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  • 1
    Online Resource
    Online Resource
    A Model for the Apparent Gas Permeability of Shale Matrix Organic Nanopore Considering Multiple Physical Phenomena
    Frontiers Media SA ; 2022
    In:  Frontiers in Earth Science Vol. 9 ( 2022-1-10)
    Details
    In: Frontiers in Earth Science, Frontiers Media SA, Vol. 9 ( 2022-1-10)
    Abstract: The flow of shale gas in nano scale pores is affected by multiple physical phenomena. At present, the influence of multiple physical phenomena on the transport mechanism of gas in nano-pores is not clear, and a unified mathematical model to describe these multiple physical phenomena is still not available. In this paper, an apparent permeability model was established, after comprehensively considering three gas flow mechanisms in shale matrix organic pores, including viscous slippage Flow, Knudsen diffusion and surface diffusion of adsorbed gas, and real gas effect and confinement effect, and at the same time considering the effects of matrix shrinkage, stress sensitivity, adsorption layer thinning, confinement effect and real gas effect on pore radius. The contribution of three flow mechanisms to apparent permeability under different pore pressure and pore size is analyzed. The effects of adsorption layer thinning, stress sensitivity, matrix shrinkage effect, real gas effect and confinement effect on apparent permeability were also systematically analyzed. The results show that the apparent permeability first decreases and then increases with the decrease of pore pressure. With the decrease of pore pressure, matrix shrinkage, Knudsen diffusion, slippage effect and surface diffusion effect increase gradually. These four effects will not only make up for the permeability loss caused by stress sensitivity and adsorption layer, but also significantly increase the permeability. With the decrease of pore radius, the contribution of slippage flow decreases, and the contributions of Knudsen diffusion and surface diffusion increase gradually. With the decrease of pore radius and the increase of pore pressure, the influence of real gas effect and confinement effect on permeability increases significantly. Considering real gas and confinement effect, the apparent permeability of pores with radius of 5 nm is increased by 13.2%, and the apparent permeability of pores with radius of 1 nm is increased by 61.3%. The apparent permeability model obtained in this paper can provide a theoretical basis for more accurate measurement of permeability of shale matrix and accurate evaluation of productivity of shale gas horizontal wells.
    Type of Medium: Online Resource
    ISSN: 2296-6463
    URL: Article
    DOI: 10.3389/feart.2021.813585
    Language: Unknown
    Publisher: Frontiers Media SA
    Publication Date: 2022
    detail.hit.zdb_id: 2741235-0
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  • 2
    Online Resource
    Online Resource
    Two-phase Flow Model and Productivity Evaluation of Gas and Water for Dual-Medium Carbonate Gas Reservoirs
    Frontiers Media SA ; 2022
    In:  Frontiers in Earth Science Vol. 9 ( 2022-1-20)
    Details
    In: Frontiers in Earth Science, Frontiers Media SA, Vol. 9 ( 2022-1-20)
    Abstract: Fluid flow in the dual-medium carbonate gas reservoir is characterized by stress sensitivity and non-Darcy flow effect. In order to accurately describe the unsteady flow of gas and water in the dual-medium gas reservoir, a two-phase flow model of gas and water is built. First, reservoir space and fluid flow characteristics of carbonate gas reservoirs are investigated, and the flow model that considers both the stress sensitivity and non-Darcy flow is built based on the fundamental flow theory, after fully investigating the reservoir space and fluid flow characteristics of carbonate gas reservoirs. Then, the perturbation theory is introduced, and the model is solved in the Laplace space, after which the obtained Laplace space analytical solution is converted into the real-space solution. Finally, the productivity evaluation model for the dual-medium gas reservoir with the gas-water two-phase flow is built, based on the flowing material balance method and Newton iteration. The presented productivity evaluation model is applied to analyze the effects of stress sensitivity and non-Darcy flow on the two-phase flow model of gas and water for the dual-medium gas reservoir and the reservoir productivity. The results indicate that a higher stress sensitivity coefficient is demonstrated to indicate higher stress sensitivity and accelerated production decline of the reservoir, while a lower non-Darcy flow effect coefficient represents a stronger non-Darcy effect and boosted drop of initial production of the reservoir. Hence, it is not reasonable to neglect the effects of stress sensitivity and non-Darcy flow during the evaluation of the productivity of a dual-medium carbonate gas reservoir. The model presented in this research provides important references for improving the recovery performance of dual-medium gas reservoirs.
