Poster Session Abstracts

Alphabetical according to lead presenter

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Lateral variability of the Marcellus Shale

Bruno Abersold, Department of Geology and Geography, West Virginia University

The Marcellus Formation, a large shale gas reservoir located within in the Appalachian basin, produces the energy that fuels the economy across the United States. Well data and rock core for the Coastal 1H well, found in Fayette County, Pennsylvania, provides the basis to understand reservoir characteristics and depositional processes of the Marcellus Formation across the basin. The well is located near along the eastern edge of the productive fairway and adjacent to the Allegheny mountain front. We used characteristics, such as total organic carbon (TOC), geomechanical properties, and lithology, to integrate with ten other available wells across the basin. The Marcellus Formation was divided into five informal units – three shale layers (upper, middle, and lower), separated by two limestone beds. Ternary diagrams visualize the mineralogical composition of the Marcellus Formation. Consistently they indicate that carbonate and silica content increases with depth and clay decreases. Total organic carbon, however, increases with depth in only certain wells. Geomechanical properties vary the most when looking at the individual units of a well and brittleness decrease upwards with increased clay content. Overall, the Marcellus Formation is weak and brittle compared to adjacent units. The Coastal 1H shares similar lithological properties with the nearby wells, however, it is less organic rich and less brittle in comparison to the other study wells. In general, it seems that the lower Marcellus is the optimal unit for hydraulic fracturing, as it is the most brittle and organic rich.

Phase associations of rare earths and critical minerals in Marcellus and Haynesville Shale: Implications on release and recovery strategies

Shailee Bhattacharya, Vikas Agrawal, Bennington Opdahl, and Shikha Sharma, West Virginia University

The focus on clean energy transmission and rapid advancement of technological devices has resulted in high demand for rare earth elements (REEs) and critical minerals (CM). Hydrocarbon rich shales that have been major supplier of natural gas in US over the last decade have the potential to serve as source of some of the REE’s and CM’s. However, there is little understanding of the geological and geochemical processes that lead to enrichment REEs and CMs in these shale reservoirs. To develop economically viable extraction techniques there is a need to build better geochemical models for enrichment. The goal of our study is to investigate the distribution of REEs and CMs in the different fractions of shale, namely, exchangeable, acidsoluble, pyritic, organic and silicate phases. A sequential leaching experiment was performed on Marcellus shale and Haynesville shale samples to compare the differences in phase associations of REEs and CMs. Results show that REY are mostly concentrated in the acid-soluble fraction. Critical minerals, such as Al, As, Cr, Cu, Co, Li, Mn, V, Ti, and U are found widely distributed among all the phases. The Haynesville shale has elemental abundances majorly in acid-soluble and silicate phases, while the Marcellus shale has relatively higher contribution of critical elements from the pyritic fraction followed by acid-soluble and organic phases. The Marcellus shale is at least ten times more enriched in As, Li and U than the upper continental crustal average. Additionally, although the individual concentrations of Platinum group elements are considerably low, there is a significant difference in the nature of associations between Marcellus and Haynesville shale. These preliminary results help us understand the mechanisms that caused the phase associations. The study is critical as it also will help improve strategies to increase extraction efficiency and economics of REE and CM recovery from shales.

Preliminary high-resolution mapping of organic carbon distribution in the lower Huron Member of the Ohio Shale

Erika M. Danielsen, Ohio Department of Natural Resources, Division of Geological Survey

The Devonian shales of the Appalachian Basin have been studied extensively in terms of hydrocarbon resource potential; however, the increasing demand for carbon capture, utilization, and storage calls for continued reassessment of the properties of the Devonian shale formations at a finer scale. This project aims to estimate and map total organic carbon (TOC) distribution in the lower Huron Member of the Ohio Shale in Ohio at a high geographic and stratigraphic resolution using geophysical logs to estimate TOC. The Eastern Gas Shales Project (EGSP) of the 1970s and 1980s funded the drilling of several cores in Ohio with accompanying TOC lab analyses. These data have been used for TOC mapping previously, but core data only covers a narrow geographic area and the data is scattered through several of the Devonian shale formations. These TOC data from the EGSP and other cores were used to develop an equation for this project that uses gamma-ray and bulk density logs to estimate TOC in wells that penetrate the lower Huron. This project builds on previous work by the Ohio Geological Survey that increased the stratigraphic resolution of the upper Devonian shale mapping in Ohio, particularly in the lower Huron Member. TOC estimates were mapped across eight depositional cycles within the lower Huron to determine if changes in basin morphology during deposition impacted the distribution of high TOC zones.

