Search

A continuous core drilled in the Barnett Shale Formation (Fort Worth Basin, Texas, United States), a remarkable example of Paleozoic organic-rich sediments deposited in a narrow inland seaway, was analysed by means of sedimentological, geochemical and biostratigraphic data. As the influence of sea-level fluctuations on benthic anoxia in ancient seas is still poorly understood, our work aims to shed light on the control exerted by relative sea-level variations on the paleoceanographic processes that drove fine-grained sediment deposition, organic matter dispersal and preservation during the sedimentation of the Barnett Shale Formation. Using spectral gamma-ray log a large second-order sequence modulated by a total of thirteen third-order sequences was inferred. Third-order relative sea-level cycles modulated the level of restriction of the basin through time, alternating pulses of bottom-water oxygenation and relatively more efficient watermass circulation with times of sluggish bottom-water and stagnation, which controlled the facies stacking pattern and organic matter preservation. In particular, relatively increased stagnation occurred during lowstand phases, while relatively reduced restriction was principally associated with transgressive and highstand systems tracts with more efficient bottom current circulation. On a larger scale, second-order eustatic cycles played a crucial role in determining the paleoceanographic and depositional processes responsible for anoxia. During the early phase of sea-level rise, the pre-existing topography was flooded establishing the conditions for a shallow strongly restricted anoxic basin. During the second-order regression the basin experienced increased isolation with bottom-water stagnation and deep-water renewal of ~ 6000 years. Anoxia terminated abruptly, corresponding to the eustatic sea-level rise associated with the beginning of a new second-order sequence. Therefore, the Barnett Shale Formation represents a significant example of the complex interplay between sea-level-controlled basin physiography and local paleoceanographic conditions.

Oil and natural gas operations have continued to expand and move closer to densely populated areas, contributing to growing public concerns regarding exposure to hazardous air pollutants. During the Barnett Shale Coordinated Campaign in October, 2013, ground-based whole air samples collected downwind of oil and gas sites revealed enhancements in several potentially toxic volatile organic compounds (VOCs) when compared to background values. Molar emissions ratios relative to methane were determined for hexane, benzene, toluene, ethylbenzene, and xylene (BTEX compounds). Using methane leak rates measured from the Picarro mobile flux plane (MFP) system and a Barnett Shale regional methane emissions inventory, the rates of emission of these toxic gases were calculated. Benzene emissions ranged between 51 ± 4 and 60 ± 4 kg h-1. Hexane, the most abundantly emitted pollutant, ranged from 642 ± 45 to 1070 ± 340 kg h-1. While observed hydrocarbon enhancements fall below federal workplace standards, results may indicate a link between emissions from oil and natural gas operations and concerns about exposure to hazardous air pollutants. The larger public health risks associated with the production and distribution of natural gas are of particular importance and warrant further investigation, particularly as the use of natural gas increases in the United States and internationally.

Our goal is to invert total organic carbon (TOC) using the multilayer perceptron neural network. Three-dimensional seismic data recorded near two horizontal wells drilled in the lower Barnett Shale Formation are used as input to train a neural machine, while the calculated acoustic impedance from sonic and density well-log data for the horizontal wells is used as output. The multilayer perceptron neural machine is trained in a supervised mode, and weights of connections are calculated. The full 3D seismic data are then propagated through this machine, and a cube of acoustic impedance is inverted. A crossplot of the acoustic impedance versus the TOC is used to provide a linear relationship between these two parameters. This relationship is used to suggest a 3D TOC cube from the inverted cube of the acoustic impedance. Obtained results are checked with the Schmoker's TOC of another horizontal well drilled in the lower Barnett. These results show the ability of the genetic inversion to enhance characterization of shale-gas reservoirs.

