Abstract Sequence Stratigraphic Framework for the Upper Devonian Lower Huron Shale Member of the Ohio Shale, North-Central Appa

Home , Cleveland Shale, Foreknobs Formation, Java Formation, Ohio Shale, Olentangy Shale

ABSTRACT

SEQUENCE STRATIGRAPHIC FRAMEWORK FOR THE UPPER DEVONIAN LOWER HURON SHALE MEMBER OF THE OHIO SHALE, NORTH-CENTRAL APPALACHIAN BASIN

by Patrick James Cullen

Evaluation of the Upper Devonian (Famennian Stage) lower Huron Member in the north-central Appalachian Basin has revealed 4th-order cyclicity that can be correlated in subsurface geophysical well logs across Ohio, Kentucky, West Virginia, and western Pennsylvania. Correlations consist of 21 parasequence-set cycles bounded by sequence boundaries, identified by low gamma ray log values. Trends in lithofacies, color, and total organic carbon identified from a core support sequence stratigraphic interpretation from geophysical well logs. Sequence trends show that the lower Huron Member can be divided into three separate sequence sets corresponding to different stages of basin development throughout the Late Devonian. Sequence sets include an initial transgressive stage exhibiting increases in stratigraphically condensed intervals to an overall regressive stage with increased erosional truncation of older sequences. Further, geochemical analysis using total organic carbon, Rock-Eval pyrolysis, vitrinite reflectance, and gas chromatography data from the lower Huron Member show that hydrocarbon generation likely occurred in eastern Ohio, northeastern Kentucky, and western West Virginia. Study results increase the area of lower Huron Member hydrocarbon generative potential relative to previous studies. SEQUENCE STRATIGRAPHIC FRAMEWORK FOR THE UPPER DEVONIAN LOWER HURON SHALE MEMBER OF THE OHIO SHALE, NORTH-CENTRAL APPALACHIAN BASIN

A Thesis

Submitted to the

Faculty of Miami University

in partial fulfillment of

the requirements for the degree of

Master of Science

Patrick James Cullen

Miami University

Oxford, Ohio

2018

Advisor: Dr. Brian Currie

Reader: Dr. Michael Brudzinski

Reader: Dr. Mark Krekeler

This Thesis titled

SEQUENCE STRATIGRAPHIC FRAMEWORK FOR THE UPPER DEVONIAN LOWER HURON SHALE MEMBER OF THE OHIO SHALE, NORTH-CENTRAL APPALACHIAN BASIN

Patrick James Cullen

has been approved for publication by

The College of Arts and Science and Department of Geology and Environmental Earth Science

______

Dr. Brian Currie (Thesis Advisor)

______

Dr. Michael Brudzinski (Committee Member)

______

Dr. Mark Krekeler (Committee Member)

Table of Contents

List of Tables……...……………………………………………………………….……………v List of Figures..…………...………………….……………………………………….………..vi Acknowledgements..………………………...……………………………………….………..vii 1. Introduction……………………………………………………………………………………..1 1.1 Tectonic Setting………………………………………………………………………..2 1.2 Stratigraphy and Age………………………………………………………………..…4 1.3 Depositional Framework………………………………………………………………6 2. Previous Sequence Stratigraphic Interpretations………..…………..…………………………..8 3. Sequence Stratigraphy of the Lower Huron Member………………………………...………...10 3.1 Well Log Evaluation and Subsurface Mapping………………………………………10 3.2 Identification and Sequence Stratigraphic Interpretations of Depositional Cyclicity...12 3.3 Core Analysis………………………………………………………………………...12 4. Sedimentological Observations and Facies Division…………………………………………..14 4.1 Facies Assemblage A (FA-A)……………………………..………………………….16 4.2 Facies Assemblage B (FA-B)…………...……………………………………………18 4.3 Facies Assemblage C (FA-C)…………………………...…………………...……….20 4.4 Facies Assemblage D (FA-D)……………...………..………………………………..22 4.5 Facies Assemblages and Paleoenvironmental Interpretations………………………..24 5. Regional Well Log Correlations...……………………………………………………………..26 5.1 Sequence Set identification…………………………………………………………..27 5.2 Significance for Understanding Basin Architecture………………………………….32 6. Source Rock Characterization…………………………………………………………………34 6.1 Geochemical Database Compilation…………………………………………………35 6.2 Total Organic Carbon (TOC) Analysis………………………………………………35 6.3 Rock-Eval Pyrolysis Analysis………………………………………………………..36 6.4 Thermal Maturity Analysis…………………………………………………………...36 7. Hydrocarbon Potential of the Lower Huron Member………………………………………….38 7.1 Total Organic Carbon………………………………………………………………...38 7.2 Kerogen Analysis…………………………………………………………………….40 7.3 Thermal Maturity…………………………………………………………………….42 iii

7.4 Tmax and Thermal Maturity Patterns………………………………………………...45 7.5 Hydrocarbon Implications……………………………………………………………48 8. Conclusions………………………………………...………………………………………….54 9. References……………………………………………………………………………………..56 10. Appendix……………………………………………………………………………………..66

List of Tables

Table 1: Compiled Gas Analysis for Lower Huron Core……………………...……...…..………49 Table S1: Sequence Boundary and Lower Huron Member Top Data………………...…..………66 Table S2: Thin Section Depth for Shockling #1 Well………………………………...…..………67

List of Figures

Figure 1: Map of Study Area In the Central Appalachian Basin………………...…..………….…3 Figure 2: Generalized Stratigraphic Column………………………………………....……..……..5 Figure 3: Paleogeographic Map………………………………….…………….. …….....……...... 7 Figure 4: Sea-Level Curve Compared to Gamma Ray Log…………………….. …….....…….....9 Figure 5: Map Showing Distribution of Well Log Data………………………………..…..……..11 Figure 6: Correlation Technique Example……………………….………………………..……..13 Figure 7: Whole Core Diagram Showing Lithological Variation……………………….………..15 Figure 8: Facies Assemblage A (FA-A) Characterization……………………………...…...……17 Figure 9: Facies Assemblage B (FA-B) Characterization……………………………………...…19 Figure 10: Facies Assemblage C (FA-C) Characterization………………………………....……21 Figure 11: Facies Assemblage D (FA-D) Characterization………………………………....……23 Figure 12: Sequence Stratigraphic Annotated Core Diagram…………………………..…..……25 Figure 13: West to East Cross-Section Along Dip……………………………………..…….…..28 Figure 14: South to North Cross-Section Along Strike…...……………………………….……..29 Figure 15: Isochore Map of the Lower Huron Member…..………………………………………30 Figure 16: Subsea Structure Map of the Lower Huron Member………..……………..…………31 Figure 17: Isochore Mapping of Sequence Sets…………………..………………...... …….……33 Figure 18: Map Showing Distribution of Geochemical Data……………………………………..37 Figure 19: Average and Max Total Organic Carbon (TOC) Maps…………………………..…...39 Figure 20: Pseudo Van Krevelen Diagram and S2 vs. TOC Diagram……………………….…..41 Figure 21: Map of Average Vitrinite Reflectance (Ro)…………………………..……..………...44 Figure 22: HI vs. Tmax Diagram………………………..……………………………….…...…..46 Figure 23: Tmax Thermal Maturity Map…...……………………..………………….………..…47 Figure 24: Measured Ro vs. Calculated Ro………………………..…………………………..…51 Figure 25: δ13C and Gas Wetness Analysis………………………..…………………………..…52 Figure 26: Current Hydrocarbon Production..……………………..…………………………..…53

Acknowledgements

I would like to thank the Ohio Geological Survey and the Ohio Department of Natural Resources, specifically Jeffrey Deisher, Christopher Waid, Mike Angle, and Mohammad Fakhari, for supplying core, cutting samples, and well logs in Ohio. I would also like to thank John Curtis and Stephen Brown at GeoMark Research, Ltd for access to their extensive database and for analyzing the additional samples that were utilized in this study.

Funding was provided by the American Association of Petroleum Geologist Eastern Section Named Grant and the Miami University Petroleum Geology Research Fund. The use of GeoGraphix Discovery Suite software was made possible through a grant from LMKR, Ltd.

I would also like to acknowledge my advisor Brian Currie for agreeing to work with me and providing me with everything I needed to progress my understanding in the field of Geology. Thank you to my thesis committee Mike Brudzinski and Mark Krekeler, and my fellow graduate students at Miami University, specifically my lab group Shannon Fasola, Marysia Kozlowska, Sara Smith, Jared Wink, and Sutton Chiorini. Finally, thank you to my wife and family for supporting me when I left a job and paused our life to pursue a master’s degree.

vii

1. Introduction The Upper Devonian (Famennian) Huron Member of the Ohio Shale interval is an organic- rich, mudstone-dominated marine stratigraphic unit deposited in distal portions of the north-central Appalachian Basin. While knowledge pertaining to the regional stratigraphy of the Huron Member was developed during the late 1970’s-early 1980’s (e.g. Schwietering, 1979; Broadhead et al., 1982), detailed regional correlation of the unit with proximal shallow marine/non-marine stratigraphic equivalents in eastern parts of the basin has remained allusive due to limited lithological variability in the medial portions of the basin in eastern Ohio, and western West Virginia. In these areas, thick (>600 ft) siltstone/mudstone-dominated intervals display a monotonous geophysical log signature that is difficult to correlate with more cyclic signatures contained in more organic-rich mudstone deposits in Ohio and Kentucky, and sandstone-bearing intervals in eastern West Virginia, western Pennsylvania, and western New York (Filer 1994, 2002). Further, high rates of sediment influx in proximal facies masks the typical Huron Member black shale deposition (Woodrow et al., 1988) hampering correlatability. This lack of proven time- stratigraphic equivalency has hampered comprehensive studies on the overall stratigraphic evolution of the Huron Member and it regional stratigraphic equivalents in the north-central portion of the Appalachian Basin. In addition to the potential paleogeographic and tectonic implications more detailed stratigraphic resolution on this stratigraphic interval might provide, the Huron Member is also a proven hydrocarbon-producing unit in the Appalachian Basin with higher stratigraphic resolution potentially able to identify zones of high hydrocarbon generation. Hydrocarbon-resource assessments of Upper Devonian deposits in the northern and central portions of the Appalachian Basin contain recoverable reserves ranging from 6-16 TCF (trillion cubic feet) of natural gas and 65-211 MMB (million barrels) of natural gas liquids. (Milici et al. 2003; Milici and Swezey, 2014). However, while the Huron Member is a component of these assessed resources, these estimates contain both older and younger stratigraphic units. To date, no resource estimates have been calculated specifically for the Huron Member and its stratigraphic equivalents in the north-central portions of the Appalachian Basin. The purpose of this study is to create a sequence-stratigraphic framework for the Huron Member and its proximal stratigraphic equivalents in the north-central portion of the Appalachian Basin that can be used to provide regional stratigraphic constraints on the hydrocarbon potential of the unit. Because previous studies have noted that the oldest stratigraphic intervals of the unit

1 contain the lithologies with the highest organic content and the best potential as a hydrocarbon source rock (Boswell, 1996; Curtis, 2002), this study will focus on the lower Huron Member. The sequence stratigraphic component of the study will rely on interpretations derived from cyclicity observed in the gamma ray (GR) log signature of the lower Huron Member from oil and gas wells from the study area in Kentucky, Ohio, West Virginia, and Pennsylvania. Previous studies on Middle-Upper Devonian strata in the Appalachian Basin have linked the cyclic fluctuations between higher and lower GR log values to variations in relative sea level during the time of deposition and have demonstrated that these cycles can be correlated across the basin (Filer, 1994, 2002, 2003). Sequence stratigraphic interpretations derived from the well log analysis will be verified with lithological and sedimentological data derived from a core of the lower Huron Member from southeastern Ohio. This study will address hydrocarbon potential for the lower Huron Member, by evaluating the regional stratigraphic distribution of intervals of high organic content, kerogen type, and changes in thermal maturation in different parts of the basin. This will be accomplished by evaluating total-organic carbon (TOC), programmed Rock-Eval pyrolysis, and vitrinite reflectance (Ro) data compiled from previously published reports, as well as data generated as part of this investigation. Collectively, study results will produce the first integrated sequence-stratigraphic interpretation of the lower Huron Member in the north-central Appalachian Basin and provide greater insight into the viability of the unit as a hydrocarbon resource.

