Geochemical Impact of Rock-Fluid Interactions during Hydraulic Fracturing in Marcellus Shale
2023 Global Energy Meet, Boston, MA, March 6-10, 2023
Xiong, Wei↗
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Predicting Lithium Fluxes from a Heterogenous Brine Source Marcellus Shale
For presentation at the Geological Society of America Annual Meeting, Pittsburgh, PA, October 15-18, 2023.
Mackey, Justin↗
Characterization of the Oriskany and Berea Sandstones: Evaluating Biogeochemical Reactions of Potential Sandstone–Hydraulic Fracturing Fluid Interaction
The Marcellus shale, located in the mid-Atlantic Appalachian Basin, has been identified as a source for natural gas and targeted for hydraulic fracturing recovery methods. Hydraulic fracturing is a technique used by the oil and gas industry to access petroleum reserves in geologic formations that cannot be accessed with conventional drilling techniques (Capo et al., 2014). This unconventional technique fractures rock formations that have low permeability by pumping pressurized hydraulic fracturing fluids into the subsurface. Although the major components of hydraulic fracturing fluid are water and sand, chemicals, such as recalcitrant biocides and polyacrylamide, are also used (Frac Focus, 2015). There is domestic concern that the chemicals could reach groundwater or surface water during transport, storage, or the fracturing process (Chapman et al., 2012). In the event of a surface spill, understanding the natural attenuation of the chemicals in hydraulic fracturing fluid, as well as the physical and chemical properties of the aquifers surrounding the spill site, will help mitigate potential dangers to drinking water. However, reports on the degradation pathways of these chemicals are limited in existing literature. The Appalachian Basin Marcellus shale and its surrounding sandstones host diverse mineralogical suites. During the hydraulic fracturing process, the hydraulic fracturing fluids come into contact with variable mineral compositions. The reactions between the fracturing fluid chemicals and the minerals are very diverse. This report: 1) describes common minerals (e.g. quartz, clay, pyrite, and carbonates) present in the Marcellus shale, as well as the Oriskany and Berea sandstones, which are located stratigraphically below and above the Marcellus shale; 2) summarizes the existing literature of the degradation pathways for common hydraulic fracturing fluid chemicals [polyacrylamide, ethylene glycol, poly(diallyldimethylammonium chloride), glutaraldehyde, guar gum, and isopropanol]; 3) reviews the known research about the interactions between several hydraulic fracturing chemicals [e.g. polyacrylamide, ethylene glycol, poly(diallyldimethylammonium chloride), and glutaraldehyde] with the minerals (quartz, clay, pyrite, and carbonates) common to the lithologies of the Marcellus shale and its surrounding sandstones; and 4) characterizes the Berea sandstone and analyzes the physical and chemical effects of flowing guar gum through a Berea sandstone core.
58 GEOSCIENCES↗
Subcritical fracturing of shales under chemically reactive conditions
Growth of opening-mode fractures under chemically reactive subsurface conditions is potentially relevant for seal integrity in subsurface CO2 storage and hazardous waste disposal. Using double-torsion load relaxation tests we determine mode-I fracture toughness (KIC), subcritical index (SCI), and the stress-intensity factor vs fracture velocity (K-V) behavior of Marcellus, Woodford, and Mancos shales. Samples are tested under ambient air and aqueous conditions with variable NaCl and KCl concentrations, variable pH, and temperatures of up to 70°C. Under ambient air condition, KIC determined from double torsion tests is 1.3, 0.6, and 1.1 MPa∙m1/2 for Marcellus, Woodford, and Mancos shales, respectively. SCI under ambient air condition is between 55 and 90 for the shales tested. Tests in aqueous solutions show a significant drop of KIC compared to ambient air condition. For tests in deionized water, KIC reduction is 18.5% for Marcellus and 47.0% for Woodford. The presence of aqueous fluids also results in a reduction of the SCI up to 85% compared to ambient condition. K-V curves generally obey a power-law relation throughout the load-relaxation period. However, aqueous-based tests on samples result in K-V curves deviating from the power-law relation, with the SCI values gradually decreasing with time during the relaxation period. This non-power-law behavior is obvious in Woodford and Mancos, but negligible in Marcellus. We find that the shales interact with the aqueous solution both at the fracture tip and within the rock matrix during subcritical fracturing. For Marcellus shale, water mainly interacts with the fracture tip on both tests due to low matrix permeability and less reactive mineral composition. However, Woodford and Mancos react strongly with water causing significant sample degradation. The competition between degradation and fracture growth results in the time-dependent SCI: at lower fracture velocities, the tip interacts longer with the chemically altered area around the tip; at higher fracture velocities, the fracture propagates through the altered area before significant degradation. Our results display strong weakening effects of chemically reactive fluids on subcritical fracture properties with implications on subsurface storage seal performance.
