Geoenergy Science and Engineering最新文献

{"title":"Numerical investigation on hydrate reservoir deformation induced by depressurization production and analysis of CO2 reinjection potential","authors":"Xianzhuang Ma ,&nbsp;Hengjie Luan ,&nbsp;Yujing Jiang ,&nbsp;Peng Yan ,&nbsp;Xuezhen Wu ,&nbsp;Changsheng Wang ,&nbsp;Qinglin Shan","doi":"10.1016/j.geoen.2025.213723","DOIUrl":"10.1016/j.geoen.2025.213723","url":null,"abstract":"<div><div>Depressurization production causes reservoir deformation to change the physical and mechanical properties, thus affecting the fluid flow and production performance. The mechanical deformation and gas production characteristics of multilayer hydrate reservoir at the first depressurization production site in the Shenhu area need to be further simulated and investigated. In this paper, a multilayer hydrate reservoir model is established based on the real logging data of SHSC-4 well, and the simulation results are compared with the test production results to verify the model validity. The production performance and reservoir stability are evaluated by considering reservoir deformation and gas production behavior, and the CO₂ reinjection potential of the multilayer reservoir after production is analyzed by numerical methods. Low production pressure can serve to increase cumulative gas production, but reservoir deformation can also be an unfavorable factor hindering gas production. The negative effects of reservoir deformation caused by depressurization on gas production results need to be considered when numerical methods are used to evaluate reservoir production performance or optimize production design. Percentage contribution of free gas layer (FGL) decreases with the reduction of production pressure, and the gas production from the reservoir is mainly from hydrate-bearing layer (HBL) and three phase layer (TPL). There is a turning point in the production performance of HBL and TPL around 3 MPa. The gas production performance of HBL is better than TPL when the production pressure is lower than 3 MPa, and the percentage contribution of HBL and TPL are about 40% under different initial inherent permeability conditions. Permeability enhancement measures promote the propagation of low pore pressure in the reservoir, which is prone to cause large reservoir deformation. CO₂ reinjection leads to reservoir uplift around production well, and stress concentration distribution induced by depressurization production are mitigated. TPL has better CO₂ reinjection potential than FGL and HBL, and it accounts for about 50% of the total reinjected gas.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"247 ","pages":"Article 213723"},"PeriodicalIF":0.0,"publicationDate":"2025-01-31","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143150604","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Simulation on detachment and migration behaviors of mineral particles induced by fluid flow in porous media based on CFD-DEM","authors":"Haoting Li ,&nbsp;Gang Gao ,&nbsp;Min Hao ,&nbsp;Ruichao Tian ,&nbsp;Zechen Lu ,&nbsp;Yuting Zhao","doi":"10.1016/j.geoen.2025.213727","DOIUrl":"10.1016/j.geoen.2025.213727","url":null,"abstract":"<div><div>The adhesion and detachment of mineral particles from host sandstone have a significant influence on their subsequent migration, deposition behaviors and the seepage characteristics of pore fluid in porous media. In this work, the effects of injected fluid velocity, porosity and adherent particle number on the detachment and subsequent migration behaviors of adhesive mineral particles are investigated using CFD-DEM method. The main focus is on the particle detachment behaviors from the host sandstone, subsequent migration mechanisms, and their effects on fluid seepage behaviors and hydraulic performance of porous media. The parallel bond model is used to analyze the force balance mechanisms of particle adhesion and detachment after verifying the accuracy of the numerical model through classical theoretical equations and experiments. According to the equilibrium relationship between fluid impulsive force and particle adhesion force, mineral particles can be divided into non-detached adhesive particles, detached-migratable particles and detached-deposited particles based on their existence states. The local fluid velocity near wall, especially at the corner, is significantly higher than that inside the pore due to the formation of dominant fluid channel. Results show that high injected fluid velocity facilitates both particle detachment rate and detachment intensity, which also accelerates the escape efficiency of detached particles. Low porosity accelerates the detachment of mineral particles, and the detached particles predominantly deposit rather than escape when porosity is below 30 %. Meanwhile, the detachment of particle is not contingent on the number of adherent particles, even though an increase in this condition leads to a greater number of particles being detached. The variations in pressure drop and absolute permeability are also investigated.