1.1 Tectonic Setting The study area is located in the north-central portion of the Appalachian basin (Figure 1) where ~1-5 km of Paleozoic sedimentary strata overlies Precambrian igneous and metamorphic rocks. Paleozoic deposition in the basin occurred in a composite peripheral foreland basin setting during a series of collisional tectonic events associated with the Taconic-Salinic (Ordovician- Silurian), Acadian (Mississippian-Devonian), and Alleghanian (Permian-Pennsylvanian) orogenies (Fiall, 1997; Fiall, 1997b; Fiall, 1998). Late Devonian deposition of the Huron Member occurred during the later stages of Acadian foreland basin development as a result of crustal loading associated with the dextral collision of the Carolina terrane along the continental margin to the east (Ettensohn, 1987; Ettensohn et al., 1988; Ettensohn & Lierman, 2012).

In eastern parts of the study area, foreland basin deposition was superposed above the preexisting structures of the Rome Trough, a Cambrian- aged rift basin formed during final stages of extension along the Laurentian margin (Ryder et al., 1992). Reactivation of Rome Trough fault structures (Shumaker & Wilson, 1996; Gao et al., 2000) and/or flexural partitioning of the foreland lithosphere in its vicinity (Filer, 2003) influenced the development of accommodation during the Late Devonian.

Figure 1. Study area (gray) map showing the geographic relationship between the source of sedimentation, the Rome Trough (a failed Cambrian rift basin), and the extent of the Devonian Shales within the Central Appalachian Basin. The Devonian Shale outcrop is approximately where the western extent of the Devonian Shales is (Roen, 1983).

1.2 Stratigraphy and Age The Upper Devonian (Famennian) Huron Member is the lowermost member of the Ohio Shale in Ohio and Kentucky. The Huron Member is bounded by Devonian-aged Frasnian stage Java/Olentangy formation at its base and the Famennian Chagrin Member of the Ohio Shale at its top (Figure 2). Provo (1976) divided the Huron Member further into three intervals the upper, middle, and lower Huron Shale in order to assess the Huron Member in the subsurface using the GR log signature from industry wells and outcrop data in northeastern Kentucky. This was accomplished by tying lithological types and uranium concentrations for individual intervals to the GR log signature. The depositional age of the lower Huron Member is constrained by conodonts sampled from previous studies for the interval across the study area. The base of the lower Huron Member lies just above the contact between the Frasnian/Famennian stage boundary that contains conodonts indicative of the Middle Palmatolepis triangularis Zone (Over, 2002). The identification of conodonts within the biostratigraphically constrained Protosalivina (Foerstia) Zone between the middle and upper Huron Member in Ohio (Broadhead et al., 1982; Over et al., 2009) and in Lincoln Co. West Virginia (Schwietering and Neal, 1978) suggests that the lower Huron Member is older than the Lower P. expansa zone. Importantly, conodonts sampled from carbonate concretions in the uppermost portions of the lower Huron Member in northern Ohio were identified as belonging to the Lower P. marginifera Zone (Gutschick and Wuellner, 1983) Collectively, these studies indicate the lower Huron Member ranges from the Middle P. triangularis Zone to the Lower P. marginifera Zone. In the Appalachian basin, this stratigraphic range is equivalent to the IIe transgressive-regressive cycle as defined by Johnson et al. (1985). Global calibration of these conodont zones with existing radiometric dates indicates deposition of the lower Huron Member occurred between ~372-366 Ma (Gradstein et al., 2012).

Figure 2. A generalized stratigraphic column showing common distal and proximal stratigraphy for the study area (Provo, 1976; Schwietering, 1979; Clausen and McGhee, 1988; Filer 2002; McClung et al., 2016; Beard et al., 2017). Current age constraints based on conodont biostratigraphy is provided for the stratigraphy (Klapper and Becker, 1999; Smith and Jacobi, 2001; Kaufmann, 2006; Over et al., 2009; Gradstein et al., 2012)

1.3 Depositional Framework An extensive body of previous work has established the overall depositional framework for Famennian-age strata in the north-central Appalachian Basin (Schwietering, 1979; Broadhead et al., 1982; Tassel, 1987; Boswell and Donaldson, 1988; Woodrow et al., 1988; Smith and Jacobi, 2001; Filer, 2002; Ettensohn and Lierman, 2012; McClung et al., 2013, 2016; Beard et al., 2017). Using the observed lithological variation in this study, depositional environments were determined for distal to proximal stratigraphy (Figure 3). The most distal stratigraphy, black shale facies, was deposited in an outer shelf environment where stratigraphic condensation readily occurred and sediment influx via sediment gravity flows was sparse. Transitional gray shale and siltstones were deposited in an inner shelf-delta slope environment where accommodation and sediment influx rates were in tandem and sediment gravity flows occurred regularly. The most proximal sandstones and siltstones were deposited in the prograding delta system and typically have a nonmarine origin and exhibit truncation throughout deposition. It should be noted that changes in sediment influx, accommodation, and eustatic sea level would have shifted the paleoenvironmental boundaries throughout deposition. Further, Rome Trough fault reactivation during this time could influence localized depositional environments (Shumaker and Wilson, 1996; Gao et al., 2000; Filer, 2003). Lithostratigraphic correlations for the lower Huron Member show that the distal black shale facies are temporally equivalent to the New Albany shale in western Kentucky and Indiana (Conkin, 1985) and portions of the Chattanooga Shale in southern Kentucky and Tennessee (Schwietering, 1979). The proximal equivalents are more difficult to distinguish due to the lithological variation observed transitioning from the stratigraphically condensed organic rich shales in distal outer shelf basin environments in the west to the prograding sandstones and siltstones in the inner shelf-delta slope and nonmarine proximal environments to the east. Clausen and McGhee (1988), Filer (2002), and McClung et al. (2013) used well log correlation, outcrop evaluation, and conodont biostratigraphy to interpret that the Frasnian-Famennian boundary (Over, 2002) as being roughly the contact between the Pound Member and the Red Lick Member of the Foreknobs Formation in West Virginia. The sequence stratigraphic interpretations of Smith and Jacobi (2001) correlated the base of the lower Huron Member with the base of the Dunkirk Formation of the Canadaway Group in western New York. In the same region, Over (2013) identified P. marginifera Zone conodonts in the Northeast Shale of the upper Canadaway Group providing a correlation tie to the upper parts of the lower Huron Member in northern Ohio.

Figure 3. A paleogeographic map over the study area showing depositional environments for the lower Huron Member and its temporal equivalents transitioning from proximal nonmarine facies in the east to distal outer shelf deposits in the west. Delta boundaries for the Catskill Fm. and Hampshire Fm. are based on Boswell and Donaldson’s (1988) paleoreconstruction.

2. Previous sequence stratigraphic interpretations The Upper Devonian stratigraphy of the Appalachian Basin has been studied since the late 1800’s. Hoover (1960) compiled a thorough compilation of studies pertaining to the Devonian- age stratigraphy up to the date of his publication, which includes an annotated bibliography for further study. Modern knowledge on the Upper Devonian stratigraphy of the basin is heavily influenced by the Eastern Gas Shales Project (EGSP) during the 1970’s and 1980’s. Initial lithostratigraphic studies provided the framework using cycles of interpreted transgression/regression preserved in marine deposits in the Appalachian Basin as a tool to aid in regional correlation, paleoenvironmental reconstruction, and to decipher the eustatic and tectonic controls on basin development. Relevant to the present study, Boswell and Donaldson (1988) linked interpreted progradational/retrogradational sequences observed in Upper Devonian strata in West Virginia, Pennsylvania, and Ohio with eustatic sea level changes corresponding to the Euramerican sea level curve of Johnson et al. (1985) that was formulated, in part, with data from the northern Appalachian basin (Figure 4). The application of sequence-stratigraphic models using concepts developed by Vail et al. (1977, 1991) and Van Wagoner et al. (1988) has been utilized to interpret variable scales of depositional cyclicity associated with fluctuations in basin accommodation development. Filer (1994), demonstrated the regional consistency of parasequence/parasequence sets (5th-4th order cycles) developed in Upper Devonian (Frasnian) organic/inorganic shales in the northern and central portions of the Appalachian Basin. Using primarily GR logs from oil and gas wells, Filer (1994) correlated these cycles in relatively distal, deeper water portions of the basin with more proximal silty/sandy shelf and shoreface facies to the east and interpreted them to reflect deepening/shallowing trends linked to eustatic fluctuations. Brett and Baird (1996) applied sequence stratigraphic principles to explain observed cyclicity in Middle Devonian stratigraphy across central New York and Pennsylvania. Using both sedimentological and paleontological evidence of fluctuating paleowater depths and depositional energies, Brett and Baird (1996) defined parasequences (5th -6th order cyclicity), parasequence sets/systems tracts (4th order cyclicity), and unconformity-/correlative conformity-bounded depositional sequences (3rd order cyclicity). In their framework, individual (3rd order) depositional sequences are initiated at unconformities formed in shallow marine deposits during a drop in relative sea level. Associated Low Stand Systems Tract deposits (LST) (or the unconformity surface itself) are overlain by strata

8 deposited during a subsequence sea-level increase, the Transgressive Systems Tract (TST). Brett and Baird (1996) defined deposits overlying a surface of maximum flooding (MFS) as highstand or regressive systems tract (HST/RST) deposits. Variations based on this general sequence stratigraphic model have been applied to Middle- Upper Devonian strata in the northern Appalachian Basin by Ver Straeten (2007), Lash and Engelder (2011), Brett et al. (2011), Ver Straeten et al. (2011), and Kohl et al. (2014), amongst others. Similarly, Smith and Jacobi (2001), Filer (2002, 2003), and McClung et al., (2013) utilized paraseqeunce-/sequence-scale cyclicity observed in outcrops and the GR log signature of subsurface intervals to construct regional correlations of Upper Devonian (Frasnian-Famennian) stratigraphy in the northern and central parts of the Appalachian Basin. Most previous sequence stratigraphic studies, however, have focused on strata older than the lower Huron Member, and none have extensively investigated the organic-rich interval that likely has the best potential as a hydrocarbon source for Famennian stage stratigraphy.

