Recent production of light sweet oil from shallow (~2,000 ft) horizontal wells in the Upper Devonian Berea Sandstone of eastern Kentucky and historical oil production from conventional wells in the Berea of adjoining southern Ohio has prompted re-evaluation of Devonian petroleum systems in the central Appalachian Basin. Herein, we examined Upper Devonian Ohio Shale (lower Huron Member) and Middle Devonian Marcellus Shale organic-rich source rocks from eastern Ohio and nearby areas using organic petrography and geochemical analyses of solvent extracts. The data indicate the organic matter in the Ohio and Marcellus Shales was primarily derived from marine algae and its degradation products including bacterial biomass. Absence of odd-over-even n-alkane distributions in gas chromatograms and low gammacerane index values in Devonian source rocks are similar to properties reported for Devonian-reservoired oils in eastern Ohio, suggesting a strong oil-source rock correlation. However, petrographic and geochemical parameters presented here were unable to discriminate specific shale source rocks (e.g., Ohio Shale vs. Marcellus Shale) for the Devonian oils. Lower Paleozoic oils from eastern Ohio, in contrast, are characterized by the presence of odd-over-even n-alkane distributions and higher gammacerane values which clearly discriminate them from Devonian shale-derived oils. Measurements of solid bitumen reflectance (BRo) at the thermal maturity range of the samples (immature to peak oil conditions) tend to underestimate ‘true’ thermal maturity because solid bitumen has lower reflectance than co-occurring vitrinite. Because solid bitumen dominates the organic matter in Devonian shale and vitrinite is sparse, the value of reflectance as a thermal proxy is questionable and its use may lead to reports of ‘vitrinite reflectance suppression’ in early mature to oil window mature areas. For example, thermal maturity estimates from equilibrium(?) biomarker isomerization ratios may suggest some of the Devonian source rock samples are at middle to peak oil window conditions e.g., approximate vitrinite reflectance values of 0.8-0.9%, whereas solid bitumen reflectance is approximately 0.52-0.54% in the same samples. If correct, this observation may require that the predicted onset of oil generation from Devonian shale source rocks in eastern Ohio is moved farther westward. As a consequence, only local to short-distance (30-50 mi) migration would be necessary for emplacement of Devonian-sourced oils into Devonian reservoirs of eastern Ohio, rather than long-distance migration (>50 mi) from ‘deep in the Appalachian basin’, as suggested by previous workers, potentially impacting exploration and future assessments of undiscovered petroleum resources in the Berea Sandstone. However, biomarker isomerization ratios do not show consistent relationships to other thermal maturity parameters (BRo, Tmax), thereby preventing development of robust empirical calibrations for these thermal proxies in the Devonian of eastern Ohio.

Raman spectroscopy was studied as a thermal maturity probe in a series of Upper Devonian Ohio Shale samples from the Appalachian Basin spanning from immature to dry gas conditions. Raman spectroscopy also was applied to samples spanning a similar thermal range created from 72-hour hydrous pyrolysis (HP) experiments of the Ohio Shale at temperatures from 300 to 360°C and isothermal HP experiments lasting up to 100 days of similar Devonian-Mississippian New Albany Shale. Raman spectra were treated by an automated evaluation software based on iterative and simultaneous modeling of signal and baseline functions to decrease subjectivity. Spectra show robust correlation to measured solid bitumen reflectance (BRo) values and were therefore used to construct logarithmic regression relationships for calculation of BRo equivalent values. Raman spectra show considerable differences between natural samples and HP. residues with similar measured BRo values, indicating as-yet undetermined differences in carbon chemistry. We speculate this result may be due to differences in the sampling interactions of Raman vs. reflectance measurements, and the incomplete nature of maturation reactions in the time-limited hydrous pyrolysis residues. Samples used in this study are similar in organic assemblage (dominantly solid bitumen) to other commonly exploited North American shale petroleum systems, i.e., Bakken, Barnett, Duvernay, Fayetteville and Woodford shales. Therefore, results presented herein may be broadly applicable to other important shale plays. However, caution is suggested and Raman spectroscopy as a thermal probe may need individual calibration in each shale play due to differences in solid bitumen carbon chemistry. Samples were collected and tested between 2013 and 2018, in studies preformed by Ryder et al., 2013; Hackley and Lewan, 2018; Hackley et al., 2017; Yang et al., 2017; Hackley and Lundsdorf, 2018.

