Energies

Research

20 pages, 6121 KiB

Open AccessArticle

Prediction of ORF for Optimized CO₂ Flooding in Fractured Tight Oil Reservoirs via Machine Learning

by Ming Yue, Quanqi Dai, Haiying Liao, Yunfeng Liu, Lin Fan and Tianru Song

Energies 2024, 17(6), 1303; https://doi.org/10.3390/en17061303 - 08 Mar 2024

Viewed by 418

Tight reservoirs characterized by complex physical properties pose significant challenges for extraction. CO₂ flooding, as an EOR technique, offers both economic and environmental advantages. Accurate prediction of recovery rate plays a crucial role in the development of tight oil and gas reservoirs. [...] Read more.

Tight reservoirs characterized by complex physical properties pose significant challenges for extraction. CO₂ flooding, as an EOR technique, offers both economic and environmental advantages. Accurate prediction of recovery rate plays a crucial role in the development of tight oil and gas reservoirs. But the recovery rate is influenced by a complex array of factors. Traditional methods are time-consuming and costly and cannot predict the recovery rate quickly and accurately, necessitating advanced multi-factor analysis-based prediction models. This study uses machine learning models to rapidly predict the recovery of CO₂ flooding for tight oil reservoir development, establishes a numerical model for CO₂ flooding for low-permeability tight reservoir development based on actual blocks, studies the effects of reservoir parameters, horizontal well parameters, and injection-production parameters on CO₂ flooding recovery rate, and constructs a prediction model based on machine learning for the recovery. Using simulated datasets, three models, random forest (RF), extreme gradient boosting (XGBoost), and light gradient boosting machine (LightGBM), were trained and tested for accuracy evaluation. Different levels of noise were added to the dataset and denoised, and the effects of data noise and denoising techniques on oil recovery factor prediction were studied. The results showed that the LightGBM model was superior to other models, with R² values of 0.995, 0.961, 0.921, and 0.877 for predicting EOR for the original dataset, 5% noise dataset, 10% noise dataset, and 15% noise dataset, respectively. Finally, based on the optimized model, the key control factors for CO₂ flooding for tight oil reservoirs to enhance oil recovery were analyzed. The novelty of this study is the development of a machine-learning-based method that can provide accurate and cost-effective ORF predictions for CO₂ flooding for tight oil reservoir development, optimize the development process in a timely manner, significantly reduce the required costs, and make it a more feasible carbon utilization and EOR strategy. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Simulation and Carbon Utilization and Storage)

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23 pages, 10555 KiB

Open AccessArticle

A Viscoplasticity Model for Shale Creep Behavior and Its Application on Fracture Closure and Conductivity

by Shiyuan Li, Jingya Zhao, Haipeng Guo, Haigang Wang, Muzi Li, Mengjie Li, Jinquan Li and Junwang Fu

Energies 2024, 17(5), 1122; https://doi.org/10.3390/en17051122 - 27 Feb 2024

Viewed by 456

Abstract

Hydraulic fracturing is the main means for developing low-permeability shale reservoirs. Whether to produce artificial fractures with sufficient conductivity is an important criterion for hydraulic fracturing evaluation. The presence of clay and organic matter in the shale gives the shale creep, which makes [...] Read more.

Hydraulic fracturing is the main means for developing low-permeability shale reservoirs. Whether to produce artificial fractures with sufficient conductivity is an important criterion for hydraulic fracturing evaluation. The presence of clay and organic matter in the shale gives the shale creep, which makes the shale reservoir deform with time and reduces the conductivity of the fracture. In the past, the influence of shale creep was ignored in the study of artificial fracture conductivity, or the viscoelastic model was used to predict the conductivity, which represents an inaccuracy compared to the actual situation. Based on the classical Perzyna viscoplastic model, the elasto-viscoplastic constitutive model was obtained by introducing isotropic hardening, and the model parameters were obtained by fitting the triaxial compression creep experimental data under different differential stresses. Then, the constitutive model was programmed in a software platform using the return mapping algorithm, and the model was verified through the numerical simulation of the triaxial creep experiment. Then, the creep calculation results of the viscoplastic constitutive model and the power law model were compared. Finally, the viscoplastic constitutive model was applied to the simulation of the long-term conductivity of the fracture to study the influence of creep on the fracture width, and sensitivity analysis of the influencing factors of the fracture width was carried out. The results show that the numerical calculation results of the viscoplastic model were in agreement with the experimental data. The decrease in fracture width caused by pore pressure dissipation and reservoir creep after 72 h accounts for 32.07% of the total fracture width decrease. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Simulation and Carbon Utilization and Storage)