58 GEOSCIENCES↗
Assessing impacts of unconventional natural gas extraction on microbial communities in headwater stream ecosystems in Northwestern Pennsylvania
Hydraulic fracturing and horizontal drilling have increased dramatically in Pennsylvania Marcellus shale formations, however the potential for major environmental impacts are still incompletely understood. High-throughput sequencing of the 16S rRNA gene was performed to characterize the microbial community structure of water, sediment, bryophyte, and biofilm samples from 26 headwater stream sites in northwestern Pennsylvania with different histories of fracking activity within Marcellus shale formations. Further, we describe the relationship between microbial community structure and environmental parameters measured. Approximately 3.2 million 16S rRNA gene sequences were retrieved from a total of 58 samples. Microbial community analyses showed significant reductions in species richness as well as evenness in sites with Marcellus shale activity. Beta diversity analyses revealed distinct microbial community structure between sites with and without Marcellus shale activity. For example, operational taxonomic units (OTUs) within the Acetobacteracea, Methylocystaceae, Acidobacteriaceae, and Phenylobacterium were greater than three log-fold more abundant in MSA+ sites as compared to MSA- sites. Further, several of these OTUs were strongly negatively correlated with pH and positively correlated with the number of well-pads in a watershed. It should be noted that many of the OTUs enriched in MSA+ sites are putative acidophilic and/or methanotrophic populations. This study revealed apparent shifts in the autochthonous microbial communities and highlighted potential members that could be responding to changing stream conditions as a result of nascent industrial activity in these aquatic ecosystems.
beta diversity↗
Measurements and modeling to quantify emissions of methane and VOCs from shale gas operations: Final Report
The objectives of the project were to determine the leakage rates of methane and ozone-forming Volatile Organic Compounds (VOCs) and the emission rates of air toxics from Marcellus shale gas activities. Methane emissions in the Marcellus Shale region were differentiated between “newer” sources associated with shale gas development and “older” sources associated with coal or conventional natural gas exploration. This project conducted measurements of methane and VOC emissions from both shale and non-shale natural gas resources. The initial scope of the project was the Marcellus Shale basin, and measurements were conducted in both the western wet gas regions (southwest PA and WV) and eastern dry gas region (northeast PA) of the basin. During this project, we obtained additional funding from other agencies to expand the scope of measurements to include additional basins. The data from both the Marcellus and other basins were combined to construct a national analysis of methane emissions from oil & gas production activities.
03 NATURAL GAS↗
Refined Lithostratigraphy of Middle and Upper Devonian shales in West Virginia
The evolution of the formal lithostratigraphy for the Middle and Upper Devonian strata in the central Appalachian basin has been complex. The original terminology (Chemung, Portage, Marcellus, Catskill, and others) was assigned late in the 19th century. However, by the 1930s, the realization that these units changed in nature dramatically when traced laterally resulted in a crisis in stratigraphy that forced the differentiation of chronostratigraphy from lithostratigraphy. Further, the sheer size of the basin creates challenges, as stratigraphic terminology defined by examination along the outcrop belts at the basin margins is difficult to extend into the subsurface due to the distances involved, the different nature of outcrop and subsurface data, the different perspective of workers attempting to extend units either from the north and west or from the east, and the complex facies changes within the strata. As a result, the facies architecture and associated lithostratigraphic nomenclature for many Middle and Upper Devonian units remained unsettled, particularly in the basin center. This study uses log data from nearly 400 wells from West Virginia to produce detailed maps of the economically important, organic-rich facies and identifies various associated vertical and lateral lithostratigraphic unit boundaries. The study focuses on the Middle Devonian Hamilton Group and its constituent Marcellus and Mahantango formations. Within the Marcellus, a lower Union Springs Member, a middle Cherry Valley Member, and an upper Oatka Creek Member are defined within northeastern West Virginia only. Throughout the rest of the subsurface of the State, the Marcellus has no distinguishable members. In the Upper Devonian, the occurrence and limits of the Harrell Shale (and its basal Burket Shale Member), and its westward lateral transition into the largely-correlative Genesee Formation (with basal Geneseo Shale and upper West River Shale members) are mapped. Maps also detail the position at which the Sonyea Formation (with basal Middlesex Shale and upper Cashaqua Shale members), West Falls Formation (with basal Rhinestreet Shale and upper Angola Shale members), Java Formation (undifferentiated), and lower part of the Huron Member of the Ohio Shale transition eastward into age-equivalent strata of the Brallier Formation.