Leveraging state system resources for a collaborative, comprehensive geologic field camp

Kyle C. Fredrick, Tamra Schiappa, Nick Deardorff, Daniel Harris, Sarah Tindall, Jonathan Lewis, Sean Cornell, Eric Straffen, Logan Wiest, and Daria Nikitina

Geology is inherently a field science. A transformative experience for students on their paths to careers in geology is through “field camp.” In these unique courses, students receive hands-on training and apply geological tools. Unfortunately, the availability of geological field camps has declined and have become cost prohibitive. This is a challenge for undergraduate students seeking careers in geology, lacking demonstrable, comprehensive field experiences on their resume. It is a challenge to our discipline as well, which has long relied upon a robust, field-based capstone for entrants into the workforce, graduate school, and professional licensure. In Pennsylvania, particularly the State System (PASSHE), most geology programs require or recommend field camp. Currently, the 11 Geoscience programs within PASSHE operate independently, many struggling to offer field instruction due to limitations on faculty time, campus resources, and enrollment. Consequently, students shop for alternatives, often attending camps with high, out-of-state tuition and expensive travel. This is burdensome for students and families and a barrier for underserved and marginalized populations. In Summer 2022, a PASSHE-wide option launches with its first cohort. Designed by PASSHE geology faculty for PASSHE students, the participants will travel to system campuses each summer. Students are housed on campus and investigate the geology with local professionals and faculty from those institutions. Field activities include surficial and bedrock mapping, geophysical surveys, and geochemical sampling. Projects will be designed to using current technologies and develop communication and problem-solving skills in a group setting. The program includes outreach to engage pre-college students and teachers, and service-learning activities with the community. As we develop the course, we seek input and ideas from industry professionals. This field camp will be the first of its kind and will benefit from forethought and recommendations from hiring managers aware of workforce needs in the energy and environmental sectors.

Lithofacies, depositional setting, and sequence framework of the Cambrian Rogersville Shale, Rome Trough, Kentucky

Dave C. Harris, and John B. Hickman, Kentucky Geological Survey, University of Kentucky

Cores and related data from the Cambrian Rogersville Shale in the Rome Trough, Lawrence and Johnson Counties, Kentucky, were analyzed in a regional study recently completed by the Conasauga Shale Research Consortium. More than 900 feet of Rogersville Shale from two wells, and almost 400 feet of Nolichucky Shale from a single well, were provided to the consortium. These cores constitute an important sedimentologic record for the deep Cambrian formations in the subsurface of the Appalachian Basin.

The Rogersville Shale in the cored intervals is composed of heterolithic intervals of thinly bedded calcareous siltstones to very fine-grained sandstones, interbedded with medium to dark gray shale. Calcite-cemented siltstones and sandstones occur in beds up to 6 cm thick, and commonly occur as millimeter-scale laminations separated by shale partings. The coarser layers commonly have sharp, erosional bases and low-angle to hummocky cross-stratification. Lenticular siltstone beds with climbing or starved ripple lamination, and flat-pebble conglomerates composed of siltstone intraclasts are common. Bioturbation is abundant throughout the Rogersville in both shale and siltstone beds. Carbonate content varies in the coarser-grained beds, both as transported grains and cement.

The thin-bedded and heterolithic nature of the Rogersville suggests deposition in a distal marine setting with intermittent silt-sized sediment supply. Siltstones and sandstones are interpreted as discrete event beds, deposited by storm currents in a deeper basinal environment below normal wave base. Hummocky crossbedded siltstones with erosional basal contacts also support storm deposition. Individual event beds cannot be correlated between the cored wells.

The Rogersville Shale comprises parts of two third-order depositional sequences based on outcrop exposures. The mid-Rogersville sequence boundary marked by the shallow-water Craig Limestone Member in outcrop has been interpreted in the basin as a correlative conformity and helps to explain the distribution of organic-rich shale in the play area.

