Search Results (37)

Economic gas recovery from shale reservoirs is inherently difficult because of the extremely low permeability of these formations. To overcome this challenge, horizontal wells are drilled and subjected to multi-stage hydraulic fracturing treatments, which generate high-conductivity flow pathways. The adoption of these technologies has significantly boosted the economic recovery of gas from shale formations, particularly the Marcellus Shale, which stands as the most productive shale gas play in the United States. The effectiveness of a fracturing treatment in enabling economic gas production from shale reservoirs is governed by the characteristics of the fractures it creates. The propagation of initial fracture, during multi-stage hydraulic fracturing, modifies the initial stress conditions in the surrounding area, commonly referred to as a “stress shadow.” The stress shadow restricts the initiation and subsequent propagation of later fracture stages, leading to the development of less favorable fracture properties. As a result, the uneven contribution of individual fracture stages to gas flow ultimately diminishes overall gas recovery from the horizontal well. For efficient gas drainage from the shale, the fracture stages are often closely spaced. When fracture stages are placed in close proximity, the stress shadow effect can be intensified. Thus, accounting for the stress shadow is essential in the design of hydraulic fracture treatments. This study investigates how fracture spacing, injected fluid volume, and fluid type influence the magnitude of the stress shadow effect, its impact on fracture properties, and the resulting gas recovery from the Marcellus Shale. The goal is to facilitate the optimization of the hydraulic fracture design to mitigate the stress shadow impact and enhance gas production. Data from several Marcellus Shale horizontal wells, along with published findings, were compiled and analyzed to determine the petrophysical and geomechanical characteristics of the formation. These results were then used to construct a reservoir model representative of a Marcellus Shale horizontal well. Fracture properties, altered by the stress shadow, were assessed through hydraulic fracturing simulations and incorporated into the model. Ultimately, the reservoir model was employed to predict the production performance. The results of the investigation confirmed that close stage spacing intensifies the impact of the stress shadow. The stress shadow was found to impair fracture conductivity which negatively impacted gas recovery. The negative impact of the stress shadow on gas recovery was observed to gradually diminish as the production rate declined over time. The volume and type of the fluid injected during fracturing treatment can amplify the stress shadow’s impact. Full article

Localized employment gains from new or expanded fossil fuel development commonly are cited by its proponents in response to sustainability-related concerns raised by local drilling area residents. This paper analyzes local employment effects in drilling areas within the Marcellus shale formation in the state of Pennsylvania, USA. The Marcellus shale formation was one of the early natural gas fracking boom development areas globally, so these local employment outcomes can inform future policy decisions on not-yet-developed shale gas formations worldwide. As long-term sustainable jobs are a key part of any locale’s sustainable development program, the magnitude and persistence of employment gains in the local drilling area is highly relevant. The existing research literature on employment effects from increased shale gas extraction is dominated by usage of panel estimation on annual data at the U.S. state/county level. The innovative contribution of this paper is its use of monthly data, sub-state local areas (67 counties within PA), and a parsimonious vector autoregression model (VAR) estimated separately for each of the 67 counties. The estimated VAR models are used to ascertain whether Marcellus shale drilling activity in PA led to actual county-level employment above forecasted based on data prior to the shale boom. Actual versus forecasted employment is compared from 2010–2019. Higher than forecasted employment findings were much more likely to occur in approximately the top quarter of drilling counties, with the observed gains being modest. Most importantly, however, any employment gains above forecast were short-lived, gone within four years in most counties. Given the modest and temporary local employment gains found and the many known potential damages to local residents and the environment from intensive drilling, it is questionable that the local areas in the Marcellus shale formation most intensively drilled benefited overall from the shale gas extraction. These findings are germane to ongoing current debates about expanding natural-gas-fired electricity generation, versus solar plus storage, to meet anticipated large rises in electricity demand from rapid data center development globally. Full article