Raman spectroscopy was studied as a thermal maturity probe in a series of Upper Devonian Ohio Shale samples from the Appalachian Basin spanning from immature to dry gas conditions. Raman spectroscopy also was applied to samples spanning a similar thermal range created from 72-hour hydrous pyrolysis (HP) experiments of the Ohio Shale at temperatures from 300 to 360°C and isothermal HP experiments lasting up to 100 days of similar Devonian-Mississippian New Albany Shale. Raman spectra were treated by an automated evaluation software based on iterative and simultaneous modeling of signal and baseline functions to decrease subjectivity. Spectra show robust correlation to measured solid bitumen reflectance (BRo) values and were therefore used to construct logarithmic regression relationships for calculation of BRo equivalent values. Raman spectra show considerable differences between natural samples and HP. residues with similar measured BRo values, indicating as-yet undetermined differences in carbon chemistry. We speculate this result may be due to differences in the sampling interactions of Raman vs. reflectance measurements, and the incomplete nature of maturation reactions in the time-limited hydrous pyrolysis residues. Samples used in this study are similar in organic assemblage (dominantly solid bitumen) to other commonly exploited North American shale petroleum systems, i.e., Bakken, Barnett, Duvernay, Fayetteville and Woodford shales. Therefore, results presented herein may be broadly applicable to other important shale plays. However, caution is suggested and Raman spectroscopy as a thermal probe may need individual calibration in each shale play due to differences in solid bitumen carbon chemistry. Samples were collected and tested between 2013 and 2018, in studies preformed by Ryder et al., 2013; Hackley and Lewan, 2018; Hackley et al., 2017; Yang et al., 2017; Hackley and Lundsdorf, 2018.

Citation Note: These data were collected as part of a research study published in Environmental Science and Technology. Please reference the following paper when citing these data. Blondes, M.S., Shelton, J.L., Engle, M.A., Trembly, J.P., Doolan, C.A., Jubb, A.M., Chenault, J.M., Rowan, E.L., Haefner, R.J., and Mailot, B.E., 2020, Utica Shale Play Oil and Gas Brines: Geochemistry and Factors Influencing Wastewater Management: Environmental Science & Technology, https://dx.doi.org/10.1021/acs.est.0c02461. The Utica and Marcellus Shale Plays in the Appalachian Basin are the 4th and 1st largest natural gas producing plays in the United States. 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 solides = 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 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.

Citation Note: These data were collected as part of a research study published in Environmental Science and Technology. Please reference the following paper when citing these data. Blondes, M.S., Shelton, J.L., Engle, M.A., Trembly, J.P., Doolan, C.A., Jubb, A.M., Chenault, J.M., Rowan, E.L., Haefner, R.J., and Mailot, B.E., 2020, Utica Shale Play Oil and Gas Brines: Geochemistry and Factors Influencing Wastewater Management: Environmental Science & Technology, https://dx.doi.org/10.1021/acs.est.0c02461. The Utica and Marcellus Shale Plays in the Appalachian Basin are the 4th and 1st largest natural gas producing plays in the United States. 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 solides = 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 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.

This data release contains Rock-Eval pyrolysis, organic petrographic (reflectance), and X-ray diffraction mineralogy data for subsurface Mesozoic rock samples from the eastern onshore Gulf Coast Basin (primarily Mississippi and Louisiana). Samples were analyzed in support of the U.S. Geological Survey (USGS) assessment of undiscovered petroleum resources in the Upper Cretaceous Tuscaloosa marine shale and evaluation of shale gas prospectivity in the Aptian section of the Mississippi Salt Basin.

This data release contains Rock-Eval pyrolysis, organic petrographic (reflectance), and X-ray diffraction mineralogy data for subsurface Mesozoic rock samples from the eastern onshore Gulf Coast Basin (primarily Mississippi and Louisiana). Samples were analyzed in support of the U.S. Geological Survey (USGS) assessment of undiscovered petroleum resources in the Upper Cretaceous Tuscaloosa marine shale and evaluation of shale gas prospectivity in the Aptian section of the Mississippi Salt Basin.

The U.S. Geological Survey assessed undiscovered petroleum resources in the downdip Paleogene formations of the U.S. Gulf Coast in 2018. During the assessment new data and information were collected to evaluate thermal maturity, source rock character, and unconventional reservoir rock prospectivity for the Cenozoic-aged section in south Louisiana. Samples were analyzed using multiple analytical approaches, including programmed pyrolysis (Rock-Eval), Leco TOC, organic petrographic analysis including vitrinite reflectance (Ro, %), and X-ray diffraction mineralogy.

The Assessment Unit is the fundamental unit used in the National Assessment Project for the assessment of undiscovered oil and gas resources. The Assessment Unit is defined within the context of the higher-level Total Petroleum System. The Assessment Unit is shown here as a geographic boundary interpreted, defined, and mapped by the geologist responsible for the province and incorporates a set of known or postulated oil and (or) gas accumulations sharing similar geologic, geographic, and temporal properties within the Total Petroleum System, such as source rock, timing, migration pathways, trapping mechanism, and hydrocarbon type. The Assessment Unit boundary is defined geologically as the limits of the geologic elements that define the Assessment Unit, such as limits of reservoir rock, geologic structures, source rock, and seal lithologies. The only exceptions to this are Assessment Units that border the Federal-State water boundary. In these cases, the Federal-State water boundary forms part of the Assessment Unit boundary.

This release contains isotopic composition (δ7Li, δ11B, δ138Ba) data of produced water and core samples taken from the Utica Shale and Point Pleasant Formation.