Background: There is an increasing awareness of the multiple potential pathways leading to human health risks from hydraulic fracturing. Setback distances are a legislative method to mitigate potential risks. Objectives: We attempted to determine whether legal setback distances between well-pad sites and the public are adequate in three shale plays. Methods: We reviewed geography, current statutes and regulations, evacuations, thermal modeling, air pollution studies, and vapor cloud modeling within the Marcellus, Barnett, and Niobrara Shale Plays. Discussion: The evidence suggests that presently utilized setbacks may leave the public vulnerable to explosions, radiant heat, toxic gas clouds, and air pollution from hydraulic fracturing activities. Conclusions: Our results suggest that setbacks may not be sufficient to reduce potential threats to human health in areas where hydraulic fracturing occurs. It is more likely that a combination of reasonable setbacks with controls for other sources of pollution associated with the process will be required. Citation: Haley M, McCawley M, Epstein AC, Arrington B, Bjerke EF. 2016. Adequacy of current state setbacks for directional high-volume hydraulic fracturing in the Marcellus, Barnett, and Niobrara Shale Plays. Environ Health Perspect 124:1323–1333; http://dx.doi.org/10.1289/ehp.1510547

Horizontal completions within a complex oil condensate window of the Barnett Shale have proven challenging because of problematic well placement within an optimum reservoir section and the vertical and mechanical proximity to mobile water in the Viola Limestone. Accurate formation properties along the horizontal well are required to identify both conditions in order to effectively avoid water production. At the request of the operator, a post-mortem study was conducted on a horizontal well in the Lower Barnett Shale to determine the cause of excessive water production. Completion optimization studies are typically conducted using wireline tools; however, for the purposes of this study, an advanced LWD logging suite consisting of electromagnetic azimuthal resistivity, neutron, azimuthal density, laterolog resistivity imager, and quadrapole sonic was run on the well. An integrated interpretation of all sensor data was used to first confirm the stratigraphic placement of the well and then evaluate effective porosity, anisotropic closure stress, geologic texture, and natural fracture distribution. Fracture stages and cluster stages were then selected to target similar rock and lowest closure stress along the well, while taking into consideration the existing natural fractures determined from the image log. Fracture-stage placement data, chemically traced production flow, and a flowing temperature log were all used to interpret well flow vs. the actual perforation cluster positions. This paper presents conclusions drawn regarding both the engineering evaluation criteria used to fracture the well, as well as the geologic-based texture and fracture interpretation that explains the ultimate well performance. Finally, a new automatic staging and cluster-placement software solution was employed to use insight gained from the case study well to better plan future horizontal completions within the field.

Summary Knowledge of water/rock interactions on the surface of fractures is important to develop an understanding of the geological structures and changes within the formation, and to determine hydraulic-fracturing (HF) performance. To obtain this knowledge, this study investigates water/shale interactions in carbonate-rich (Eagle Ford), organic-rich (Green River), clay-rich (Barnett), and other-minerals-rich (Marcellus) shale samples. Crushed shale samples were exposed to water for 3 weeks at reservoir conditions. The water and rock samples before and after each static experiment were subjected to several analyses. The change in the rock mineralogy was defined by X-ray diffraction (XRD), the elemental composition of rock was determined by X-ray photoelectron spectroscopy (XPS) and scanning electron microscopy energy dispersive spectroscopy (SEM-EDS), and the organic content of rock samples was estimated by thermogravimetric analysis (TGA). The water was analyzed for its anions and cations, total dissolved solids (TDS), conductivity, pH, total organic carbon (TOC), and average particle sizes of colloids. The stability of the colloids was characterized by zeta-potential. We show that Barnett rock is high in illite content, and the greatest calcite concentration is determined for Eagle Ford. The sulfate content of water correlates with the atomic percent of the sulfur and oxygen elements determined through XPS analyses. The magnesium content of water correlates mainly with the illite amount in the rock, and calcium concentration associates with the calcite and gypsum content of the rock samples. The greatest dissolution rate belongs to the minerals that yield sulfate in the water; then, gypsum and calcite that yield calcium cation in the water come second; and the lowest dissolution rates are obtained from the magnesium-containing minerals (mainly, dolomite). TDS of the water samples shows that Green River has the least tendency to interact with water, and Barnett has the greatest tendency. Zeta-potential values indicate that particles in the water that interacted with Eagle Ford have the highest tendency for precipitation. The results of this study are used to make suggestions on the engineering of hydraulic-fracturing fluids (HFFs) in the context of water/rock interactions by considering the type and the concentration of ions along with colloidal stability determined through zeta-potential measurements.