The lack of in-depth analysis on the reservoir characteristics and the paleoenvironmental conditions of the Niutitang Formation in the study area has led to an unclear understanding of its geological background. In this study, core samples from well SZY1 were selected, and X-ray diffraction (XRD), scanning electron microscopy (SEM), and quantitative elemental analysis were employed to systematically investigate the reservoir properties and paleoenvironment of the shales. The results indicate that the Niutitang Formation shales form a low-porosity, low-permeability reservoir. By utilizing indicators such as the chemical index of alteration (CIA) and elemental ratios, the study delves into the paleoclimate and paleoproductivity of the region. The (La/Yb)_n ratio is approximately 1, indicating a rapid deposition rate that is beneficial for the accumulation and preservation of organic matter. The chondrite-normalized and North American Shale Composite (NASC)-normalized rare earth element (REE) distribution patterns of the shales show consistent trends with minimal variation, reflecting the presence of mixed sources for the sediments in the study area. Analysis reveals that the Niutitang Formation shales are enriched in light rare-earth elements (LREEs) with a negative europium anomaly, and the primary source rocks are sedimentary and granitic, located far from areas of seafloor hydrothermal activity. The Ni_EF and Cu_EF values suggest high paleoproductivity, and the shales were deposited in an anoxic-reducing environment. The depositional environments of the Marcellus and Utica shales in the United States, the Wufeng-Longmaxi black shales in the Changning area of the Sichuan Basin, and the shales in the study area are similar, characterized by anoxic reducing conditions and well-developed fractures. The thermal evolution degree of the study area is relatively moderate, currently in the peak gas generation stage, with the reservoir quality rated as medium to high, indicating good potential for hydrocarbon accumulation and promising exploration prospects. Full article

This study investigates the application of fiber optic technology to optimize completion design in a hydraulic fracture stimulation for Marcellus Shale Reservoir. With a focus on improving cluster efficiencies and overcoming interstage communication challenges, the research utilizes real-time data from distributed acoustic (DAS), temperature (DTS), and strain (DSS) measurements. The methodology comprises a comprehensive analysis of completion and stimulation reports, fiber optics, microseismic data, and well logs. Conducted at the MSEEL well pads, MIP, and Boggess, and equipped with permanent and deployable fiber optic cables, this study emphasizes that engineered/geomechanical completion design leads to sustained cluster efficiency and stage production performance. Inefficient cluster efficiencies are primarily linked to fracture communication. Recommendations include employing a geomechanical completion design, avoiding non-uniform high natural fracture zones during hydraulic fracture stimulations, implementing short stage length, and using more 100 mesh sand. These insights, derived from correlations between fracture counts, distributed strain sensing (DSS), cluster efficiency, production logging, and production data, offer significant implications for optimizing completion design in unconventional reservoirs. The effective application of fiber optic technology, providing real-time DAS, DTS, and slow strain data, proves instrumental in addressing interstage communication challenges, contributing to improved reservoir performances and cost-effective operations in hydraulic fracture stimulations. Full article

With the development of artificial intelligence technology, machine learning-based production forecasting models can achieve the rapid prediction and analysis of production. However, these models need to be built on a large dataset, and having only a small amount of data may result in a decrease in prediction accuracy. Therefore, this paper proposes a transfer learning prediction method based on the hierarchical interpolation model. It uses data from over 2000 shale gas wells in 22 blocks of the Marcellus Shale formation in Pennsylvania to train the transfer learning model. The knowledge obtained from blocks with sufficient sample data is transferred and applied to adjacent blocks with limited sample data. Compared to classical production decline models and mainstream time-series prediction models, the proposed method can achieve an accurate production decline trend prediction in blocks with limited sample data, providing new ideas and methods for studying the declining production trends in shale gas. Full article

