Search Results (72)

Ultra-tight gas reservoirs present severe flow constraints due to complex interactions between rock–fluid properties and hydraulic fracturing. This study investigates the impact of unconventional capillary pressure correlations and permeability jail effects on post-fracture cleanup in multiple-fractured horizontal wells (MFHWs) using high-resolution numerical simulations. A novel modelling approach is applied to represent both weak and strong permeability jail phenomena in heterogeneous rock systems. A comprehensive suite of parametric simulations evaluates gas production loss (GPL) and produced fracture fluid (PFF) across varying fracture fluid volumes, shut-in times, drawdown pressures, and matrix permeabilities. The analysis leverages statistically designed experiments and response surface models to isolate the influence of rock heterogeneity and saturation-dependent flow restrictions on cleanup efficiency. The results reveal that strong jail zones drastically hinder fracture fluid recovery, while weak jail configurations interact with heterogeneity to produce non-linear cleanup trends. Notably, reducing the pore size distribution index in Pc models improves predictive accuracy for ultra-tight conditions. These findings underscore the need to integrate unconventional Kr and Pc behaviour in hydraulic fracturing design to optimise flowback and long-term gas recovery. This work provides critical insights for improving reservoir performance and supports ambitions in energy resilience and net-zero transition strategies. Full article

Accurate understanding of natural fractures, faults, in situ stress, and mechanical properties of reservoir rocks is a prerequisite for evaluating well interference. During hydraulic fracturing, hydraulic fractures may connect with natural fractures or fault zones, leading to communication with adjacent wells and resulting in cross-well interference. Additionally, horizontal well spacing is a critical factor influencing the occurrence and severity of interference. The Mahu tight oil reservoir experiences severe fracturing interference issues, presenting multiple challenges. This study employs numerical simulation methods to quantitatively assess the influence of geological and engineering factors, including reservoir depletion volume, well spacing, natural fractures, and fracturing operation parameters on fracturing interference intensity. By integrating geological data, engineering parameters, and production data with microseismic monitoring and pressure information, this research aims to clarify key influencing factors and elucidate the fundamental mechanisms governing fracturing-driven interference occurrences. Through production performance analysis and microseismic monitoring, it has been established that well spacing, fracturing intensity, and natural fracture networks are the primary factors affecting interference in hydraulically fractured horizontal wells. Full article

Hydraulic fracturing of gas and oil reservoirs is the primary stimulation method for enhancing production in the field of petroleum engineering. The hydraulic fracturing technology plays a crucial role in increasing shale gas production from shale reservoirs. Understanding the effects of reservoir and fracturing conditions on fracture propagation is of great significance for optimizing the hydraulic fracturing process and has not been adequately explored in the current literature. In the context of shale reservoirs in Yibin, Sichuan Province, China, the study selects outcrops to prepare samples for uniaxial compression and Brazilian splitting tests. These tests measure the compressive and tensile strengths of shale in parallel bedding and vertical bedding directions, obtaining the shale’s anisotropic elastic modulus and Poisson’s ratio. These parameters are crucial for simulating reservoir hydraulic fracturing. This paper presents a numerical model utilizing a finite element (FE) analysis to simulate the process of multi-cluster hydraulic fracturing in a shale reservoir with natural fractures in three dimensions. A numerical simulation of the intersection of multiple clusters of 3D hydraulic fractures and natural fractures was performed, and the complex 3D fracture morphologies after the interaction between any two fractures were revealed. The influences of natural fractures, reservoir ground stress, fracturing conditions, and fracture interference concerning the spreading of hydraulic fractures were analyzed. The results highlight several key points: (1) Shale samples exhibit distinct layering with significant anisotropy. The elastic compressive modulus and Poisson’s ratio of parallel bedding shale samples are similar to those of vertical bedding shale samples, while the compressive strength of parallel bedding shale samples is significantly greater than that of vertical bedding shale samples. The elastic compressive modulus of shale is 6 to 10 times its tensile modulus. (2) The anisotropy of shale’s tensile properties is pronounced. The ultimate load capacity of vertical bedding shale samples is 2 to 4 times that of parallel bedding shale samples. The tensile strength of vertical bedding shale samples is 2 to 5 times that of parallel bedding shale samples. (3) The hydraulic fractures induced by the injection well closest to the natural fractures expanded the fastest, and the natural fractures opened when they intersected the hydraulic fractures. When the difference in the horizontal ground stress was significant, natural fractures were more inclined to open after the intersection between the hydraulic and natural fractures. (4) The higher the injection rate and viscosity of the fracturing fluid, the faster the fracture propagation. The research findings could improve the fracturing process through a better understanding of the fracture propagation process and provide practical guidance for hydraulic fracturing design in shale gas reservoirs. Full article

