Probabilistic Reserves and Resources Estimation of the West Virginia Marcellus Shale Play Using the MCMC PDCA Method

The Marcellus shale is currently the most productive shale play in the United States. In 2015, the Marcellus shale play led in natural gas production per rig and had the highest shale gas production in the United States. Several reports and articles have been published on Marcellus shale play reserves/resources estimates. Some of these estimates were deterministic, while some were probabilistic. These published estimates are all now outdated. Updated probabilistic reserves and resources estimates for the Marcellus shale play are needed. The Marcellus shale play covers six states with the two most productive states being Pennsylvania (PA) and West Virginia (WV). Between these two states, only WV has monthly production data in its production reports; PA production is reported semi-annually. The Markov Chain Monte Carlo (MCMC) method has been successfully used to quantify uncertainty in production forecasts and estimated ultimate recovery (EUR) for the Barnett shale and Eagle Ford shale. There are 20 shale plays that have been discovered in United States. Confirmation of the reliability of the MCMC method using other shale play data is still needed. The objectives of this work are to generate probabilistic reserves and resources estimates for the WV Marcellus shale play and to confirm the reliability of the MCMC method in quantifying uncertainty in production forecasts using production data from the WV Marcellus shale play. Based on geology and initial gas-liquid-ratio (GLR) analysis, the WV Marcellus shale play was divided into liquid-rich and dry-gas regions. A hindcast study was performed to confirm the reliability of the MCMC method in forecasting production and estimating reserves in the WV Marcellus shale play. Type probabilistic decline curves were then generated to forecast Technically Recoverable Resources (TRR) at 20 years (TRR20) for the wells in both the liquid-rich and dry-gas regions. Reserves and resources for the WV Marcellus shale play were estimated by performing Monte Carlo simulation. Based on the WV Marcellus shale play analysis, reserves and resources estimates for PA, Ohio (OH), and entire Marcellus shale play are then extrapolated. Hindcast study results show that the MCMC Probabilistic Decline Curve Analysis (PDCA) method is able to reliably quantify uncertainty in production forecasts and reserves estimates in the WV Marcellus shale play. The total WV NGL reserves and resources range from a P10 of 0.12 billion barrels NGL (BBNGL) to a P90 of 0.58 BBNGL, with a P50 of 0.23 BBNGL. The total WV gas reserves and resources range from a P10 of 81.54 trillion cubic feet (TCF) to a P90 of 283.81 TCF, with a P50 of 145.091 TCF. These estimates are generally much higher than most of the previously published estimates

Regional Mapping and Reservoir Analysis of the Middle Devonian Marcellus Shale in the Appalachian Basin

The main purpose of this investigation is to define the distribution of organic-rich facies of the Middle Devonian Marcellus Shale in New York, Ohio, Pennsylvania, and West Virginia. The analysis is based on well-log data, primarily gamma-ray (the most common and best calibrated) and bulk-density logs (where available). Detailed log analysis has been performed to normalize the logs and define key indicators of reservoir quality. Stratigraphic correlations have been conducted to trace key formation across the study area.;The following maps were generated over the study area.;• Isopach maps of the Mahantango Shale, Marcellus Shale, Oatka Creek Member, Cherry Valley and Union Springs Member. These maps show the stratigraphic thicknesses of the various formations and members.;• Net thickness maps of the Marcellus Shale where the gamma-ray \u3c 100 API and gamma-ray is between 100-180 API. The gamma-ray \u3c 100 API map shows the thickness of the various limestone intervals within the Marcellus. The paleography of these intervals represents carbonate shoals along the basin margin (north and west) and over the peripheral bulge. The gamma-ray map between 100-180 API shows the net thickness of calcareous shale and gray shale. These intervals represent the shallow muddy sea above the thermocline.;• Net thickness maps of the Marcellus Shale where the gamma-ray \u3e180 API, \u3e 200 API, \u3e 250 API, and \u3e 300 API. These maps show the thickness and distribution of shale with different organic-richness within the Marcellus. The paleography of these shale intervals was the deep basin below the thermocline. These maps show the location of the better reservoir.;• Average gamma-ray over the Marcellus interval. This map shows the average gamma-ray value for the Marcellus Shale across the basin. The map can be used as an indication of the highest average organic-richness of the Marcellus Shale, and is best used in conjunction with the net thickness maps by comparing the thickest portion of the various maps and where they may overlap regionally.;• Net thickness maps of the Marcellus Shale where the bulk-density \u3c 2.55 g/cc, \u3c 2.4 g/cc, and \u3c 2.35 g/cc. These maps show various reservoir quality grades of organic-richness (where lower density equals higher quality).;• Isopach Maps of stratigraphic sequences and their systems tracts in the Marcellus Shale. Thin Transgressive Systems Tracts equal a condensed section, whereas thick Regressive Systems Tracts equal a major clastic influx.;These observations and others portrayed on this new series of maps provide a better understanding of the exploratory development of the Marcellus Shale in the Appalachian Basin. By using all of these maps in conjunction, the best target areas for oil and gas exploration can be identified and exploited. The sequence stratigraphic maps can be used for regional correlations and to develop target zones within the Marcellus Shale