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"247 ","pages":"Article 213727"},"PeriodicalIF":0.0,"publicationDate":"2025-01-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143150605","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Silane-modified hydroxyethyl cellulose / lithium magnesium silicate composite as a rheology modifier for temperature and salt resistance","authors":"Zheng Li ,&nbsp;Ling Lin ,&nbsp;Yuanhao Luo ,&nbsp;Shenwen Fang ,&nbsp;Hongdan Ao ,&nbsp;Meirong Wang","doi":"10.1016/j.geoen.2025.213724","DOIUrl":"10.1016/j.geoen.2025.213724","url":null,"abstract":"<div><div>The characteristics of natural materials for drilling fluid additives that are not resistant to high temperature and high salt are well known. In this paper, hydroxyethyl cellulose (HEC) was modified with different silane coupling agents (SCA). Then, lithium magnesium silicate (LMS) was introduced to prepare a composite material (HEC/APS/LMS) to further improve the structural strength of the polymer. FTIR and ¹H NMR showed that the composites were successfully prepared. TGA analysis showed that the degradation rate of the composites was much lower than that of unmodified HEC at 263 °C–320 °C. The rheological analysis of the drilling fluid after adding the composite material showed that the viscosity of the drilling fluid remained stable before and after aging at 160 °C, and the change rate was less than 10 %. After aging at 180 °C, the viscosity retention rate is still greater than 50 %. SCA is interpenetrated into the polymer network structure by chemical bonds, hydrogen bonds, and polycondensation to form a low molecular weight polysiloxane structure. The thermal stability of the polymer was enhanced. The introduction of LMS, through hydrogen bonding and electrostatic adsorption, further enhances the spatial network structure of drilling fluid, and improves the ability of drilling fluid to suspend cuttings and clean wellbore. Silanized cellulose materials provide a new way to reinforce the temperature and salt resistance of natural materials.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"247 ","pages":"Article 213724"},"PeriodicalIF":0.0,"publicationDate":"2025-01-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143150610","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Insights on the fracture behavior of mudstone subjected to water and liquid CO2 fracturing","authors":"Dongdong Ma ,&nbsp;Xunjian Hu ,&nbsp;Xiao Ma ,&nbsp;Decheng Li","doi":"10.1016/j.geoen.2025.213721","DOIUrl":"10.1016/j.geoen.2025.213721","url":null,"abstract":"<div><div>Hydraulic fracturing stands as the predominant method for the commercial development of reservoirs. However, maintaining the integrity of the mudstone caprock during fracturing is critical for ensuring the long-term stability of reservoir production. In this case, we conducted fracturing tests on downhole mudstone cores using both water and L-CO₂. Advanced techniques, including micro-computed tomography (μCT), nuclear magnetic resonance (NMR), and scanning electron microscopy (SEM), were utilized to characterize the differences in fracture response between the two methods and to further elucidate the fracturing mechanisms of mudstone. The findings reveal that the breakdown pressure in L-CO₂ fracturing was consistently lower than that in water fracturing, with both being lower than theoretical predictions. In water fracturing, the injection pressure curve showed pronounced fluctuations during the failure phase. The induced cracks exhibited a stepped morphology macroscopically and sliding traces microscopically. This phenomenon is attributed to the infiltration of water into the layered particles of the mudstone, which weakens inter-particle bonds and creates numerous micro-pores, leading to a multi-scale cracking feature. In contrast, the perturbation of pore pressure in L-CO₂ fracturing contributed to the cracking along the weak plane, with a predominant in microscopic feature. The insights gained from this research are invaluable for the optimization of field-scale fracturing operations.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"247 ","pages":"Article 213721"},"PeriodicalIF":0.0,"publicationDate":"2025-01-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143150674","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Towards automated joint detection and RQD estimation in acoustic televiewer imaging using deep learning (instance segmentation)","authors":"Negin Houshmand,&nbsp;Kamran Esmaeili,&nbsp;Sebastian Goodfellow","doi":"10.1016/j.geoen.2025.213730","DOIUrl":"10.1016/j.geoen.2025.213730","url":null,"abstract":"<div><div>A thorough understanding of rock mass structural complexity is essential for geotechnical design and analysis of surface and underground excavations in rock. Borehole imaging is commonly used to rapidly and accurately