Qualitative REE analysis of Ohio underclays by pXRF

Samuele R.W. Hulett, Franklin L. Fugitt, and Christopher E. Wright, Ohio Department of Natural Resources, Division of Geological Survey

Aluminum-rich clays and claystones associated with Pennsylvanian-age coal horizons can be found throughout eastern Ohio. Similar clays from Pennsylvania and West Virginia have been recognized as a potential low-grade, large-volume source of Rare Earth Elements (REE). Samples were gathered samples from 66 sites, with subsamples taken at regular intervals throughout the clay. Samples were prepared and analyzed via portable X-Ray Fluorescence (pXRF) in order to qualitatively assess REE content. While the pXRF can only measure four of the REEs (Lanthanum, Cerium, Praseodymium and Neodymium), some associations emerge. Total REE content ranges from about 50 ppm to over 350 ppm, with an average of 210 ppm. Average clay/shale REE content over these four elements is 183 ppm. The greatest concentrations occur in the Lower Kittanning underclay and red Conemaugh Group shale. The lowest concentration comes from the Middle Mercer underclay. Preliminary data does not show any correlation between total REE concentration and proximity of the subsample to the overlying coal. A comparison of total REE vs other major element concentrations show a direct correlation with iron. This association coupled with a weak aluminum correlation suggests the possibility that the REEs are not adsorbed onto the clay minerals but instead may be hosted in iron minerals in the clay. Future analysis via tabletop XRF and XRD will aid in confirming these results. If accurate, these associations may be able to help target intervals with the greatest potential for future economic use and give an insight into the origins of these REE rich units.

Organic source characterization of the Utica, Marcellus and Burkett Shales

Nandini Kar, Kathryn Tamulonis, Richard Smith, Stella Woodard, Mark Noll, Reilly Blocho, and Andre Brunette

We present new geochemical data from the Ordovician Utica shale (n=3) and Devonian Marcellus (n=8 plus 6 previously published data) and Burkett shales (n=2) – some of the biggest producers of natural gas in North America in recent times. The <1 to 9% organic carbon contents in Burkett and Marcellus shales were typical for mature shales. Total lipid extracts (TLE) from the NY Marcellus samples were nearly 2x the average TLE of the Utica shales. TLEs from the hydrothermally altered PA samples were generally lower, except one Burkett sample. The n-alkane distributions from three Marcellus and one Burkett shale samples show a single peak centered on C-26-C-27. Other samples have a bimodal distribution with a secondary, sometimes dominant, peak, centered on C-15 to C-16. The abundance of longer chain n-alkanes along with 13Corg values <-22‰ indicate terrestrial inputs in both these shales. Negative Cerium anomalies from Marcellus and Burkett samples point to anoxic condition during deposition. The 13Corg values further indicate that deposition took place in shallower water and not in anoxic deep water setting. Presence of medium to long chain n-alkanes (C23-C33) in the Ordovician Utica shale also likely indicate shallower water deposition with input from terrestrial bryophyte and fungi. The high (>1 for n = 11) Terrestrial to Aquatic ratio and Carbon Preference Index values of ~1 farther point to mature terrestrial or type III kerogen that are gas-prone. The geochemical signature suggests that deposition of the gas rich black shales were linked to development of shallow anoxic water with high terrestrial sediment supply during both the Taconic and Acadian orogenies.

Vug and fracture characterization of Trenton-Black River reservoirs through CT scan and image log analysis in the southern Michigan Basin

Laura Keister, Amber Conner, Autumn Haagsma, and Srikanta Mishra, Battelle

A comprehensive evaluation of chemically enabled CO2-EOR in the Southern Michigan Basin Trenton-Black River (TBR) reservoirs is underway as part of work supported by the U.S. DOE under DOE-FOA-0001988. The TBR consists of complex, multi-porosity and/or hydrothermally altered dolomite (HTD) reservoirs with secondary porosity (i.e., vugs and fractures), which contributes significantly to total porosity, permeability, and storage potential throughout the reservoirs. These reservoirs are especially challenging for enhanced oil recovery due to heterogeneities, compartmentalization, and presence of thief zones. As a result, there is a heightened need to understand and predict these potential reservoir features for satisfactory incremental oil recovery.
To address these challenges, a database of image logs and 3D computed tomography (CT) scans that depict secondary porosity features were compiled. Image logs provide high-resolution, 360-degree wellbore images that can be used to derive planar structural and sedimentary features for detailed reservoir characterization, such as faults, fractures, bedding, stress fields, and pores. Flags were developed to identify and classify vugs and fractures, and the frequency and orientations were analyzed. The 3D CT scans capture high-resolution images of whole core that represent variations in density, indicating changes in composition and porosity. We developed a technique which isolates specific rock density ranges, quantifies the percent of each feature, and creates 3D visualizations. Image logs and CT scans were compared for wells that had both datasets.
The results produced quantitative size, orientation, and distribution for thousands of secondary porosity features in the TBR. The features varied greatly from well to well but had the highest concentration within dolomitic intervals. Total porosity increased where features were present, indicating an important role in reservoir quality. Overall, this study quantitatively detailed the distribution of these complex porosity networks. The results will be used to inform 3D modeling to assess the CO2-EOR feasibility in the TBR.