Figure 4. A modified diagram from Boswell and Donaldson (1988) showing a comparison of the Euramerican sea-level curve for the Famennian stage (Johnson et al., 1985) against the paleo- shoreline migration for the central Appalachian basin, a proximal sea level curve from southern New York (Smith and Jacobi, 2001), and a first-order comparison of a gamma ray curve from a distal basin setting in north-central Ohio (API: 3407323446). The gamma ray curve was stretched and compressed to obtain proper thickness for comparison with the paleo-shoreline, proximal sea level, and Euramerican sea level curves.

3. Sequence Stratigraphy of the Lower Huron Member Using the GR signature from well log and sedimentological evidence from core data, sequence stratigraphic interpretations as discussed by Brett and Baird (1996) are applied to the lower Huron Member. Initial analysis of cyclicity focused on determining parasequence set (4th order) to parasequence (5th to 6th order) cyclicity and interpreting general transgression/regression stages based on sequence boundary (SB) and MFS identification. This was done in order to correlate temporal horizons, moving past strict lithofacies correlations, and evaluate zones of high organic content and petroleum generating potential. Systems tracts are later applied to observed cyclicity based on sedimentological evidence from core data.

3.1 Well Log Evaluation and Subsurface Mapping Correlation of the lower Huron Member and its stratigraphic equivalents in the north- central Appalachian Basin was done using the GR signature from oil and gas industry geophysical well logs throughout the study area. Extending from the outcrop belt in Ohio and eastern Kentucky throughout West Virginia and western Pennsylvania (Figure 5). The 379 well logs used in this study were compiled from several sources (including the Ohio Geological Survey, Kentucky Geological Survey, and West Virginia Geological Survey). Raster well logs were digitized using Neuralog software. Digitization of the curves allowed for the scale to be standardized (0-400 API) for easier correlation and for log GR values and interval thicknesses to be digitally stretched and compressed to aid in correlation. Logs were normalized by taking the average GR values for the first 20 ft. of penetration into the stratigraphically lower Onondaga Limestone, and mechanically shifting GR values for higher stratigraphic depth intervals. If the Onondaga Limestone was not penetrated by the wellbore, an average for the Mississippian Greenbrier Limestone was used in the normalizations. High-resolution correlations were conducted by using the observed cyclicity between low and high GR values to interpret paraseqeunce through sequence-scale cyclicity (see below). Motifs were created based on observed trends and by stretching or compressing the digitized log for motif matches. All correlations and mapping were done using GeoGraphix Discovery software with post-processing using Adobe Illustrator.

Figure 5. Well log location map showing distribution of the 379 well logs utilized during this study (black circles). All gamma ray logs were normalized using the first 20 ft. of penetration into the Onondaga Limestone or Greenbrier Limestone.

3.2 Identification and Sequence Stratigraphic Interpretations of Depositional Cyclicity Correlations were done using the GR signature from well logs and creating cross-sections across the study area (Figure 6). Evaluation of increases and decreases in GR signature were performed looking for trends of high and low GR peaks, similar to the methodology of Filer (1994, 2002, 2003) in his evaluation of Frasnian stratigraphy in the Appalachian Basin. Identification of motifs based on patterns from the GR signature were then used to correlate temporal horizons for the lower Huron Member across the study area. Initial sequence stratigraphic interpretations were based on the correlation of GR to organic rich and organic poor lithologies and inferred depositional environment. High GR values are associated with dark organic rich black shale deposited in distal outer shelf environments while low GR values are associated with gray silt rich shale and siltstone deposited in inner shelf and delta slope environments. Using this knowledge, the correlation of a SB was defined by a GR low peak and a MFS was correlated with a GR high peak. Sequences defined by GR patterns were then compared to other workers interpretations for sequences from similar stratigraphy (Filer 1994; Brett and Baird, 1996; Smith and Jacobi, 2001; Filer 2002, 2003; Mcclung et al., 2013) for scale identification. Based on these studies and the thickness trends observed in this investigation, correlated cyclicity is of the parasequence set (4th order) and individual parasequence (5th to 6th order) scale.

3.3 Core Analysis In order to verify the sequence stratigraphic interpretations for the lower Huron Member produced in this study, the evaluation of the lithological and sedimentological characteristics of over 385 ft (3085 – 3470.5 ft) of unslabbed core from the Shockling #1 well (API: 3412122255) from Noble County, in southeastern Ohio was performed (Figure 7). The Shockling #1 core was chosen for its sampling completeness of the lower Huron Member, which extends from the contact with the underlying Java Formation to ~250 ft from the top of the unit. Additionally, the well is geographically situated in the medial part of the basin, and thus provides a valuable link in regional correlation of the lower Huron Member. Written core descriptions in this study are based on guidelines recommended by Lazar et al. (2015) for describing fine-grained sedimentary rocks. The unslabbed core was sprayed with water and described at a cm-scale with emphasis placed on documenting lithology, Munsell color

Figure 6. A cross-section of 3 wells along strike with adjusted cycle thickness and gamma ray signature for ease in correlation. Adjusted thickness and gamma ray allows for the recognition of patterns that would otherwise not be observable. Note that these wells are showing the correlatability across large distances in the basin, correlation and correlatability among well logs closer together has a higher confidence level. Unadjusted thicknesses for the sequences is provided for reference. Sequences have been correlated for 21 horizons (black lines); maximum flooding surface (MFS) for sequence 12 is shown by the red dashed line.

(Rock Color Chart, 1984), bedding characteristics, and sedimentary structures in the context of the GR log of the cored interval. A log shift of +6 feet was determined necessary to equate the vertical stratigraphic position of measured GR values with the recorded subsurface depth of lithologies documented in the core. Facies analysis and general characterization of mudstone sedimentology were assisted by analyzing 16 thin sections prepared for type sedimentological features in the lower Huron Member, indicated by a red asterisk on figure 7. Thin section preparation was accomplished by cutting a stratigraphically oriented billet from the core in a zone of interest, using a diamond tipped saw. Unpolished thin sections impregnated with clear epoxy were prepared for each billet using a standard 24x46 mm dimension and 30 µm thickness. Initial petrographic evaluation was accomplished using an Olympus BX51 polarizing microscope with 2x, 10x, and 40x objective magnification, 10x lens magnification, and a 530nm compensator. Imaging was done using a Nikon DS-Ri1 equipped on a Labarlus 12 polarizing microscope with 4x, 10x, and 40x objective magnification and 10x lens magnification. Scanning electron microscopy (SEM) was performed on 6 samples using a Zeiss SUPRA 35VP SEM. Samples were broken and cut from core samples to isolate the feature to be investigated. Both variable vacuum pressures (N2 compensating gas) and back-scatter techniques were used to image features of interest. Energy-dispersive x-ray spectroscopy (EDS) was used for mineral identification.

4. Facies Assemblages and Paleoenvironmental Interpretations Evaluation of the of the lower Huron Member in the Shockling #1 core resulted in the unit being divided into four lithofacies assemblages based on lithological and sedimentological characteristics. This was done to characterize sequence stratigraphic interpretations from this study, infer fluctuations in relative sea level (Williams et al., 2001), and to help identify areas of organic richness. Identification of Munsell colors (Rock Color Chart, 1984), clay/silt concentrations, siltstone bed prevalence and morphology, and bioturbation and pyrite concentration were all utilized in determining facies assemblages. Further, TOC was analyzed on 30 samples from the core to help identify changes in organic richness throughout the facies assemblages.

Figure 7. Shockling #1 cored interval (3085 – 3470.5 ft.) in the lower Huron Member. Colors are based on the Rock Color Chart (1984); white intervals denote missing section. The siltstone beds represent an influx of detrital material via sediment gravity flow. The gamma ray (GR) was plotted with a +6 ft. log shift. The 12 sequences represent parasequence sets (4th order). Sequence boundaries (SB) are defined by GR lows that are interpreted to represent low sea level. Internally, sequences contain maximum flooding surfaces (MFS) that separate transgressive and regressive deposits. Observed facies assemblages (FA-A, FA-B, FA-C, and FA-D) described in the text are assigned based on lithological and sedimentological characteristics. Red asterisks denote positions of evaluated thin sections. Core samples that have total organic carbon are plotted with purple squares.

4.1 Facies Assemblage A (FA-A) Facies Assemblage A (FA-A) consists of organic rich black and dark gray mudstone (5YR 1/0 and 5YR 2/0) and occasional intercalated discontinuous/continuous silt laminae and lenses (Figure 8). Overall silt concentration is <10%. Scour surfaces are observed at both the base of silt lamina and in mud-dominated intervals, the latter of which are recognized by truncated bioturbated horizons or different colored lamina, and concentrations of silt-sized detrital pyrite. Bioturbation in the form of Chondrites burrows is rare to moderate in abundance. Diffuse and strataform pyrite framboids are commonly observed throughout organic-rich mudstones of FA-A. Abundant Tasmanites are observed in thin section and SEM, and carbonized fish scales have been observed in core samples. FA-A deposits are typically observed with high overall GR signature from well log, when compared to the other three facies assemblages, and is typically the highest values for a sequence (Figure 7). Upper and lower contacts for FA-A is associated with Facies Assemblage B and C (see below) and marked by an increase in GR at its base and a decrease in GR at is top. Measured total organic carbon (TOC) values for the Shockling #1 core range from >1 wt. % to 2.15 wt. % from samples collected as part of this investigation. The relatively high organic content and low percentage of silt observed in FA-A lithologies suggests overall low depositional energies and rates of clastic input during the time of deposition (Hosterman and Whitlow, 1980.). The clay-dominated character of the facies suggests suspension- settling of clay-sized particles was the primary means of sediment deposition. Sparse to moderate bioturbation indicates dysoxic to anoxic bottom water conditions, potentially driven by high amounts of organic material being deposited at any given time depleting the oxygen supply (Curtis and Faure, 1997). Scour surfaces and intercalated silt lamina, however suggest periodic sediment transport and deposition by bottom-flowing currents. Stray silt lenses and continuous silt laminae suggest deposition by turbidity/hyperpicnal flows or distal, storm surge-generated currents (Lowe, 1982; Mulder et al., 2003; Potter et al., 2005; Wilson and Schieber, 2014; Schieber, 2015). Collectively, FA-A lithologies are interpreted as being deposited in a distal outer-shelf environment (cf. Wilson and Schieber., 2015). Compared to other lithofacies assemblages observed in the lower Huron Member, its relatively high organic content, low overall concentration of silt-sized grains and silt laminae, and the scarcity of discreet siltstone beds suggests deposition during periods of high relative sea level.

Figure 8. Lithological and organic characterization of Facies Assemblage A. (A) Core sample showing typical black mudstone with planar-contionous silt laminae. (B) Crossed nicols (XN) photomicrograph of typical black mudstone fabric for FA-A. (C) XN photomicrograph of silt laminae showing (1) phytodetritus, (2) silt lamaniae, and (3) organic rich mudstone. (D) Plane light photomicrograph showing (1) crushed Tasmanites cysts and (2) calcite recrystallization. (E) Variable pressure SEM images showing crushed Tasmanites cyst. (F) SEM top view of a crushed Tasmanites cyst with pyrite replacement and organic porosity.