Knowledge of induced fractures can help to evaluate the success of reservoir stimulation. Seismic P-waves through fracturing media can exhibit azimuthal variation in traveltime, amplitude, and thin-bed tuning, so amplitude variation with azimuth (AVAz) can be used to evaluate the hydraulic-fracturing-caused anisotropy. The Barnett Shale of the Fort Worth Basin was the first large-scale commercial shale gas play. We have analyzed two adjacent Barnett Shale seismic surveys: one acquired before hydraulic fracturing and the other acquired after hydraulic fracturing by more than 400 wells. Although not a rigorous time-lapse experiment, comparison of AVAz anisotropy of these two surveys provided valuable insight into the possible effects of hydraulic fracturing. We found that in the survey acquired prior to hydraulic fracturing, AVAz anomalies were stronger and highly correlated with major structural lineaments measured by curvature. In contrast, AVAz anomalies in the survey acquired after hydraulic fracturing were weaker and compartmentalized by rather than correlated to the most-positive curvature lineaments. We found in five microseismic experiments within the survey that these ridge lineaments form fracture barriers. These findings suggested that future time-lapse experiments may be valuable in mapping the modified horizontal stress field to guide future drilling and in recognizing zones of bypassed pay.

Because of its significant impact on relative permeability, capillary pressure, stimulation methods, and ultimate recovery, the wettability of reservoir rocks is a critical factor of the petroleum recovery process. However, characterizing the wettability of shale with extremely low matrix permeabilities is a challenging task because of the dominant presence of nanopores in shale and high heterogeneity of shale compositions at multiple scales. From spontaneous imbibition behavior that uses two types of imbibing fluid (water and n-decane), the present study examines the wettability characteristics of gas-window Barnett Shale samples taken from four different depths of Texas United 1 Blakely core in Wise County in Texas. Imbibition experiments were conducted in two directions: parallel and transverse to the lamination of the samples. A scaling method was used to analyze imbibition data, and observed imbibition behaviors were interpreted to infer the different wettability conditions of four samples with different mineralogy, total organic carbon content, and pore-throat size distribution. Our results show that wettability significantly affects fluid imbibition behavior and that four tested samples can be divided into three wettability categories: more water wet, mixed wet, and more oil wet. Overall, the variable wettability of Barnett samples will affect hydrocarbon storage, distribution, and production.

Background: Sleep duration may influence risk for sarcopenia but studies on this topic are scarce, especially from low and- middle-income countries (LMICs). Thus, the aim of the present study was to investigate the association between sleep duration and sarcopenia among adults aged ≥ 65years from five LMICs (China, Ghana, India, Russia, South Africa). Methods: Cross-sectional, community-based data from the WHO study on global ageing and adult health (SAGE) were analysed. Sarcopenia was defined as having low skeletal muscle mass (SMM) and weak handgrip strength, while severe sarcopenia was defined as having low SMM, weak handgrip strength, and slow gait speed. Self-reported sleep duration in the past two nights were averaged and classified as ≤ 6, > 6 to ≤ 9, and ≥ 9h/day. Multivariable logistic regression analysis was conducted. Results: Data on 13,210 adults aged ≥ 65years [mean (SD) age 72.6 (11.3) years; 55.0% females] were analyzed. In the overall sample, compared to > 6 to ≤ 9h/day of sleep duration, > 9h/day was associated with 1.70 (95% CI 1.15–2.51) and 1.75 (95% CI 1.08–2.84) times higher odds for sarcopenia and severe sarcopenia, respectively. No significant associations were observed among males, but associations were particularly pronounced among females [i.e., OR = 2.19 (95% CI 1.26–3.81) for sarcopenia, and OR = 2.26 (95% CI 1.20–4.23) for severe sarcopenia]. Conclusions: Long sleep duration was associated with an increased odds of sarcopenia and severe sarcopenia in LMICs, particularly in females. Future studies should investigate whether addressing long sleep duration among females can lead to lower risk for sarcopenia onset in LMICs. © 2022, The Author(s), under exclusive licence to Springer Nature Switzerland AG.

