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Special Issue "Unconventional Natural Gas (UNG) Recoveries 2018"

A special issue of Energies (ISSN 1996-1073).

Deadline for manuscript submissions: closed (30 April 2018).

Special Issue Editor

Prof. Dr. Ranjith Pathegama Gamage
E-Mail Website1 Website2
Guest Editor
Department of Civil Engineering, Faculty of Engineering, Monash University, Clayton Campus, Clayton, VIC 3800, Australia
Interests: unconventional oil and gas (shale gas, tight gas, coal seam gas); deep geothermal energy; geological sequestration of carbon dioxide; petroleum geomechanics; in situ leaching; mining geomechanics; rock mechanics; enhanced oil recovery methodologies (EOR); sand production from unconsolidated reservoirs; wellbore stability; well cement
Special Issues, Collections and Topics in MDPI journals

Special Issue Information

Dear Colleagues,

“Unconventional Natural Gas (UNG) Recoveries 2018” is a continuation of the previous and successful Special Issue, “Unconventional Natural Gas (UNG) Recoveries”.

Our energy resources are crucial; but they are under pressure from growing populations, urbanisation, and economic prosperity. By 2040, global demand for energy will increase by 40% over present levels. By then, it is forecast that approximately 75% of energy demand will still be met by fossil fuels—but oil and coal will have lessened in importance due to tight regulation and advances in more environmentally friendly alternatives. Which newer fossil fuel will emerge to dominate in the next few decades? There is one clear answer: Natural gas.

Despite the challenges, climate change legislation and regulation to limit greenhouse gases have already allowed natural gas to compete favourably with oil and coal. It is now ranked third among the world’s major energy sources; and it is the cleanest and the richest in hydrocarbons, offering high energy-conversion efficiencies for power generation.

Conventional gas is easy to harvest. It has been produced across the world in the last few decades, so its reserves are now rapidly depleting. In contrast, the earth holds huge untapped reserves of unconventional—but locked within compact rocks, such as shale, coal seams, and tight sandstones.

The greatest challenge for exploitation of unconventional natural gas (UNG) is very low recovery rates, because of low permeability in its deep reservoirs. Reducing the complexity in exploration targets, using suitable exploration and production technologies (such as new stimulation technologies to prompt release of the gas), has potential to release vast quantities of UNG from highly impermeable format­ions. However, unique conditions in UNG reservoirs call for innovative technologies founded securely on new science. This proposal calls for papers in the areas of new sciences developed to enhance the recovery process of gas from coal seams, shale, and tight formations. 

We will, therefore, especially welcome submissions on the following topics:

  • Gas flow and diffusions of coal seams, shales, tight gas reservoirs
  • Techniques to enhance gas recoveries, such as hydro fracking and innovations in well drilling
  • Caprock integrity and associated environmental issues
  • Coupled hydro-chemico-mechanical processes
  • Reservoir geomechanics, and wellbore and drilling mechanics
  • Constitutive modelling and numerical methods
  • Numerical modelling of THM
  • Adsorption/desorption characterises of rocks
  • Case studies of international interest
Prof. Ranjith Pathegama Gamage
Guest Editor

Manuscript Submission Information

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Please visit the Instructions for Authors page before submitting a manuscript. The Article Processing Charge (APC) for publication in this open access journal is 2000 CHF (Swiss Francs). Submitted papers should be well formatted and use good English. Authors may use MDPI's English editing service prior to publication or during author revisions.

Keywords

  • shale gas
  • coal seams gas
  • tight gas
  • geomechanics
  • adsorptions
  • desorption
  • stimulations

Published Papers (17 papers)