Shale gas has revolutionized the global energy supply, underscoring the importance of robust production forecasting for the effective management of well operations and gas field development. Nonetheless, the intricate and nonlinear relationship between gas production dynamics and physical constraints like shale formation properties and engineering parameters poses significant challenges. This investigation introduces a hybrid neural network model, GRU-MLP, to proficiently predict shale gas production. The GRU-MLP architecture can capture sequential dependencies within production data as well as the intricate nonlinear correlations between production and the governing constraints. The proposed model was evaluated employing production data extracted from two adjacent horizontal wells situated within the Marcellus Shale. The comparative analysis highlights the superior performance of the GRU-MLP model over the LSTM and GRU models in both short-term and long-term forecasting. Specifically, the GRU model’s mean absolute percentage error of 4.7% and root mean squared error of 120.03 are notably 66% and 80% larger than the GRU-MLP model’s performance in short-term forecasting. The accuracy and reliability of the GRU-MLP model make it a promising tool for shale gas production forecasting. By providing dependable production forecasts, the GRU-MLP model serves to enhance decision-making and optimize well operations. Full article

The Marcellus shale is an unconventional reservoir of significant economic potential with Total Organic Carbon (TOC) ranging from 1 to 20%. Hydraulic fracturing is used to extract the shale’s resources, which requires large amounts of water and can result in mineral-rich flowback waters containing hazardous contaminants. This study focuses on a geochemical analysis of the flowback waters and an evaluation of the potential environmental impacts on water and soil quality. Drilled core samples from different depths were treated with lab-prepared hydraulic fracturing fluids. Rock samples were analyzed using Energy Dispersive Spectroscopy (EDS), while effluents’ chemical compositions were obtained using Inductively Coupled Plasma Optical Emission Spectroscopy (ICP-OES). A comparison of results from drilled core samples treated with additives for hydraulic fracturing to those treated with deionized (DI) water confirms that, as expected, the major elements present in the effluent were Ca, Ba, and Cl in concentrations greater than 100 µg/L. The most concerning elements in the effluent samples include As, Ca, Cd, Pb, Se, S, K, Na, B, Mo, and Mn, with Cd and Cr values averaging 380 and 320 µg/L, respectively, which are above safe limits. Se concentrations and high levels of Ca pose major safety and scaling concerns, respectively. We also compared Marcellus shale drilled core samples’ geochemical reactivity to samples collected from an outcrop. Full article

Wastewaters and leachates from various inland resource extraction activities contain high ionic concentrations and differ in ionic composition, which complicates the understanding and effective management of their relative risks to stream ecosystems. To this end, we conducted a stream mesocosm dose–response experiment using two dosing recipes prepared from industrial salts. One recipe was designed to generally reflect the major ion composition of deep well brines (DWB) produced from gas wells (primarily Na⁺, Ca²⁺, and Cl⁻) and the other, the major ion composition of mountaintop mining (MTM) leachates from coal extraction operations (using salts dissociating to Ca²⁺, Mg²⁺, Na⁺, SO₄²⁻ and HCO₃⁻)—both sources being extensive in the Central Appalachians of the USA. The recipes were dosed at environmentally relevant nominal concentrations of total dissolved solids (TDS) spanning 100 to 2000 mg/L for 43 d under continuous flow-through conditions. The colonizing native algal periphyton and benthic invertebrates comprising the mesocosm ecology were assessed with response sensitivity distributions (RSDs) and hazard concentrations (HCs) at the taxa, community (as assemblages), and system (as primary and secondary production) levels. Single-species toxicity tests were run with the same recipes. Dosing the MTM recipe resulted in a significant loss of secondary production and invertebrate taxa assemblages that diverged from the control at all concentrations tested. Comparatively, intermediate doses of the DWB recipe had little consequence or increased secondary production (for emergence only) and had assemblages less different from the control. Only the highest dose of the DWB recipe had a negative impact on certain ecologies. The MTM recipe appeared more toxic, but overall, for both types of resource extraction wastewaters, the mesocosm responses suggested significant changes in stream ecology would not be expected for specific conductivity below 300 µS/cm, a published aquatic life benchmark suggested for the region. Full article