Northern Bohemian Massif: an example fo multi-phase tectonic reactivation recorded by Late Paleozoic–Mesozoic basins

Roland Nádaskay, Jiří Žák, Karel Martínek, Kateřina Schöpfer, Jiří Sláma, Martin Svojtka, Tamara Sidorinová, Radim Jedlička

The northern Bohemian Massif (BM) experienced a complex Late Paleozoic–Mesozoic intra-plate tectonosedimentary evolution. Processes that led to current basin configuration have recently been explored through facies analysis, lithostratigraphic correlation of sedimentary formations and provenance analysis (U–Pb geochronology; heavy minerals). The provenance data point to multiple sources, both local and distant within the BM, or exotic sources (Baltica). Temporal and spatial evolution of source areas and juxtaposition of preserved basin fills suggest that least four generations of basins developed in the study area:

(1) Extensional early Permian basins, formed by reactivation of SSW-NNE normal faults;
(2) Permian outliers within the Elbe Zone and the Döhlen Basin (Germany) . We interpret them as remnants of a series of pull-apart basins governed by NW-SE faults (the Elbe Zone);
(3) Middle-Upper Jurassic outliers within the Elbe Zone, interpreted as a trace of now completely eroded Late Jurassic-Early Cretaceous basin;
(4) Upper Cretaceous of the Bohemian Cretaceous Basin, interpreted as either transtensional (Uličný 2001) or intraplate foreland basin (Voigt et al. 2021).

Provenance of the Upper Jurassic and Upper Cretaceous indicates two-stage deposition, interrupted by reactivation of basement faults and shift of depositional and source areas. Certain Upper fromations received a substantial portion of Baltica-derived siliciclastic material interpreted to be recycled from the hypothetic Lower Cretaceous during unroofing of the adjacent source area. A reconstruction of Mesozoic tectoinosedimentary evolution and paleogeography of the northern BM shows that the mentioned phases of basin development were interrupted by major non-depositional intervals (Middle Triassic-Early Jurassic, mid-Cretaceous, post-early Campanian). This was caused by reactivation of Variscan NW-SE faults due to stress transfer from the North Atlantic Rift (Jurassic-Early Cretaceous), which was overridden by far-field effect of the convergence of Iberia, Africa, and Europe during Late Cretaceous times.

Vein evolution and hydrocarbon migration in the Marcellus Shale across the Appalachian Basin

Natalie Odegaarden and Tim Carr, West Virginia University

Four cored wells of the entire Middle Devonian Marcellus Shale from Ohio and West Virginia were used to investigate the distribution and morphological evolution of natural fractures with cement when kerogen matured to different burial depths. The cores from west to east across the Appalachian basin have increasing VRo (1.21 to >2.0 %), depths and thicknesses, along with changes in clay composition and redox environment. Each core has a decreasing upwards trend in total organic carbon and multiple organic-rich units. Examination of spectral GR logs (U, Th/U, and Th/K ratio), cores and thin sections were used to determine vein composition and crystal morphology related to kerogen maturation, vein orientation, abundance, and length. Veins were classified based on angle to bedding: horizontal, horizontal swarm, oblique, and vertical. Bitumen and calcite were the main vein composition, where calcite cement morphologies include fibrous and granular calcite. Horizontal fibrous calcite veins with bitumen inclusions throughout the vein width and along inclusion bands formed during early oil generation. Granular calcite formed during the peak oil window because it mainly occurred between fibrous calcite veins with vertical orientation; contained a plethora of bitumen inclusions giving it a dark color in comparison the adjoining white fibrous calcite; and developed when partially cross-cutting bitumen veins supplied fluids. Vein abundance increased with increasing thermal maturity, while redox condition became more cyclical and clay type became less illitic across the Appalachian basin. Horizontal/horizontal swarm bitumen and fibrous calcite veins dominate the westernmost well, whereas eastward vertical bitumen and calcite veins containing fibrous and granular crystals increase. Based on calcite and bitumen vein abundance and length, fractures propagated from the lower organic-rich units to upper units, thereby promoting hydrocarbon migration throughout the shale. Natural fracture studies provide insight to shale as a store for carbon-dioxide.

