Barnett Shale Research Articles

Analysis of fluid property variations across the Barnett and Eagle Ford Shale using fuzzy logic

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]

Cam-Clay plasticity. Part IX: On the anisotropy, heterogeneity, and viscoplasticity of shale

We investigate three aspects of material behavior in this ninth installment of the Cam-Clay series, namely, anisotropy, heterogeneity, and viscoplasticity. The main focus of the paper is creep in shale and how this time-dependent deformation behavior may be quantified across the scales, from nanometers to millimeters. Recognizing the highly heterogeneous nature of shale, we adopt a simplified representation of this material as a mixture of softer matter representing organics and clay, and harder matter representing the inorganic rock matrix. Due to the presence of bedding planes in the rock matrix, anisotropy in both the elastic and inelastic responses is assumed; however, the superimposed softer matter may be taken to be isotropic unless experimental evidence indicates otherwise. Viscoplasticity is considered for the first time in this series of work, in which both the Duvaut–Lions and Perzyna formulations are utilized. The two viscoplastic formulations are shown to predict very similar time-dependent deformation responses. The framework is used to interpret the results of multiscale triaxial laboratory creep tests in organic-rich Barnett shale. Time-dependent strain localization in the form of dilative shear bands is also shown to result from loading with varying strain rates, as well as from creep processes that accommodate the multiscale heterogeneity of shale.

An integrated approach of measuring permeability of naturally fractured shale

During the past decade, despite the rapid development of shale resources, it is still facing a great challenge of determining reliable petrophysical properties of both nonfractured and fractured shales. In this study, we innovatively combine a discrete fracture network model and a single-porosity model to simulate the pulse-decay experiments using one fractured Barnett shale plug to obtain accurate properties for both matrix and fracture. The workflow consists of two stages: 1) estimate roughly porosity and permeability for the matrix and fracture by history-matching pressure curves in the single-porosity model and 2) simulate the fracture geometry more realistically considering fracture roughness based on the discrete fracture network model. The fracture geometry is depicted explicitly in two dimensions. The effect of fracture roughness on flow behavior is explored in terms of different values of Dykstra–Parsons coefficients (Vdp): 0, 0.06, 0.29, and 0.47. Our simulated results match the experimental data excellently, with a global average absolute relative deviation (AARD) being within the order of 1E-4. The fracture permeability estimated from the pulse-decay experiment will be underestimated if fracture roughness is ignored. Therefore, the fracture permeability should be adjusted to compensate for the effect of fracture roughness.

Impact of energy production in the Barnett Shale gas region on the measured ambient hydrocarbon concentrations in Denton, Texas

The Barnett Shale play in North Texas is one of the largest active onshore shale gas regions in the United States. Over the past two decades, unconventional energy production from shale gas in North Texas has grown rapidly. The energy production peaked in 2012 and has declined since. The city of Denton is located at the edge of the Barnett Shale play and is within the Dallas-Fort Worth metropolitan area. In this paper, we describe a long-term trend study of 84 total non-methane organic carbon (TNMOC) species measured at the Denton Airport South monitoring station, an exurban site. The annual mean TNMOC concentrations measured during 2000–2017 increased by +8.03 ± 12.92 ppb-C/year (+12.75%/year). The year-to-year increase in the mean TNMOC concentrations mirrored the energy production volume changes from natural gas wells and liquid condensate facilities within 2-km from the ambient air quality monitoring station. Concentrations of alkanes increased significantly, especially the natural gas species of ethane, propane, n-butane, and isobutane. The annual variations in the ethane concentrations were similar to changes observed in the natural gas and liquid condensate production from nearby wells. High levels of ethane, a dominant natural gas species, were originating from regions with a higher density of gas wells within close proximity of the monitoring site. In contrast, the concentrations of alkene and aromatic species have declined during the study period as a result of decreases from traditional urban emission sources. However, the trend in benzene, a carcinogenic aromatic species found in vehicular and natural gas emissions, and xylene concentrations were similar to the n-alkane trend, suggesting the influence of energy production activities on key ambient aromatic compounds.