With the increasing use of information communication technologies (ICT) for teaching and learning in the early years, this serves as a primary and timely textbook for early childhood education (ECE...

Microseismicity can be triggered by various dynamic processes related to a hydraulic fracturing treatment. These processes alter the in-situ stress field inside and around the stimulated reservoir volume, due to both creation of new fractures and fluid leakoff into the surrounding rock matrix. The analysis of spatiotemporal dynamics of fluid-induced seismicity can reveal important characteristics of the hydraulic fracturing process. With the knowledge of treatment data, it can be used in conjunction with the reservoir geomechanical theories in hydraulic fracture growth to investigate the fracture geometry and fluid-rock interactions. By applying these theories to a real microseismic dataset, two types of triggering front expansion patterns are evident. With the presence of a dominant hydraulic fracture, the radius of the triggering front expands linearly with time. Moreover, the microseismic event cloud forms a planar shape with low opening angles (failed by shear), indicating fracture slippages around the major hydraulic fracture. On the other hand, in the case of a complex fracture network with the absence of any major hyfraulic fracture, the triggering front grows non-linearly with time. This scenario can be treated as equivalent to a diffusion model and the microseismic events exhibit a higher fracture of tensile components (either opening or closing) and an equidimensional event cloud. In this study, two stages were analyzed and the derived fracture widths and fluid-loss coeffcients fall into a realistic range of general observations in the context of these two theories.

Methane (CH

This paper presents a diagnostic-driven method of evaluating refracturing (refrac) techniques in unconventional wells. Detailed analysis across the lateral, using intervention based distributed fiber optic (DFO) measurements, allows for a comprehensive understanding of the refrac performance. While there are various approaches to refracing an unconventional well, there is a categorical division of two main strategies: iterations of limited interval re-stimulation or re-stimulate the entire lateral at once. Stage-by-stage refrac, via casing-in-casing or coil tubing with isolation-type packer tool, offers potential control over stimulation distribution but often incurs heavier cost compared to refracing the entire well simultaneously. The economically favorable simultaneous refrac of all stages (Bull head) can be executed at a lower price but at the cost of not knowing the extent of lateral distribution. With several possible approaches for refracing an entire lateral at once, further questions arise regarding which method provides the most laterally uniform re-stimulation and whether the resultant production improvement is from re-stimulated existing or newly created fractures. A major hurdle in both executing and evaluating the success of an all stage simultaneous refrac is the uncertainty of creating new fracture initiation points; furthermore, with complex heterogenic rock, different fracture designs, and different well completions, it is difficult to develop a comprehensive understanding of how well the refrac design worked. Diagnostic validation of the success of a refrac operation, as well as iterative improvements based on those learnings, is fundamental to determining a cost-effective strategy. A strong data set takes the guesswork out of refrac and is the best method for understanding how effective the refrac designs performed.

Gas-producing wells in the Barnett Formation show a steep decline from initial production rates, even within the first year, and only 12–30% of the estimated gas-in-place is recovered. The underlying causes of these production constraints are not well understood. The rate-limiting step in gas production is likely diffusive transport from matrix storage to the stimulated fracture network. Transport through a porous material such as shale is controlled by both geometry (e.g., pore-size distribution) and topology (e.g., pore connectivity). Through an integrated experimental and theoretical approach, this work finds that the Barnett Formation has sparsely-connected pores. Evidence of low pore connectivity includes the sparse and heterogeneous presence of trace levels of diffusing solutes beyond a few mm from a sample edge, the anomalous behavior of spontaneous water imbibition, the steep decline in edge-accessible porosity observed in tracer concentrations following vacuum saturation, the low (about 0.2–0.4% by volume) level presence of Wood's metal alloy when injected at 600 MPa pressure, and high tortuosity from mercury injection capillary pressure. Results are consistent with an interpretation of pore connectivity based on percolation theory. Low pore connectivity of shale matrix limits its mass-transfer interaction with the stimulated fracture network from hydraulic fracturing, and serves as an important underlying cause for steep declines in gas production rates and a low overall recovery rate.