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19 pages, 4842 KiB

Open AccessArticle

Experimental Study of the Fluid Contents and Organic/Inorganic Hydrocarbon Saturations, Porosities, and Permeabilities of Clay-Rich Shale

by Fenglan Wang, Binhui Li, Sheng Cao, Jiang Zhang, Quan Xu and Qian Sang

Energies 2024, 17(2), 524; https://doi.org/10.3390/en17020524 - 22 Jan 2024

Cited by 1 | Viewed by 525

Abstract

Unlike conventional reservoirs, shale is particularly complex in its mineral composition. As typical components in shale reservoirs, clay and organic matter have different pore structures and strong interactions with fluids, resulting in complex fluid occurrence-states in shale. For example, there are both free [...] Read more.

Unlike conventional reservoirs, shale is particularly complex in its mineral composition. As typical components in shale reservoirs, clay and organic matter have different pore structures and strong interactions with fluids, resulting in complex fluid occurrence-states in shale. For example, there are both free water and adsorbed water in clay, and both free oil and ad/absorbed oil in organic matter. Key properties such as fluid content, organic/inorganic porosity, and permeability in clay-rich shale have been poorly characterized in previous studies. In this paper, we used a vacuum-imbibition experimental method combined with nuclear magnetic resonance technique and mathematical modeling to characterize the fluid content, organic/inorganic porosity, saturation, and permeability of clay-rich shale. We conducted vacuum-imbibition experiments on both shale samples and pure clay samples to distinguish the adsorbed oil and water in clay and organic matter. The effects of clay content and total organic matter content (TOC) on porosity and adsorbed-fluid content are then discussed. Our results show that, for the tested samples, organic porosity accounts for 26–76% of total porosity. The oil content in organic matter ranges from 29% to 69% of the total oil content, and 2% to 58% of the organic oil content is ad/absorbed in kerogen. The inorganic porosity has a weak positive correlation with clay content, and organic porosity increases with rising levels of organic matter content. The organic permeability is 1–3 orders of magnitude lower than the inorganic permeability. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Simulation and Carbon Utilization and Storage)

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20 pages, 5113 KiB

Open AccessArticle

CO₂–Water–Rock Interaction and Its Influence on the Physical Properties of Continental Shale Oil Reservoirs

by Sheng Cao, Qian Sang, Guozhong Zhao, Yubo Lan, Dapeng Dong and Qingzhen Wang

Energies 2024, 17(2), 477; https://doi.org/10.3390/en17020477 - 18 Jan 2024

Viewed by 466

Abstract

Shale oil resources are abundant, but reservoirs exhibit strong heterogeneity with extremely low porosity and permeability, and their development is challenging. Carbon dioxide (CO₂) injection technology is crucial for efficient shale oil development. When CO₂ is dissolved in reservoir formation [...] Read more.

Shale oil resources are abundant, but reservoirs exhibit strong heterogeneity with extremely low porosity and permeability, and their development is challenging. Carbon dioxide (CO₂) injection technology is crucial for efficient shale oil development. When CO₂ is dissolved in reservoir formation water, it undergoes a series of physical and chemical reactions with various rock minerals present in the reservoir. These reactions not only modify the reservoir environment but also lead to precipitation that impacts the development of the oil reservoir. In this paper, the effects of water–rock interaction on core porosity and permeability during CO₂ displacement are investigated by combining static and dynamic tests. The results reveal that the injection of CO₂ into the core leads to reactions between CO₂ and rock minerals upon dissolution in formation water. These reactions result in the formation of new minerals and the obstruction of clastic particles, thereby reducing core permeability. However, the generation of fine fractures through carbonic acid corrosion yields an increase in core permeability. The CO₂–water–rock reaction is significantly influenced by the PV number, pressure, and temperature. As the injected PV number increases, the degree of pore throat plugging gradually increases. As the pressure increases, the volume of larger pore spaces gradually decreases, resulting in an increase in the degree of pore blockage. However, when the pressure exceeds 20 MPa, the degree of carbonic acid dissolution will be enhanced, resulting in the formation of small cracks and an increase in the volume of small pores. As the temperature reaches the critical point, the degree of blockage of macropores gradually increases, and the blockage of small pores also occurs, which eventually leads to a decrease in core porosity. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Simulation and Carbon Utilization and Storage)