Experimental investigation of oil generation, retention, and expulsion within Type II kerogen-dominated marine shales: Insights from gold-tube nonhydrous pyrolysis of Barnett and Woodford Shales using miniature core plugs

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.

Probabilistically Mapping Well Performance in Unconventional Reservoirs with a Physics-Based Decline-Curve Model

Summary Decline curves are the simplest type of model to use to forecast production from oil and gas reservoirs. Using a selected decline model and observed production data, a trend is projected to predict future well performance and reserves. Despite capturing general trends, these models are not sufficient at describing the underlying physics of complex multiphase porous-media flow phenomena and at explaining variations in production caused by changes in operational conditions. The application of these models within a Bayesian framework is a feasible alternative to mitigate this issue and obtain more-robust forecasts by representing the possible outcomes with probability distributions. However, one important aspect that conditions the production forecasts and their uncertainty is the design of a suitable prior distribution, which can be subjective. To address the aforementioned issue, this paper presents a workflow for the development of a localized prior distribution for new wells drilled in shale formations that combines production data from pre-existing surrounding wells and spatial data, specifically well-surface/bottom coordinates. This workflow aims to establish engineering criteria to reduce the subjectivity in the design of a prior distribution, assessing spatial continuity of the parameters of a physics-based decline-curve model (θ2 model), automatically identifying regions where uncertainty can be reduced a priori, and reliably quantifying the uncertainty. A case study of 814 gas wells in the Barnett Shale is presented, and several maps are generated for the analysis of important properties to be considered during field development. The dry-gas window presented more-continuous decline-curve parameters than the wet-gas and gas/condensate windows, which resulted in lower uncertainty with the localized prior approach. As more data are acquired with time, the uncertainty in the production forecasts is further reduced and the localized prior becomes more informative, especially in the dry-gas window. The localized prior can then serve as an indicator for the performance of new infill wells in different locations. Portions of the content of this paper were initially presented in Holanda et al. (2018b), and are further developed and reviewed here.

Experimental investigation of the primary and secondary creep behaviour of shale gas reservoir rocks from deep sections of the Cooper Basin

This paper investigates the mechanical properties of shale gas reservoir rocks from deep sections of the Cooper Basin with a focus on the creep deformation at high stress and temperature conditions. Rock samples are collected from depths greater than 3000 m in Nappamerri Trough of the Cooper Basin and a series of deformation as well as creep tests were carried out using a triaxial apparatus under simulated reservoir pressure and temperature conditions. Creep tests were conducted at different axial stresses for different durations. The results of this study show that temperature and differential axial stress (a difference between axial stress and confining stress) have significant bearing on the shales' mechanical properties, including creep deformation behaviour. A number of models developed by different authors were used to analyse the experimental data (creep deformation). It has been found that none of these models can adequately describe the creep behaviour of shale gas reservoir rocks from deep sections of the Cooper Basin. In this study we have revised the power-law model and incorporated Arrhenius factor (equation) to account for temperature effect on creep behaviour of shale gas reservoir rocks. The revised power-law model is used to simulate wellbore deformation of the Roseneath, Barnett and Eagle-ford shales at the Cooper Basin temperature and pressure conditions. The results show that the Barnett exhibits little viscoelastic deformation over time while Eagle-ford exhibited twice and Roseneath 180% as much as its instantaneous elastic response over a 24 h period.