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Research

Article
Estimation of the Relative Arrival Time of Microseismic Events Based on Phase-Only Correlation
Energies 2018, 11(10), 2527; https://doi.org/10.3390/en11102527 - 21 Sep 2018
Cited by 2 | Viewed by 1159
Abstract
The arrival time of a microseismic event is an important piece of information for microseismic monitoring. The accuracy and efficiency of arrival time identification is affected by many factors, such as the low signal-to-noise ratio (SNR) of the records, the vast amount of [...] Read more.
The arrival time of a microseismic event is an important piece of information for microseismic monitoring. The accuracy and efficiency of arrival time identification is affected by many factors, such as the low signal-to-noise ratio (SNR) of the records, the vast amount of real-time monitoring records, and the abnormal situations of monitoring equipment. In order to eliminate the interference of these factors, we propose a method based on phase-only correlation (POC) to estimate the relative arrival times of microseismic events. The proposed method includes three main steps: (1) The SNR of the records is improved via time-frequency transform, which is used to obtain the time-frequency representation of each trace of a microseismic event. (2) The POC functions of all pairs of time-frequency representations are calculated. The peak value of the POC function indicates the similarity of the traces, and the peak position in the time lag axis indicates the relative arrival times between the traces. (3) Using the peak values as weighting coefficients of the linear equations, consistency processing is used to exclude any abnormal situations and obtain the optimal relative arrival times. We used synthetic data and field data to validate the proposed method. Comparing with Akaike information criterion (AIC) and cross-correlation, the proposed method is more robust at estimating the relative arrival time and excluding the influence of abnormal situations. Full article
(This article belongs to the Special Issue Unconventional Natural Gas (UNG) Recoveries 2018)
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Article
Method for Visualizing Fractures Induced by Laboratory-Based Hydraulic Fracturing and Its Application to Shale Samples
Energies 2018, 11(8), 1976; https://doi.org/10.3390/en11081976 - 30 Jul 2018
Cited by 6 | Viewed by 1472
Abstract
A better understanding of the process of stimulation by hydraulic fracturing in shale gas and oil reservoirs is necessary for improving resource productivity. However, direct observation of hydraulically stimulated regions including induced fractures has been difficult. In the present study, we develop a [...] Read more.
A better understanding of the process of stimulation by hydraulic fracturing in shale gas and oil reservoirs is necessary for improving resource productivity. However, direct observation of hydraulically stimulated regions including induced fractures has been difficult. In the present study, we develop a new approach for directly visualizing regions of shale specimens impregnated by fluid during hydraulic fracturing. The proposed laboratory method uses a thermosetting resin mixed with a fluorescent substance as a fracturing fluid. After fracturing, the resin is fixed within the specimens by heating, and the cut sections are then observed under ultraviolet light. Based on brightness, we can then distinguish induced fractures and their surrounding regions impregnated by the fluid from other regions not reached by the fluid. Polarization microscope observation clearly reveals the detailed structures of tortuous or branched fractures on the micron scale and interactions between fractures and constituent minerals. The proposed experimental and observation method is useful for understanding the process of stimulation by hydraulic fracturing and its relationship with microscopic rock characteristics, which is important for fracturing design optimization in shale gas and oil resource development. Full article
(This article belongs to the Special Issue Unconventional Natural Gas (UNG) Recoveries 2018)
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Article
Influence of Grain Size Heterogeneity and In-Situ Stress on the Hydraulic Fracturing Process by PFC2D Modeling
Energies 2018, 11(6), 1413; https://doi.org/10.3390/en11061413 - 01 Jun 2018
Cited by 14 | Viewed by 1422
Abstract
A modified fluid-mechanically coupled algorithm in PFC2D was adopted in this article to study the influence of grain size heterogeneity and in-situ stress on hydraulic fracturing behavior. Simulated results showed that the in-situ stress and grain size heterogeneity significantly affect the initiation, [...] Read more.