The Middle Devonian Marcellus Formation of North America is the most prolific hydrocarbon play in the Appalachian basin, the second largest producer of natural gas in the United States, and one of the most productive gas fields in the world. Regional differences in Marcellus fluid chemistry reflect variations in thermal maturity, migration, and hydrocarbon alteration. These differences define specific wet gas/condensate and dry gas production in the basin. Marcellus gases co-produced with condensate in southwest Pennsylvania and northwest West Virginia are mixtures of residual primary-associated gases generated in the late oil window and postmature secondary hydrocarbons generated from oil cracking in the wet gas window. Correlation of API gravity and C₇ expulsion temperatures, high heptane and isoheptane ratios, and the gas geochemical data confirm that the Marcellus condensates formed through oil cracking. Respective low toluene/nC₇ and high nC₇/methylcyclohexane ratios indicate selective depletion of low-boiling point aromatics and cyclic light saturates in all samples, suggesting that water washing and gas stripping altered the fluids. These alterations may be related to deep migration of hot basinal brines. Dry Marcellus gases produced in northeast Pennsylvania and northcentral West Virginia are mixtures of overmature methane largely cracked from refractory kerogen and ethane and propane cracked from light oil and wet gas. Carbon and hydrogen isotope distributions are interpreted to indicate (1) mixing of hydrocarbons of different thermal maturities, (2) high temperature Rayleigh fractionation of wet gas during redox reactions with transition metals and formation water, (3) isotope exchange between methane and water, and, possibly, (4) thermodynamic equilibrium conditions within the reservoirs. Evidence for thermodynamic equilibrium in the dry gases includes measured molecular proportions (C₁/(C₁ − C₅) = 0.96 to 0.985) and δ¹³C₁ values significantly greater than δ¹³C_KEROGEN. Noble gas systematics support the interpretation of hydrocarbon–formation water interactions, constrain the high thermal maturity of the hydrocarbon fluids, and provide a method of quantifying gas retention versus expulsion in the reservoirs. Full article

Hydrocarbon-rich shales have been a major natural gas source in the US over the last decade. These organic-rich shales can also potentially serve as a source of some rare earth elements (REYs). However, the mode of occurrence and the geochemical processes that led to REY enrichment in these shales are still poorly understood. In this study, we investigated the whole-rock REY content and associations of REYs in the different phases of Marcellus and Haynesville Shale samples. A traditional sequential extraction procedure was adopted to understand the association of REYs in (i) exchangeable, (ii) acid-soluble, (iii) pyritic, (iv) organic matter, and (v) silicate fractions. Extraction efficiency was assessed by comparing the mineralogy of the pre- and post-sequential extraction samples using XRD. Elemental ratios such as La/Lu, La/Sm, Gd/Lu, Y/Ho, and Ce and Eu anomalies were utilized to understand whole-rock-normalized REY distribution patterns. Further, the distribution pattern in each extracted phase was examined to account for the relative contribution of phases to REY enrichment. The economic potential of these samples was evaluated by calculating HREE/LREE ratios, outlook coefficients, and by comparing their REY levels with those of coal fly ash deposits. Our results indicate that whole-rock REY content in the analyzed shale samples ranged from 295 to 342 ppm, with Haynesville Shale having a higher concentration than the Marcellus Shale sample. All samples exhibited an MREE–HREE-enriched pattern, indicating that the REY content is primarily contributed by carbonate and siliciclastic inputs. However, the average total REY extraction efficiency was only approximately 20% from the Haynesville samples and 9% from the Marcellus sample. We postulate that the poor REY yield is due to a high amount of refractory aluminosilicate/clay fraction in these samples. We demonstrate that traditional sequential extraction procedures may not be effective for extracting REYs from high organic–high aluminosilicate shale. Full article