The process of fully mechanized coal seam mining under aquifers and surface water bodies has been a challenge in recent years for different countries. During the evolution of subsidence and the overburdening of rock mass movement above the longwall goaf, there is always a potential risk of connecting the water-conducting fracture zone with aquifers. The water inflows in the coal mine’s roadways have a negative impact on the productivity of the working faces and pose significant hazards to miners in the event of water inrush. Therefore, the assessment of the height of the water-flowing fractured zone has an important scientific and practical significance. The background of this study is the Xinhu Coal Mine in Anhui Province, China. In the number 81 mining area of the Xinhu Coal Mine during the mining of the number 815 longwall, a water inflow occurred due to fractures in the sandstone in the overburden rock. The experience of the successful implementation of the water inrush control method by horizontal regional grouting through multiple directional wells is described in this paper. This study proposes an algorithm for the assessment of the risk of water inrush from aquifers, based on an ANSYS 17.2 simulation in the complex anticline coal seam bedding. It was found that the safety factors based on the stress and strain parameters can be used as criteria for the risk of rock failure in the aquifer zone. For the number 817 longwall panel of the Xinhu Coal Mine, the probability of rock mass failure indicates a low risk of the occurrence of a water-flowing fractured zone. Full article

Horizontal well fracturing is a pivotal technology for enhancing the efficiency of shale oil and gas development. Shale reservoirs exhibit significant heterogeneity and intricate fracture propagation patterns, often resulting in uneven multiple fractures caused by horizontal well fracturing. Temporary plugging technology plays a critical role in optimizing fracture propagation patterns; however, there is currently limited research on its optimization. Based on a hydraulic fracturing fracture propagation simulation, an optimization study was conducted on temporary plugging technology for horizontal well fracturing in shale oil reservoirs. Numerical simulation results demonstrate that the uniformity of hydraulic fracture propagation during horizontal well fracturing in shale oil reservoirs is maximized when 30 perforations are plugged. The most uniform fracture propagation pattern is achieved by adding temporary plugging agents after pumping a total volume of 30% fracturing fluid. Furthermore, a comparison between one-time plugging with temporary plugging balls and multiple plugging was made to evaluate differences in fracture propagation. It was observed that performing temporary plugging once significantly improves the uniformity of fracture propagation compared to multiple temporary plugging. These research findings have been successfully validated through the practical application of hydraulic fracturing techniques, as indicated by substantial improvements in both the mode and uniformity of fracture propagation following temporary plugging. Full article

The irregular outer boundaries of reservoirs and the associated heterogeneous high-permeability zones formed by complex geological environment pose significant challenges in reservoir characterization and performance prediction. These irregular geometries, which are commonly encountered in field applications but often oversimplified in conventional models, can substantially influence fluid flow dynamics and transient pressure behavior. To solve this critical issue, this paper presents a semi-analytical model for studying the transient pressure behavior of irregular heterogeneous reservoirs, focusing on the dynamic interactions between hydraulic fractures and the surrounding matrix. The model integrates Green’s function solutions for matrix flow with finite difference methods to simulate fluid flow within complex fracture networks, capturing the heterogeneity of the reservoir and the irregularity of its boundaries. Specifically, the reservoir is divided into locally homogeneous blocks, and the flow within each block is solved using bounded Green’s functions, while the fracture networks are discretized and solved using finite difference methods. This proposed model significantly reduces computational complexity compared to traditional numerical simulations, while maintaining high accuracy. Subsequently, we conducted comprehensive parameter sensitivity analyses. The calculational results show that a multi-fractured horizontal well in an irregular heterogeneous reservoir can observe the following flow regimes: bilinear flow, elliptical flow, and boundary-dominated flow. Longer fractures and higher conductivity enhance fracture flux by increasing the contact area and reducing flow resistance, respectively. However, these positive impacts are constrained by drainage area limitations as production progresses. Full article