4.2 Facies Assemblage B (FA-B) Facies Assemblage B (FA-B) is composed of mostly organic-rich black and gray mudstone with intercalated discontinuous/continuous silt laminae and lenses, and discreet, cm-thick laminated siltstone beds (Figure 9). Visual estimates of mudstone silt concentrations from thin sections is <15%. Both silt laminae and siltstone beds include basal scour surfaces that commonly display reworked pyrite framboids and spheres. Siltstone beds will typically have developed planar to wavy continuous to discontinuous laminae with interlaminations of phytodetritus (c.f. Gooday and Turley, 1990; Macquaker et al., 2010). Both mudstone and siltstones have sparse to abundant horizontal burrows (i.e. Chondrites or Planolites). Abundant Tasmanites are commonly observed in thin sections of FA-B mudstones with measured TOC values from the Shockling #1 core of 0.5- 1.81 wt. %, with high 7.03 wt. % value near the base of the core (Figure 7). GR signature typically exhibits relatively higher values when compared to transitional/proximal gray mudstone facies assemblages (see below) but are lower than FA-A deposits. FA-B is typically bounded by Facies Assemblage C (FA-C; see below) or FA-A deposits (Figure 7). The presence of organic mudstone (TOC 0.5-1.81 wt. %) and relatively low silt concentration (<15%) indicates that FA-B was deposited during relatively high sea level that was likely dysoxic to anoxic during most of its deposition. Abundant scour surfaces and the presence of cm-thick siltstone beds indicate that higher energy events, such as turbidity or hyperpycnal flows (Wilson and Schieber, 2014; Schieber, 2016), were able to provide silt sized sediment influx during this time. The abundance of scour surfaces and siltstone beds along with higher overall silt concentration when compared to FA-A supports lower relative sea level and closer proximity to source than FA-A. The stacking pattern of FA-B with the relatively lower sea level deposits associated with the Facies Assemblage C (see below) indicates that sea level was highly variable throughout this time and that FA-B was associated with the periods of higher sea level when compared to Facies Assemblage C (see below). Given these characteristics, lithologies associated with FA-B are interpreted as being deposited in the proximal outer shelf and distal inner shelf environments.

Figure 9. Lithological characterization of Facies Assemblage B. (A) Photo of thin section showing (1) planar continuous silt laminae with clay rich interlaminae, (2) massive silt bed, (3) basal scour surface, and (4) typical organic rich facies observed in FA-B deposition. (B) Crossed nicols (XN) micrograph showing basal scour surface with transition from organic rich mudstone to silt. Planolites burrow and abundant pyrite located at scour surface contact. (C) Core sample showing typical lithologies and sedimentological structures observed in FA-B deposition.

4.3 Facies Assemblage C (FA-C) Facies Assemblage C (FA-C) is primarily comprised of dark gray/green (5Y 4/1) mudstone that is interbedded with abundant laminated/cross laminated siltstone beds and occasional beds of organic rich black mudstone. Darker, more organic rich mudstones contain pyrite framboids/spheres. Both gray/green and black mudstones display intercalated discontinuous/continuous silt laminae and lenses (Figure 10). The concentration of silt in FA-C mudstones from visual estimates is <25%. Individual silt laminations in both FA-C mudstones and discreet siltstone beds display scoured bases and commonly have higher concentrations of detrital pyrite. All lithologies in the FA-C facies display abundant bioturbation dominated by Chondrites and Planolites burrows. TOC values are typically <0.5 wt. % with anomalous samples showing >1 wt. % from the Shockling #1 core. GR signature typically exhibits relatively lower readings when compared to FA-A or FA-B, but higher values when compared to Facies Assemblage D (see below). Carbonate concretions (up to 15 cm diameter) displaying evidence for differential compaction of overlying/underlying mudstone (cf. Criss et al., 1988) were also observed in FA-C deposits. Deposits of the FA-C facies are typically bounded below by FA-D facies and above by FA-B and FA-A deposits (Figure 7). The prevalence of gray/green, organic-poor (<0.5 wt. %) mudstone and abundant bioturbation in FA-C lithologies suggests oxic bottom water conditions during the time of deposition. However, the presence of occasional organic rich beds with abundant pyrite indicates that intermittent periods of dysoxic to anoxic conditions also existed. Abundant sediment gravity flow deposits, observed with scour surfaces and silt bed morphology, and higher overall silt concentration (<25%) indicate shallower water conditions and closer proximity to the source of sediment than both FA-A and FA-B deposits. FA-C deposition is interpreted to have been deposited in the distal inner shelf/delta slope during an overall relative low sea level with periods of higher sea level indicated by organic rich bed deposition.

Figure 10. Lithological and organic characterization of Facies Assemblage C. (A) Core sample showing typical gray shale and silt bed deposition. (B) Photo of thin section showing internal sedimentary features. (1) Clay rich drap, (2) planar continuous alternating clay and silt rich laminae, (3) truncation of (4) Climbing ripples, and (5) phytodetritus interlamaine. (C) Crossed nicols (XM) micrograph showing silt rich laminae with (5) clay rich interlaminae. (D) (1) Pyrite spheres from replacement of precompacted Tasmanites cyst with pyrite (2)? Dolomite recrystallization. (E) Variable pressure SEM image of pyrite spheres.

4.4 Facies Assemblage D (FA-D) Facies Assemblage D (FA-D) is comprised of light gray (5YR 7/0) mudstone, abundant scour surfaces, moderate silt bed prevalence, and moderate continuous silt laminae (Figure 11). Overall silt concentration from visual estimates is 50-60%. Agglutinated foraminifera are commonly observed in thin section with abundant bioturbation and pyrite observed throughout. TOC values are typically <0.3 wt. % with higher anomalous values from the Shockling #1 core. GR signature is observed to have the lowest overall value for any give sequence (Figure 7). FA-D deposits are bounded by FA-C and FA-B at its top and base. The overall organic poor nature (<0.3 wt. %) of FA-D and the high overall concentration of silt (50-60%) in FA-D lithologies indicate that sea level was relatively low during deposition when compared to the other three facies. Oxygenated bottom waters during deposition are inferred from the presence of benthic foraminifera (Pike and Kemp, 1996; Schieber, 2009), abundant bioturbation, and overall low TOC. Lack of discreet silt beds is likely due to the extensive bioturbation observed in facies mudstones. Because of the high silt concentration and interpreted oxic bottom water conditions, deposition of FA-D lithologies is interpreted as occurring in distal- medial inner shelf environments during periods of low relative sea level.

Figure 11. Lithological and organic characterization of the Facies Assemblage D. (A) Photo of thin section showing typical FA-D facies mudstone. (B) Crossed nicols (XN) micrograph of typical gray mudstone FA-D fabric. (C and D) XN micrograph showing typical gray mudstone FA-D fabric with a distinct (C) pyrite framboid.

4.5 Facies Assemblages and Sequence Stratigraphy The four facies assemblages identified in the Shockling #1 core provide support for the sequence stratigraphic model developed for then lower Huron Member using the GR-log signature of industry wells (Figure 12). Interpreted SBs correspond to low GR peaks observed in medial and distal parts of the basin. These GR lows are represented by FA-D, FA-C, and FA-B facies representing deposition in medial inner shelf, distal inner shelf, and proximal outer shelf environments, respectively. These facies correlate with similarly low GR and low TOC values observed at the top of upward-coarsening mudstone, siltstone, and sandstone assemblages deposited in more proximal inner shelf/shoreface and nonmarine environments to the east (Boswell and Donaldson, 1988; Filer, 1994 & 2002). Within the context of the model, the lower portions of these intervals represent a lowstand systems tract (LST) that developed during maximum regression of basin depositional systems during periods of low relative sea level. Increasing GR values of FA-D, FA-C, FA-B, and FA-A facies overlying LST deposits are interpreted as the deposits of a Transgressive Systems Tract (TST) deposited as outer shelf and inner shelf environments shifted to the east during increases in relative sea level in the basin. Deposits of the TST in medial and distal portions of the basin can be correlated with overall upward-fining shelf mudstone, siltstone, and sandstone assemblages to the east (Boswell and Donaldson, 1988; Filer, 1994 & 2002). The fluctuating GR values that accompany vertical stacking of these facies are interpreted as representing periods of shallowing/deepening caused by parasequence-scale fluctuations in sea level during the time of deposition. The maximum flooding surface (MFS) is represented by primarily FA-A or FA-B facies deposits that display the highest GR and TOC values in most sequences. The MFS marks the boundary between the TST and highstand systems tract (HST). Deposits of the HST are represented by an upsection transition from FA-A deposits to overlying FA-B, FA-C, and FA-D facies that display corresponding decreases in GR values. Vertical fluctuations in facies stacking patterns and corresponding GR trends likely represent parasequence-scale increase/decreases in relative sea level during deposition. HST intervals in the distal/medial portions of the basin correlate with upward-coarsening mudstone, siltstone, and sandstone assemblages to the east (Boswell and Donaldson, 1988; Filer, 1994 & 2002). and represent an overall westward shift in outer/inner shelf depositional systems related to an overall progradation of deltaic/nonmarine systems into the basin.

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25 5. Regional Well Log Correlations Utilizing the sequence stratigraphic model developed in well log and core data, 4th-order sequences were correlated on a regional basis for the central Appalachian basin. Figure 13 shows a west to east dip cross-section of 4 wells with 21 4th order sequences transitioning from distal to proximal localities in the basin. In the cross section, the overall thickness of the lower Huron Member increases from ~200 ft in central Ohio to >1400 ft in northern West Virginia, before thinning slightly to ~1300 ft in eastern West Virginia (Figure 13). Individual sequences in the distal parts of the basin (e.g. Well 1, Vinton Co., Ohio) are <20 ft thick, while correlative intervals in the proximal parts of the basin, (e.g. Well 3, Doddridge Co., West Virginia) have an average thickness of ~60 ft (Figure 13). Truncation and/or stratigraphic condensation of the sequences in both the lower and upper parts of the lower Huron Member can be observed in the distal-medial parts of the basin in Ohio between well 1 and well 2 (Noble Co., Ohio) (Figure 13). Figure 14 shows a south to north cross-section of 5 wells along the depositional strike of the basin showing the same 4th order sequences as in Figure 13. Thicknesses remain relatively consistent for all three sequence sets throughout Ohio and into central West Virginia with slight thinning of the unit in southwestern West Virginia (Figure 14). Regional thickness trends of the lower Huron Member generally thicken towards the more proximal parts of the basin to the east (Figure 15). The lower Huron Member and its stratigraphic correlatives thicken from <100 ft along the outcrop belt in central Ohio to >1700 ft in northern West Virginia and southwestern Pennsylvania. This general eastward thickening of Upper Devonian strata across Ohio and western West Virginia has been interpreted as being generated by lithospheric flexure in response to tectonic and sediment loads in the foredeep of the Acadian foreland basin (Beaumont, 1981; Tankard, 1986a & 1986b) Further east in eastern West Virginia, however, proximal strata equivalent to the lower Huron Member thin to <1400 ft (Figure 13 and Figure 15). This thinning may have been influenced by syndepositional faulting within the Acadian foredeep along the Rome Trough east-margin fault (Shumaker and Wilson, 1996; Gao et al., 2000). Conversely, Filer (2003) argued that depositional thinning of Frasnian-Famennian age strata in the eastern part of the study area was associated with flexural partitioning west of an peripheral bulge and foredeep that formed to east between the Rome Trough and the Acadian orogen. Additional numerical simulations of Late Devonian lithospheric flexure in the Appalachian Basin to are likely required to resolve these contrasting interpretations.