A modified fluid-mechanically coupled algorithm in PFC2D was adopted in this article to study the influence of grain size heterogeneity and in-situ stress on hydraulic fracturing behavior. Simulated results showed that the in-situ stress and grain size heterogeneity significantly affect the initiation, growth, and spatial distribution of the hydraulic fractures: (1) the initiation and breakdown pressure are gradually reduced with the increase of the grain size heterogeneity; (2) with increased in-situ stress, the initiation and breakdown pressure increase, and the reduction effect of grain size heterogeneity on the breakdown pressure becomes more obvious; (3) in grain size homogeneous rock, the initiation pressure decreases with increasing in-situ stress ratio, however, the initiation pressure of grain size heterogeneous rock is almost unaffected by the in-situ stress ratio; (4) The in-situ stress ratio and grain size heterogeneity affect the spatial distribution of hydraulic fractures simultaneously. When the in-situ stress ratio is larger than 1, the hydraulic fractures propagate substantially along the direction of the maximum principal stress. When the in-situ stress ratio is 1, the initiation position and extension direction of hydraulic fractures are random and complex fracture networks can easily develop in a grain size homogeneous model. Full article
(This article belongs to the Special Issue Unconventional Natural Gas (UNG) Recoveries 2018)
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Article
Mechanical Property Measurements and Fracture Propagation Analysis of Longmaxi Shale by Micro-CT Uniaxial Compression
Energies 2018, 11(6), 1409; https://doi.org/10.3390/en11061409 - 31 May 2018
Cited by 22 | Viewed by 2066
Abstract
The mechanical properties and fracture propagation of Longmaxi shale loading under uniaxial compression were measured using eight cylindrical shale specimens (4 mm in diameter and 8 mm in height), with the bedding plane oriented at 0° and 90° to the axial loading direction, [...] Read more.
The mechanical properties and fracture propagation of Longmaxi shale loading under uniaxial compression were measured using eight cylindrical shale specimens (4 mm in diameter and 8 mm in height), with the bedding plane oriented at 0° and 90° to the axial loading direction, respectively, by micro computed tomography (micro-CT). Based on the reconstructed three-dimensional (3-D) CT images of cracks, different stages of the crack growth process in the 0° and 90° orientation specimen were revealed. The initial crack generally occurred at relatively smaller loading force in the 0° bedding direction specimen, mainly in the form of tensile splitting along weak bedding planes. Shear sliding fractures were dominant in the specimens oriented at 90°, with a small number of parallel cracks occurring on the bedding plane. The average thickness and volume of cracks in the 90° specimen is higher than those for the specimen oriented at 0°. The geometrical characterization of fractures segmented from CT scan binary images shows that a specific surface area correlates with tortuosity at the different load stages of each specimen. The 3-D box-counting dimension (BCD) calculations can accurately reflect crack evolution law in the shale. The results indicate that the cracks have a more complex pattern and rough surface at an orientation of 90°, due to crossed secondary cracks and shear failure. Full article
(This article belongs to the Special Issue Unconventional Natural Gas (UNG) Recoveries 2018)
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Article
Reconstruction of Hydraulic Fractures Using Passive Ultrasonic Travel-Time Tomography
Energies 2018, 11(5), 1321; https://doi.org/10.3390/en11051321 - 22 May 2018
Cited by 8 | Viewed by 1902
Abstract
The knowledge of hydraulic fracture morphology is significant for the analysis of fracture mechanisms. This paper utilizes passive Ultrasonic Travel-time Tomography (UTT) to characterize the hydraulic fracture. We constructed a velocity model based on X-ray computerized tomography (X-CT) images scanned on a real [...] Read more.
The knowledge of hydraulic fracture morphology is significant for the analysis of fracture mechanisms. This paper utilizes passive Ultrasonic Travel-time Tomography (UTT) to characterize the hydraulic fracture. We constructed a velocity model based on X-ray computerized tomography (X-CT) images scanned on a real hydraulically fractured shale column. Then, ray-paths and travel times corresponding to the source-receiver configuration were calculated by curved ray-tracing schemes. Lastly, we performed tomographic inversions using total variation regularization (TVR). The simulation results showed that 3D passive UTT based on TVR is an accurate, efficient, and stable method to reconstruct the velocity structures with fractures, even in the case of sparse ray-coverage or high noise level. Meanwhile, we also verified that the passive UTT is a valid alternative to X-CT in depicting the hydraulic fracturing rock via a proper interpretation method. Full article
(This article belongs to the Special Issue Unconventional Natural Gas (UNG) Recoveries 2018)
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Article
Effects of Water and Brine Saturation on Mechanical Property Alterations of Brown Coal
Energies 2018, 11(5), 1116; https://doi.org/10.3390/en11051116 - 02 May 2018
Cited by 15 | Viewed by 1576
Abstract
The adsorption of moisture or brine into coal causes the coal mass mechanical properties to be significantly altered, which can greatly affect the coal mining and coal seam gas extraction process. A study was therefore initiated to investigate the influence of moisture and [...] Read more.