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19 pages, 16082 KiB

Open AccessArticle

High Permeability Streak Identification and Modelling Approach for Carbonate Reef Reservoir

by Dmitriy Shirinkin, Alexander Kochnev, Sergey Krivoshchekov, Ivan Putilov, Andrey Botalov, Nikita Kozyrev and Evgeny Ozhgibesov

Energies 2024, 17(1), 236; https://doi.org/10.3390/en17010236 - 02 Jan 2024

Viewed by 508

Abstract

Reef reservoirs are characterised by a complex structure of void space, which is a combination of intergranular porosity, fractures, and vuggy voids distributed chaotically in the carbonate body in different proportions. This causes great uncertainty in the distribution of porosity and permeability properties [...] Read more.

Reef reservoirs are characterised by a complex structure of void space, which is a combination of intergranular porosity, fractures, and vuggy voids distributed chaotically in the carbonate body in different proportions. This causes great uncertainty in the distribution of porosity and permeability properties in the reservoir volume, making field development a complex and unpredictable process associated with many risks. High densities of carbonate secondary alterations can lead to the formation of zones with abnormally high porosity and permeability—high permeability streaks or super-reservoirs. Taking into account super-reservoirs in the bulk of the deposit is necessary in the dynamic modelling of complex-structure reservoirs because it affects the redistribution of filtration flows and is crucial for reservoir management. This paper proposes a method for identifying superreservoirs by identifying enormously high values of porosity and permeability from different-scale study results, followed by the combination and construction of probabilistic curves of superreservoirs. Based on the obtained curves, three probabilistic models of the existence of a superreservoir were identified: P10, P50, and P90, which were further distributed in the volume of the reservoir and on the basis of which new permeability arrays were calculated. Permeability arrays were simulated in a dynamic model of the Alpha field. The P50 probabilistic model showed the best history matching after one iteration. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Simulation and Carbon Utilization and Storage)

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19 pages, 6633 KiB

Open AccessArticle

A Case Study on the CO₂ Sequestration in Shenhua Block Reservoir: The Impacts of Injection Rates and Modes

by Ligen Tang, Guosheng Ding, Shijie Song, Huimin Wang, Wuqiang Xie and Jiulong Wang

Energies 2024, 17(1), 122; https://doi.org/10.3390/en17010122 - 25 Dec 2023

Viewed by 657

Abstract

Carbon capture and storage (CCS) is the most promising method of curbing atmospheric carbon dioxide levels from 2020 to 2050. Accurate predictions of geology and sealing capabilities play a key role in the safe execution of CCS projects. However, popular forecasting methods often [...] Read more.

Carbon capture and storage (CCS) is the most promising method of curbing atmospheric carbon dioxide levels from 2020 to 2050. Accurate predictions of geology and sealing capabilities play a key role in the safe execution of CCS projects. However, popular forecasting methods often oversimplify the process and fail to guide actual CCS projects in the right direction. This study takes a specific block in Shenhua, China as an example. The relative permeability of CO₂ and brine is measured experimentally, and a multi-field coupling CO₂ storage prediction model is constructed, focusing on analyzing the sealing ability of the block from the perspective of injection modes. The results show that when injected at a constant speed, the average formation pressure and wellbore pressure are positively correlated with the CO₂ injection rate and time; when the injection rate is 0.5 kg/s for 50 years, the average formation pressure increases by 38% and the wellbore pressure increases by 68%. For different injection modes, the average formation pressures of various injection methods are similar during injection. Among them, the pressure increases around the well in the decreasing injection mode is the smallest. The CO₂ concentration around the wellbore is the largest, and the CO₂ diffusion range continues to expand with injection time. In summary, formation pressure increases with the increase in injection rate and injection time, and the decreasing injection mode has the least impact on the increase in formation pressure. The CO₂ concentration is the largest around the well, and the CO₂ concentration gradually decreases. The conclusion helps determine the geological carrying capacity of injection volumes and provides insights into the selection of more appropriate injection modes. Accurate predictions of CO₂ storage capacity are critical to ensuring project safety and monitoring potentially hazardous sites based on reservoir characteristics. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Simulation and Carbon Utilization and Storage)

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22 pages, 7284 KiB

Open AccessArticle

Fracture Spacing Optimization Method for Multi-Stage Fractured Horizontal Wells in Shale Oil Reservoir Based on Dynamic Production Data Analysis

by Wenchao Liu, Chen Liu, Yaoyao Duan, Xuemei Yan, Yuping Sun and Hedong Sun

Energies 2023, 16(24), 7922; https://doi.org/10.3390/en16247922 - 05 Dec 2023

Viewed by 771

Abstract

In order to improve the shale oil production rate and save fracturing costs, based on dynamic production data, a production-oriented optimization method for fracture spacing of multi-stage fractured horizontal wells is proposed in this study. First, M. Brown et al.’s trilinear seepage flow [...] Read more.