Hydraulic fracturing or fracking has led to a rapid growth of oil and gas production in the United States, but the impact of fracking on public health is an important but underresearched topic. We designed a methodology to study spatiotemporal correlations between the risk of fracking and stroke mortality. An annualized loss expectancy (ALE) model is applied to quantify the risk of fracking. The geographically and temporally weighted regression (GTWR) model is used to analyze spatiotemporal correlations of stroke mortality, fracking ALE, and nine other socioeconomic- and health-related factors. The analysis shows that fracking ALE is moderately correlated with stroke mortality at ages over 65 in most states of fracking, in addition to cardiovascular disease and drug overdose being positively correlated with stroke mortality. Furthermore, the correlations between fracking ALE and stroke mortality in men appear to be higher than in women near the Marcellus Shale, including Ohio, Pennsylvania, West Virginia, and Virginia, while stroke mortality among women is concentrated in the Great Plains, including Montana, Wyoming, New Mexico, and Oklahoma. Lastly, within two kilometers of the fracking mining activity, the level of benzene in the air was found to be significantly correlated with the fracking activity in Colorado. Full article

The main goal of hydraulic fracturing stimulation in unconventional and tight reservoirs is to maximize hydrocarbon production by creating an efficient stimulated reservoir volume (SRV) around the horizontal wells. To zreach this goal, a physics-based model is typically used to design and optimize the hydraulic fracturing process before executing the job. However, two critical issues make this approach insufficient for achieving the mentioned goal. First, the physics-based models are based on several simplified assumptions and do not correctly represent the physics of unconventional reservoirs; hence, they often fail to match the observed SRVs in the field. Second, the success of the executed stimulation job is evaluated after it is completed in the field, leaving no room to modify some parameters such as proppant concentration in the middle of the job. To this end, this paper proposes data-driven and global sensitivity approaches to address these two issues. It introduces a novel workflow for estimating SRV in near real-time using some hydraulic fracturing parameters that can be inferred before or during the stimulation process. It also utilizes a robust global sensitivity framework known as the Sobol Method to rank the input parameters and create a reduced-order (mathematically simple) model for near real-time estimation of SRV (referred to as DSRV). The proposed framework in this paper has two main advantages and novelties. First, it is based on a pure data-based approach, with no simplified assumptions due to the use of a simulator for generating the training and test dataset, which is often the case in similar studies. Second, it treats SRV generation as a rock mechanics problem (rather than a reservoir engineering problem with fixed fracture lengths), accounting for changes in hydraulic fracture topology and SRV changes with time. A dataset from the Marcellus Shale Energy and Environment Laboratory (MSEEL) project is used. The model’s input parameters include stimulation variables of 58 stages of two wells. These parameters are stage number, step, pump rate and duration, proppant concentration and mass, and treating pressure. The model output consists of the corresponding microseismic (MS) cloud size at each step (i.e., time window) during the job. Based on the model, guidelines are provided to help operators design more efficient fracturing jobs for maximum recovery and to monitor the effectiveness of the hydraulic fracturing process. A few future improvements to this approach are also provided. Full article

The rapid development of unconventional oil and gas (O&G) extraction around the world produces a significant amount of wastewater that requires appropriate management and disposal. Produced water (PW) is primarily disposed of through saltwater disposal wells, and other reuse/disposal methods include using PW for hydraulic fracturing, enhanced oil recovery, well drilling, evaporation ponds or seepage pits within the O&G field, and transferring PW offsite for management or reuse. Currently, 1–2% of PW in the U.S. is used outside the O&G field after treatment. With the considerable interest in PW reuse to reduce environmental implications and alleviate regional water scarcity, it is imperative to analyze the current regulatory framework for PW management and reuse. In the U.S., PW is subject to a complex set of federal, state, and sometimes local regulations to address the wide range of PW management, construction, and operation practices. Under the supervision of the U.S. Environment Protection Agency (U.S. EPA), different states have their own regulatory agencies and requirements based on state-specific practices and laws. This study analyzed the regulatory framework in major O&G-producing regions surrounding the management of PW, including relevant laws and jurisdictional illustrations of water rules and responsibilities, water quality standards, and PW disposal and current/potential beneficial reuse up to early 2022. The selected eastern states (based on the 98th meridian designated by the U.S. EPA as a tool to separate discharge permitting) include the Appalachian Basin (Marcellus and Utica shale areas of Pennsylvania, Ohio, and West Virginia), Oklahoma, and Texas; and the western states include California, Colorado, New Mexico, and Wyoming. These regions represent different regulations; climates; water quantities; quality diversities; and geologic, geographic, and hydrologic conditions. This review is particularly focused on the water quality standards, reuse practices and scenarios, risks assessment, knowledge gaps, and research needs for the potential reuse of treated PW outside of O&G fields. Given the complexity surrounding PW regulations and rules, this study is intended as preliminary guidance for PW management, and for identifying the knowledge gaps and research needs to reduce the potential impacts of treated PW reuse on the environment and public health. The regulations and experiences learned from these case studies would significantly benefit other states and countries with O&G sources for the protection of their environment and public health. Full article