The Impact of Shale Gas on Gas Storage Performance

The advances in technology has resulted in significant gas production from the shale formations across the United States. Marcellus Shale which spans most of the Appalachian Basin is one the most prolific gas producers in the United States. Marcellus Shale gas has a distinctly different composition from the existing Northern Appalachian typical dry natural gas. As gas production from Marcellus shale has increased, so has the amount of the shale gas in the natural gas transportation system in the Appalachian Basin. The composition of the injected gas into a storage reservoir can the storage volumes, pressures, the withdrawal rate, and the pressure drawdown.;The objective of this study is to investigate the impact of storing Marcellus Shale gas on the capacity and deliverability of a gas storage reservoir. In this study, the working gas in the storage was assumed to be a mixture of the Marcellus Shale gas and the original pipeline (storage) gas. The fraction of the shale gas in the mixture was varied from 10 percent to 50 percent to determine the changes in the storage working volume, storage top pressure, withdrawal rate, and pressure drawdown. The results indicate that there is linear relationship between the fraction of the shale gas in the working gas and the changes in mixture storage working volume, storage top pressure, withdrawal rate, and pressure drawdown

The Economic Impact of the Value Chain of a Marcellus Shale Well

The Economic Impact of the Value Chain of a Marcellus Shale Well Site examines the direct economic impact of a Marcellus Shale well located in Southwestern Pennsylvania. This study seeks to fill a critical information gap on the impact of gas drilling and extraction from Marcellus Shale deposits deep underground: an assessment of the economic impacts – emphasizing the direct economic impact, rather than just focusing on the perceived benefits and impacts affecting the region. Our analysis is based on extensive field research, including a site visit and interviews with industry participants. It is further cross-validated by examining similar costs for development of Marcellus Wells by a vertically-integrated exploration and production firm

An Artificial Neural Network Approach to Predicting Formation Stress in Multi-Stage Fractured Marcellus Shale Horizontal Wells Based on Drilling Operations Data

The distribution of the anisotropic minimum horizontal stress, both in horizontal and vertical directions, is necessary for effective hydraulic fracture treatment design in Marcellus Shale horizontal wells. Typically, the minimum horizontal stress can be estimated sonic logs. However, sonic log data is not commonly available for the horizontal Marcellus shale wells due to the complexity and cost. The objective of this research is to predict the anisotropic minimum horizontal stress by utilizing drilling parameters including depth, weight-on-bit (WOB), revolution per minute (RPM), standpipe pressure, torque, pump flow rate, and the rate of penetration (ROP). More specifically, artificial neural network (ANN) models will be developed to predict the anisotropic minimum horizontal stress for a horizontal Marcellus shale well from the drilling and well log data. Artificial neural networks are particularly useful to identify complex relationships to predict the properties of unconventional formations. The available data from a Marcellus Shale horizontal well was collected and filtered to prepare data sets for ANN training, testing, and validation purposes. Two networks, for the vertical and lateral sections of the well, were developed. The preliminary results indicated that inclusion of lithology, gamma-ray, and bulk density well log data as inputs can improve the predictability of the networks. Finally, the networks were used to predict the anisotropic minimum horizontal stress in a different Marcellus shale horizontal well with the available sonic log data. To evaluate the applicability of the ANN models, the predicted stresses by the networks were compared against those estimated from the sonic logs. The predictions by both networks (vertical and horizontal) were found to be in close agreement with those estimated from the sonic logs. The results of this research can be utilized as a predictive tool to help fill in the need for an accurate estimation of static geomechanical properties including the minimum horizontal stress in Marcellus Shale horizontal wells and to improve the fracturing treatment design

Geochemical and isotopic variations in surface waters of the monongahela river basin: An area of accelerating marcellus shale development in West Virginia

Water samples were collected from fifty streams in the Monongahela River basin of West Virginia at baseflow condition. The study area was divided into different Marcellus Shale production categories based the amount of Marcellus Shale gas production in a particular HUC-12 sub-watershed. All samples were analyzed for selected major and minor geochemistry, as well as stable isotopes of delta2HH2O, delta18OH2O, delta13CDIC, delta18OSO4 and delta34SSO4. The geochemical and isotopic characteristics of the 50 water samples collected show no clustering based on production category. Extremely high concentrations of total dissolved solids (TDS) are characteristic of produced water from Marcellus Shale production. All of our samples have TDS concentrations less than 1000 mg/L, with a direct correlation between TDS and dissolved sulfate concentration. The area with the greatest density of Marcellus Shale development has also undergone extensive coal mining. Hence geochemical and isotopic characteristics were used to decouple the effects of coal mining from shale gas development in the area. Elevated dissolved sulfate concentrations are interpreted to be the result of contribution from coal mine drainage. The stable isotopic composition of delta2HH2O and delta18OH2O lie along to meteoric water line and show expected trends with altitude indicating that this is meteoric water. The geochemical and isotopic characteristics of the waters also does not indicate that the streams are receiving any significant contribution from produced waters associated with Marcellus Shale drilling or natural structural pathways. However, the water samples collected represent synoptic, or one-time sampling, and continued site-specific monitoring might better assess the impact of shale gas drilling on water quality of streams