In order to improve the shale oil production rate and save fracturing costs, based on dynamic production data, a production-oriented optimization method for fracture spacing of multi-stage fractured horizontal wells is proposed in this study. First, M. Brown et al.’s trilinear seepage flow models and their pressure and flow rate solutions are applied. Second, deconvolution theory is introduced to normalize the production data. The data of variable pressure and variable flow rate are, respectively, transformed into the pressure data under unit flow rate and the flow rate data under unit production pressure drop; and the influence of data error is eliminated. Two kinds of typical curve of the normalized data are analyzed using the pressure and flow rate solutions of M. Brown et al.’s models. The two fitting methods constrain each other. Thus, reservoir and fracture parameters are interpretated. A practical model has been established to more accurately describe the seepage flow behavior in shale oil reservoirs. Third, using Duhamel’s principle and the rate solution, the daily and cumulative production rate under any variable production pressure can be obtained. The productivity can be more accurately predicted. Finally, the analysis method is applied to analyze the actual dynamic production data. The fracture spacing of a shale oil producing well in an actual block is optimized from the aspects of production life, cumulative production, economic benefits and other influencing factors, and some significant conclusions are obtained. The research results show that with the goal of maximum cumulative production, the optimal fracture spacing is 5.5 m for 5 years and 11.4 m for 10 years. All in all, the fracture spacing optimization and design theory of multi-stage fractured horizontal wells is enriched. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Simulation and Carbon Utilization and Storage)

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20 pages, 5665 KiB

Open AccessArticle

Dynamic Productivity Prediction Method of Shale Condensate Gas Reservoir Based on Convolution Equation

by Ping Wang, Wenchao Liu, Wensong Huang, Chengcheng Qiao, Yuepeng Jia and Chen Liu

Energies 2023, 16(3), 1479; https://doi.org/10.3390/en16031479 - 02 Feb 2023

Cited by 1 | Viewed by 1176

Abstract

The dynamic productivity prediction of shale condensate gas reservoirs is of great significance to the optimization of stimulation measures. Therefore, in this study, a dynamic productivity prediction method for shale condensate gas reservoirs based on a convolution equation is proposed. The method has [...] Read more.

The dynamic productivity prediction of shale condensate gas reservoirs is of great significance to the optimization of stimulation measures. Therefore, in this study, a dynamic productivity prediction method for shale condensate gas reservoirs based on a convolution equation is proposed. The method has been used to predict the dynamic production of 10 multi-stage fractured horizontal wells in the Duvernay shale condensate gas reservoir. The results show that flow-rate deconvolution algorithms can greatly improve the fitting effect of the Blasingame production decline curve when applied to the analysis of unstable production of shale gas condensate reservoirs. Compared with the production decline analysis method in commercial software HIS Harmony RTA, the productivity prediction method based on a convolution equation of shale condensate gas reservoirs has better fitting affect and higher accuracy of recoverable reserves prediction. Compared with the actual production, the error of production predicted by the convolution equation is generally within 10%. This means it is a fast and accurate method. This study enriches the productivity prediction methods of shale condensate gas reservoirs and has important practical significance for the productivity prediction and stimulation optimization of shale condensate gas reservoirs. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Simulation and Carbon Utilization and Storage)

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24 pages, 6037 KiB

Open AccessArticle

Numerical Simulation Study on Temporary Well Shut-In Methods in the Development of Shale Oil Reservoirs

by Qitao Zhang, Wenchao Liu, Jiaxin Wei, Arash Dahi Taleghani, Hai Sun and Daobing Wang

Energies 2022, 15(23), 9161; https://doi.org/10.3390/en15239161 - 02 Dec 2022

Cited by 1 | Viewed by 1116

Abstract

Field tests indicate that temporary well shut-ins may enhance oil recovery from a shale reservoir; however, there is currently no systematic research to specifically guide such detailed operations in the field, especially for the design of the shut-in scheme and multiple rounds of [...] Read more.