High-volume hydraulic fracturing (“fracking”) for natural gas in the Marcellus Shale (underlying about 24 mil ha in New York, Pennsylvania, Maryland, West Virginia, Ohio, and Virginia) has become a politically charged issue, primarily because of concerns about drinking water safety and human health. This paper examines fracking in the Marcellus region, and the tradeoffs between the energy and economic potential of natural gas extraction and the environmental impacts on wildlife. Therefore, we introduce a new E3 analysis that combines the costs and benefits as regards energy, economics, and the environment. The Marcellus Shale has the most proven reserves of natural gas of any basin in the United States, at 129 trillion cubic feet. Income from natural gas development comes primarily from direct and indirect jobs, and induced jobs (those created when direct workers spend their earnings in a community), taxes and fees, and royalty and lease payments to rights holders. Fracking, however, has detrimental effects on wildlife and wildlife habitats. Terrestrial habitat effects are primarily due to landscape fragmentation from the clearing of land for pipeline and well pad development, which often removes mature forest and creates open corridors and edge habitats. An increase in forest edge and open corridors is associated with shifts in the bird community, as generalist species that do well around people increase in abundance, while forest specialists decline. Invasive plants associated with disturbance further degrade forest habitats. Aquatic habitats are also affected, both directly and indirectly. Hydraulic fracturing requires up to 20 mil L of water per well fracture, most of which comes from surface water sources in the Marcellus region. The removal of water, especially in smaller headwaters, can increase sedimentation, alter water temperature and change its chemistry, resulting in reductions in aquatic biodiversity. Given the reality that hydraulic fracturing will continue, there is a need to develop practices that best minimize negative impacts on terrestrial and aquatic habitats, as well as policies and the resolve to enforce these practices. To achieve a more sustainable balance between economic, energy, and environmental costs and benefits, we recommend that industry, scientists, non-governmental organizations, mineral rights holders, landowners, and regulators work together to develop a set of best management practices that represent the best knowledge available. Full article

We adopt a physics-guided, data-driven method to predict the most likely future production from the largest tight oil and gas deposits in North America, the Permian Basin. We first divide the existing 53,708 horizontal hydrofractured wells into 36 spatiotemporal well cohorts based on different reservoir qualities and completion date intervals. For each cohort, we fit the Generalized Extreme Value (GEV) statistics to the annual production and calculate the means to construct historical well prototypes. Using the physical scaling method, we extrapolate these well prototypes for several more decades. Our hybrid, physico-statistical prototypes are robust enough to history-match the entire production of the Permian mudstone formations. Next, we calculate the infill potential of each sub-region of the Permian and schedule the likely future drilling programs. To evaluate the profitability of each infill scenario, we conduct a robust economic analysis. We estimate that the Permian tight reservoirs contain 54–62 billion bbl of oil and 246–285 trillion scf of natural gas. With time, Permian is poised to be not only the most important tight oil producer in the U.S., but also the most important tight gas producer, surpassing the giant Marcellus shale play. Full article