Understanding the physiochemical mechanisms that control the loss of gas during coring processes is critical to accurately determining gas-in-place (GIP) resource assessments of unconventional shale-gas plays. Our study uses an experimental approach, utilizing methane (CH4) adsorption isotherms and degassing curves of methane-resaturated Barnett Formation core plugs, to determine the amount of lost-gas based on mass-balance analysis at different CH4 re-saturation pressures and varied exposure times. Several readily available empirical methods for estimating lost-gas were evaluated, quantified, and compared with the mass balance–derived lost-gas values in our experiments. A CH4 isotherm measurement on 3/8-inch Barnett Formation core plugs was performed at 35.4 °C; the amount of gas adsorbed in excess was then quantified and fitted to the modified Langmuir equation to determine the Langmuir maximum, Langmuir constant, and adsorbed gas-phase density. Two sets of CH4 gas-resaturation and degassing measurements, one varying saturation pressures and the other varying exposure times, were performed on 3/8-inch Barnett Formation core-plugs at an isothermal temperature of 35.4 °C. Degassing curves, the plot of the released gas yield versus the square root of degassing time, display three stages that correspond to different gas-releasing mechanisms. The rapid increase of released gas yield at the beginning of degassing represents that nonlinear gas expansion is dominant and that degassing evolves into a linear desorption-dominated phase over time. Experimentally derived values for lost gas were determined by subtracting the sum of the desorbed and retained gas at the peak of the degassing curve from the amount of gas initially charged into the samples at equilibrated resaturation pressure. Lost gas varies linearly with increasing gas-resaturation pressure and nonlinearly by a greater magnitude with increasing exposure time, indicating that lost gas is more sensitive to exposure time. The uncertainty evaluation of lost gas determined by three empirical methods was conducted by direct comparison with mass-balance-derived lost-gas values from our experiment. Nonlinear least-squares extrapolation overestimates, and both linear extrapolation and polynomial equation fitting underestimate, mass-balance lost-gas control points. Among the three empirical methods, the polynomial-fitted lost-gas values most closely agree with mass-balance lost gas, revealing that polynomial fitting to degassing curves is a viable way to accurately estimate lost gas and, more importantly, to estimate GIP values with up to 85% accuracy. As free gas is the dominant storage mechanism in the Barnett Formation, the trends of experimentally measured cumulative desorbed gas content versus the square root of elapsed time match neither the calculated curves derived from USBM Direct Method nor Amoco Method.

Although oil retention has recently emerged as a key topic of unconventional-shale resource assessment, oil-retention and expulsion controls in organic-rich shales during thermal maturation remain poorly constrained. This study presents an experimental comparison of oil generation, retention, and expulsion in two immature, Type II kerogen-dominated marine shales, the Mississippian Barnett Shale and the Upper Devonian-Lower Mississippian Woodford Shale, mainly with respect to the combined effects of the organic macerals and rock fabric involved. In both cases, miniature core plugs drilled from the given samples were isothermally pyrolyzed at 130 to 425 °C for 72 h under a confining pressure of 68 MPa during gold-tube nonhydrous pyrolysis, corresponding to the thermally immature, early stage of the oil window, the main stage of the oil window, the late stage of the oil window, the main stage of oil cracking to wet gas, and the late stage of oil cracking. Yields of generated oil, retained oil, and expelled oil for the two studied samples were systematically quantified on the basis of mass-balance calculation of measured oil and gas yields, as well as Rock-Eval analyses on pyrolyzed subsamples. Through the six stages of petroleum formation investigated, the principal difference in oil generation was observed in the two studied samples, with approximately 38 to 68% greater yields of generated oil (equivalent to ~130 mg oil/g TOCo) for the Woodford Shale when it evolved into the main and late stages of the oil window. These elevated yields of generated oil for the Woodford Shale were compensated for by additional oil generation resulting from conversion of abundant Type I kerogen-like algae such as Tasmanites and Leiosphaeridia, which lag in onset and have a shorter period of petroleum generation upon maturation. As a response to the difference in oil generation, oil retention was found to be significantly enhanced for the Woodford Shale at equivalent stages, with 0.2 to 1.7 times more free oil (equivalent to 24–105 mg oil/g TOCo) and 0.7 to 3.9 times more sorbed oil (equivalent to 58–76 mg oil/g TOCo) being retained than that of the Barnett Shale, although this effect was not pronounced for oil expulsion. In contrast to the Barnett Shale, relatively low expelled oil yields and expulsion efficiencies both indicate highly limited oil expulsion in the Woodford Shale, implying that the Woodford Shale, whose mineral composition and lithofacies are similar to those of the Barnett Shale, may have a relatively low permeability rock fabric to prevent oil from being expelled. Furthermore, not only significantly higher oil-saturation index (OSI) values but also a wider range of maturity at which the oil crossover effect (OSI > 100 mg/g TOC) occurs is expected for the Woodford Shale when extrapolation to a geological setting occurs. These data suggest that the presence of abundant Type I kerogen-like algae and relatively low permeability rock fabric in the Woodford Shale are critical to significant oil retention during oil generation and expulsion, which jointly raise the possibility of potential commercial shale oil within Type II kerogen-dominated marine shales.