Field tests indicate that temporary well shut-ins may enhance oil recovery from a shale reservoir; however, there is currently no systematic research to specifically guide such detailed operations in the field, especially for the design of the shut-in scheme and multiple rounds of shut-ins. In this study, the applicability of well shut-in operations for shale oil reservoirs is studied, and a numerical model is built using the finite element method. In order to simulate the production in a shale oil reservoir, two separate modules (i.e., Darcy’s law and phase transport) were two-way coupled together. The established model was validated by comparing its results with the analytical Buckley–Leverett equation. In this paper, the geological background and parameters of a shale oil reservoir in Chang-7 Member (Chenghao, China) were used for the analyses. The simulation results show that temporary well shut-in during production can significantly affect well performance. Implementing well shut-in could decrease the initial oil rate while decreasing the oil decline rate, which is conducive to long-term production. After continuous production for 1000 days, the oil rate with 120 days shut-in was 9.85% larger than the case with no shut-in. Besides, an optimal shut-in time has been identified as 60 days under our modeling conditions. In addition, the potential of several rounds of well shut-in operations was also tested in this study; it is recommended that one or two rounds of shut-ins be performed during development. When two rounds of shut-ins are implemented, it is recommended that the second round shut-in be performed after 300 days of production. In summary, this study reveals the feasibility of temporary well shut-in operations in the development of a shale oil reservoir and provides quantitative guidance to optimize these development scenarios. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Simulation and Carbon Utilization and Storage)

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20 pages, 3375 KiB

Open AccessArticle

Well Testing Methodology for Multiple Vertical Wells with Well Interference and Radially Composite Structure during Underground Gas Storage

by Hongyang Chu, Tianbi Ma, Zhen Chen, Wenchao Liu and Yubao Gao

Energies 2022, 15(22), 8403; https://doi.org/10.3390/en15228403 - 10 Nov 2022

Cited by 2 | Viewed by 1451

Abstract

To achieve the goal of decarbonized energy and greenhouse gas reduction, underground gas storage (UGS) has proven to be an important source for energy storage and regulation of natural gas supply. The special working conditions in UGS cause offset vertical wells to easily [...] Read more.

To achieve the goal of decarbonized energy and greenhouse gas reduction, underground gas storage (UGS) has proven to be an important source for energy storage and regulation of natural gas supply. The special working conditions in UGS cause offset vertical wells to easily interfere with target vertical wells. The current well testing methodology assumes that there is only one well, and the interference from offset wells is ignored. This paper proposes a solution and analysis method for the interference from adjacent vertical wells to target vertical wells by analytical theory. The model solution is obtained by the solution with a constant rate and the Laplace transform method. The pressure superposition is used to deal with the interference from adjacent vertical wells. The model reliability in the gas injection and production stages is verified by commercial software. Pressure analysis shows that the heterogeneity and interference in the gas storage are caused by long-term gas injection and production. As both the adjacent well and the target well are in the gas production stage, the pressure derivative value in radial flow is related to production rate, mobility ratio, and 0.5. Gas injection from offset wells will cause the pressure derivative to drop later. Multiple vertical wells from the Hutubi UGS are used to illustrate the properties of vertical wells and the formation. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Simulation and Carbon Utilization and Storage)

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18 pages, 6506 KiB

Open AccessArticle

Numerical Simulation on Borehole Instability Based on Disturbance State Concept

by Daobing Wang, Zhan Qu, Zongxiao Ren, Qinglin Shan, Bo Yu, Yanjun Zhang and Wei Zhang

Energies 2022, 15(17), 6295; https://doi.org/10.3390/en15176295 - 29 Aug 2022

Cited by 3 | Viewed by 1178

Abstract

This paper carries out a study on the numerical simulation of borehole instability based on the disturbance state concept. By introducing the disturbance damage factor into the classical Mohr–Coulomb yield criterio, we establish a finite element hydro-mechanical coupling model of borehole instability and [...] Read more.