The relation between stimulated shear fractures and production in the Barnett Shale: Implications for unconventional oil and gas reservoirs

Economic production from extremely low permeability unconventional reservoirs is accomplished through multistage slick water hydraulic fracturing, which generates opening-mode hydraulic fractures and induces shear slip on preexisting fractures in the surrounding formation. We have addressed the critical contribution of the stimulated shear fracture network on production. We found production decline curves from tens of thousands of wells in four unconventional plays in the U.S. (two oil and two gas). These data indicate that during the early years of production: (1) Production is dominated by linear flow from the extremely low permeability matrix into much more permeable fracture planes, (2) the rapid decrease in production rates is a natural consequence of pressure depletion in the matrix within several meters of the more permeable planes, and (3) the cumulative area of permeable fracture planes created during stimulation is an important factor affecting cumulative production. Using data from two case studies in the Barnett Shale, we estimate the area of the fracture network from the microseismicity generated during hydraulic fracturing operations. The data from one study demonstrates that the cumulative area of the shear fracture network is needed to match production data. With data from the other case study, we demonstrate that the relative fracture area created during each stage correlates well with the relative stage-by-stage production determined from distributed temperature sensing.

Generalized Extreme Value Statistics, Physical Scaling, and Forecasts of Gas Production in the Barnett Shale

We develop a new method of predicting fieldwide gas or oil production from unconventional reservoirs, using the Barnett shale as an illustration. First, we divide the qualifying 13 141 horizontal gas wells in the Barnett into six static samples in which reservoir quality and completion technologies are similar. These samples contain wells of all ages. The Barnett samples coincide with the main gas producing counties, Tarrant, Johnson, Denton, Wise, Parker, and Hood. Second, for each sample, we use a purely data-driven nonparametric approach to arrive at appropriate generalized extreme value (GEV) distributions of gas production from the sample’s dynamic well cohorts with at least 1, 2, 3, ..., up to 14 years on production. We now have up to 14 cumulative probability distribution functions (cdfs) of annual well productivity per sample. From these cdfs, we stitch together six P50, P10, and P90 statistical well prototypes, one per sample or county. Our statistical well prototypes are conditioned by well attr...

On the release of acidic NSO compounds from the oil-mature Barnett Shale using different solvents

Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR-MS) is continuing to provide new and important insights into the composition of nitrogen-, sulfur-, and oxygen-containing (NSO) compounds of shale extracts, but its analytical window is principally determined by the polarity of the solvent used for extraction. Here we compare the selectivity with which DM (dichloromethane: methanol, v/v = 99:1) and an azeotropic solvent mixture ACM (acetone: chloroform: methanol, v/v/v = 38: 32: 30) release NSO-compounds from the oil-mature Barnett Shale of the Fort Worth Basin (USA). DM extracted less polar and smaller NSO compounds in comparison with ACM, in line with its relatively low polarity. N1, N1O1 and O2 compounds are the dominating species in the DM extracts, whereas the likely more polar compounds such as the N2, N1O2 and N2O1 species are almost un-extracted using DM. Even for the N1, N1O1 and O2 species, their high DBE (double bond equivalent) classes were neither efficiently extracted using DM. Because NSO compounds are fractionated during both primary and secondary migration, and geochemical indices have been developed to address the magnitude of these processes, it is vital that relevant chemical species are recovered from the shale efficiently. The inefficient extraction of DM makes the previous investigations of NSO compounds apparently doubtful. ACM has proved to be by far a better solvent, not only because of its high polarity but also because it is likely to gain access to the components trapped in kerogen by bringing about swelling. The azeotropic solvent mixture ACM is recommended for extracting oil-mature shale for future FT-ICR-MS analysis.

Simultaneous determination of permeability and diffusivity subject to dynamic sorption in gas shales

Gas storage and transport mechanisms are essential for the shale gas development, while the three critical parameters are fracture permeability, adsorption capacity, and diffusivity. However, significant errors on the measured permeability may occur due to the gas sorption in the pores during the lab tests, which also affects the in-situ pore pressure. In this paper, a new approach is proposed to simultaneously determine the permeability, adsorption capacity, and diffusivity based on a modified pressure transient technique in the shale formation. Results showed that the shale permeability would be overestimated by >27.3% for Barnett shale and 55.5% for Eagle Ford shale when ignoring the sorption effect. The factors leading to errors in the measured permeability is numerically investigated and it was found that the sorption effect on the measured permeability can be reduced by using short core samples. In addition, the volume of the reference cell should be at least 6 times larger than the pore volume of the sample in order to control the permeability error within 5%. This study provides a methodology which can be readily applied in simultaneous determination of gas permeability, gas storage, and gas diffusivity, and sheds lights on better understanding of the gas storage and transport mechanisms in gas shale reservoirs.