Effects of an igneous intrusion on the Devonian Millboro Shale, Sugar Grove, West Virginia

Matt Rhodes, Noelle Kidd, Susannah Herz, Katharine Lee Avary, and Kathryn Tamulonis

The Devonian Millboro Shale crops out near Sugar Grove, West Virginia, where an Eocene basalt sill-dike complex intruded the shale. We collected seventeen samples along a 100-foot transect to the south of the intrusion, starting at the center of the intrusion and moving out into the surrounding shale. Seven of the samples were collected within the first ten feet of the transect, and the remainder were collected at ten-foot intervals. Petrographic and scanning electron microscopy were used to characterize shale mineralogy, texture, diagenetic/alteration features, and reservoir quality as a function of distance from the intrusion.

Avary and Dennison (2013) describe a phyllitic sheen within a three-foot zone of the intrusion caused by contact metamorphism. We observe slate between three and ten feet, followed by shale containing alteration features for the remainder of the outcrop. For all samples, SEM results indicate the presence of period 3 and 4 elements (e.g., aluminum, calcium, potassium) in addition to an expected abundance of silicon and oxygen. Yttrium, thorium, titanium, and phosphorus were also present within the first five feet of the phyllite and slate surrounding the intrusion.

Pyrite framboids, veins, and organic material are ubiquitous throughout the samples. Within the first ten feet immediately south of the intrusion/Millboro contact, 1) euhedral pyrite occurs, 2) vein frequency is higher, and 3) bedding/laminations are not observed. The framboids show signs of deformation and alteration within a 40-foot zone of the contact. Further understanding these features will provide insight into alteration processes caused by the intrusion, as well as effects of Appalachian Basin intrusions on organic-rich shale reservoir quality.

Mapping update of the Middle to Upper Ordovician Black River Group to Utica Shale interval, Ohio

Michael P. Solis and Erika M. Danielsen, Ohio Department of Natural Resources, Division of Geological Survey

As part of a study to characterize the Point Pleasant/Utica Play for potential EOR in Ohio, the Ohio Geological Survey remapped, in stratigraphic order, the Middle to Upper Ordovician Black River Group; Trenton Limestone; the Curdsville, Logana, and upper Lexington members of the Lexington Limestone; Point Pleasant Formation; and Utica shale. This study used 1,033 wells to map the interval.

The structure contours for each mapped unit roughly parallel each other. Variations in dip for each surface are primarily a result of differing thicknesses of each unit. Structural features common to each unit are a low associated with the faults bounding the Bellefontaine Outlier and a north-plunging anticline east of the Bowling Green Fault.

The isopach map of the Curdsville Member show that it is continuous with the basal Trenton Limestone across the region. The Logana Member is more shaley, it thins and becomes indistinguishable from shales in the Sebree Trough, while cleaner carbonates continued to be deposited on the Trenton and Galena shelf. The upper Lexington Member thins in the Utica/Point Pleasant sub-Basin and pinches out in the Sebree Trough. The combined Trenton/Lexington isopach shows the axis of the Sebree Trough and some localized structural thickening of the interval. The Point Pleasant Formation is thickest in southern Ohio and is not continuous across the Sebree Trough. The Utica shale is thickest along the Sebree Trough and pinches out along the northern margin of the Lexington Platform. The isopach maps of the interval show the shales of the Point Pleasant were deposited in low-energy areas while carbonates were deposited in higher-energy areas and during higher-energy events. As the basin evolved, the low-energy Utica shale was deposited over the Trenton Limestone and Point Pleasant Formation.

New maps showing dolomitization extent and mineralogical brittleness index in the Utica Shale, Point Pleasant Formation, and Lexington Limestone in Ohio

Christopher B.T. Waid, Michael P. Solis, and Erika M. Danielsen, Ohio Department of Natural Resources, Division of Geological Survey

To facilitate enhanced oil recovery (EOR) in the oil-bearing Utica shale/Point Pleasant formation, the Ohio Geological Survey performed an assessment of the Utica/Point Pleasant interval in Ohio. This project included quality controlling and using source rock and geochemical data from previous studies in new ways. This poster focuses on a new map of percent dolomitization of the Utica shale through Lexington/Trenton limestones (undifferentiated) and mineral brittleness index (MBI) maps of the Lexington/Trenton limestones, Point Pleasant formation, and Utica shale.