characterize fractures without handling core specimens. Acoustic televiewer (ATV) imaging is an effective tool for detecting structural fractures and determining Rock Quality Designation (RQD) along a borehole. As part of interpreting the ATV data, the logger typically detects and identifies joints manually. This is a time-consuming, subjective, and inconsistent process. This study introduces a method that can automate joint detection, joint orientation (alpha and beta angles), and RQD estimation. For this study, a total of 1390 m of ATV data, including 1847 joints, were collected from 24 boreholes. In the first step, several filtering techniques were used, including Canny, Laplacian of Gaussian, K-Means, Multiple thresholding, Hough transform, and watershed segmentation for automated joint segmentation. In comparison, watershed segmentation outperforms other techniques, but it is sensitive to noise and outbreaks present in some of the ATV images. As a result, a deep learning algorithm called Mask R-CNN was used. This approach is an instance segmentation method that showed promising results with an F1-score of 0.82 in automated joint detection on an unseen test dataset. Based on the model, the mean absolute errors of alpha and beta angles and the RQD calculated by the model are 1.4^o, 20.1^o, and 1%, respectively.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"247 ","pages":"Article 213730"},"PeriodicalIF":0.0,"publicationDate":"2025-01-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143150673","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Effect of Multifunctional Boron Nitride Nanoparticles on the Performance of Oil-Based Drilling Fluids in High-Temperature Unconventional Formation Drilling","authors":"Aftab Hussain Arain ,&nbsp;Syahrir Ridha","doi":"10.1016/j.geoen.2025.213722","DOIUrl":"10.1016/j.geoen.2025.213722","url":null,"abstract":"<div><div>Wellbore instability is a persistent challenge faced during the drilling of unconventional formations. The successful drilling operation in these formations requires the appropriate selection of an efficient drilling fluid. The utilisation of oil-based drilling fluid augmented with nanoparticles can mitigate these problems by improving the rheological and filtration properties. However, the influence of nanoparticles on these properties of oil-based drilling fluid is inadequately comprehended. This research study investigates the effect of boron nitride nanoparticles on the rheological and filtration characteristics of oil-based drilling fluid. The impact of boron nitride nanoparticles on the rheological and filtration characteristics of the invert emulsion drilling fluid at high temperatures was examined and quantified through a comprehensive experimental investigation. Furthermore, the influence of boron nitride nanoparticles on the emulsion stability, barite sagging tendency, swell inhibition characteristics and flow behaviour was also examined. The drilling fluid was also subjected to thermal aging to analyse the influence of temperature on its rheological characteristics under dynamic conditions. Boron nitride nanoparticles were characterised to evaluate their morphology and purity. The results showed that adding boron nitride nanoparticles has substantially enhanced the rheological characteristics of invert emulsion drilling fluid. A concentration of 0.2 ppb results in a 24% improvement in plastic viscosity and a 27% increase in yield point. While a maximum reduction of 67% in filtrate loss was attained at a concentration of 0.5 ppb. Similarly, an enhancement in emulsion stability and a reduction in barite sagging tendency were also observed. The flow behaviour and rheological modelling suggest the non-Newtonian behaviour of nanoparticles-enhanced oil-based drilling exhibiting the shear-thinning characteristics, associated with the Herschel-Bulkley model. In conclusion, this study illustrates that the incorporation of boron nitride nanoparticles into oil-based drilling fluids substantially enhances their performance by enhancing the rheological and filtration characteristics under high-temperature conditions. This may avert and alleviate the wellbore instability problems during drilling the unconventional formations.