Significance and evolution characteristics of the isobutane/n-butane ratio of natural gas

In previous studies, two conflicting conclusions existed, which were: (a) the isobutane/n-butane ratio of natural gas increases with the increasing maturity (Ro) of source rocks and (b) decreases with the increasing Ro. In this paper, the correlations between the isobutane/n-butane ratios, dryness of natural gases, and the Ro values of source rocks of 77 gas samples from Cretaceous and Tertiary in Kuqa Depression, Tarim Basin, Triassic Xujiahe Formation in central Sichuan Basin, Carboniferous–Permian in Sulige and Yulin gas field, Ordos Basin, China, and 80 shale gas samples from Mississippian Barnett Shale in the Fort Worth Basin, the United States are analyzed to reveal the evolution of the isobutane/n-butane ratios, then mathematical models of the isobutane/n-butane ratios and Ro are attempted to be established. Results show that the isobutane/n-butane ratio initially increases and then decreases with increasing Ro, both coal-derived gas and oil-type gas. Diverse types of kerogens may be responsible for the different corresponding Ro values when the isobutane/n-butane ratios of gases reach their maximum values. The initial increase in the isobutane/n-butane ratios with increasing Ro is the reason that isobutane is mainly generated at a higher rate by carbonium ion reaction of α-olefins with protons during kerogen primary cracking at lower maturity, whereas free radical reactions to form n-butane relatively quickly during oil cracking at higher maturity and isobutane cracked at a higher rate during the wet gas cracking stage may result in the terminal decreases in the isobutane/n-butane ratios. Besides, mathematical models of the isobutane/n-butane ratios of different types of natural gas and maturity are established. Therefore, the maturity of gas source rock can be obtained quickly based on the models using the isobutane/n-butane ratio combined with other component information (such as dryness, wetness, etc.), which is of great significance to the characterization of natural gas maturity and gas source rock correlation.

Evaluation of the Total Organic Carbon (TOC) Using Different Artificial Intelligence Techniques

Total organic carbon (TOC) is an essential parameter used in unconventional shale resources evaluation. Current methods that are used for TOC estimation are based, either on conducting time-consuming laboratory experiments, or on using empirical correlations developed for specific formations. In this study, four artificial intelligence (AI) models were developed to estimate the TOC using conventional well logs of deep resistivity, gamma-ray, sonic transit time, and bulk density. These models were developed based on the Takagi-Sugeno-Kang fuzzy interference system (TSK-FIS), Mamdani fuzzy interference system (M-FIS), functional neural network (FNN), and support vector machine (SVM). Over 800 data points of the conventional well logs and core data collected from Barnett shale were used to train and test the AI models. The optimized AI models were validated using unseen data from Devonian shale. The developed AI models showed accurate predictability of TOC in both Barnett and Devonian shale. FNN model overperformed others in estimating TOC for the validation data with average absolute percentage error (AAPE) and correlation coefficient (R) of 12.02%, and 0.879, respectively, followed by M-FIS and SVM, while TSK-FIS model showed the lowest predictability of TOC, with AAPE of 15.62% and R of 0.832. All AI models overperformed Wang models, which have recently developed to evaluate the TOC for Devonian formation.