X-ray diffraction data from previous studies was compiled, quality controlled, and assigned to the three geological units. The percent of dolomitization of total carbonate material within each unit was averaged for each well and mapped using Esri ArcGIS. These data indicate that dolomitization was minor throughout the eastern half of Ohio (3–15%), with regions of higher dolomitization (20–45%) localized to basement faults. Dolomitization generally increases westward, where much of the dolomitization occurred along extensive basement faulting in northwestern Ohio.

MBI was calculated and mapped for the three units within each well. Several brittleness trends are consistent from Lexington deposition to Point Pleasant deposition. One is the north–south high-brittleness zone in central Ohio. In the Lexington, this zone extends from Pickaway and Hocking Counties in the south to Huron County in the north. During Point Pleasant deposition, this trend was reduced and extended northwards into Richland County. High brittleness values in this trend are reduced further to only Pickaway County in the Utica shale. Another area with consistent MBI values in each formation is eastern Washington County (eastern Ohio), which shows low brittleness values in both the Lexington and Point Pleasant maps. In general, brittleness in the Utica is uniform (0.45-0.55) across the study area, except for high values in Pickaway County and northeastern Harrison County (eastern Ohio).

Regional correlation and depositional history using well log and core data of the Middle Devonian Marcellus Poseidon 8M Well, Westmoreland County, PA, USA

Spencer L Williams and Tim Carr, West Virginia University

Natural gas producers have invested billions in Pennsylvania Ohio and West Virginia to establish significant gas production from the Marcellus Shale and the deeper Ordovician Utica-Point Pleasant intervals. The Marcellus Shale is the largest natural gas play in the United States producing and together with the Utica-Point Pleasant account for more than 28% of current total US gas production. Commercial gas production has been reported from several other Devonian shale units in the Appalachian region, including the Rhinestreet, Levanna and Geneseo-Burket units. However, these younger and shallower shale units remain underdeveloped and represent future opportunities.
The Geneseo-Burket shale similar to the Marcellus is one of the most highly radioactive and organic-rich of the Devonian shale units, yet little is in the public domain as to its stratigraphic distribution, depositional history, geomechanical properties, and geologic controls on gas production.
The main objective of the research is to examine the geologic characteristics of the Geneseo-Burket Shale from wells in southeast Pennsylvania and northern West Virginia. A complete core of the Geneseo-Burket from a well in Westmoreland County, Pennsylvania is integrated with CT-scans, geochemical data and well logs. The results provide an improved understanding of the lithology, vertical and regional depositional patterns, contacts with the underlying Tully Limestone and overlying Penn Yan Shale, the stratigraphic distribution across the Appalachian basin and ultimately the potential resources.

Statistical and economic assessment of rare earth elements in West Virginia Coals

Rachel Yesenchak and Shikha Sharma, West Virginia University

Rare earth elements (REEs) are critical to essential technologies, including those used for renewable energy production, communication, transportation, and national defense. Recent research has suggested that specific coal seams and coal byproducts are enriched in these elements and may be a promising resource due to an abundance of domestic supply and pre-existing mining infrastructure. With one of the largest coal reserves in the country, West Virginia can play a key role in maintaining the nation’s supply of REEs. However, to identify economically viable reserves and develop efficient extraction techniques, it is important to understand patterns of occurrence and concentration of REEs in different coal seams. Additionally, understanding statistical relationships between REE concentrations and potential predictor variables can reduce the need for expensive laboratory analysis of the full suite of elements when quantifying resources within seams. We utilized coal chemistry data from the U.S. Geological Survey’s CoalQUAL database to help identify viable REE reserves and gain insight into elemental and mineral relationships that can enhance prediction and extraction of rare earth elements in West Virginia coals. Linear regression was used to evaluate the relationship between light, medium, heavy, and total rare earth content and proxies for the mineral fraction of coal, including ash yield and aluminum. Regression was also used to assess the suitability of using yttrium, thorium, and aluminum as predictor variables to estimate rare earth concentrations. Results indicate that the strength of these statistical relationships varies between coal seams. The proportion of economically promising samples and their spatial distribution will be evaluated on a seam-by-seam basis to assist in developing West Virginia coal reserves as a resource for REEs.