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

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.

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.

This data release contains the boundaries of assessment units and input data for the assessment of undiscovered gas hydrate resources on the north slope of Alaska. 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 herein 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. Methodology of assessments are documented in USGS Data Series 547 for continuous assessments (https://pubs.usgs.gov/ds/547) and USGS DDS69-D, Chapter 21 for conventional assessments (https://pubs.usgs.gov/dds/dds-069/dds-069-d/REPORTS/69_D_CH_21.pdf). See supplemental information for a detailed list of files included this data release.

This data release contains the boundaries of assessment units and input data for the assessment of undiscovered gas hydrate resources on the north slope of Alaska. 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 herein 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. Methodology of assessments are documented in USGS Data Series 547 for continuous assessments (https://pubs.usgs.gov/ds/547) and USGS DDS69-D, Chapter 21 for conventional assessments (https://pubs.usgs.gov/dds/dds-069/dds-069-d/REPORTS/69_D_CH_21.pdf). See supplemental information for a detailed list of files included this data release.

This data release includes whole rock geochemical data, and uranium-lead isotopic data collected by both Laser Ablation Inductively Coupled Plasma Mass Spectrometry (LA-ICP-MS) and Sensitive High Resolution Ion Microprobe-Reverse Geometry (SHRIMP-RG) methods. Whole rock geochemistry was collected by Activation Laboratories in Ancaster, Ontario. LA-ICP-MS data was collected at the PLASMA at the USGS in Denver, Colorado. SHRIMP-RG data was collected at the USGS-Stanford SHRIMP-RG in Palo Alto, California. Rock samples for all methods were collected by Mark Carter of the USGS. The whole rock geochemistry and uranium lead isotopic data constrain the age and origin of rocks in the newly defined Dinwiddie Terrane of eastern Virginia.

Inorganic compositions of flowback and co-produced waters from hydrocarbon extraction have been studied directly and through laboratory experiments that seek to replicate subsurface water-rock interaction. Here a broad analysis is made of compositions from the U.S. Geological Survey Produced Waters Database (v2.3) and leachates (water, hydrochloric acid, artificial brine) for 12 energy-resource related shales from across the United States. The database illustrates common ranges for 26 elements in 4 produced water types and enhanced solubility with increasing ionic strength is observed for Al, Ba, Fe, Li, Mn, Rb, Sr, and possibly 11 other elements. Differences are observed between laboratory leachates and produced waters. Reasons for those differences include: (1) ionic strength effects and low ionic strength of some leachates relative to subsurface brines, (2) pH-sensitivity of constituents and leachate offsets from produced water pH values, (3) oxidative conditions and enhanced pyrite oxidation in leachates compared to subsurface conditions, (4) kinetic controls on reaction rates and insufficient durations for leaching experiments, (5) leachate water-rock ratios that are commonly 3 or 4 orders of magnitude greater than in the subsurface. The findings provide important context for interpreting produced water compositions and efforts to simulate them in the laboratory.

Inorganic compositions of flowback and co-produced waters from hydrocarbon extraction have been studied directly and through laboratory experiments that seek to replicate subsurface water-rock interaction. Here a broad analysis is made of compositions from the U.S. Geological Survey Produced Waters Database (v2.3) and leachates (water, hydrochloric acid, artificial brine) for 12 energy-resource related shales from across the United States. The database illustrates common ranges for 26 elements in 4 produced water types and enhanced solubility with increasing ionic strength is observed for Al, Ba, Fe, Li, Mn, Rb, Sr, and possibly 11 other elements. Differences are observed between laboratory leachates and produced waters. Reasons for those differences include: (1) ionic strength effects and low ionic strength of some leachates relative to subsurface brines, (2) pH-sensitivity of constituents and leachate offsets from produced water pH values, (3) oxidative conditions and enhanced pyrite oxidation in leachates compared to subsurface conditions, (4) kinetic controls on reaction rates and insufficient durations for leaching experiments, (5) leachate water-rock ratios that are commonly 3 or 4 orders of magnitude greater than in the subsurface. The findings provide important context for interpreting produced water compositions and efforts to simulate them in the laboratory.

Sediment composition data to support the manuscript "Multivariate analysis of shale gas development on the chemical and biological health of headwater streams"