26 Structure mapping on the top of the lower Huron Member shows a general trend of increasing depth moving to the southeast from the surface in central Ohio to <-2500 ft MSL in West Virginia (Figure 16), before shallowing in eastern West Virginia. While observed structural trends generally correspond to thickness variations in the lower Huron interval (Figure 15), interpretations of the present-day structures in eastern parts of the study area show evidence for post-depositional uplift. Specifically, the area of structural shallowing of the Lower Huron interval corresponds with both compressional/transpressional reactivation of basement-involved faults near the eastern boundary of the Rome Trough and thrust-related shortening in the frontal Alleghianian fold and thrust belt (Shumaker and Wilson, 1996; Faill, 1998; Gao et al., 2000; Ryder et al., 2009).

5.1 Sequence Set Identification The 21 sequences of the lower Huron Member can be subdivided into three distinct sequence sets based on stratigraphic variation and overall sequence geometry. This was accomplished by evaluating the overall range of GR values and regional thickness variations in each sequence. For example, in Figure 14, well 5 in southern West Virginia displays a series of thin, high GR-value sequences at its base that are overlain by a series of thicker overall lower GR- value sequences in the middle part of the lower Huron Member. In turn, this middle interval is capped by another set of thin sequences with slightly higher GR values. This pattern can be observed in the other wells to the north in the along-strike cross section of the basin (Figure 14). The same GR/thickness trends can be observed along proximal-distal cross sections through the basin cross-strike cross sections of the basin (Figure 13). In this case, however, the upper sequences are markedly coarser in the proximal locations in the east (i.e. well 4, Preston Co., WV) compared to those in the west (Figure 13). Based on these criteria, identified sequences were grouped into related sequence sets for all wells in the study area (Figure 5). Stratigraphically, sequence set A includes the portions of the lower Huron Member from the top of the Java/Olentangy formations to the top of Sequence 8, sequence set B includes sequences 9 to 13, and sequence set C is from the base of Sequence 14 to the top of the lower Huron Member.

Figure 13. Dip cross-section from East to West showing transition from distal to proximal stratigraphy. Stratigraphically hung on sequence boundary 11. Sequence correlations consist of 21 sequences and 3 sequence sets, set A is from Java/lower Huron Member contact to SB 9, set B is from SB 9 to 14, and set C is from SB 14 to the lower Huron Member top.

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Figure 15. Isochore map on the lower Huron Member showing thickening towards the east and thinning towards the west. The contour interval is 100 feet and ranges from <200 ft. to >1700 ft. Data points used in mapping are represented by black circles.

Figure 16. Subsea structure map on the top of the lower Huron Member showing a general increase in depth towards the southeast. The contour interval is 200 feet and ranges in depth from >400 ft. to <-3200 ft. Data points used in mapping are represented by black circles.

31 5.2 Significance for Understanding Basin Architecture Utilizing the three sequence sets defined during this study, spatial and temporal variations in stratigraphic condensation, erosional truncation and both high and low GR value sequences can be interpreted. In proximal-distal cross sections of the basin, condensed intervals likely produced by relatively low rates of detrital influx can be observed (Figure 13). High organic content associated with stratigraphic condensation is represented by an increase in GR amplitude in distal well logs. Increases in sediment influx are represented by a reduction in GR amplitude observed in proximal well logs. All sequence sets exhibit stratigraphic condensation in distal localities, however, sequence set A is heavily influenced by stratigraphic condensation at closer proximity to the sediment source than sequence set B or C. Sequence A is the lowest stratigraphically in the lower Huron Member and exhibits the highest average GR signature. Further, A correlates with a large transgression marked by the IIe T-R cycle from Johnson et al. (1985) that is likely influenced by rapid tectonically driven subsidence (Ettensohn and Lierman, 2012). Sequence set A marks the period of highest relative sea level in the lower Huron Member and allowed for high organic content preservation and sediment starvation in transitional (inner shelf-slope delta) and distal locations (outer shelf). Sequence set B has a relatively uniform thickness in the medial and proximal localities when compared to set C or A (Figure 13). Possible explanations for this could be that the rate of accommodation and rate of deposition remained constant during this time allowing for sequences to become comparably thick with little if any truncation occurring. In distal locations stratigraphic thinning of individual sequences likely reflects stratigraphic condensation associated with lower rates of detrital sedimentation. Sequence set C represents an interval of greater progradation of inner shelf environments than the underlying sets. Truncation of sequences in C are visible moving proximal to distal with stratigraphic condensation in the most distal locations occurring as well. Sequence set C is interpreted as being deposited during relatively low rates of accommodation development which resulted in progradation of more proximal environments to the west and the condensation/truncation of individual sequences of set C in the west. Thickness mapping of the three sequence sets reveals a general west-directed migration of lower Huron Member depocenters through time (Figure 17). Out of the three sequence sets the depocenter for sequence set A (the oldest), is the furthest to the east. Sequence set A deposition

32 was followed by west-directed migration of the depocenter to the west during both sequence set B deposition and subsequent deposition of sequence set C (Figure 17). General thickness for sets remain consistent with a range from <100 ft in the west and >600 ft to the east. The migration of the depocenter is likely influenced by syndepositional faulting associated with the Rome Trough and overall westward progradation of basin depositional systems, thorough time.

Figure 17. Isochore mapping on sequence sets as determined by well log correlations. Contour interval is 100 feet for all Isochore mapping with black circles representing well log data points used for contouring. Isochore map for sequence set A is from the Java/lower Huron Member contact to SB 9, sequence set B is from SB 9 to 14, and sequence set C is from SB 14 to the top of the lower Huron Member.

33 Based on an overall evaluation of the sequence set log/core facies and stratigraphic arechitecture, it can be determined that stratigraphically lowest sequence set A has the highest overall GR and is characterized by stratigraphic condensation. Because GR has been observed to correspond to higher TOC, as observed in figure 7 and 12, and stratigraphic condensation is known to have high TOC this would indicate that sequence set A should be more organic rich than the sequence sets B and C. With the overall coarsening upward observed in the GR signature of sequences in sets A through C it can be inferred that organic richness should decrease throughout lower Huron Member deposition. This would indicate that, overall sequence set C should be more prone to hydrocarbon generation based on organic richness. However, the high GR values and likely high TOC associated with interpreted TST/early HST intervals of individual sequences throughout the lower Huron Member may also serve as effective hydrocarbon source rocks.

6. Source Rock Characterization Source rock characterization is an import aspect of hydrocarbon exploration. The type and amount of organic material present as well as the thermal maturity of a formation are key factors for hydrocarbon generation. As such, the potential of a formation to serve as a hydrocarbon source rock for conventional oil and gas reservoirs or as an “unconventional” resource (one that serves as both a source and reservoir), is dependent on these variables. TOC is a is a basic measure of source- rock potential and a key property used to assess the hydrocarbon potential a formation. However, the type of organic material present has a large influence on the potential and type of hydrocarbon being expelled during catagenesis (Tissot & Welte, 1978; Van Krevelen 1993; Rohrback & Kaplan, 1978; Dembicki, 2009). Further, minimum burial temperatures (~50°-60° C) are required for catagenesis to occur and hydrocarbons to be generated in significant amounts (Dow, 1977). Temperatures in excess of 200°C, however, may result in the thermal degradation of previously generated resources. For this reason, vitrinite reflectance (Ro) and Rock-Eval pyrolysis data is used in this study to evaluate thermal maturity and the potential for hydrocarbon generation. Using a database compiled from several sources (Repetski et al., 2008; GeoMark Research, Ltd; Ohio Department of Natural Resources; Hackley et al., 2013; Parris et al., 2016), along with new data generated for this study, this investigation characterizes the amount and type of organic material present in the lower Huron Member and compares the distribution of thermal maturation

34 indices generated in this study’s analysis with those of previous studies (Repteski et al., 2008; Ryder et al., 2013; Riley, 2016).

6.1 Geochemical Database Compilation We have compiled a database specifically for the lower Huron Member consisting of 1023 samples for 137 wells and 3 outcrops (Figure 18). The dataset includes data from Repetski et al. (2008) (n=66), large datasets from GeoMark Research, Ltd (n=235), the Ohio Department of Natural Resources (n=353), and a series of studies during the Eastern Gas Shales Project (n=228), with supplemental data from Hackley et al. (2013) (n=2) and Parris et al. (2016) (n=45). Further, additional Leco TOC and Rock-Eval pyrolysis II analyses were conducted for this study on 64 cuttings samples from 16 wells for the lower Huron Member in Ohio, and 30 samples from the Shockling #1 core by GeoMark Research, Ltd. Other data used for mapping include average TOC values for 12 locations and average Ro values for 13 locations based on mapping done by Curtis and Faure (1997). Duplicate database analyses were identified and removed. Samples not designated by the original source as sampled from the lower Huron Member were confirmed as such by checking sample depths with available geophysical logs. For wells where logs were unavailable, sample depths were compared with top/base picks for the unit using nearest neighbor wells and structure contour maps generated as part of this study.

6.2 Total Organic Carbon (TOC) Analysis Organic material in the lower Huron Member was characterized by evaluating Leco TOC data (wt. %) derived from database analyses and additional samples collected as part of this study. TOC data compiled from GeoMark Research, Ltd, Parris et al. (2016), and Hackley et al. (2013) were stated as being derived from Leco TOC analysis, the Ohio Department of Natural Resources, Eastern Gas Shales Project, and Repetski et al. (2008) datasets do not state how they were derived, however, it is assumed to be derived from Leco TOC analysis. From the 1023 samples in the database, 997 samples with TOC analyses were identified for the lower Huron Member. Further, average TOC values for 12 locations were determined from Curtis and Faure (1997). Mapping of average and maximum TOC for each well was conducted using a 2 wt. % contour interval.