Pore connectivity characterization of shale using integrated wood’s metal impregnation, microscopy, tomography, tracer mapping and porosimetry

The pore connectivity of tight shale reservoirs plays an essential role in the movement of shale gas and oil, however, the characteristics of connected pores in shale with a multi-scale and coupled pore-fracture system are poorly constrained. Working with typical American (Barnett and Eagle Ford) and Chinese (Longmaxi) shale samples in 2D/3D spaces at nano- to mm-scales, connective pores were intruded with a molten alloy (Wood’s metal; WM) under a temperature of ~85 °C and high pressure (60, 300, and 600 MPa) conditions. After solidification of the alloy at room temperature, polished sections were used to map WM components by field emission-scanning electron microscopy (SEM), micro- and nano-X-ray tomography and laser ablation-inductively coupled plasma-mass spectrometry (LA-ICP-MS). These tests were supplemented with mercury intrusion porosimetry (MIP) for pore-fracture throat size distribution. The shale matrix is generally characterized by low pore connectivity; however, the extent of connectivity within μm-sized and dispersed organic matter (OM) particles is high, with the observed WM-filled pore space ranging from 10% to 70% (averaged at 43%) for the Barnett Shale sample. The grain-edge fractures are important channels to connect multiple OM-hosted pore systems dispersed in shale matrix. Our work illustrates that shales exhibit a dual-connectivity behavior, with the effective porosity decreasing sharply as the distance from the sample boundary increases; the good pore connectivity zone away from the edge of sample is 500 μm under a pressure of 600 MPa for the Barnett Shale sample.

Generalized Extreme Value Statistics, Physical Scaling and Forecasts of Oil Production in the Bakken Shale

We aim to replace the current industry-standard empirical forecasts of oil production from hydrofractured horizontal wells in shales with a statistically and physically robust, accurate and precise method of matching historic well performance and predicting well production for up to two more decades. Our Bakken oil forecasting method extends the previous work on predicting fieldwide gas production in the Barnett shale and merges it with our new scaling of oil production in the Bakken. We first divide the existing 14,678 horizontal oil wells in the Bakken into 12 static samples in which reservoir quality and completion technologies are similar. For each sample, we use a purely data-driven non-parametric approach to arrive at an appropriate generalized extreme value (GEV) distribution of oil production from that sample’s dynamic well cohorts with at least 1 , 2 , 3 , ⋯ years on production. From these well cohorts, we stitch together the P 50 , P 10 , and P 90 statistical well prototypes for each sample. These statistical well prototypes are conditioned by well attrition, hydrofracture deterioration, pressure interference, well interference, progress in technology, and so forth. So far, there has been no physical scaling. Now we fit the parameters of our physical scaling model to the statistical well prototypes, and obtain a smooth extrapolation of oil production that is mechanistic, and not just a decline curve. At late times, we add radial inflow from the outside. By calculating the number of potential wells per square mile of each Bakken region (core and noncore), and scheduling future drilling programs, we stack up the extended well prototypes to obtain the plausible forecasts of oil production in the Bakken. We predict that Bakken will ultimately produce 5 billion barrels of oil from the existing wells, with the possible addition of 2 and 6 billion barrels from core and noncore areas, respectively.

Characterizing anthropogenic methane sources in the Houston and Barnett Shale areas of Texas using the isotopic signature δ13C in CH4

Methane (CH4) is an important greenhouse gas with its mixing ratio increasing in the global atmosphere. Identifying fingerprints of CH4 emissions is critical to understanding potential impacts of various anthropogenic sources in the Greater Houston area (GHA) and extensive natural gas operations in the Barnett Shale area (BSA) of Texas. Stable carbon isotope ratios of CH4 (δ13CCH4) has been proposed to be a useful technique for differentiating individual CH4 sources. Measurements of CH4 mixing ratios and δ13CCH4 were sampled using a mobile laboratory equipped with cavity ring-down spectrometers (CRDS). Areal CH4 distributions and the background δ13CCH4 signature were obtained from filtered ambient signals; −47.0‰ (GHA) and − 48.5‰ (BSA) were calculated. The fingerprint of thirty-three anthropogenic sources in the two study areas were sampled with forty-four δ13C analyses conducted. Repeated measurements indicated the natural variation of δ13CCH4 signatures of individual CH4 sources. An unexpected massive CH4 fugitive leak was detected near the San Jacinto River Fleet site in Houston exhibiting an δ13CCH4 value around −42‰. Our results and findings demonstrate the utility of δ13CCH4for facilitating emission inventories and atmospheric modeling.

