthrough and interwell connectivity, and present results from both phases of the CO2 injection test.