The objective for this study is to perform an investigation of the areal and vertical geospatial fluid property variations across the Barnett and Eagle Ford based on publicly-available PVT data (97 Barnett wells and 153 Eagle Ford wells). A modified multi-contact recombination procedure has been implemented to the PVT data of the reported well stream compositions for Barnett to improve estimates of in-situ reservoir composition. The Eagle Ford data were utilised without modifications as this shale play is known to be highly under-saturated. The results of modified multi-contact recombination procedure for Barnett are plotted on a ternary diagram and show that the majority of the wells were dry gas to retrograde gas. For Eagle Ford, ternary diagrams indicated the fluid type, vertical variations of OGR, C7+ and API gravity. Maps were created to review areal variations of these properties (API gravity, C7+, and initial OGR). The study was further speculated by applying fuzzy pattern recognition algorithms. The application of fuzzy logic provided additional insight to the reservoir fluid's PVT behaviour in understudy shale formations. [Received: August 23, 2018; Accepted: May 6, 2019]

In this paper, we predict the Total Organic Carbon from raw well-logs data recorded in two horizontal wells drilled in the Lower Barnett shale formation using the Multilayer Perceptron neural network machine. A comparative study between the Levenberg-Marquardt and the Conjugate Gradient learning algorithms shows the power of the Levenberg-Marquardt to predict the Total Organic Carbon in case of lake in the measurement of the Bulk density log, this can help to resolve the lake of the Schmoker’s method which requires continuous measurement of the bulk density log Keywords: Total Organic Carbon, well-logs data, Prediction, Barnett Shale, Levenberg-Marquardt, Conjugate Gradient, Schmoker’s method.

We observed multi-scale porosity and permeability at the cm-scale in a Barnett Shale core through a pulse-decay permeability test. The core is composed of alternating layers of silty-claystone and claystone. We interpret the silty-claystone has a permeability of 3.41×10 −20 m 2 (34.6 nD) and a porosity of 5.6% and that the claystone has a permeability of 1.80×10 −23 m 2 (0.0182 nD) and a porosity of 4.8%. The horizontal effective permeability is 2.05×10 −20 m 2 (20.8 nD) and we estimate the vertical effective permeability to be 4.58×10 −23 m 2 (0.0452 nD). The effective permeability anisotropy ratio is approximately 450. These results suggest that relatively high-permeability carrier beds drain organic rich lower permeability beds. The microstratigraphy of mudstones has a fundamental control on flow, and may provide an explanation for recent studies that have suggested either pervasive natural fracturing or extraordinary levels of induced fracturing are necessary to explain shale production behavior.