The adsorption of moisture or brine into coal causes the coal mass mechanical properties to be significantly altered, which can greatly affect the coal mining and coal seam gas extraction process. A study was therefore initiated to investigate the influence of moisture and brine saturations (5–25%) on brown coals’ strength through a series of unconfined compressive strength tests, with the aid of acoustic emission, optical 3-D deformation analysis and scanning electron microscopy. According to the results, the coal mass is weakened by up to 26% upon the adsorption of moisture and water saturated samples show no crack propagation, whereas brine saturation enhances coal strength by up to 21% and delays crack propagation due to the crystallization of sodium chloride. Besides, a high brine concentration (25%) greatly improves coal mass strength but impairs the increase of Young’s modulus due to its corrosive nature, which is consistent with the values of maximum strain at failure of the tested samples (3.9%, 3.1% and 3.6% for 5%, 15% and 25% brine saturated samples, respectively). In addition, because of the precipitation of sodium chloride in coal and the increase of conductivity of pore fluid, more acoustic emission signals are detected for brine saturated samples, while water saturated samples exhibit mush less acoustic release compared to the unsaturated samples. Full article
(This article belongs to the Special Issue Unconventional Natural Gas (UNG) Recoveries 2018)
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Article
Vacuum Exhaust Process in Pilot-Scale Vacuum Pressure Swing Adsorption for Coal Mine Ventilation Air Methane Enrichment
Energies 2018, 11(5), 1030; https://doi.org/10.3390/en11051030 - 24 Apr 2018
Cited by 15 | Viewed by 2327
Abstract
Recovery and treatment of methane from coal mine ventilation air methane (VAM) with cost-effective technologies have been an ongoing challenge due to low methane concentrations. In this study, a type of coconut shell-based active carbon was employed to enrich VAM with a three-bed [...] Read more.
Recovery and treatment of methane from coal mine ventilation air methane (VAM) with cost-effective technologies have been an ongoing challenge due to low methane concentrations. In this study, a type of coconut shell-based active carbon was employed to enrich VAM with a three-bed vacuum pressure swing adsorption unit. A new vacuum exhaust step for the VPSA process was introduced. The results show that the vacuum exhaust step can increase the methane concentration of the product without changing adsorption and desorption pressure. Under laboratory conditions, the concentration of product increased from 0.4% to 0.69% as the vacuum exhaust ratio increased from 0 to 3.1 when the feed gas concentration was 0.2%. A 500 m³/h pilot-scale test system for VAM enrichment was built rendering good correlation with the laboratory results in terms of the vacuum exhaust step. By using a two-stage three-bed separation unit, the VAM was enriched from 0.2% to over 1.2%. Full article
(This article belongs to the Special Issue Unconventional Natural Gas (UNG) Recoveries 2018)
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Article
Anisotropic Damage to Hard Brittle Shale with Stress and Hydration Coupling
Energies 2018, 11(4), 926; https://doi.org/10.3390/en11040926 - 13 Apr 2018
Cited by 16 | Viewed by 1978
Abstract
Acoustic-wave velocities of shale rocks with different coring angles were tested by an acoustic-emission experiment under different confining pressures and soaking time of drilling fluid. Effects of stress and hydration coupling on the acoustic-wave velocities, elastic parameters, and anisotropic damage were analyzed and [...] Read more.
Acoustic-wave velocities of shale rocks with different coring angles were tested by an acoustic-emission experiment under different confining pressures and soaking time of drilling fluid. Effects of stress and hydration coupling on the acoustic-wave velocities, elastic parameters, and anisotropic damage were analyzed and investigated. The following results were obtained: (1) Acoustic-wave velocities of shale rocks are related to the confining pressure, soaking time, and coring angles. (2) Both Young’s modulus and Poisson’s ratios increase with confining pressure under the same soaking time; under the same confining pressure, the changes of Young’s modulus and Poisson’s ratios with time are not as obvious as the confining pressure, but it shows that the Young’s modulus decreases, while the Poisson’s ratios increase. (3) With increasing confining pressure, the Thomsen coefficient ε showed an increasing trend, whereas the Thomsen coefficient γ exhibited the opposite trend; further, the anisotropy coefficient of P-wave (ε) is larger than the anisotropy coefficient of S-wave (γ). (4) Damage parameters parallel to bedding are greater than those perpendicular to bedding; when the confining pressure increases, the fracture pores gradually close, and both vertical and horizontal damage parameters are reduced. Full article
(This article belongs to the Special Issue Unconventional Natural Gas (UNG) Recoveries 2018)
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Article
Empirical Modeling of the Viscosity of Supercritical Carbon Dioxide Foam Fracturing Fluid under Different Downhole Conditions