Boswell, Ray↗
Computed Tomography Scanning and Geophysical Measurements of Core from the Coldstream 1MH Well
The computed tomography (CT) facilities and the Multi-Sensor Core Logger (MSCL) at the National Energy Technology Laboratory (NETL) Morgantown, West Virginia site were used to characterize core of the Marcellus Shale from a vertical well, the Coldstream 1MH Well in Clearfield County, PA. The core is comprised primarily of the Marcellus Shale from a depth of 7,002 to 7,176 ft. The primary impetus of this work is a collaboration between West Virginia University (WVU) and NETL to characterize core from multiple wells to better understand the structure and variation of the Marcellus and Utica shale formations. As part of this effort, bulk scans of core were obtained from the Coldstream 1MH well, provided by the Energy Corporation of America (now Greylock Energy). This report, and the associated scans, provide detailed datasets not typically available from unconventional shales for analysis. The resultant datasets are presented in this report, and can be accessed from NETL's Energy Data eXchange (EDX) online system using the following link: https://edx.netl.doe.gov/dataset/coldstream-1mh-well. All equipment and techniques used were non-destructive, enabling future examinations to be performed on these cores. None of the equipment used was suitable for direct visualization of the shale pore space, although fractures and discontinuities were detectable with the methods tested. Low resolution CT imagery with the NETL medical CT scanner was performed on the entire core. Qualitative analysis of the medical CT images, coupled with x-ray fluorescence (XRF), P-wave, and magnetic susceptibility measurements from the MSCL were useful in identifying zones of interest for more detailed analysis as well as fractured zones. En echelon fractures were observed at 7,100 ft and were CT scanned using NETL’s industrial CT scanner at higher resolution. The ability to quickly identify key areas for more detailed study with higher resolution will save time and resources in future studies. The combination of methods used provided a multi-scale analysis of this core and provides both a macro and micro description of the core that is relevant for many subsurface energy-related examinations that have traditionally been performed at NETL.
03 NATURAL GAS↗
Method to account for natural fracture induced elastic anisotropy in geomechanical characterization of shale gas reservoirs
Shale has been usually recognized as a transverse isotropic (TI) medium in conventional geomechanical log interpretation due to its laminated nature. However, when natural fractures exist in the shale rock, additional elastic anisotropy is introduced, converting laminated Shale to an orthorhombic (OB) medium. Previous studies illustrate that neglecting the natural fracture induced anisotropy in shale geomechanical log interpretation could lead to inaccurate evaluations of elastic moduli and in-situ stresses. In this paper, a new method is developed to account for the natural fracture induced anisotropy in geomechanical log interpretation based upon the TI acoustic model developed by the author and a characterization technique of elastic wave anisotropy (Sayers, 1991). The new OB model incorporates the four acoustic log data inputs and five modeling constraints in a nonlinear optimization algorithm to solve for the nine independent stiffness coefficients of an OB rock, and further to solve for the geomechanical properties and in-situ stress profiles in an OB formation. The new method was validated with a Marcellus Gas Shale field case. Both the new OB model and the conventional TI model were applied to interpret the minimum horizontal stress profile for the same formation. By comparing the results, the OB model is more robust than the TI from two aspects. First, the average stress magnitude predicted by the OB model is closer to the one measured by the Diagnostic Fracture Injection Test (DFIT). Second, the OB model predicts a more obvious stress barrier between the lower Marcellus and upper Onondaga Limestone than the TI model does. Finally, the predicted stress barrier is consistent with the observation of the microseismic events of a horizontal well drilled and completed nearby, which reveals that no hydraulic fracture propagates downward through the bottom boundary of Marcellus Shale into the underlying Onondaga Limestone.
