Assessment of undiscovered oil and gas resources of the Ordovician Utica Shale of the Appalachian Basin Province, 2012

Kirschbaum, Mark A.; Schenk, Christopher J.; Cook, Troy A.; Ryder, Robert T.; Charpentier, Ronald R.; Klett, Timothy R.; Gaswirth, Stephanie B.; Tennyson, Marilyn E.; Whidden, Katherine J.

doi:10.3133/fs20123116

Cited by 14 publications

(6 citation statements)

References 3 publications

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“…Cores of Utica shale were provided courtesy of Chesapeake Energy, Inc., as unsealed specimens exposed to ambient conditions. The Ordovician‐age Utica shale occurs in the Appalachian basin (Ohio, Pennsylvania, West Virginia, and New York) and varies in thickness from 150 to 700 ft from east to west [ Kirschbaum et al ., ]. The Utica is a calcareous to clay‐rich shale with organic carbon contents generally in excess of 1% by weight.…”

Section: Experiments Methodologymentioning

confidence: 99%

High‐stress triaxial direct‐shear fracturing of Utica shale and in situ X‐ray microtomography with permeability measurement

et al. 2016

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The challenge of characterizing subsurface fluid flow has motivated extensive laboratory studies, yet fluid flow through rock specimens in which fractures are created and maintained at high‐stress conditions remains underinvestigated at this time. The studies of this type that do exist do not include in situ fracture geometry measurements acquired at stressed conditions, which would be beneficial for interpreting the flow behavior. Therefore, this study investigates the apparent permeability induced by direct‐shear fracture stimulation through Utica shale (a shale gas resource and potential caprock material) at high triaxial stress confinement and for the first time relates these values to simultaneously acquired in situ X‐ray radiography and microtomography images. Change in fracture geometry and apparent permeability was also investigated at additional reduced stress states. Finite element and combined finite‐discrete element modeling were used to evaluate the in situ observed fracturing process. Results from this study indicate that the increase in apparent permeability through fractures created at high‐stress (22.2 MPa) was minimal relative to the intact rock (less than 1 order of magnitude increase), while fractures created at low stress (3.4 MPa) were significantly more permeable (2 to 4 orders of magnitude increase). This study demonstrates the benefit of in situ X‐ray observation coupled with apparent permeability measurement to analyze fracture creation in the subsurface. Our results show that the permeability induced by fractures through shale at high stress can be minor and therefore favorable in application to CO2 sequestration caprock integrity but unfavorable for hydrocarbon recovery from unconventional reservoirs.

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Section: Experiments Methodologymentioning

confidence: 99%

High‐stress triaxial direct‐shear fracturing of Utica shale and in situ X‐ray microtomography with permeability measurement

et al. 2016

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“…20 The Appalachian Basin is shown with a thick black outline. 21 The solid red line is the extent of the Utica Shale Play. 22 The grayscale fields are the oil (darkest gray), wet gas (middle gray), and dry gas (lightest gray) windows.…”

Section: ■ Materials and Methodsmentioning

confidence: 99%

“…Small black circles are data from the USGS Produced Water Geochemical Database v2.3 . The Appalachian Basin is shown with a thick black outline . The solid red line is the extent of the Utica Shale Play .…”

Section: Introductionmentioning

confidence: 99%

Utica Shale Play Oil and Gas Brines: Geochemistry and Factors Influencing Wastewater Management

Blondes

Shelton

Engle

et al. 2020

Environ. Sci. Technol.

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The Utica and Marcellus Shale Plays in the Appalachian Basin are the fourth and first largest natural gas producing plays in the United States, respectively. Hydrocarbon production generates large volumes of brine (“produced water”) that must be disposed of, treated, or reused. Though Marcellus brines have been studied extensively, there are few studies from the Utica Shale Play. This study presents new brine chemical analyses from 16 Utica Shale Play wells in Ohio and Pennsylvania. Results from Na–Cl–Br systematics and stable and radiogenic isotopes suggest that the Utica Shale Play brines are likely residual pore water concentrated beyond halite saturation during the formation of the Ordovician Beekmantown evaporative sequence. The narrow range of chemistry for the Utica Shale Play produced waters (e.g., total dissolved solids = 214–283 g/L) over both time and space implies a consistent composition for disposal and reuse planning. The amount of salt produced annually from the Utica Shale Play is equivalent to 3.4% of the annual U.S. halite production. Utica Shale Play brines have radium activities 580 times the EPA maximum contaminant level and are supersaturated with respect to barite, indicating the potential for surface and aqueous radium hazards if not properly disposed of.

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“…The Utica shale is Middle to Late Ordovician in age and is linked to Marcellus and Huron shale by the Appalachian Basin [25]. Utica is an emerging shale play recently discovered to contain up to 20 times more extractable natural gas than previously predicted [26].…”

Section: Utica; Ohio and Pennsylvaniamentioning

confidence: 99%

Using PCA and PLS on publicly available data to predict the extractability of hydrocarbons from shales

Gallmeier

Zhang

McFarlane

2017

Journal of Natural Gas Science and Engineering

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Prediction of hydrocarbon extraction from shale requires specialized knowledge of shale play characteristics and analysis to assess effective, economical, and sustainable implementation of oil and natural gas production. In this work, we present a statistical approach that can be used as a preliminary investigation into the hydrocarbon resource potential of a shale play based on limited data. Statistical algorithms for Principal Component Analysis (PCA) and Partial Least Squares Regression (PLS) were used to determine if depositional environments and lithographic boundary characteristics of different plays allowed prediction of specific production parameters. This project characterizes Eagle Ford and Utica formations-two high-producing shale plays in the United States-and Banff/Exshaw and Colorado formations-two recently assessed shale plays in Alberta, Canada. Partial Least Squares Regression models were unable to model gas production parameters from predictor variables, highlighting the complexity of gas formations and the need for data on microscale petrophysical characteristics. In contrast, oil production 1

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Assessment of undiscovered oil and gas resources of the Ordovician Utica Shale of the Appalachian Basin Province, 2012

Cited by 14 publications

References 3 publications

High‐stress triaxial direct‐shear fracturing of Utica shale and in situ X‐ray microtomography with permeability measurement

High‐stress triaxial direct‐shear fracturing of Utica shale and in situ X‐ray microtomography with permeability measurement

Utica Shale Play Oil and Gas Brines: Geochemistry and Factors Influencing Wastewater Management

Using PCA and PLS on publicly available data to predict the extractability of hydrocarbons from shales

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