Energies 2018, 11(4), 782; https://doi.org/10.3390/en11040782 - 29 Mar 2018
Cited by 12 | Viewed by 1969
Abstract
High-quality supercritical CO2 (sCO2) foam as a fracturing fluid is considered ideal for fracturing shale gas reservoirs. The apparent viscosity of the fracturing fluid holds an important role and governs the efficiency of the fracturing process. In this study, the [...] Read more.
High-quality supercritical CO2 (sCO2) foam as a fracturing fluid is considered ideal for fracturing shale gas reservoirs. The apparent viscosity of the fracturing fluid holds an important role and governs the efficiency of the fracturing process. In this study, the viscosity of sCO2 foam and its empirical correlations are presented as a function of temperature, pressure, and shear rate. A series of experiments were performed to investigate the effect of temperature, pressure, and shear rate on the apparent viscosity of sCO2 foam generated by a widely used mixed surfactant system. An advanced high pressure, high temperature (HPHT) foam rheometer was used to measure the apparent viscosity of the foam over a wide range of reservoir temperatures (40–120 °C), pressures (1000–2500 psi), and shear rates (10–500 s−1). A well-known power law model was modified to accommodate the individual and combined effect of temperature, pressure, and shear rate on the apparent viscosity of the foam. Flow indices of the power law were found to be a function of temperature, pressure, and shear rate. Nonlinear regression was also performed on the foam apparent viscosity data to develop these correlations. The newly developed correlations provide an accurate prediction of the foam’s apparent viscosity under different fracturing conditions. These correlations can be helpful for evaluating foam-fracturing efficiency by incorporating them into a fracturing simulator. Full article
(This article belongs to the Special Issue Unconventional Natural Gas (UNG) Recoveries 2018)
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Article
A New Scheme to Improve the Performance of Artificial Intelligence Techniques for Estimating Total Organic Carbon from Well Logs
Energies 2018, 11(4), 747; https://doi.org/10.3390/en11040747 - 26 Mar 2018
Cited by 8 | Viewed by 1887
Abstract
Total organic carbon (TOC), a critical geochemical parameter of organic shale reservoirs, can be used to evaluate the hydrocarbon potential of source rocks. However, getting TOC through core analysis of geochemical experiments is costly and time-consuming. Therefore, in this paper, a TOC prediction [...] Read more.
Total organic carbon (TOC), a critical geochemical parameter of organic shale reservoirs, can be used to evaluate the hydrocarbon potential of source rocks. However, getting TOC through core analysis of geochemical experiments is costly and time-consuming. Therefore, in this paper, a TOC prediction model was built by combining the data from a case study in the Ordos Basin, China and core analysis with artificial intelligence techniques. In the study, the data of samples were optimized based on annealing algorithm (SA) and genetic algorithm (GA), named SAGA-FCM method. Then, back propagation algorithm (BPNN), least square support vector machine (LSSVM), and least square support vector machine based on particle swarm optimization algorithm (PSO-LSSVM) were built based on the data from optimization. The results show that the intelligence model constructed based on core samples data after optimization has much better performance in both training and validation accuracy than the model constructed based on original data. In addition, R2 and MRSE in PSO-LSSVM are 0.9451 and 1.1883, respectively, which proves that models established with optimal dataset of core samples have higher accuracy. This study shows that the quality of sample data affects the prediction of the intelligence model dramatically and the PSO-LSSVM model can present the relationship between well log data and TOC; thus, PSO-LSSVM is a powerful tool to estimate TOC. Full article
(This article belongs to the Special Issue Unconventional Natural Gas (UNG) Recoveries 2018)
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Article
Experimental Study of Matrix Permeability of Gas Shale: An Application to CO2-Based Shale Fracturing
Energies 2018, 11(4), 702; https://doi.org/10.3390/en11040702 - 21 Mar 2018
Cited by 9 | Viewed by 1530
Abstract
Because the limitations of water-based fracturing fluids restrict their fracturing efficiency and scope of application, liquid CO2 is regarded as a promising substitute, owing to its unique characteristics, including its greater environmental friendliness, shorter clean-up time, greater adsorption capacity than CH4 [...] Read more.