03 NATURAL GAS↗
Response of Aquatic Bacterial Communities to Hydraulic Fracturing in Northwestern Pennsylvania: A Five-Year Study
Horizontal drilling and hydraulic fracturing extraction procedures have become increasingly present in Pennsylvania where the Marcellus Shale play is largely located. The potential for long-term environmental impacts to nearby headwater stream ecosystems and aquatic bacterial assemblages is still incompletely understood. Here, we perform high-throughput sequencing of the 16 S rRNA gene to characterize the bacterial community structure of water, sediment, and other environmental samples (n = 189) from 31 headwater stream sites exhibiting different histories of fracking activity in northwestern Pennsylvania over five years (2012–2016). Stream pH was identified as a main driver of bacterial changes within the streams and fracking activity acted as an environmental selector for certain members at lower taxonomic levels within stream sediment. Methanotrophic and methanogenic bacteria (i.e. Methylocystaceae, Beijerinckiaceae, and Methanobacterium ) were significantly enriched in sites exhibiting Marcellus shale activity (MSA+) compared to MSA- streams. This study highlighted potential sentinel taxa associated with nascent Marcellus shale activity and some of these taxa remained as stable biomarkers across this five-year study. Identifying the presence and functionality of specific microbial consortia within fracking-impacted streams will provide a clearer understanding of the natural microbial community’s response to fracking and inform in situ remediation strategies.
58 GEOSCIENCES↗
Evaluating proxies for the drivers of natural gas productivity using machine-learning models
We report the extensive development of unconventional reservoirs using horizontal drilling and multistage hydraulic fracturing has generated large volumes of reservoir characterization and production data. The analysis of this abundant data using statistical methods and advanced machine-learning (ML) techniques can provide data-driven insights into well performance. Most predictive modeling studies have focused on the impact that different well completion and stimulation strategies have on well production but have not fully exploited the available in situ rock property data to determine its role in reservoir productivity. We have used machine-learning techniques to rank rock mechanical properties, microseismic attributes, and stimulation parameters in the order of their significance for predicting natural gas production from an unconventional reservoir. The data for this study came from a hydraulically fractured well in the Marcellus Shale in Monongalia County, West Virginia. The data classes included measurements aggregated by well completion stage that included (1) gas production, (2) well-log-derived measurements including bulk density, elastic moduli, shear impedance, compressional impedance, brittleness, and gamma measurements, (3) microseismic attributes, (4) long-period long-duration (LPLD) event counts, (5) fracture counts, and (6) stimulation parameters that included the fluid injection volume and average pumping pressure. To identify observable proxies for the drivers of gas production, we evaluated five commonly used ML approaches including multivariate adaptive regression spline, Gaussian mixture model, random forest, gradient boosting, and neural network. We selected five variables including LPLD event count, seismogenic b-value, hydraulic diffusivity, cumulative moment, and fluid volume as the features most likely to impact gas productivity at the stage level in the study area. The data-driven selection of these parameters for their importance in determining gas production can help reservoir engineers design more effective hydraulic-fracture treatments in the Marcellus Shale and other similar unconventional reservoirs. Plain language summary: We use machine-learning methods and data-driven selection of reservoir parameters to rank and better understand their importance in determining gas production, which can help reservoir engineers design more effective hydraulic-fracture treatments in the Marcellus Shale and other similar unconventional reservoirs.
58 GEOSCIENCES↗
TA [2] Continuous, regional methane emissions estimates in northern Pennsylvania gas fields using atmospheric inversions
Natural Gas (NG) production activities in the northeastern Marcellus shale have significantly increased in the last decade, possibly releasing large amounts of methane (CH 4 ) into the atmosphere from the operations at the productions sites and during the processing and transmission steps of the natural gas chain. Based on an intensive aircraft survey, leakage rates from the NG production were quantified in May 2015 and found to be in the order of 0.5% of the total production, higher than reported by the Environmental Protection Agency (EPA) but below the usually observed leakage rates over the shale gases in the US. Thanks to the high production rates on average at each well, leakage rates normalized by production appeared to be low in the northeastern Marcellus shale. This result confirms that natural gas production using unconventional techniques in this region is emitting relatively less CH 4 into the atmosphere than other shale reservoirs. The low emissions rate can be explained in part by the high productivity of wells drilled across the northeastern Marcellus region. We demonstrated here that atmospheric monitoring techniques can provide an independent quantification of NG leakage rates using aircraft measurements. The CH 4 analyzers were successfully calibrated at four sites across the region, measuring continuously the atmospheric CH 4 mixing ratios and isotopic 13 Ch 4 . Our preliminary findings confirm the low leakage rates from tower data collected over September 2015 to November 2016 compared to the aircraft mass-balance estimates in may 2015. However, several episodes revealing large releases of natural gas over several weeks showed that temporal variations in the emissions of CH 4 may increase the actual leakage rate over longer time periods.