    Type of Medium: Online Resource
    ISSN: 2296-6463
    URL: Article
    DOI: 10.3389/feart.2021.823764
    Language: Unknown
    Publisher: Frontiers Media SA
    Publication Date: 2022
    detail.hit.zdb_id: 2741235-0
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  • 3
    Online Resource
    Online Resource
    A Review of Macroscopic Modeling for Shale Gas Production: Gas Flow Mechanisms, Multiscale Transport, and Solution Techniques
    MDPI AG ; 2023
    In:  Processes Vol. 11, No. 9 ( 2023-09-15), p. 2766-
    Details
    In: Processes, MDPI AG, Vol. 11, No. 9 ( 2023-09-15), p. 2766-
    Abstract: The boost of shale gas production in the last decade has reformed worldwide energy structure. The macroscale modeling of shale gas production becomes particularly important as the economic development of such resources relies on the deployment of expensive hydraulic fracturing and the reasonable planning of well schedules. A flood of literature was therefore published focused on accurately and efficiently simulating the production performance of shale gas and better accounting for the various geological features or flow mechanisms that control shale gas transport. In this regard, this paper presents a holistic review of the macroscopic modeling of gas transport in shale. The review is carried out from three important points of view, which are the modeling of the gas flow mechanisms, the representation of multiscale transport, and solution techniques for the mathematical models. Firstly, the importance of gas storage and flow mechanisms in shale is discussed, and the various theoretical models used to characterize these effects in the continuum scale are introduced. Then, based on the intricate pore structure and various pore types of shale gas reservoirs, this review summarizes the multiple-porosity models in the literature to represent multiscale gas transport, and discusses the applicability of each model. Finally, the numerical and analytical/semi-analytical approaches used to solve the macroscopic mathematical model governing shale gas production are reviewed, with a focus on the treatment of the complex fracture network formed after multistage hydraulic fracturing.
    Type of Medium: Online Resource
    ISSN: 2227-9717
    URL: Article
    DOI: 10.3390/pr11092766
    Language: English
    Publisher: MDPI AG
    Publication Date: 2023
    detail.hit.zdb_id: 2720994-5
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  • 4
    Online Resource
    Online Resource
    Machine-Learning-Based Hydraulic Fracturing Flowback Forecasting
    ASME International ; 2023
    In:  Journal of Energy Resources Technology Vol. 145, No. 8 ( 2023-08-01)
    Details
    In: Journal of Energy Resources Technology, ASME International, Vol. 145, No. 8 ( 2023-08-01)
    Abstract: Hydraulic fracturing is an indispensable procedure to the economic development of shale gas. The flowback of the hydraulic fracturing fluid is one of the most important parameters recorded after shale gas wells are put into production. Generally, the flowback ratio is used as the flowback indicator during hydraulic fracturing. The flowback ratio has a great influence on shale gas production. However, the flowback ratio is subjected to various affecting factors with their correlativity unclear. Based on a large amount of original geological, engineering, and dynamic data acquired from 373 hydraulically fractured horizontal wells, the flowback characteristics were systematically studied based on machine learning. Based on the data analysis and random forest forecasting, a new indicator, single-cluster flowback ratio, was proposed, which can more effectively reflect the inherent relationship between flowback fluid volume and influencing factors. The results of training random forests for big data show that this indicator has better learnability and predictability. A good linear relationship exists between single-cluster flowback ratios in different production stages. Accordingly, the 30-day single-cluster flowback ratio can be used to predict the 90-day and 180-day single-cluster flowback ratios. The main controlling factors of production and flowback ratio were also systematically analyzed. It is found that the main controlling factors of the flowback ratio include the number of fracturing clusters, the total amount of sand, number of fracturing stages, and fluid injection intensity per cluster. This study can provide a fundamental reference for analyzing the hydraulically fracturing fluid flowback for shale gas reservoirs.