35 6.3 Rock-Eval Pyrolysis Analysis Rock-Eval pyrolysis is the process of heating a sample under an inert atmosphere (helium) and measuring the release of hydrocarbons and CO2 through time (Espitalié et al. 1977; Peters, 1986; Bordenave, 1993). During pyrolysis of the sample three peaks are measured, using a Flame Ionization Detector for hydrocarbon effluent and an Infrared or Thermal Conductivity Sensor for

CO2. Peak S1 (mg HC/g rock) is the first peak and represents the release of free hydrocarbons in a sample at a temperature below 300°C, S2 (mg HC/g rock) is a record of the hydrocarbons produced from thermal cracking of the kerogen in the sample between 300 and 600°C, and S3 (mg

CO2/g rock) is a measure of CO2 in the sample released between 300 and 390°C during pyrolysis. The temperature (°C) at which the S2 peak’s amplitude is the greatest is called the Tmax and in some instances can be used to infer thermal maturity. Data for Rock-Eval pyrolysis analysis was filtered in the dataset using a cutoff of >1 wt. % TOC and >2 mg HC/g rock S2. These cutoffs were utilized to ensure data being collected is representative of the sample and not adsorption of the hydrocarbons onto clay minerals during pyrolysis (Peters, 1986; Langford & Blanc-Valleron, 1990). Of the 1023 samples in the compiled database, 364 met this criterion and were utilized in the present study. The hydrogen index (HI) and oxygen index (OI) for samples were calculated as described by Espitalié et al. (1977), where HI = (S1/TOC)*100 and OI = (S3/TOC)*100. HI vs. OI for the lower Huron Member was then plotted on a pseudo Van Krevelen diagram (Espitalié et al., 1977) to assess kerogen type. S2 vs. TOC was also plotted to evaluate kerogen type and assess the correlation between the sample group (Langford & Blanc-Valleron, 1990). In the S2 vs. TOC plot, the kerogen type I to II transition is defined at HI = 700 while type II to III transition is defined at HI = 200

6.4 Thermal Maturity Analysis Tmax from Rock-Eval pyrolysis is plotted against HI (Bordenave, 1993; Banerjee, 1998) to evaluate thermal maturity in conjunction with kerogen type. Thermal maturity cutoffs were determined by rearranging the equation Ro(calc.) = 0.0180*Tmax-7.16 (Jarvie et al., 2001) to solve for Tmax and calculating Tmax equivalents for 0.6% Ro (Tmax = 431°C) for the immature to peak transition and 0.9% Ro (Tmax = 448°C) for the peak to late transition. These calculated cutoffs are slightly different than Peters and Cassa’s (1994) cutoffs for hydrocarbon generation, where peak oil generation is between 0.65% and 0.9% Ro and 445°C and 450°C Tmax.

36 Measured vitrinite reflectance (Ro) from an oil immersed sample using a reflecting microscope as discussed by Dow (1977) was also used to evaluate thermal maturity in the lower Huron Member. Of the 1023 samples compiled in this study’s geochemical database only 206 measured Ro samples from 77 wells and 3 samples from outcrop were available. Further, average Ro values for 13 locations were determined from Curtis and Faure (1997). Ro values were averaged per well and mapped to show thermal maturity patterns and evaluate differences with Tmax values, based on the oil generation window occurring at 0.6% Ro (Dow, 1977). Further, several Ro contours from previous studies (Repetski et al., 2008; Ryder et al., 2013; Repetski et al., 2014; Milici and Swezey, 2014; Riley, 2016) are included for comparison with this study’s interpretations. Tmax data was also averaged per well and mapped to delineate thermal maturity patterns and compare with measured Ro values.

Figure 18. Index map showing geographic distribution of wells with samples in the lower Huron Member. The source of geochemical data is represented by a corresponding symbol. Some well locations had multiple sources, the most prominent source is represented. Phase I and II geochemical analysis represented by a blue and red cross are original data to this study, ran by GeoMark Research, LTD. Wells utilized for gas analysis below are labelled for identification.

37 7. Hydrocarbon Potential of the Lower Huron Member

7.1 Total Organic Carbon Lower Huron Member TOC values range from >10 wt. % along the outcrop belt in central Ohio and northeastern Kentucky to <2 wt. % at the West Virginia state line (Figure 19). The average TOC map (Figure 19a) shows a trend of lower values when compared to the max TOC map (Figure 19b). This is expected with the max TOC values representing the best-case scenario and average TOC values representing multiple horizons in the interval. Analysis of individual horizons in the unit may be able to identify high TOC intervals that have the potential to produce more hydrocarbons. The TOC maps populated by this study for the lower Huron Member are in general agreement with those produced by Riley (2016) for the entire Devonian black shale interval in Ohio, including the Cleveland Shale, Olentangy Shale (Java/Angola equivalent), Rhinestreet Shale, and the Marcellus Shale. Localized areas of high TOC can be observed throughout the study area. This may be attributed to localized increases in organic production (e.g. algal blooms) during the time of deposition (Curtis and Faure, 1997), or an artifact of selective or incomplete sampling. When attempting to evaluate TOC for the individual sequence sets, 74 samples from only 27 wells in the database were positively identified as being derived from a specific depositional sequence. Well logs for the other 111 wells with geochemical data were not available in the state log databases used in this study. Structure and formation top projection was not utilized for determining sequence set association due to the possibility of misidentification. Using TOC data from wells with available logs, there is no appreciable difference in TOC between the sequence sets as averages across all three ranged between 3 wt. % and 4 wt. %. This was surprising given that Sequence set A was noted has having a higher average GR signature and therefore likely higher TOC values than the other two sequence sets (Hosterman and Whitlow (1980); data presented above). This unexpected relationship may due to the small number of samples in this subset of data (8 samples from sequence set A, 21 samples from sequence set B, and 45 samples from sequence set C), or from selective sampling of thinner/less frequent but likely high TOC samples (e.g. black mudstone) from younger sequence sets. In the future, obtaining logs from all wells with TOC analysis and applying the sequence stratigraphic framework outlined in the present study may permit recognition of TOC variations between individual sequence sets.

Figure 19. (a) Average total organic carbon (TOC) for the lower Huron Member contoured at 2 wt. % TOC. (b) Max TOC values for the lower Huron Member contoured at 2 wt. % TOC. Both maps show a general trend of increasing TOC towards the west in the most distal locations.

39 7.2 Kerogen Analysis Kerogen represents the insoluble organic material that has the potential to become hydrocarbons, a complete review of kerogen can be found by Vandenbroucke and Largeau (2007). Kerogen can be divided into four main types for analysis. Type I kerogen is typical of fresh water algae and has a high HI and low OI and is thought to typically produce oil. Type II kerogen is formed from plankton/marine algae and is commonly associated with marine sediments under reducing conditions, typically thought to produce oil with some associated gas. Type III kerogen is typical of plant or terrestrial material and is thought to produce gas. Type IV kerogen is commonly oxidized/reworked organic material (i.e. inertinite) that is inert with high OI and low HI values (Hunt, 1979; Tissot & Welte, 1978; Vandenbroucke & Largeau, 2007). The determination of kerogen type should not be done exclusively with Rock-Eval pyrolysis data (Katz, 1983; Dembicki, 2009). However, with the knowledge of the depositional environment and petrographic analysis performed in this study, kerogen type can be strongly inferred. Kerogen type as discussed has implications on hydrocarbon generation, with marine kerogen producing roughly four times the amount of methane and converted organic material than terrestrial kerogen (Rohrback and Kaplan, 1978). Using the pseudo Van Krevelen diagram which plots HI vs. OI, samples from the lower Huron Member dominantly trend along the type II pathway (Figure 20a). The dominance of Type II kerogen is supported with the interpretation that the lower Huron Member is a marine sedimentary deposit and the identification of Tasmanites in thin-section and SEM. Where data points begin to trend along the transition between type II and III kerogen, it can be interpreted that samples contain a combination of both kerogen types (Dembicki, 2009). Type III kerogen presence is most likely associated with terrestrial input that has been shown to be a contributing component in the Huron Member (Maynard, 1981; Curtis & Faure, 1997). Potential phytodetritus identified in siltstones in the Shockling #1 core (Figure 10) provides evidence for this interpretation. Another explanation is given by Robl et al. (1992) who proposed that the vitrinite material associated with the Devonian marine shales in the Appalachian Basin may be derived from precursors to woody plants that are not truly terrestrial in origin. Because the lower Huron Member is determined to be a marine depositional environment and petrographic evidence supports dominantly type II kerogen, samples plotting along the type I pathway are most likely associated with alginite-rich samples (Robl et al., 1987). Further, a study on biomarkers from northeastern Kentucky and West

40 Virginia observed that the organic material in the lower Huron Member is predominately marine algae and bacteria (Kroon, 2011) supporting the interpretation that the lower Huron Member is dominantly type II. The S2 vs. TOC plot (Figure 20b) shows a strong correlation with type II kerogen. Some samples are shown to follow a type III pathway, further supporting the concept of kerogen mixing and/or more terrestrial input.

Figure 20. (a) Pseudo Van Krevelen plot for the lower Huron Member. A cutoff of >1 wt. % TOC and >2 mg HC/g rock S2 was utilized for data. (b) S2 vs. TOC plot for the lower Huron Member. Kerogen type I to II transition is based on HI = 700 and the kerogen type II to III transition is based on HI = 200. A regression line with an R2 value of 0.86 trends along the type II pathway supporting type II kerogen within the lower Huron Member.

41 7.3 Thermal Maturity The assessment of thermal maturity of lower Huron Member samples can be accomplished in several ways. The most common method is using visual estimates of vitrinite reflectance (Ro) from samples, as described by Dow (1977). Ro is typically assumed to be the best thermal maturity marker for post-Silurian stratigraphy due to its availability and ease of use. However, sampling can be highly variable between labs since vitrinite must be properly identified through petrographic analysis. Further, depositional setting and kerogen type can play an important part in the thermal maturity profiles exhibited by Ro (Price & Barker, 1985). Vitrinite suppression (Hutton & Cook, 1980; Lo, 1993; Price & Barker 1985) can also occur and has been documented in the Devonian shales of the Appalachian Basin based on inverted maturity profiles with overlying Pennsylvanian- aged coals (Rimmer et al., 1993; Repetski et al., 2008; Hackley et al., 2013; Ryder et al., 2013; Repetski et al., 2014; Riley, 2016). Other methods for assessing thermal maturity include evaluating Rock-Eval pyrolysis data, conodont alteration index (CAI), biomarker data, basin modeling, and gas chromatography (GC). This study utilizes the database compiled to evaluate thermal maturity patterns for the lower Huron Member with that of previous studies, this includes Ro and Rock-Eval pyrolysis data. Few data points for the lower Huron Member or its equivalents exist towards proximal locations in southeastern West Virginia or in Pennsylvania. Other studies (Repetski et al., 2008; Ryder et al., 2013; Repetski et al., 2014; Milici and Swezey, 2014; Riley, 2016) combined the entire sequence of Devonian black shale in the region in their overall analysis of Appalachian Basin maturation trends. This study utilized only data determined to be from the lower Huron Member and its equivalents. Averaged Ro values for each well show a trend of increasing thermal maturity towards the southeast with isolated pockets of lower thermal maturity (Figure 21). This agrees with the structural architecture of the basin derived from structure and stratigraphic thickness mapping. Mapping of a 0.6% Ro contour in this study to define the boundary of areas that have undergone oil generation, is similar to that of Riley (2016) who plotted maximum Ro values for the entire Devonian interval in Ohio, with only slight deviations. As Riley (2016) utilized a database similar to the one compiled for this study for Ohio it is not surprising that results in the state are similar. The results of the present study, however, are significantly different than those of Repetski et al. (2008 & 2014). While these authors evaluated the entire Devonian black shale interval similar to