3D Seismic Interpretation, Mechanical Stratigraphy and Production Analysis of the Marcellus Shale in Northern West Virginia

The Marcellus shale is one of the most developed unconventional shale gas reservoirs in the world with a calculated 84.5 trillion cubic feet in proved natural gas reserves in Pennsylvania and West Virginia. To better exploit this resource all geological aspects of the Marcellus shale are being studied. In this study, mechanical stratigraphy and interpreted seismic fracture zones within the Marcellus shale are examined. These geologic criteria are assessed for potential to impact gas production by analyzing the gas production of fourteen horizontal Marcellus shale wells within and around the study area.;Mechanical stratigraphy is evaluated from the top of the Tully limestone to the base of the Onondaga limestone to assess vertical heterogeneity of brittleness within and around the Marcellus shale. Brittleness estimations are derived from petrophysical well logs including bulk density, shear velocity and compressional velocity. Mineralogy assessment is completed using Schlumberger\u27s SpectroLithRTM gamma ray spectroscopy mineralogy logs. Elastic moduli including Young\u27s modulus, Poisson\u27s ratio and Lame\u27s parameters are assessed in terms of brittleness and total organic content to develop constraints for areas of high brittleness and high total organic content. The constraints developed at the study well are compared to studies at four other unconventional shale gas sites. The results suggest that mechanical properties are variable and site dependent. Conclusive ranges for Poisson\u27s ratio and Young\u27s modulus constraints for areas of high brittleness and high total organic cannot be developed for an entire shale play but may be useful in local analyses.;Seismic discontinuities were extracted from two three dimensional seismic surveys using a post-stack processing workflow that included Ant-Tracking. They are interpreted to be associated with small faults and fracture zones. The relationship between the number of seismic discontinuities intersecting horizontal wells in the Marcellus shale and cumulative gas production was evaluated. Number of intersecting discontinuities per 1000 feet of wellbore is linearly correlated to cumulative gas production with R2 values greater than 0.9

The Impact of Formation and Fracture Properties Alternations on the Productivity of the Multi-stage Fractured Marcellus Shale Horizontal Wells.

As the reservoir deplete, the pore pressure decreases and the effective stress increases. The increase in the effective stress results in the formation compaction which can alter the formation and hydraulic fracture properties. This is particularly significant for a Marcellus shale horizontal well with multi-stage hydraulic fracture due to low Young\u27s modulus and moderate Poisson\u27s ratio of the Marcellus shale. The degree of the effective stress increase depends on the initial productivity of the well, which is influenced by the hydraulic fracture properties, formation properties, as well as the operating conditions. Therefore, it is necessary to couple the geomechanical and fluid flow simulations to accurately predict the gas production from a horizontal Marcellus Shale well with multi-stage fractures. The objective of this study was to investigate the impact of the formation mechanical properties (Young\u27s modulus and Poisson\u27s ratio), the hydraulic fracture properties (half-length, initial conductivity, and spacing), as well as operating conditions (wellbore pressure) on the productivity of a horizontal Marcellus Shale well with multi-stage fractures. The advanced technical information available from the Marcellus Shale horizontal wells located at the Marcellus Shale Energy and Environment Laboratory (MSEEL) site provided an opportunity to investigate the impact of the shale compressibility on gas production. The core, well log, well test, completion, stimulation, and production data from the wells at the MSEEL site were utilized to estimate the shale mechanical and petrophysical properties as well as the hydraulic fracture characteristics. The results of the data analysis were then utilized to develop a reservoir model for a horizontal well completed in Marcellus Shale with multi-stage hydraulic fractures. A geomechanical (Mohr-Coulomb) module was coupled with reservoir model to determine the effective stress distribution and the formation compaction and its impact on the shale porosity. The impact of the shale compaction on the permeability for both matrix and fissure, and the conductivity of the hydraulic fractures were determined from the Marcellus shale core plug analysis as well as the published measurements on the propped fracture conductivity in Marcellus shale and were incorporated in the reservoir model. The inclusion of the compressibility impacts in the reservoir model provided a more realistic simulated production profile. The gas recovery was found to be negatively impacted by the formation compaction due to the increase in the effective stress. The reduction in the conductivity of the hydraulic fractures due to the compressibility impact was found to have the most adverse effect on the gas recovery. The compressibility impacts were found to be more severe during the early production due to higher production rates. Finally, the model was employed to investigate the impact of the formation’s mechanical properties, hydraulic fracture properties, and the operating conditions on the gas recovery. The higher values of Young’s modulus and Poisson\u27s ratio can mitigate the compressibility impacts and lead to higher recovery. Conversely, the higher values of the fracture half-length as well as the closer fracture spacing will amplify the adverse impacts of the compressibility on the early gas recovery. However, the adverse impacts diminishes with time. The higher values of the initial hydraulic fracture conductivity can also mitigate the compressibility impacts