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"247 ","pages":"Article 213722"},"PeriodicalIF":0.0,"publicationDate":"2025-01-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143150693","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Experimental investigation and modeling of water alternating polymer flooding in homogeneous sandstone reservoirs","authors":"Ahmed Mansour ,&nbsp;Rashid S. Al-Maamari ,&nbsp;Maissa Souayeh ,&nbsp;Emre Artun ,&nbsp;Omira Al-Riyami ,&nbsp;Al Yaqathan Al-Ghafri","doi":"10.1016/j.geoen.2025.213725","DOIUrl":"10.1016/j.geoen.2025.213725","url":null,"abstract":"<div><div>Modeling water alternating polymer (WAP) flood encounters challenges arising from the development of miscible viscous fingers between the polymer slug and chase water, as well as the potential formation of immiscible viscous fingers between the oil bank and polymer-water mixture. Existing research lacks sufficient understanding of the complexities associated with modeling WAP floods, particularly the dynamic behavior of the residual resistance factor (RRF) and the interactions between polymer slugs and chase water. The oil bank hysteresis effect and the dynamic changes in the degree of polymer retention reversibility during polymer and chase water injections further complicate the process. This dynamic behavior implies that the RRF undergoes multiple changes during and after polymer injection. Classical simulation models typically assume no change in RRF during polymer and chase water injections with some models accommodating a maximum of a one-time change of RRF. Dealing with varying degrees of reversibility during WAP processes, across different polymer slug sizes and levels of heterogeneity, requires a more flexible approach. In this study, a series of coreflood experiments were conducted utilizing homogeneous sandstone core samples and high oil viscosity (300 cP). Various polymer slug sizes were injected into fully water-saturated cores and in the presence of oil. Experiments were modeled using a high-resolution simulation utilizing multiple relative permeability sets (RPs) integrating Todd-Longstaff (TL) incomplete mixing model.</div><div>The simulation model was successfully able to capture the flow dynamics of the WAP experiments. The number of RPs required to accurately model the WAP experiments increases as the slug size decreases. The results showed that oil bank hysteresis enhanced the stability of the polymer front, as indicated by the increase in the injection pressure for small slug sizes in homogenous porous media. A strong dependence of Todd-Longstaff (TL) mixing parameter (ω) on the average water saturation behind the polymer front was observed; it increases as polymer slug size decreases, thereby promoting more thorough mixing of water and polymer. Microscopic flow divergence during WAP redirected chase water flow to unswept pores leading to additional oil production. The comprehensive analysis of the results revealed that, in the case of secondary polymer injection, the impact of the RRF can be controlled through either explicit or implicit methods. For modeling WAP experiments, the practical approach involves scaling the RRF in the relative permeability curves (implicit). The combined use of multiple RPs and the TL mixing parameter enhances the model's flexibility, allowing for more accurate capture of in-situ mixing effects, pressure behavior and oil recovery dynamics during polymer flooding.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"247 ","pages":"Article 213725"},"PeriodicalIF":0.0,"publicationDate":"2025-01-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143150692","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A critical review of assessments of geological CO2 storage resources in Pennsylvania and the surrounding region","authors":"Levent Taylan Ozgur Yildirim ,&nbsp;Qihao Qian ,&nbsp;John Wang","doi":"10.1016/j.geoen.2025.213732","DOIUrl":"10.1016/j.geoen.2025.213732","url":null,"abstract":"<div><div>This paper provides a critical and the most up-to-date review and analysis of published studies of geological carbon dioxide (CO₂) storage resources in Pennsylvania and the surrounding region through (a) carefully examining the assessments by different agencies, including the methodology, assumptions, and storage resources; (b) reconciling the different assessments on the basis of our understanding of the geology of Pennsylvania and the region; and (c) clarifying the storage resources of Pennsylvania and the region on the basis of a classification system that was published by Society of Petroleum Engineers in 2017. Total CO₂ storage resources are 756 Gt, 8 Gt, 0.8 Gt, and 104 Gt in saline formations, depleted oil and gas reservoirs, coals, and the Marcellus shale, respectively in Pennsylvania (Dooley et al., 2005; Godec et al., 2013b). Contingent (Technically accessible) CO₂ storage resources in Pennsylvania ranges from 26 Gt to 30 Gt in saline formations, depleted oil and gas reservoirs, coals, and the Marcellus shale (US-DOE-NETL, 2015; Edwards et al., 2015). Further assessment of geological CO₂ storage in organic-rich shales (e.g. the Marcellus shale in Pennsylvania) is needed. The new knowledge from this review is crucial and helps governments, industries, researchers, and policymakers to understand and manage carbon capture utilization and storage (CCUS) economy, projects, and policies in Pennsylvania.