Geochemical and microbial characterizations of flowback and produced water in three shale oil and gas plays in the central and western United States

Limited understanding of wastewater streams produced from shale oil and gas wells impedes best practices of wastewater treatment and reuse. This study provides a comprehensive and comparative analysis of flowback and produced water from three major and newly developed shale plays (the Bakken shale, North Dakota; the Barnett shale, Texas; and the Denver-Julesburg (DJ) basin, Colorado) in central and western United States. Geochemical features that included more than 10 water quality parameters, dissolved organic matter, as well as microbial community structures were characterized and compared. Results showed that wastewater from Bakken and Barnett shales has extremely high salinity (∼295 g/L total dissolved solids (TDS)) and low organic concentration (80–252 mg/L dissolved organic carbon (DOC)). In contrast, DJ basin showed an opposite trend with low TDS (∼30 g/L) and high organic content (644 mg/L DOC). Excitation-emission matrix (EEM) fluorescence spectra demonstrated that more humic acid and fluvic acid-like organics with higher aromaticity existed in Bakken wastewater than that in Barnett and DJ basin. Microbial communities of Bakken samples were dominated by Fe (III)-reducing bacteria Geobacter, lactic acid bacteria Lactococcus and Enterococcus, and Bradyrhizobium, while DJ basin water showed higher abundance of Rhodococcus, Thermovirga, and sulfate reducing bacteria Thermotoga and Petrotoga. All these bacteria are capable of hydrocarbon degradation. Hydrogenotrophic methanogens dominated the archaeal communities in all samples.

Attribute selection in seismic facies classification: Application to a Gulf of Mexico 3D seismic survey and the Barnett Shale

Automated seismic facies classification using machine-learning algorithms is becoming more common in the geophysics industry. Seismic attributes are frequently used as input because they may express geologic patterns or depositional environments better than the original seismic amplitude. Selecting appropriate attributes becomes a crucial part of the seismic facies classification analysis. For unsupervised learning, principal component analysis can reduce the dimensions of the data while maintaining the highest variance possible. For supervised learning, the best attribute subset can be built by selecting input attributes that are relevant to the output class and avoiding using redundant attributes that are similar to each other. Multiple attributes are tested to classify salt diapirs, mass transport deposits (MTDs), and the conformal reflector “background” for a 3D seismic marine survey acquired on the northern Gulf of Mexico shelf. We have analyzed attribute-to-attribute correlation and the correlation between the input attributes to the output classes to understand which attributes are relevant and which attributes are redundant. We found that amplitude and texture attribute families are able to differentiate salt, MTDs, and conformal reflectors. Our attribute selection workflow is also applied to the Barnett Shale play to differentiate limestone and shale facies. Multivariate analysis using filter, wrapper, and embedded algorithms was used to rank attributes by importance, so then the best attribute subset for classification is chosen. We find that attribute selection algorithms for supervised learning not only reduce computational cost but also enhance the performance of the classification.