42 Riley (2016), Repetski et al. (2008 & 2014) mapped the boundary between likely thermally immature/mature regions of the basin using a 0.5% Ro contour (i.e. the value for oil generation threshold opposed to the 0.6% Ro for significant oil generation used in the present study). If a 0.5% Ro contour is used to define the threshold boundary for oil generation in the lower Huron Member in Ohio using our data, it would be ~75 miles to the northwest of the Repetski et al. location. Ryder et al.’s (2013) revision of the 0.5% Ro contour based on data from Hackley et al. (2013) does not remedy this discrepancy. The primary reason for the differences between our Ro results and previous reports apparently lies in the greater number and geographic locations of the sample localities utilized in our study. Repetski et al. (2008 and 2014) and Ryder et al. (2013) evaluated Ro samples for 29 wells in Ohio. By comparison, this study evaluated Ro samples for 49 wells in Ohio. In addition, many of the wells evaluated for this study were located in southeastern Ohio where Repetski et al. (2008 and 2014) and Ryder et al. (2013) had limited data. Collectively, our additional data localities allowed for refinement of thermal maturity patterns in Ohio compared to previous workers. Further, the misidentification or the suppression of vitrinite (Dembicki, 1984; Rimmer et al., 1993; Repetski et al., 2008; Hackley et al., 2013; Ryder et al., 2013; Repetski et al., 2014; Riley, 2016) may influence thermal-maturity values for individual wells, especially when different horizons are combined to produce a single value. This may account for a few observed instances where wells in close proximity have vastly different values, especially when stratigraphically higher intervals returned higher Ro values than those from underlying formations. Milici and Swezey’s (2014) 0.6% Ro contour is further west than this study’s and is based on unpublished data at the time of their publication. Similar to Repetski et al. (2008 and 2014) and Ryder et al. (2013) the discrepancy with our study is attributed to the lack of data in Ohio. Other attempts at determining thermal maturity for the Devonian shales in the Appalachian basin include 2-D basin modeling on three transects along dip from West Virginia and Pennsylvania through Ohio by Rowan (2006). Rowan (2006) determined a 0.6% Ro contour further north than this study’s 0.6% Ro contour. Further, Ryder et al. (2013) evaluated GC, HI, and Tasmanites fluorescence spectra and revised Repteski et al.’s (2008 and 2014) 0.5% Ro contour (Figure 21) which slightly resembles this study’s interpretation of a 0.6% Ro contour more closely, to the north as proposed by Riley (2016). Hackley et al. (2013) determined that Ro values for immature Devonian Shale samples in the northern Appalachian Basin are lower than expected

43 based on biomarker ratios and bulk geochemistry, and proposed that Ro analysis should be used cautiously in these strata.

Figure 21. Average measured Ro values for the lower Huron Member with a 0.6% Ro contour (purple line). 0.5% Ro contour for combined Devonian Shale interval from Repetski et al. (2008 & 2014) and Ryder et al. (2013) (red line). Revised 0.5% Ro contour for combined Devonian Shale interval from Ryder et al. (2013) (green line). 0.6% Ro contour for combined Devonian Shale interval from Milici and Swezey (2014) (brown line). 0.6% Ro for combined Devonian Shale interval from Riley (2016) (orange line).

44 7.4 Tmax and Thermal Maturity Patterns In this study, Tmax derived from Rock-Eval pyrolysis was also used as a thermal maturity indicator to compare to measured Ro interpretations (Espitalié et al., 1977; Peters, 1986; Curiale and Curtis, 2016). Tmax can be used as a proxy for thermal maturity because it is the product of the response to the maximum rate of hydrocarbon generation, the top of the S2 peak (Espitalié et al., 1977), meaning that immature samples will have a lower Tmax compared to more mature samples. Using Tmax data to interpret thermal maturity, however, should be used cautiously and with supporting evidence. This is because immature samples, overly mature samples, organic lean or contaminated samples, and the incorrect calibration of the pyrolysis equipment may all result in anomalous Tmax values. Further, the type of organic material present will influence the Tmax value. A cutoff of 431°C (~0.6% Ro) Tmax was used for oil generation (Figure 22 and 23) based on an equation derived from empirical data by Jarvie et al. (2001) for the Barnett Shale from the Fort Worth Basin in Texas. The utilization of this equation for other formations, such as the lower Huron Member, may require modification as observed in the Wolfcamp Shale (J. B. Curtis, personal communication, June 7, 2018). However, it is utilized in this study as a baseline for hydrocarbon generation and comparison with measured Ro values. Mapping a 431°C contour for samples from the lower Huron Member results in a significant shift northwest for hydrocarbon generation in Ohio compared to the Ro mapping conducted in this study (Figure 22). Utilizing a Tmax of 435°C (~0.67% Ro), as recommended by Espitalié et al. (1977) and Peters (1986), similarly moves the oil generation window to the northwest in northeastern Ohio relative to the mapped 0.6% Ro contour (Figure 22). The Tmax interpretation in this study is closer to that of 2-D basin subsidence models that indicate hydrocarbon generation for the Huron Member likely occurred throughout most of central and eastern Ohio (Rowan, 2006) and the 0.6% Ro contour of Milici and Swezey (2014). Both interpretations represent a more optimistic view of thermal maturity for the lower Huron Member compared to the Ro 0.6% contour of the present study and the Ro 0.5% contour from Repetski et al. (2008 and 2014) and Ryder et al. (2013).

Figure 22. HI vs. Tmax showing distribution of kerogen type and inferred thermal maturity. Thermal maturity cutoffs based on rearranging the equation Ro(calc.) = 0.0180*Tmax-7.16 (Jarvie et al., 2001) to solve for Tmax. (Immature < 431°C Tmax or < 0.6% Ro; Peak between 431°C and 447°C Tmax or 0.6 and 0.9% Ro; Late between 447°C and 472°C Tmax or 0.9 and 1.35% Ro; Postmature > 472°C Tmax or 1.35% Ro). The calculated Tmax cutoffs are slightly different than that of Peters and Cassa’s (1994) interpretation.

Figure 23. Averaged Tmax data for the lower Huron Member plotted against a 0.6% Ro (purple line) value from this study. Tmax of 431°C (yellow line) is approximately equal to a 0.6% Ro according to the equation Ro(calc.) = 0.0180*Tmax-7.16 (Jarvie et al., 2001). A Tmax cutoff of 435°C (pink line) was used based on the oil generation window defined by Espitalie et al. (1977).

47 7.5 Hydrocarbon Implications Natural gas has been produced from the Upper Devonian black shales in the Appalachian Basin since 1821, with 80% of conventional gas in the Appalachian Basin being produced from the Upper Devonian black shales of the Cleveland and lower Huron Member in the Big Sandy field of north-eastern Kentucky and western West Virginia (Boswell, 1996). Most of the historical production in the lower Huron Member has been associated with areas where the unit contains extensive natural fractures. Fractures in the lower Huron Member and other black shale units occur throughout the Appalachian Basin. The prolific nature of the natural fracture system associated with the lower Huron Member has permitted hydrocarbon production from the formation (Boswell, 1996). These fractured systems are most likely the consequence of faulting in the basin generated by the reactivation of the Rome Trough and other basement-involved faults during the Alleghenian orogeny (Patchen, 1977). Natural fractures in the formation have likely increased porosity and permeability allowing for production from conventional and hydraulically fractured vertical wells and hydrocarbon migration into reservoirs stratigraphically overlying the Huron Member (Repetski et al., 2008). Recently with the advent of horizontal drilling and larger hydraulic fracturing techniques the potential exists to further exploit the lower Huron Member for hydrocarbon production. The extent of conventional/vertical wells producing from the interval was determined by Boswell (1996) and is used as the extent of historical production in the lower Huron Member. The current horizontal production was determined by evaluating state databases for horizontal wells designated as being completed in the Huron Member. Nearly all wells completed in the Huron Member, historically and presently, are dominated by natural gas production. Because significant natural gas generation for type II kerogen is thought to occur at Ro values >1.0 (Dow 1977; Peters and Cassa, 1994), it appears that gas production from the lower Huron Member is occurring outside of the thermogenic boundaries for gas generation indicated by this study’s Ro mapping (Figure 21). Other possibilities that explain this observed discrepancy is that gas has migrated from higher maturity areas of the basin, that the gas produced in the thermally immature zones may have a biogenic origin (Osborne and McIntosh, 2008, Kroon, 2011) or formed as “associated gas” during thermal oil generation (Schoell, 1982). Intriguingly, the possibility exists that gas associated with source rocks with Ro values as low as 0.41% may be thermogenic in origin. Carbon isotopic analysis of methane produced from

48 the lower Huron Member in northwestern Pennsylvania suggest it originated during oil generation (Laughrey, 2008). Both pyrolysis Tmax values (439° - 442°C) and biomarker (C29 sterane, hopane) maturation indices measured from Huron Member samples from the same well indicate a level of thermal maturity associated with oil generation. This suggests that the relatively low Ro values from the well were due to vitrinite suppression (Laughrey, 2008). In addition, off-gassing studies of lower Huron Member cores across the entire study area contains significant wet gas constituents (C2-C7, Ethane through Heptane) indicative of a thermal origin, even from wells with observed Ro values (< 0.6%) that indicate immature conditions (Table 1). While the presence of thermally generated hydrocarbons may be due to the migration of gas from deeper parts of the basin, the close correspondence between TOC and overall hydrocarbon content in lower Huron Member samples suggests the gas is locally sourced (McIver and Zielinski, 1978). While absolute gas wetness percentage (%W = C2-C4/C1-C4) may be high due to the loss of methane during drilling and core-retrieval, their presence in sampled intervals with observed mean Ro values as low as 0.36% again suggests the possibility of vitrinite suppression.

Table 1. Gas Chromatography, vitrinite reflectance, and Rock-Eval pyrolysis data for the lower Huron Member.

Well % Wetness δ13C Mean Ro Ro (Tmax) Tmax OH8 51.2 - 0.73 0.83 444 PA3 51.8 -54.4 0.41 0.78 441 OH4 32.8 - 0.42 - - OH5 39.7 - 0.36 0.65 434 OH3 39.5 -53.0 0.55 0.74 439

OH9 73.2 - 0.48 0.90 448 WV5 34.5 -50.2 0.58 0.67 435 KY4 49.5 -53.7 0.45 0.62 432 KY2 56.1 -53.1 0.49 0.74 439 VA1 16.9 -39.6 0.99 1.16 462

Sources: Gas Wetness: Zielinski (1977, 1978a, 1978b), Zielinski and Nance (1979, 1980a, 1980b), Bayless (1980), Zielinski and Moteff (1980, 1981); δ13C Data: de Witt (1978), Laughrey (2008); Ro: Project Databse; Tmax: Project Database; Ro (Tmax) Calculated from Tmax (Jarvie et al., 2001).