We have developed a careful chronological review of multistage stimulation treatments, in which microseismic interpretation was supported by fracture simulation and finite-element geomechanical simulation. The interpretation of a zipper frac stimulation treatment conducted in the Barnett Shale Formation in 2011 progressed from microseismic interpretation, from well-site observation, to a self-consistent understanding across multiple stages and multiple wells. Through this process, we have developed a tutorial on practical interpretation of microseismic data in the context of the hydraulic fracture treatment information (pump data) and regional structural information from interpretation of 3D seismic sections. Analysis of microseismic data included summarizing groups of events in the form of [Formula: see text]-value, [Formula: see text]-value, and extracted planar geometries. We advocate the development of a chronological interpretation, the consistency of which is tested using forward modeling. The process is iterative and relies on the forward modeling of complex fracturing and finite-element geomechanical models to inform iterations of the interpretation. Although extended case studies of this type are unsuitable for well-site analysis, we recommend their use for planning stimulation treatments for future nearby wells and to inform strategies for refracturing later in the well’s life.

In the usual formulation of the Jahn-Teller effect a simplification is made in going from the adiabatic to the crude adiabatic approximation in which the electronic parts of the vibronic wavefunction are assumed independent of the nuclear coordinates. This then neglects momentum coupling in the vibronic coupling matrix. The momentum coupling has been termed the molecular Barnett effect when the active vibration transforms as the irreducible representation of a rotation in the molecular point group. Experimental evidence for the molecular Barnett effect has recently been found. In this paper the various point groups in which momentum and Barnett coupling can occur are investigated. A vibration capable of momentum coupling is contained in the asymmetric direct product of the degenerate electronic state and, as with the Jahn-Teller effect, is possible in the orbitally degenerate electronic states of molecules of all non-linear point groups. A static distortion along such a coordinate will lift the electronic degeneracy. Unlike the Jahn-Teller effect, however, in some point groups a minimum complexity of the molecule is required before such coupling can occur. In particular it will be absent in the degenerate electronic states of such simple molecules of the form X 3 (D 3h ); XY 3 (C 3v , D 3h ); XY 4 (T d ); and XY 6 (O h ).

The behavior of fractal analysis using the continuous wavelet transform in shale-gas reservoirs is studied based on estimation of the so-called Hölder exponent by analyzing a total-organic-carbon (TOC) well log using the continuous wavelet transform; the Morlet is the analyzing wavelet. Application to the TOC well-log data of a horizontal well drilled in the Fort Worth Basin, Texas, USA, where the main objective is the lower Barnett Shale, clearly shows no special behavior of the Hölder exponents for known sweet spots. This process can be applied to other well-log data of shale-gas reservoirs to compare results and generalize a rule about the fractal behavior in shale-gas reservoirs.

Henry J.M. Barnett, MD, FRCP(C), CC, known by his friends as Barney, was born on February 10, 1922 in Newcastle upon Tyne, England, and died at Toronto, Canada, on Thursday, October 20, 2016. He died peacefully in the company of family and caregivers, after 94 fearless and adventurous years. He was predeceased by his beloved wife Kathleen (Kay) in 2006. A defining moment occurred when, as a boy rambling around the marshes at Ashbridges Bay in Toronto, he chanced upon 2 ornithologists who showed him a hoary redpoll through binoculars. From then on, birds, natural science, and eventually medical science captivated him. In 1944, he graduated from University of Toronto Medical School, where he met a beautiful nurse, Kathleen (Kay), whom he married. He continued his studies in Toronto, then Queen Square, London, United Kingdom, and Oxford, specializing in Neurology, which he practiced and taught for over 45 years in Toronto and then London, Ontario. His clinical research led him to contribute to scientific knowledge on stroke prevention, early detection, clinical care, and treatment for which he received acclaim and prizes worldwide, including an Honorary Doctorate of Letters from Oxford, the Karolinska Stroke Award for Excellence in Stroke Research in Stockholm, and the Companion of the Order of Canada. In later life, he pursued his passion for the natural world as a volunteer advocate with the Nature Conservancy of Canada for the Happy Valley Forest in King Township, Ontario. He bought property there when his children were young and used the 80 acres of forest, ponds, and meadows to pass on his and Kay’s delight in Nature to the Nature Conservancy of Canada. Barney was the Principal Investigator of the first randomized trial to show that Aspirin reduced the risk of stroke,1 the NASCET (North American Carotid Endarterectomy Trial), …