Because the limitations of water-based fracturing fluids restrict their fracturing efficiency and scope of application, liquid CO2 is regarded as a promising substitute, owing to its unique characteristics, including its greater environmental friendliness, shorter clean-up time, greater adsorption capacity than CH4 and less formation damage. Conversely, the disadvantage of high leak-off rate of CO2 fracturing due to its very low viscosity determines its applicability in gas shales with ultra-low permeability, accurate measurement of shale permeability to CO2 is therefore crucial to evaluate the appropriate injection rate and total consumption of CO2. The main purpose of this study is to accurately measure shale permeability to CO2 flow during hydraulic fracturing, and to compare the leak-off of CO2 and water fracturing. A series of permeability tests was conducted on cylindrical shale samples 38 mm in diameter and 19 mm long using water, CO2 in different phases and N2 considering multiple influencing factors. According to the experimental results, the apparent permeability of shale matrix to gaseous CO2 or N2 is greatly over-estimated compared with intrinsic permeability or that of liquid CO2 due to the Klinkenberg effect. This phenomenon explains that the permeability values measured under steady-state conditions are much higher than those under transient conditions. Supercritical CO2 with higher molecular kinetic energy has slightly higher permeability than liquid CO2. The leak-off rate of CO2 is an order of magnitude higher than that of water under the same injection conditions due to its lower viscosity. The significant decrease of shale permeability to gas after water flooding is due to the water block effect, and much longer clean-up time and deep water imbibition depth greatly impede the gas transport from the shale matrix to the created fractures. Therefore, it is necessary to substitute water-based fracturing fluids with liquid or super-critical CO2 in clay-abundant shale formations. Full article
(This article belongs to the Special Issue Unconventional Natural Gas (UNG) Recoveries 2018)
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Article
An Artificially Intelligent Technique to Generate Synthetic Geomechanical Well Logs for the Bakken Formation
Energies 2018, 11(3), 680; https://doi.org/10.3390/en11030680 - 17 Mar 2018
Cited by 13 | Viewed by 2333
Abstract
Artificially intelligent and predictive modelling of geomechanical properties is performed by creating supervised machine learning data models utilizing artificial neural networks (ANN) and will predict geomechanical properties from basic and commonly used conventional well logs such as gamma ray, and bulk density. The [...] Read more.
Artificially intelligent and predictive modelling of geomechanical properties is performed by creating supervised machine learning data models utilizing artificial neural networks (ANN) and will predict geomechanical properties from basic and commonly used conventional well logs such as gamma ray, and bulk density. The predictive models were created by following the approach on a large volume of data acquired from 112 wells containing the Bakken Formation in North Dakota. The studied wells cover a large surface area of the formation containing the five main producing counties in North Dakota: Burke, Mountrail, McKenzie, Dunn, and Williams. Thus, with a large surface area being analyzed in this research, there is confidence with a high degree of certainty that an extensive representation of the Bakken Formation is modelled, by training neural networks to work on varying properties from the different counties containing the Bakken Formation in North Dakota. Shear wave velocity of 112 wells is also analyzed by regression methods and neural networks, and a new correlation is proposed for the Bakken Formation. The final goal of the research is to achieve supervised artificial neural network models that predict geomechanical properties of future wells with an accuracy of at least 90% for the Upper and Middle Bakken Formation. Thus, obtaining these logs by generating it from statistical and artificially intelligent methods shows a potential for significant improvements in performance, efficiency, and profitability for oil and gas operators. Full article
(This article belongs to the Special Issue Unconventional Natural Gas (UNG) Recoveries 2018)
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Article
Automatic Identification of Fractures Using a Density-Based Clustering Algorithm with Time-Spatial Constraints
Energies 2018, 11(3), 563; https://doi.org/10.3390/en11030563 - 06 Mar 2018
Cited by 6 | Viewed by 1610
Abstract
In shale gas hydraulic fracture monitoring or rock acoustic emission experiments, fracture plane identification is always a complex task. Conventional approaches typically use the source locating results derived from the micro-seismic event and then interpret the fracture plane using manual qualitative analysis. Large [...] Read more.
In shale gas hydraulic fracture monitoring or rock acoustic emission experiments, fracture plane identification is always a complex task. Conventional approaches typically use the source locating results derived from the micro-seismic event and then interpret the fracture plane using manual qualitative analysis. Large errors typically occur due to manual operations. On the other hand, the density-based clustering algorithm with spatial constraints is widely used in geographic information science, biological cells science and astronomy. It is an automated algorithm and can achieve good classification results. In this paper, we introduced the above-mentioned clustering algorithm with spatial constraints to fracture identification applications. Moreover, because micro-seismic events are 4D in nature, every micro-seismic event has both time and space information. Hence, we improve the conventional clustering algorithm by incorporating a time constraint. We test the proposed method using rock acoustic emissions data and compare our fracture identification results with CT scan images; the comparison clearly shows the effectiveness of the proposed method. Full article