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"247 ","pages":"Article 213732"},"PeriodicalIF":0.0,"publicationDate":"2025-01-27","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143150698","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"The interaction behaviors between the hydraulic fracture and natural fracture in hot dry rock","authors":"Zixiao Xie ,&nbsp;Zhongwei Huang ,&nbsp;Zhaowei Sun ,&nbsp;Gensheng Li ,&nbsp;Xiaoguang Wu ,&nbsp;Xu Zhang ,&nbsp;Rui Yang ,&nbsp;Tengda Long ,&nbsp;Wenchao Zou ,&nbsp;Yaoyao Sun ,&nbsp;Xinyu Qin ,&nbsp;Dawei Zhang","doi":"10.1016/j.geoen.2025.213731","DOIUrl":"10.1016/j.geoen.2025.213731","url":null,"abstract":"<div><div>Hydraulic fracturing is a prerequisite for efficiently extracting heat from hot dry rock (HDR), which is expected to create complex and inter-connected fracture networks between injection and production wells. Natural fractures are widely distributed within HDR and would prominently affect the propagation of hydraulic fractures. However, little work has been done utilizing granite specimens to investigate the interactive role between natural fractures and artificial fractures under the influence of thermal stress. We hereby performed high-temperature hydraulic fracturing tests on granite outcrops embedded with pre-existing natural fractures to reveal the fracture interaction behaviors. Consequently, the fracture interaction modes for guiding the generation of complex fracture networks were established. The findings indicate that a greater temperature differential between the injection fluid and the rock promotes the stimulation of natural fractures, attributable to the combined effects of thermal stress and fluid pressure exerted on the fracture interface. As the initial rock temperature rose to 180 °C, the activation of the natural fractures was likely to occur even under a relatively large injection rate and horizontal stress difference ratio, which unfavored the opening of the natural fracture. Additionally, with the increment of the rock temperature, the fracture conductivity of the generated fracture network rises accordingly. The average fracture conductivity of granite under 180 °C is around 5 times and 1.3 times higher than that of those under 25 °C and 100 °C, respectively. Furthermore, the reactivation of the natural fracture enlarges both the volume and surface area of the fracture networks in comparison to the crossing-only pattern, and this could be further enhanced as the hydraulic fracture propagated through the natural fractures afterward. The findings are expected to provide a comprehensive insight into the hydraulic fracturing of HDR with natural fractures.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"247 ","pages":"Article 213731"},"PeriodicalIF":0.0,"publicationDate":"2025-01-27","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143150606","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Effect of flexible fibers for preventing proppant flowback after fracture closure by CFD-DEM method","authors":"Jianping Zhou ,&nbsp;Dingli Yan ,&nbsp;Maotang Yao ,&nbsp;Liansong Wu ,&nbsp;Dingdong Mo ,&nbsp;Wengang Wang ,&nbsp;Zhongwu Yang ,&nbsp;Yuxuan Liu","doi":"10.1016/j.geoen.2025.213719","DOIUrl":"10.1016/j.geoen.2025.213719","url":null,"abstract":"<div><div>Proppant flowback can lead to blockages in the wellbore and surface pipelines. Adding fibers during the hydraulic fracturing process has been proven to be an effective method to control proppant flowback. Proppant flowback involves interactions between proppant-proppant, proppant-wall, proppant-flexible fiber, and solid phase-fluid. To study this issue, this paper employs a multi-node structural modeling method, overcoming the limitations of a single-node cylindrical rigid fiber, and establishes flexible fibers that can undergo arbitrary deformations. To analyze the movement of fibers-proppant under fluid action, the Gidaspow model is used for proppants, and the Marheineke&amp;Wegener model is used for fibers, coupling fluids and solids to achieve a simulation of fiber-proppant flowback under fluid action. Simulation results indicate that the average flowback velocity of proppant is lower after adding fibers than without them. The longer the fiber length and the higher the mass concentration, the better the effect of the fibers in controlling the flowback of the proppant. The velocity of proppant flowback is positively correlated with the fracture width to particle size ratio and negatively correlated with the closing pressure. Under conditions of low fracture width to particle size ratio or high closing pressure, the contact force between particles are large and the proppants are not prone to flowback, so fibers can be used less or not at all. In addition, the proppant flowback velocity is directly proportional to the fracture fluid viscosity and velocity. This study provides new insights into the interaction between fiber and proppant after fracture closure.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"247 ","pages":"Article 213719"},"PeriodicalIF":0.0,"publicationDate":"2025-01-27","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143150608","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}