In this paper, we show that the Pegg–Barnett formalism accepts coherent states constructed as eigenstates of the annihilation operator, considering both the number and the phase. These operators are defined within a ( s + 1 ) -dimensional Hilbert space H s and with periodic conditions. The coherent states that we find are determined by the eigenvalue of the annihilation operator, which leads to a discrete spectrum. This approach allows calculation of the discrete-finite counterpart of the Wigner function in a phase space defined by the variables of number and phase.

We present estimates of regional methane (CH4) emissions from oil and natural gas operations in the Barnett Shale, Texas, using airborne atmospheric measurements. Using a mass balance approach on eight different flight days in March and October 2013, the total CH4 emissions for the region are estimated to be 76 ± 13 × 10(3) kg hr(-1) (equivalent to 0.66 ± 0.11 Tg CH4 yr(-1); 95% confidence interval (CI)). We estimate that 60 ± 11 × 10(3) kg CH4 hr(-1) (95% CI) are emitted by natural gas and oil operations, including production, processing, and distribution in the urban areas of Dallas and Fort Worth. This estimate agrees with the U.S. Environmental Protection Agency (EPA) estimate for nationwide CH4 emissions from the natural gas sector when scaled by natural gas production, but it is higher than emissions reported by the EDGAR inventory or by industry to EPA's Greenhouse Gas Reporting Program. This study is the first to show consistency between mass balance results on so many different days and in two different seasons, enabling better quantification of the related uncertainty. The Barnett is one of the largest production basins in the United States, with 8% of total U.S. natural gas production, and thus, our results represent a crucial step toward determining the greenhouse gas footprint of U.S. onshore natural gas production.

We present high time resolution airborne ethane (C2H6) and methane (CH4) measurements made in March and October 2013 as part of the Barnett Coordinated Campaign over the Barnett Shale formation in Texas. Ethane fluxes are quantified using a downwind flight strategy, a first demonstration of this approach for C2H6. Additionally, ethane-to-methane emissions ratios (C2H6:CH4) of point sources were observationally determined from simultaneous airborne C2H6 and CH4 measurements during a survey flight over the source region. Distinct C2H6:CH4 × 100% molar ratios of 0.0%, 1.8%, and 9.6%, indicative of microbial, low-C2H6 fossil, and high-C2H6 fossil sources, respectively, emerged in observations over the emissions source region of the Barnett Shale. Ethane-to-methane correlations were used in conjunction with C2H6 and CH4 fluxes to quantify the fraction of CH4 emissions derived from fossil and microbial sources. On the basis of two analyses, we find 71-85% of the observed methane emissions quantified in the Barnett Shale are derived from fossil sources. The average ethane flux observed from the studied region of the Barnett Shale was 6.6 ± 0.2 × 10(3) kg hr(-1) and consistent across six days in spring and fall of 2013.

Atmospheric methane (CH4) was measured using a mobile laboratory to quantify fugitive CH4 emissions from Oil and Natural Gas (ONG) operations in the Barnett Shale area. During this Barnett Coordinated Campaign we sampled more than 152 facilities, including well pads, compressor stations, gas processing plants, and landfills. Emission rates from several ONG facilities and landfills were estimated using an Inverse Gaussian Dispersion Model and the Environmental Protection Agency (EPA) Model AERMOD. Model results show that well pads emissions rates had a fat-tailed distribution, with the emissions linearly correlated with gas production. Using this correlation, we estimated a total well pad emission rate of 1.5 × 10(5) kg/h in the Barnett Shale area. It was found that CH4 emissions from compressor stations and gas processing plants were substantially higher, with some "super emitters" having emission rates up to 3447 kg/h, more then 36,000-fold higher than reported by the Environmental Protection Agency (EPA) Greenhouse Gas Reporting Program (GHGRP). Landfills are also a significant source of CH4 in the Barnett Shale area, and they should be accounted for in the regional budget of CH4.