    Type of Medium: Online Resource
    ISSN: 0195-0738 , 1528-8994
    URL: Article
    DOI: 10.1115/1.4056993
    Language: English
    Publisher: ASME International
    Publication Date: 2023
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  • 5
    Online Resource
    Online Resource
    A Deep Learning Approach to Predict Conductive Hearing Loss in Otitis Media With Effusion Using Otoscopic Images
    Elsevier BV ; 2022
    In:  SSRN Electronic Journal
    Details
    In: SSRN Electronic Journal, Elsevier BV
    Type of Medium: Online Resource
    ISSN: 1556-5068
    URL: Article
    DOI: 10.2139/ssrn.4000466
    Language: English
    Publisher: Elsevier BV
    Publication Date: 2022
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  • 6
    Online Resource
    Online Resource
    A Deep Learning Approach to Predict Conductive Hearing Loss in Patients With Otitis Media With Effusion Using Otoscopic Images
    American Medical Association (AMA) ; 2022
    In:  JAMA Otolaryngology–Head & Neck Surgery Vol. 148, No. 7 ( 2022-07-01), p. 612-
    Details
    In: JAMA Otolaryngology–Head & Neck Surgery, American Medical Association (AMA), Vol. 148, No. 7 ( 2022-07-01), p. 612-
    Type of Medium: Online Resource
    ISSN: 2168-6181
    URL: Article
    DOI: 10.1001/jamaoto.2022.0900
    Language: English
    Publisher: American Medical Association (AMA)
    Publication Date: 2022
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  • 7
    Online Resource
    Online Resource
    Investigation of Flowback Behaviours in Hydraulically Fractured Shale Gas Well Based on Physical Driven Method
    MDPI AG ; 2022
    In:  Energies Vol. 15, No. 1 ( 2022-01-04), p. 325-
    Details
    In: Energies, MDPI AG, Vol. 15, No. 1 ( 2022-01-04), p. 325-
    Abstract: Due to the complex microscope pore structure of shale, large-scale hydraulic fracturing is required to achieve effective development, resulting in a very complicated fracturing fluid flowback characteristics. The flowback volume is time-dependent, whereas other relevant parameters, such as the permeability, porosity, and fracture half-length, are static. Thus, it is very difficult to build an end-to-end model to predict the time-dependent flowback curves using static parameters from a machine learning perspective. In order to simplify the time-dependent flowback curve into simple parameters and serve as the target parameter of big data analysis and flowback influencing factor analysis, this paper abstracted the flowback curve into two characteristic parameters, the daily flowback volume coefficient and the flowback decreasing coefficient, based on the analytical solution of the seepage equation of multistage fractured horizontal Wells. Taking the dynamic flowback data of 214 shale gas horizontal wells in Weiyuan shale gas block as a study case, the characteristic parameters of the flowback curves were obtained by exponential curve fittings. The analysis results showed that there is a positive correlation between the characteristic parameters which present the characteristics of right-skewed distribution. The calculation formula of the characteristic flowback coefficient representing the flowback potential was established. The correlations between characteristic flowback coefficient and geological and engineering parameters of 214 horizontal wells were studied by spearman correlation coefficient analysis method. The results showed that the characteristic flowback coefficient has a negative correlation with the thickness × drilling length of the high-quality reservoir, the fracturing stage interval, the number of fracturing stages, and the brittle minerals content. Through the method established in this paper, the shale gas flowback curve containing complex flow mechanism can be abstracted into simple characteristic parameters and characteristic coefficients, and the relationship between static data and dynamic data is established, which can help to establish a machine learning method for predicting the flowback curve of shale gas horizontal wells.
    Type of Medium: Online Resource
    ISSN: 1996-1073
    URL: Article
    DOI: 10.3390/en15010325
    Language: English
    Publisher: MDPI AG
    Publication Date: 2022
    detail.hit.zdb_id: 2437446-5
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  • 8
    Online Resource
    Online Resource
    Battle of the Water Calibration Networks
    American Society of Civil Engineers (ASCE) ; 2012
    In:  Journal of Water Resources Planning and Management Vol. 138, No. 5 ( 2012-09), p. 523-532
    Details
    In: Journal of Water Resources Planning and Management, American Society of Civil Engineers (ASCE), Vol. 138, No. 5 ( 2012-09), p. 523-532
    Type of Medium: Online Resource
    ISSN: 0733-9496 , 1943-5452
    URL: Article
    DOI: 10.1061/(ASCE)WR.1943-5452.0000191
    Language: English
    Publisher: American Society of Civil Engineers (ASCE)
    Publication Date: 2012
    detail.hit.zdb_id: 2068478-2
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  • 9
    Online Resource
    Online Resource
    Research Status of and Trends in 3D Geological Property Modeling Methods: A Review
    MDPI AG ; 2022
    In:  Applied Sciences Vol. 12, No. 11 ( 2022-06-02), p. 5648-
    Details
    In: Applied Sciences, MDPI AG, Vol. 12, No. 11 ( 2022-06-02), p. 5648-
    Abstract: Three-dimensional (3D) geological property modeling is used to quantitatively characterize various geological attributes in 3D space based on geostatistics with the help of computer visualization technology, and the results are often stored in grid data. The 3D geological property modeling includes two main components, grid model generation and property interpolation. In this review article, the existing grid generation methods are systematically investigated, and both traditional and multiple-point geostatistical algorithms involved in interpolation methods are comprehensively analyzed. It is shown that considering the numerical simulation of oil reservoirs, the orthogonal hexahedral grid remains the most suitable grid model for simulations in petroleum exploration and development. For the interpolation methods aspect, most geological phenomena are nonstationary, to simulate various types of reservoirs; the main development trends are increasing geological constraints and reducing the limitation of stationarity. Both methods have certain constraints, and the multiscale problem of multiple-point geostatistics poses a main challenge to the field. In addition, the deep-learning based method is a new trend in geological property modeling.
    Type of Medium: Online Resource
    ISSN: 2076-3417
    URL: Article
    DOI: 10.3390/app12115648
    Language: English
    Publisher: MDPI AG
    Publication Date: 2022
    detail.hit.zdb_id: 2704225-X
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