03 NATURAL GAS↗
Computed Tomography Scanning and Geophysical Measurements of Core from the Boggess 17H Well
The computed tomography (CT) facilities and the Multi-Sensor Core Logger (MSCL) at the National Energy Technology Laboratory (NETL) in Morgantown, West Virginia were used to characterize the Marcellus Shale and underlying formations. The core is from a vertical pilot well (Boggess 17H) drilled in western Monongalia County near Core, West Virginia by Northeast Natural Energy for the second Marcellus Shale Energy and Environmental Laboratory (MSEEL). MSEEL is a joint venture between NETL, Northeast Natural Energy, and West Virginia University. The primary impetus for this report is to characterize the core to better understand the structure and variation of the Marcellus Shale and surrounding formations. This report, and the associated scans, provide detailed datasets not typically available from unconventional shales for analysis.
58 GEOSCIENCES↗
Geochemical characterization of lithium deposition in fossil energy wastes
Lithium is a critical mineral used in rechargeable batteries for electric vehicles (EVs) and future modernization of electric grids with sensitive supply chains that are subject to volatility. Therefore, methods to recover lithium from domestic unconventional sources are actively being pursued in the United States. Herein, we report on the lithium recovery potential from four fossil energy waste feedstocks: oil and gas drill cuttings (sample number n = 16); oil and gas produced waters (n > 200) from Marcellus, Bakken and Permian basins; coal byproducts (n>20), such as coal ash; and acid mine drainage treatment solids (AMD solids). Select solid samples underwent sequential extraction to explore lithium hosting phases and simple organic and inorganic acid extraction to explore lithium recovery potential. Our preliminary results found lithium concentrations up to 440 mg/kg in select AMD treatment solids and up to 300 mg/L in Marcellus Shale produced waters, demonstrating these sources have lithium yield potentials comparable to conventionally mined lithium ores and brines. Sequential extractions revealed that lithium is mostly associated with clay and silicate phases in shale drill cuttings, whereas lithium resides in Fe,Mn-oxide reducible phases in AMD solids. Further, the lithium content in produced waters has a strong linear relationship with total dissolved solid (TDS) levels in three separate oil and gas basins. At the same TDS level, Marcellus Shale produced waters contain more lithium compared to Bakken Shale and Permian Basin waters, with higher percentages of Ca and Mg, major cations that might impact lithium recovery efficiencies. Our study demonstrates the heterogeneity of lithium hosts from different fossil energy wastes. Characterization results will inform future lithium recovery from these different feedstocks.
Stuckman, Mengling↗
Predicting the potential for mineral scale precipitation in unconventional reservoirs due to fluid-rock and fluid mixing geochemical reactions
Mineral precipitation within hydraulically fractured shale may affect fluid flow pathways and impact longterm hydrocarbon production. The ability to predict geochemical reactions that lead to problematic mineral precipitation will lead to active reservoir management strategies to improve overall production. Using the Marcellus Shale as a case study, a combination of laboratory experiments and reaction path modeling was applied to determine which reactions are likely to occur upon introduction of hydraulic fracturing fluid into the shale reservoir. Experimental results indicate that contact between fracturing fluid and shale will result in dissolution of primary minerals (quartz, feldspars, kaolinite, chlorite, pyrite) and secondary mineral precipitation over time periods of less than one week. Precipitation of barite, Fe-oxides, feldspars, amorphous silica and clay is likely to occur within the reservoir during shut in and early flowback due to mixing between fracturing fluid and reservoir brine as based on modeling saturation indices using experimental fluid data. Reaction path modeling of the experimental scenarios corroborates the specific dissolution and precipitation reactions observed experimentally. Comparison of the results to injected and produced waters from a Marcellus Shale well pad in Greene County, PA, USA, shows that the mineral reactions occur during the hydraulic fracturing, shut in, and early flowback periods. The results presented in this paper demonstrate the value in applying experimental approaches to identify mineral precipitation/dissolution reactions that may significantly impact reservoir performance. The good agreement between geochemical models and experimental results provides confidence that numerical models can be applied to screen the potential fluid-mineral and fluid-mixing reactions in unconventional reservoirs that result in undesired mineral scale precipitation.