(This article belongs to the Special Issue Unconventional Natural Gas (UNG) Recoveries 2018)
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Article
Brazilian Tensile Strength of Anisotropic Rocks: Review and New Insights
Energies 2018, 11(2), 304; https://doi.org/10.3390/en11020304 - 30 Jan 2018
Cited by 36 | Viewed by 3313
Abstract
Strength anisotropy is one of the most distinct features of anisotropic rocks, and it also normally reveals strong anisotropy in Brazilian test Strength (“BtS”). Theoretical research on the “BtS” of anisotropic rocks is seldom performed, and in particular some significant factors, such as [...] Read more.
Strength anisotropy is one of the most distinct features of anisotropic rocks, and it also normally reveals strong anisotropy in Brazilian test Strength (“BtS”). Theoretical research on the “BtS” of anisotropic rocks is seldom performed, and in particular some significant factors, such as the anisotropic tensile strength of anisotropic rocks, the initial Brazilian disc fracture points, and the stress distribution on the Brazilian disc, are often ignored. The aim of the present paper is to review the state of the art in the experimental studies on the “BtS” of anisotropic rocks since the pioneering work was introduced in 1964, and to propose a novel theoretical method to underpin the failure mechanisms and predict the “BtS” of anisotropic rocks under Brazilian test conditions. The experimental data of Longmaxi Shale-I and Jixi Coal were utilized to verify the proposed method. The results show the predicted “BtS” results show strong agreement with experimental data, the maximum error is only ~6.55% for Longmaxi Shale-I and ~7.50% for Jixi Coal, and the simulated failure patterns of the Longmaxi Shale-I are also consistent with the test results. For the Longmaxi Shale-I, the Brazilian disc experiences tensile failure of the intact rock when 0° ≤ βw ≤ 24°, shear failure along the weakness planes when 24° ≤ βw ≤ 76°, and tensile failure along the weakness planes when 76° ≤ βw ≤ 90°. For the Jixi Coal, the Brazilian disc experiences tensile failure when 0° ≤ βw ≤ 23° or 76° ≤ βw ≤ 90°, shear failure along the butt cleats when 23° ≤ βw ≤ 32°, and shear failure along the face cleats when 32° ≤ βw ≤ 76°. The proposed method can not only be used to predict the “BtS” and underpin the failure mechanisms of anisotropic rocks containing a single group of weakness planes, but can also be generalized for fractured rocks containing multi-groups of weakness planes. Full article
(This article belongs to the Special Issue Unconventional Natural Gas (UNG) Recoveries 2018)
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Article
A New Insight into Shale-Gas Accumulation Conditions and Favorable Areas of the Xinkailing Formation in the Wuning Area, North-West Jiangxi, China
Energies 2018, 11(1), 12; https://doi.org/10.3390/en11010012 - 21 Dec 2017
Cited by 9 | Viewed by 2196
Abstract
In north-west Jiangxi, China, most shale-gas exploration has been focused on the Lower Cambrian Hetang and Guanyintang formations, whereas the Upper Ordovician Xinkailing formation shale has been ignored for years due to heavy weathering. This study systematically analyzed gas source conditions, reservoir conditions [...] Read more.
In north-west Jiangxi, China, most shale-gas exploration has been focused on the Lower Cambrian Hetang and Guanyintang formations, whereas the Upper Ordovician Xinkailing formation shale has been ignored for years due to heavy weathering. This study systematically analyzed gas source conditions, reservoir conditions and gas-bearing ability in order to reveal the shale-gas accumulation conditions of the Xinkailing formation. The results show that the Xinkailing formation is characterized by thick deposition of black shale (10–80 m), high organic content (with total organic carbon between 1.18% and 3.11%, on average greater than 2%), relatively moderate thermal evolution (with vitrinite reflectance between 2.83% and 3.21%), high brittle-mineral content (greater than 40%), abundant nanopores and micro-fractures, very good adsorption ability (adsorption content between 2.12 m3/t and 3.47 m3/t, on average about 2.50 m3/t), and strong sealing ability in the underlying and overlying layers, all of which favor the generation and accumulation of shale gas. The Wuning-Lixi and Jinkou-Zhelin areas of the Xinkailing formation were selected as the most realistic and favorable targets for shale-gas exploration and exploitation. In conclusion, the Wuning area has great potential and can provide a breakthrough in shale gas with further investigation. Full article
(This article belongs to the Special Issue Unconventional Natural Gas (UNG) Recoveries 2018)
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Article
A Novel Acoustic Liquid Level Determination Method for Coal Seam Gas Wells Based on Autocorrelation Analysis
