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At least 127 records · Page 7
All sourcesNASA NTRSDOE OSTI
DOE OSTI2019

Effect of Water on Fracture Mechanical Properties of Shales

Abstract Recognition of the potential for subcritical fracture growth of rocks is essential for the evaluation of long‐term stability of fluids trapped in geologic structures. In shales, subcritical fracture growth may control migration of hydrocarbons in source rock and unconventional reservoirs and of sequestered CO 2 across top seals. Using the double torsion method, we investigated the mode‐I fracture mechanical properties of three shales of different composition, namely, Woodford Shale, Mancos Shale, and Marcellus Shale, under water‐saturated conditions, in ambient air, and in dry CO 2 gas conditions to systematically investigate the effect of water on the fracture growth properties of shales. The clay‐rich (illite with minor kaolinite) Woodford and Mancos Shales demonstrate a strong water‐weakening effect despite their low smectite content, with the fracture toughness reduced by up to 54% and the subcritical fracture growth index by up to 77% under water‐saturated conditions compared to tests in ambient air. Carbonate‐rich Marcellus Shale, in contrast, displays negligible water‐weakening effects. The clay‐CO 2 interaction is minor for the three shales. Specimens treated with a hydrophobic surface coating were also tested to limit water‐weakening effects to the fracture tip. Data from these tests reveal rate‐dependent stress intensity factor‐velocity curves for clay‐rich Woodford and Mancos Shales suggesting a competition between mechanical fracture growth and physicochemical water‐rock interactions. Our results suggest that subcritical failure by water‐enhanced subcritical fracture growth could significantly increase brittle failure in clay‐rich shales.

Chen, Xiaofeng↗
DOE OSTI2022

Uniformity and volume-representativity of consecutive submillimetre wafers of shale for SANS and USANS investigations

(Ultra) Small Angle Neutron Scattering (SANS/USANS) is a non-destructive technique suitable for characterization of porous structures from nano- to micro-pore size (1 nm to 20 μm), which has been widely used to characterize accessible and inaccessible porosity in tight unconventional hydrocarbon reservoirs (e.g., shales). Here, in this study, SANS and USANS are used to examine the degree of nano- to micropore uniformity of the rock body on sub-millimetre to centimetre scale. This study presents a test of the hypothesis of volume representativity of pore structure information measured by SANS and USANS for shale wafers (0.22–1 mm) cut from six North American unconventional shale cores of different maturities (New Albany Shale and Marcellus Shale). Experimental reproducibility of USANS is further investigated for two wafers measured using various acquisition times. All samples show that fluctuations of the relative intensity generally decrease from the USANS Q-range (pore size from around 200 nm to 20 μm) to most of the SANS Q-range (pore size from around 5 nm to 700 nm), and peaks in the SANS large-Q region (for pores smaller than about 5 nm). There is a positive correlation between the spatial fluctuation of the relative SANS intensity and the scattering power of shales. In addition, the scattering intensity and its fluctuations is larger for the less mature shale cores. Shale is known to be highly heterogenous and the hypothesis of uniformity does not apply at sub-millimetre scale even for samples that appear homogeneous at visual inspection. This study presents an approach to minimise the variation through sample selection, data interpretation methodology and instrumental reproducibility tests. The best values of the microstructural spatial uniformity for the apparently homogeneous sections of a core (i.e., the SANS and USANS intensity variation) is less than ±10%.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2016

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↗
DOE OSTI2014

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↗
DOE OSTI2014

The Coal-Seq III Consortium. Advancing the Science of CO 2 Sequestration in Coal Seam and Gas Shale Reservoirs