Development of a full 3D numerical model to investigate the hydraulic fracture propagation under the impact of orthogonal natural fractures

Although hydraulic fracturing has been massively studied and applied as a key technique to enhance the gas production from tight formations, some problems and uncertainties exist to accurately predict and analyze the fracture behavior in complex reservoirs, especially in the naturally fractured reservoirs like shale reservoirs. This paper presents a full 3D numerical model (FLAC3D) to study hydraulic fracturing behavior under the impact of preexisting orthogonal natural fractures. In this numerical model, the hydraulic fracture propagation direction is assumed perpendicular to the minimum principal stress and activated only by tensile failure, whereas the preexisting natural fractures can be activated by tensile or shear failure or a combination of them, and only tensile failure can open the natural fracture as well. The newly developed model was used to study the impact of preexisting orthogonal natural fractures on hydraulic fracturing behavior, based on a multistage hydraulic fracturing operation in a naturally fractured reservoir from the Barnett Shale formation, northwest of Texas in USA. In this multistage operation, two more representative stages, i.e., stage 1 with a relatively large horizontal stress anisotropy of 3.3 MPa and stage 4 with a comparatively small one of 1.3 MPa, were selected to conduct the simulation. Based on the numerical results, one can observe that the interaction between hydraulic and natural fracture is driven mainly by induced stress around fracture tip. Besides, the horizontal stress anisotropy plays a key role in opening the natural fracture. Thus, no significant opened fracture is activated on natural fracture in stage 1, while in stage 4 an opened fracture invades to about 90 m into the first natural fracture. Conversely, the hydraulic fracture length in stage 1 is much longer than in stage 4, as some fluid volume is stored in the opened natural fracture in stage 4. In this work, the shear failure on natural fractures is treated as the main factor for inducing the seismic events. And the simulated seismic events, i.e., shear failure on natural fractures, are very comparable with the measured seismic events.

Integrated Approach Improves Modeling of Rejuvenation in Unconventional Plays

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 191457, “Coupling Geomechanical Effects and Reservoir Dynamics for Modeling Rejuvenation in Unconventional Plays,” by R. Dutta, SPE, Drilling Info; R. Pinto, Sciences Po University; and J.C. Flores, S.M. Stolyarov, SPE, and J. Yang, Baker Hughes, a GE Company, prepared for the 2018 SPE International Hydraulic Fracturing Technology Conference and Exhibition, Muscat, Oman, 16–18 October. The paper has not been peer reviewed. An integrated understanding of geomechanical effects, fracture propagation, and reservoir dynamics is critical in the efficient and cost-effective application of rejuvenation technologies for unconventional plays. While various reservoir models depicting the hydraulic-fracturing process are available in the industry, many tend to be simplified or do not capture the numerous parameters that affect both the initial and restimulation processes. This work takes a further step toward building a more-realistic picture of fracturing in unconventional plays. Introduction A common assumption in reservoir simulation is that the proppant-fluid mixture is present in the hydraulic fracture before flowback and production. The quantity of water assumed to be present in the hydraulic fractures is a conjecture and is calibrated generally with production-logging tools. These assumptions may skew the results of hydrocarbon recovery. A method of incorporating geomechanical aspects of fracturing into the model involves the concept of pressure-dependent permeability variation in natural fractures that results in formation of pressure-dependent stimulated reservoir volume (SRV). Hysteretic permeability models employed in numerical modeling can offer a description of the SRV and also can be used in addressing longer-term geomechanical effects in a practical manner. While this concept has matured in the context of modeling hydraulic fracturing in reservoir simulation, it is being newly applied in modeling refracturing treatments. Because the importance of capillary effect in low-permeability formations is recognized, the authors also incorporate capillary pressure in their model. In addition to pressure-dependent permeability variation, results explain how capillarity is significant in understanding fluid migration, the trapping of fluid in the matrix, and, consequently, restimulation. Methodology The main challenge in selecting good candidate wells for this study was in finding wells that targeted the same formation, used varying refracturing technologies, and had sufficient data to build a reservoir-simulation model with input for the reservoir properties. After studying a large number of wells, the authors focused on two horizontal gas wells producing from the Barnett Shale. One well was identified to be refractured with a selective zone-treatment method, while the other used a method of fluid diversion. The wells are located approximately 3 miles from each other and approximately 1,600 ft from neighboring wells. These wells have differing production signatures, but this is not indicative of a difference in the performance of two technologies. Understanding the difference in performance may be key to planning a successful refracturing operation.