This paper carries out a study on the numerical simulation of borehole instability based on the disturbance state concept. By introducing the disturbance damage factor into the classical Mohr–Coulomb yield criterio, we establish a finite element hydro-mechanical coupling model of borehole instability and program the relevant field variable by considering elastic–plastic deformation in borehole instability, the distribution of the damage disturbance area, the variation of porosity and permeability with the disturbance damage factor, etc. Numerical simulation shows that the borehole stability is related to the action time of drilling fluid on the wellbore, stress anisotropy, the internal friction angle of rock, and borehole pressure. A higher horizontal stress difference helps suppress shear instability, and a higher rock internal friction angle enhances shear failure around the borehole along the maximum horizontal principal stress. When considering the effect of the internal friction angle of rock, the rock permeability, disturbance damage factor, and equivalent plastic strain show fluctuation characteristics. Under the high internal friction angle of rock, a strong equivalent plastic strain area and disturbance damage area occur in the direction of the maximum horizontal principal stress. Their cloud picture shows the mantis shape, where the bifurcation corresponds to the whiskers of the shear failure area in borehole instability. This study provides a theoretical basis for solving the problem of borehole instability during drilling engineering. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Simulation and Carbon Utilization and Storage)

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22 pages, 9346 KiB

Open AccessArticle

Experimental Study on the Hydraulic Fracture Propagation in Inter-Salt Shale Oil Reservoirs

by Yunqi Shen, Zhiwen Hu, Xin Chang and Yintong Guo

Energies 2022, 15(16), 5909; https://doi.org/10.3390/en15165909 - 15 Aug 2022

Cited by 2 | Viewed by 1128

Abstract

In response to the difficulty of fracture modification in inter-salt shale reservoirs and the unknown pattern of hydraulic fracture expansion, corresponding physical model experiments were conducted to systematically study the effects of fracturing fluid viscosity, ground stress and pumping displacement on hydraulic fracture [...] Read more.

In response to the difficulty of fracture modification in inter-salt shale reservoirs and the unknown pattern of hydraulic fracture expansion, corresponding physical model experiments were conducted to systematically study the effects of fracturing fluid viscosity, ground stress and pumping displacement on hydraulic fracture expansion, and the latest supercritical

{CO}_{2}

fracturing fluid was introduced. The test results show the following. (1) The hydraulic fractures turn and expand when they encounter the weak surface of the laminae. The fracture pressure gradually increases with the increase in fracturing fluid viscosity, while the fracture pressure of supercritical

{CO}_{2}

is the largest and the fracture width is significantly lower than the other two fracturing fluids due to the high permeability and poor sand-carrying property. (2) Compared with the other two conventional fracturing fluids, under the condition of supercritical

{CO}_{2}

fracturing fluid, the increase in ground stress leads to the increase in inter-salt. (3) Compared with the other two conventional fracturing fluids, under the conditions of supercritical

{CO}_{2}

fracturing fluid, the fracture toughness of shale increases, the fracture pressure increases, and the fracture network complexity decreases as well. (4) With the increase in pumping displacement, the fracture network complexity increases, while the increase in the displacement of supercritical

{CO}_{2}

due to high permeability leads to the rapid penetration of inter-salt shale hydraulic fractures to the surface of the specimen to form a pressure relief zone; it is difficult to create more fractures with the continued injection of the fracturing fluid, and the fracture network complexity decreases instead. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Simulation and Carbon Utilization and Storage)

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16 pages, 6101 KiB

Open AccessArticle

A Core Damage Constitutive Model for the Time-Dependent Creep and Relaxation Behavior of Coal

by Tingting Cai, Lei Shi, Yulong Jiang and Zengchao Feng

Energies 2022, 15(11), 4174; https://doi.org/10.3390/en15114174 - 06 Jun 2022

Cited by 1 | Viewed by 1254

Abstract

The creep and stress relaxation behaviors of coal are common in coal mining. The unified constitutive model is suitable to describe and predict both the creep and relaxation evolution characteristics of rocks. The generalized Kelvin model is the core element for traditional and [...] Read more.

The creep and stress relaxation behaviors of coal are common in coal mining. The unified constitutive model is suitable to describe and predict both the creep and relaxation evolution characteristics of rocks. The generalized Kelvin model is the core element for traditional and improved component models to reflect both the nonlinear creep and relaxation. In this paper, an improved core damage model, which could both reflect the creep and stress relaxation in relation to the damage evolution, was established based on a comparison of the traditional and improved component models, and the responding constitutive equations (creep and stress relaxation equation) at constant stress/strain were deduced. Then, the core damage model was validated to the uniaxial compressive multistage creep and stress relaxation test results of coal, showing that the model curves had great accordance with the experimental data. Moreover, the model comparisons on accuracy, parameter meaning, and popularization among the core damage model, hardening-damage model, and the fractional derivative model were further discussed. The results showed that the parameters in the core damage model had clear and brief physical significances. The core damage model was also popularized to depict the time-dependent behaviors of other rocks, showing great accuracy. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Simulation and Carbon Utilization and Storage)

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