The Coal-Seq consortium is a government-industry collaborative that was initially launched in 2000 as a U.S. Department of Energy sponsored investigation into CO2 sequestration in deep, unmineable coal seams. The consortium’s objective aimed to advancing industry’s understanding of complex coalbed methane and gas shale reservoir behavior in the presence of multi-component gases via laboratory experiments, theoretical model development and field validation studies. Research from this collaborative effort was utilized to produce modules to enhance reservoir simulation and modeling capabilities to assess the technical and economic potential for CO2 storage and enhanced coalbed methane recovery in coal basins. Coal-Seq Phase 3 expands upon the learnings garnered from Phase 1 & 2, which has led to further investigation into refined model development related to multicomponent equations-of-state, sorption and diffusion behavior, geomechanical and permeability studies, technical and economic feasibility studies for major international coal basins the extension of the work to gas shale reservoirs, and continued global technology exchange. The first research objective assesses changes in coal and shale properties with exposure to CO2 under field replicated conditions. Results indicate that no significant weakening occurs when coal and shale were exposed to CO2, therefore, there was no need to account for mechanical weakening of coal due to the injection of CO2 for modeling. The second major research objective evaluates cleat, Cp, and matrix, Cm, swelling/shrinkage compressibility under field replicated conditions. The experimental studies found that both Cp and Cm vary due to changes in reservoir pressure during injection and depletion under field replicated conditions. Using laboratory data from this study, a compressibility model was developed to predict the pore-volume compressibility, Cp, and the matrix compressibility, Cm, of coal and shale, which was applied to modeling software to enhance model robustness. Research was also conducted to improve algorithms and generalized adsorption models to facilitate realistic simulation of CO2 sequestration in coal seams and shale gas reservoirs. The interaction among water and the adsorbed gases, carbon dioxide (CO2), methane (CH4), and nitrogen (N2) in coalbeds is examined using experimental in situ laboratory techniques to comprehensively model CBM production and CO2 sequestration in coals. An equation of state (EOS) module was developed which is capable of predicting the density of pure components and mixtures involving the wet CBM gases CH4, CO2, and N2 at typical reservoir condition, and is used to inform CO2 injection models. The final research objective examined the effects adsorbed CO2 has on coal strength and permeability. This research studied the weakening or failure of coal by the adsorption of CO2 from empirically derived gas production data to develop models for advanced modeling of permeability changes during CO2 sequestration. The results of this research effort have been used to construct a new and improved model for assessing changes in permeability of coal reservoirs due CO2 injection. The modules developed from these studies and knowledge learned are applied to field validation and basin assessment studies. These data were used to assess the flow and storage of CO2 in a shale reservoir, test newly developed code against large-scale projects, and conduct a basin-oriented review of coal storage potential in the San Juan Basin. The storage potential and flow of CO2 was modeled for shale sequestration of a proprietary Marcellus Shale horizontal gas production well using COMET3 simulation software. Simulation results from five model runs indicate that stored CO2 quantities are linked to the duration of primary production preceding injection. Matrix CO2 saturation is observed to increase in each shale zone after injection with an increase in primary production, and the size of the CO2 plume is also observed to increase in size the longer initial production is sustained. The simulation modules developed around the Coal-Seq experimental work are also incorporated into a pre-existing large-scale numerical simulation model of the Pump Canyon CO2-ECBM pilot in the San Juan Basin. The new model was applied to re-history match the data set to explore the improvements made in permeability prediction against previously published data sets and to validate this module. The assessment of the new data, however, indicates that the impact of the variable Cp is negligible on the overall behavior of the coal for CO2 storage purposes. Applying these new modules, the San Juan Basin and the Marcellus Shale are assessed for their technical ECBM/AGR and CO2 storage potential and the economic potential of these operations. The San Juan Basin was divided into 4 unique geographic zones based on production history, and the Marcellus was divided into nine. Each was assessed based upon each zone’s properties, and simulations were run to assess the potential of full Basin development. Models of a fully developed San Juan Basin suggest the potential for up to 104 Tcf of CO2 storage, and 12.3 Tcf of methane recovery. The Marcellus models suggest 1,248 Tcf of CO2 storage and 924 Tcf of AGR. The economics are deemed favorable where credits cover the cost of CO2 in the San Juan Basin, and in many cases in the Marcellus, but to maximize storage potential, credits need to extend to pay the operator to store CO2.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2017

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↗
DOE OSTI2024

Characterizing Radium Distributions, Source Attribution and Impacts from Marcellus Produced Water

This presentation characterizes spatial trends in radium (Ra) concentrations, sources, and potential impacts generated from Marcellus Shale produced waters. Here, we combine previously published produced water data with additional Ra activity measurements extracted from residual waste reports submitted to the Pennsylvania Department of Environmental Protection from 2012-2023. This is the largest, spatially referenced compilation of Ra activity measurements from produced water sourced from the Marcellus Shale to date. The median Marcellus Shale produced water Ra activity presented here is 6,906 pCi/L (interquartile range = 12,515 pCi/L). Radium activities in the positively skewed dataset can exceed 30,000 pCi/L in some parts of the state. The regional trends in Ra concentrations and isotopic ratios will be characterized and potential environmental and health implications discussed.

Mackey, Justin↗
DOE OSTI2022

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↗
DOE OSTI2018

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↗
DOE OSTI2018

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↗
DOE OSTI2021

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↗
DOE OSTI2020

Chemical Speciation and Stability of Uranium in Unconventional Shales: Impact of Hydraulic Fracture Fluid

Uranium and other radionuclides are prominent in many unconventional oil/gas shales and is a potential contaminant in flowback/produced waters due to the large volumes/types of chemicals injected into the subsurface during stimulation. In this work, to understand the stability of U before and after stimulation, a geochemical study of U speciation was carried out on three shales (Marcellus, Green River, and Barnett). To do so, two types of samples for each shale were subjected to sequential chemical extractions: unreacted and shale-reacted with a synthetic hydraulic fracture fluid. Furthermore, a significant proportion of the total U (20–57%) was released from these three shales after reaction with fracture fluid, indicating that U is readily leachable. The total U released exceeds labile water-soluble and exchangeable fractions in unreacted samples, indicating that fluids leach more recalcitrant phases in the shale. Radiographic analysis of unreacted Marcellus shale thin sections shows U associated with detrital quartz and the clay matrix in the shale. Detrital zircon and TiO2 identified by an electron microprobe could account for the hot spots. This study shows that significant proportions of U in three shales are mobile upon stimulation. In addition, the extent of mobilization of U depends on the U species in these rocks.

58 GEOSCIENCES↗