49 An evaluation of δ13C values of methane from sampled lower Huron cores indicates values ranging from -54.4‰ to -39.6 ‰ (Table 1). This level of methane fractionation and its occurrence with wet gas is indicative of formation of “associated gas” during early to late thermal oil generation (0.5% > ~Ro% < 1.2%) (Schoell, 1983). That the mean observed vitrinite reflectance values of half the lower Huron Member intervals with measured methane δ13C values is below 0.5% provides additional evidence for vitrinite suppression. The natural gas analyses from the lower Huron Member support the conclusion that the observed vitrinite reflectance values from the interval may be suppressed. An evaluation of mean observed Ro values and calculated Ro values derived from mean pyrolysis Tmax temperatures (Ro (Tmax) (Jarvie et al., 2001) from the same samples suggest this suppression is ~0.2%, although samples from individual wells may be suppressed as much as ~0.4% (Figure 24a and b). This study’s suppression values are similar to that of Rimmer et al.’s (1993) values (0.1 – 0.3%) for the Cleveland Member in northeastern Kentucky. A comparison between Tmax-derived vitrinite reflectance and methane δ13C values indicates all sampled wells have Ro (Tmax) > 0.6% while measured Ro values are not all > 0.6% (Table 1, Figure 25a and b). Additionally, the wet gas content of lower Huron core samples generally increases from ~35% to 73% between Ro (Tmax) values of 0.62% to 0.9% before decreasing to 16% at a Ro (Tmax) of 1.16% as would be expected for associated gas generated at increasing burial temperatures (Figure 25c, Schoell, 1983). Collectively, the overall higher Ro (Tmax) values from sampled wells suggests that the pyrolysis-derived Tmax values may be a better indicator of overall lower Huron Member source rock maturity than observed Ro values. A comparison of Tmax values from the lower Huron member in the study area reveals that most areas of historical production lie to the east of the 431°C Tmax contour (calculated Ro Tmax of ~0.6%, Figure 26). When evaluating the distribution of horizontal wells, in northeastern Kentucky, West Virginia, and Ohio, drilled in the Huron Member they remain east of the 431°C Tmax contour. However, there is a lack of horizontal wells being drilled in the Huron Member further west into West Virginia. Because the thermal maturity should be great enough throughout West Virginia, based on this study’s Tmax map (Figure 26), TOC is likely the limiting factor for expanding the horizontal play further west in West Virginia. However, the potential of localized areas of high TOC from Tasmanites blooms in West Virginia, that are associated with localized Rome Trough depocenters also exists (Curtis and Faure, 1997), may provide localized areas of hydrocarbon generation. As such, additional analysis of TOC and

50 Rock-Eval pyrolysis for lower Huron Member equivalents in West Virginia could potentially expand the play further into West Virginia. Additionally, utilizing the sequence stratigraphic model developed in this study may be able to further identify high TOC sequences in the zone indicating hydrocarbon generation.

Figure 24. (a) Ro % vs. calculated Ro % (Tmax) for all samples in the databased containing Tmax data from Rock-Eval pyrolysis and measured Ro values. (b) Ro % vs. calculated Ro % (Tmax) for samples that had associated gas analysis data (Table 1). The geographic location of these wells is in figure 18.

Figure 25. Plotted gas analysis data from Table 1. (a) δ13C vs. measured Ro % and (b) δ13C vs. calculated Ro % (Tmax)from Tmax data using Jarvie et al’s (2001) equation. The plot shows δ13C values ranging from -54.4‰ to -39.6 ‰ indicating that it is associated gas. (c) Gas wetness as a % (C2-C4/C1-C4) vs. calculated Ro % from Tmax data. The plot shows a decrease in gas wetness for the VA-1 well with increased thermal maturity.

Figure 26. Existing Huron Member production compared to this study’s thermal maturity indicies and the 0.6% Ro contour of Milici and Swezey (2014). Boswell’s (1996) production outline is used to define conventional production with horizontal wells drilled in the Huron Member marked by a red dot or line. Huron Member production is most closely related to our 431°C and the 0.6% Ro contour (yellow line) of Milici and Swezey (2014) (brown line).

53 8. Conclusions This study provides a sequence stratigraphic model that explains observed lithological cyclicity in the lower Huron Member, based on sedimentological and subsurface evidence. The evaluation of core allowed for the identification of four facies assemblages that define systems tracts within a model depositional sequence. Interpreted SBs correspond to low GR peaks observed in medial and distal parts of the basin. These GR lows are represented by FA-D, FA-C, and FA-B facies representing deposition in medial inner shelf, distal inner shelf, and proximal outer shelf environments, respectively. The lower portions of each sequence consist of bioturbated organic- poor FA-D deposited during a LST that developed during maximum regression of basin depositional systems. Overlying FA-C, FA-B, and FA-A deposits become increasing organic rich as outer shelf and inner shelf environments shifted to the east during increases in relative sea level in the basin. These intervals are interpreted as the deposits of a TST. The MFS of each sequence is represented by primarily FA-A or FA-B facies deposits that commonly display the highest GR and TOC values. Deposits of the HST are represented by an upsection transition from FA-A deposits to overlying FA-B, FA-C, and FA-D facies that display corresponding decreases in GR values. Using this sequence-stratigraphic model, 21 4th order sequences were correlated on a regional basis. Further, stratigraphic condensation and truncation observed within and between sequences allowed for the division of the lower Huron Member into three distinct sequence sets. Sequence A is the lowest stratigraphically in the lower Huron Member. With the highest overall GR log values, the interval represents overall transgressive stage marked by stratigraphic condensation. Sequence set A marks the period of highest relative sea level in the lower Huron Member which allowed for high organic content preservation and sediment starvation in transitional (inner shelf-slope delta) and distal locations (outer shelf). Sequence set B has a relatively uniform thickness in the medial and proximal parts of the basin that suggests a relative balance between accommodation development and sediment supply during the time of deposition. Sequence set C represents an interval of greater progradation of inner shelf environments into medial portions of the basin than the underlying sets. Truncation of individual sequences in set C suggest the interval was deposited during relatively low rates of accommodation development. Contour mapping of TOC shows that the lower Huron Member varies from >10 wt. % TOC in the distal portions of the basin along the outcrop belt (central Ohio) and <2 wt. % TOC in the

54 more proximal regions (West Virginia and Pennsylvania). TOC values above 4 wt. % are typically referred to as organic rich sediments and are thought to be major source rocks. Pockets of higher TOC may be attributed to localized Tasminities blooms or are simply an artifact of selective sampling and/or techniques. Kerogen analysis based on Rock-Eval pyrolysis, thin-section, and SEM analysis supports the conclusion that the lower Huron Member is dominantly comprised of type II kerogen. Type III mixing is evident in the pseudo Van Krevelen and S2 vs. TOC plots and is most likely attributed to terrestrial input. Data trending along the type I pathway could potentially be a consequence of alginite-rich samples or sulfur-rich samples resembling a type IIs morphology. Thermal maturity mapping based on measured Ro is in general agreement with Riley (2016) in Ohio. However, a large discrepancy in respect to Repetski et al. (2008 & 2014) and Ryder et al. (2013) exist. This discrepancy is most likely a consequence of this study having more data and the division of the lower Huron Member from the entire Middle-Upper Devonian black shale interval. Based on measured Ro, northeastern Kentucky is largely immature based on mapping performed in this study. However, it should be noted that most of the data points in northeastern Kentucky are near the 0.6% Ro cutoff and may have experienced early oil generation. The suppression of vitrinite is suspected based on comparisons between measured Ro values, δ13C values, and the presence of wet gas in samples with Ro values < 0.6%. Differences between measured Ro and calculated Ro (Tmax) indicate suppression of ~0.2%, although samples from individual wells may be suppressed at much as ~0.4%. Given the possibility of vitrinite suppression, pyrolysis-derived Tmax values may provide a more complete picture of thermal maturity for the lower Huron Member than Ro values. Tmax mapping based on a 431°C moves the oil generation threshold further northwest and provides evidence of hydrocarbon generation throughout eastern Ohio. This is similar to the location determined by Rowan (2006) based on 2D basin modeling. The correlation between the 431°C Tmax contour and the historical production further supports Tmax data as being superior to Ro data for the lower Huron Member.

55 9. References

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65 10. Appendix * SB truncated or condensed. Shockling #1 log shift +6 ft. SB - SB 1 - Java/Olentangy

Top - Lower Huron

+6log shift study this given elevation has that Note feet. used. the with a datum measure in well #1 data Top the Shockling depth S1. Table Well Number: Well Name: Datum (ft.): Horizon SB - SB 10 - SB 11 - SB 12 - SB 13 - SB 14 - SB 15 - SB 16 - SB 17 - SB 18 - SB 19 - SB 20 - SB 21 SB - SB 2 - SB 3 - SB 4 - SB 5 - SB 6 - SB 7 - SB 8 - SB 9

API:

Top data Top for the and lower the sequence 21 Member wells for base and top in shown Huron boundaries the associated with it, based it, providedcore on study. this in associatedwith data Maxwell William 3416320207 1735.34* 1706.48* 1654.70* 1654.70* 1654.70* 1637.72* 1637.72* 1755.40 1751.04 1742.13 1735.34 1717.93 1706.48 1692.05 1676.59 1664.03 1654.70 1637.72 1618.62 1609.71 1594.01 1586.82 780 #1 1 Shockling #1 3412122255 3473.64 3460.64 3450.35 3424.36 3404.86 3392.40 3357.20 3346.37 3323.09 3284.64 3217.49 3082.44 3042.15 2987.87 2978.67 2960.25 2941.84 2929.39 2904.48 2879.57 2860.61 2835.90 860 2 Freeman Flora 4701702556 4569.59 4538.27 4513.12 4490.91 4429.01 4374.84 4337.66 4168.01 4089.36 3980.31 3861.27 3703.23 3660.10 3613.74 3581.34 3504.75 3436.01 3399.86 3323.65 3266.50 3199.30 3172.85 #OR-1 806 3 William Sgley B. 4707700168 4225.48 4170.38 4094.34 4036.74 3967.62 3941.12 3886.98 3833.99 3774.08 3713.02 3605.88 3541.37 3426.17 3373.17 3336.31 3234.93 3180.78 3125.49 3081.71 3026.41 2968.81 2944.89 #11481 1830 Measured DepthMeasured (ft.) 4 Pardee Land #67 4704501085

5635.42 5618.62 5607.56 5595.33 5586.59 5578.47 5559.23 5544.22 5520.68 5476.59 5394.17 5311.37 5288.67 5275.83 5253.57 5235.16 5202.20 5185.51 5171.81 5159.82 5151.69 5132.15

1996 5 Holstein Paul L 4703501943 4288.00 4273.47 4264.61 4232.54 4213.98 4205.96 4187.39 4179.38 4160.28 4122.03 4046.30 3952.36 3906.29 3861.12 3852.68 3834.96 3816.81 3795.72 3768.29 3742.55 3728.86 3711.00 824 6 S. & D. Noll &S. D. #3 3401921766 2753.81 2742.18 2732.28 2720.55 2706.24 2694.44 2658.22 2638.31 2589.68 2552.69 2504.87 2395.13 2360.20 2286.74 2273.37 2259.44 2242.57 2234.42 2215.79 2193.08 2170.99 2147.45 1070 7 Brayman, H&D #1 3400720193 1500.37 1480.59 1472.44 1463.12 1444.49 1417.71 1399.66 1381.61 1355.98 1324.02 1267.11 1156.84 1123.65 1048.54 1030.49 1015.93 1005.45 990.89 976.34 955.37 933.25 912.01 968 8

66 Thin Section - Shockling #1 Sample ID Depth Core (ft) S1-1 3199.8 S1-2 3217.6 S1-3 3218 S1-4 3221.3 S1-5 3222.47 S1-6 3233.8 S1-7 3242.3 S1-8 3244.3 S1-9 3246.1 S1-10 3246.3 S1-11 3248.6 S1-12 3251.3 S1-13 3254.95 S1-14 3256.35 S1-15 3258.3 S1-16 3258.6

Table S2. Depth of the 16 thin sections utilized in the study.