Energies 2017, 10(12), 1961; https://doi.org/10.3390/en10121961 - 24 Nov 2017
Cited by 4 | Viewed by 2457
Abstract
In coal seam gas (CSG) wells, water is periodically removed from the wellbore in order to keep the bottom-hole flowing pressure at low levels, facilitating the desorption of methane gas from the coal bed. In order to calculate gas flow rate and further [...] Read more.
In coal seam gas (CSG) wells, water is periodically removed from the wellbore in order to keep the bottom-hole flowing pressure at low levels, facilitating the desorption of methane gas from the coal bed. In order to calculate gas flow rate and further optimize well performance, it is necessary to accurately monitor the liquid level in real-time. This paper presents a novel method based on autocorrelation function (ACF) analysis for determining the liquid level in CSG wells under intense noise conditions. The method involves the calculation of the acoustic travel time in the annulus and processing the autocorrelation signal in order to extract the weak echo under high background noise. In contrast to previous works, the non-linear dependence of the acoustic velocity on temperature and pressure is taken into account. To locate the liquid level of a coal seam gas well the travel time is computed iteratively with the non-linear velocity model. Afterwards, the proposed method is validated using experimental laboratory investigations that have been developed for liquid level detection under two scenarios, representing the combination of low pressure, weak signal, and intense noise generated by gas flowing and leakage. By adopting an evaluation indicator called Crest Factor, the results have shown the superiority of the ACF-based method compared to Fourier filtering (FFT). In the two scenarios, the maximal measurement error from the proposed method was 0.34% and 0.50%, respectively. The latent periodic characteristic of the reflected signal can be extracted by the ACF-based method even when the noise is larger than 1.42 Pa, which is impossible for FFT-based de-noising. A case study focused on a specific CSG well is presented to illustrate the feasibility of the proposed approach, and also to demonstrate that signal processing with autocorrelation analysis can improve the sensitivity of the detection system. Full article
(This article belongs to the Special Issue Unconventional Natural Gas (UNG) Recoveries 2018)
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Article
Coupled Thermo-Hydro-Mechanical-Chemical Modeling of Water Leak-Off Process during Hydraulic Fracturing in Shale Gas Reservoirs
Energies 2017, 10(12), 1960; https://doi.org/10.3390/en10121960 - 24 Nov 2017
Cited by 7 | Viewed by 2783
Abstract
The water leak-off during hydraulic fracturing in shale gas reservoirs is a complicated transport behavior involving thermal (T), hydrodynamic (H), mechanical (M) and chemical (C) processes. Although many leak-off models have been published, none of the models fully coupled the transient fluid flow [...] Read more.
The water leak-off during hydraulic fracturing in shale gas reservoirs is a complicated transport behavior involving thermal (T), hydrodynamic (H), mechanical (M) and chemical (C) processes. Although many leak-off models have been published, none of the models fully coupled the transient fluid flow modeling with heat transfer, chemical-potential equilibrium and natural-fracture dilation phenomena. In this paper, a coupled thermo-hydro-mechanical-chemical (THMC) model based on non-equilibrium thermodynamics, hydrodynamics, thermo-poroelastic rock mechanics, and non-isothermal chemical-potential equations is presented to simulate the water leak-off process in shale gas reservoirs. The THMC model takes into account a triple-porosity medium, which includes hydraulic fractures, natural fractures and shale matrix. The leak-off simulation with the THMC model involves all the important processes in this triple-porosity medium, including: (1) water transport driven by hydraulic, capillary, chemical and thermal osmotic convections; (2) gas transport induced by both hydraulic pressure driven convection and adsorption; (3) heat transport driven by thermal convection and conduction; and (4) natural-fracture dilation considered as a thermo-poroelastic rock deformation. The fluid and heat transport, coupled with rock deformation, are described by a set of partial differential equations resulting from the conservation of mass, momentum, and energy. The semi-implicit finite-difference algorithm is proposed to solve these equations. The evolution of pressure, temperature, saturation and salinity profiles of hydraulic fractures, natural fractures and matrix is calculated, revealing the multi-field coupled water leak-off process in shale gas reservoirs. The influences of hydraulic pressure, natural-fracture dilation, chemical osmosis and thermal osmosis on water leak-off are investigated. Results from this study are expected to provide a better understanding of the predominant leak-off mechanisms for slickwater fracturing-fluids in hydraulically fractured shale gas reservoirs. Full article
(This article belongs to the Special Issue Unconventional Natural Gas (UNG) Recoveries 2018)
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