58 GEOSCIENCES↗
Extraction of organic compounds from representative shales and the effect on porosity
This study is an attempt to understand how native organics are distributed with respect to pore size to determine the relationship between hydrocarbon chemistry and pore structure in shales, as the location and accessibility of hydrocarbons is key to understanding and improving the extractability of hydrocarbons in hydraulic fracturing. Selected shale cores from the Eagle Ford and Marcellus formations were subjected to pyrolysis gas chromatography (GC), thermogravimetric analysis, and organic solvent extraction with the resulting effluent analyzed by GC-mass spectrometry (MS). Organics representing the oil and gas fraction (0.1 to 1 wt. %) were observed by GC-MS. For most of the samples, the amount of native organic extracted directly related to the percentage of clay in the shale. The porosity and pore size distribution (0.95 nm to 1.35 m) in the Eagle Ford and Marcellus shales was measured before and after solvent extraction using small angle neutron scattering (SANS). An unconventional method was used to quantify the background from incoherent scattering as the Porod transformation obscures the Bragg peak from the clay minerals. Furthermore, the change in porosity from SANS is indicative of the extraction or breakdown of higher molecular weight bitumen with high C/H ratios (asphaltenes and resins). This is mostly likely attributed to complete dissolution or migration of asphaltenes and resins. These longer carbon chain lengths, C30-C40, were observed by pyrolysis GC, but either were too heavy to be analyzed in the extracts by GC-MS or were not effectively leached into the organic solvents. Thus, experimental limitations meant that the amount of extractable material could not be directly correlated to the changes in porosity measured by SANS. But, the observable porosity generally increased with solvent extraction. A decrease in porosity after extraction as observed in a shale with high clay content and low maturity was attributed to swelling of pores with solvent uptake or migration of resins and asphaltenes.
04 OIL SHALES AND TAR SANDS↗
Gaining Perspective on Unconventional Well Design Choices through Play-level Application of Machine Learning Modeling
The recent development of unconventional oil and gas (O&G) reservoirs has led to an abundant hydrocarbon supply, both domestically and globally. However, there is a continued push to develop new and innovative approaches to improve exploration and extraction efficiencies and overall well productivity moving forward. Substantial improvements in unconventional O&G development are expected through optimized well completion and stimulation strategies aimed at maximizing well productivity. Optimizing well designs will require tailoring to the distinctive geologic conditions present for any newly placed well. To better evaluate the impact of well design attributes and their associated interactions on productivity in a major unconventional play, multivariate machine learning-based models that use empirical datasets were developed. A gradient boosted regression tree (GBRT) algorithm was applied. GBRT has been narrowly investigated for O&G applications but enables straightforward parametric importance and influence evaluation, as well as assessment of parameter interaction effects. Models were trained on well design and locational parameters that serve as a proxy for variable geologic conditions to estimate two types of productivity indicator response variables strongly correlated to estimated ultimate recovery (EUR). The dataset utilized consists of over 7,000 well observations that cover the majority of the productive region of the Marcellus Shale. Model performance was evaluated and algorithm parameters tuned by analyzing the goodness-of-fit for simulated results against observed data in a cross-validation approach. Models were found capable of 73–79 percent prediction accuracy on held out testing data of gas equivalent production and can be used to inform future well design and placement decisions for increasing EUR per well and improving overall field-level recovery. Study results indicate that Marcellus well performance improves most with upscaling perforated interval lengths and water and proppant volumes per foot; but relative productivity improvements are spatially dependent across the play. Finally, optimal combinations of water and proppant on well performance were found to vary depending on well location, emphasizing the utility of data-driven models capable of broad application across a play of interest for informing tailored well design approaches prior to their field deployment.
04 OIL SHALES AND TAR SANDS↗
Goff55 Well
CT and core logger data from the Nathan Goff #55 well, Brown Lumberport Field, and is comprised primarily of the Marcellus Formation from depths of 7,043 to 7,235.75 ft. For full details please see Brown, S.; Crandall, D.; Moore, J.; Mackey, P.; Martin, K.; Carr, T. CT Scanning and Geophysical Measurements of the Marcellus Formation from the Nathan Goff #55 Well; NETL-TRS-10-2018; NETL Technical Report Series; U.S. Department of Energy, National Energy Technology Laboratory: Morgantown, WV, 2018; p 48. DOI: 10.18141/1436857.
Computed Tomography↗