Geological and topographic site effects lead to variations in the spatial distribution of ground motion during large earthquakes. Despite the impact of such phenomena, they remain poorly understood. There is a lack of joint studies of numerical predictions and experimental observations on the geomorphological site effects. Therefore, a comparison between well-constrained models and experimental field observations is needed. Byblos is a seismic region in Lebanon surrounded by faults that historically generated destructive earthquakes. Its geological and geomorphological settings are interestingly characterized by fractured rocks and anthropic deposits altering seismic ground motions. Field surveys in Byblos gathered ambient vibration recordings and surface waves. It identified multiple resonant frequency peaks, suggesting impedance contrasts and lateral variations in subsurface stiffness, using Horizontal-to-Vertical Spectral Ratio (HVSR) and directivity. It also revealed soft, shallow layers with low velocities, indicating potential resonance during earthquakes, using Multichannel Analysis of Surface Waves (MASW) and 2D seismic arrays. Thus, our study on Byblos is a first step for seismic microzoning of the area that evaluated its heterogeneous subsoil, soft surface layers, and anthropic deposits. Finally, combining geophysical data and field measurements with a numerical model allowed a better understanding of Byblos seismic hazards and enhanced its resilience and sustainability. Full article

Shale gas extraction is hindered by the complex geological conditions of shale reservoirs, such as deep burial, low permeability, and multi-zone characteristics. Therefore, horizontal well hydraulic fracturing is essential for improving reservoir permeability. However, fracture interference and fracturing fluid retention can lead to gas–water co-production. Existing models for predicting the productivity of fractured horizontal wells typically focus on single-phase flow or do not fully account for fracture interactions and dynamic water saturation changes. In contrast, this study introduces a novel fast prediction model for the steady-state productivity of fractured horizontal wells under a gas–water two-phase flow. The model extends single-phase fluid seepage theory by incorporating a gas–water two-phase pseudo-pressure function, while also accounting for fracture interference using potential theory and the superposition principle. Furthermore, it dynamically integrates formation pressure and water saturation variations, offering a more accurate prediction of productivity. The result demonstrates that fracture interference significantly affects the distribution of productivity, with end fractures producing up to 5.6 × 10⁴ m³ while intermediate fractures maintain a relatively uniform production of around 0.9 × 10⁴ m³. The sensitivity analysis reveals that productivity increases with an increase in formation pressure, fracture number, fracture half-length, and fracture angle, while an increcase in water saturation and skin factor reduce it. These results highlight the importance of optimizing fracture design and production strategies. This work provides a more comprehensive and efficient method for predicting and optimizing the gas–water two-phase productivity of fractured horizontal wells. Full article

The deep shale gas resources of the Sichuan Basin are abundant and constitute an important component of China’s natural gas production. Complicated by fault zones and other geostructures, the in situ stress state of the deep shale gas reservoirs in the Luzhou block remains poorly understood. This study integrated multiple datasets, including acoustic logging, diagnostic fracture injection testing (DFIT), imaging logging, and laboratory stress measurements, for calibration and constraint. A high-precision geomechanical model of the Luzhou block was constructed using the finite element method. This model characterizes the geomechanical properties of the reservoir and explores its applications in optimizing shale gas horizontal well placement, drilling processes, and fracture design. The study findings indicate that the Longmaxi Formation reservoir demonstrates abnormally high pore pressure, with gradients ranging from 16.7 to 21.7 kPa/m. The predominant stress regime is strike-slip, with an overburden stress gradient of 25.5 kPa/m and a minimum horizontal principal stress gradient ranging from 18.8 to 24.5 kPa/m. Based on a three-dimensional geomechanical model, a quantitative delineation of areas conducive to density reduction and pressure control drilling was conducted, and field experiments were implemented in well Y65-X. Utilizing an optimized drilling fluid density of 1.85 g/cm³, the deviated horizontal section was completed in a single trip, resulting in a 67% reduction in the drilling cycle compared to adjacent wells. Similarly, the Y2-X well demonstrated a test daily output of 506,900 cubic meters following an optimization of segmentation clustering and fracturing parameters. Studies indicate that 3D geomechanical modeling, informed by multi-source data constraints, can markedly enhance model precision, and such geomechanical models and their results can effectively augment drilling operational efficiency, elevate single-well production, and are advantageous for development. Full article

Horizontal well hydraulic fracturing technology has been widely used in the efficient development of shale gas to address the challenges posed by these reservoirs’ low permeability and porosity. Despite the availability of numerous models for evaluating shale gas productivity post-fracturing, the effect of gas dynamic viscosity has been neglected. This study establishes a multiple-media and multiple-permeability coupled flow model based on the Barnett Shale and introduces Lee’s correlation for gas viscosity. The model’s feasibility and accuracy were verified by comparing the simulation results with the Barnett Shale data. The effects of reservoir damage, stimulation intensity, and fracture spacing on shale gas productivity are discussed. The results demonstrated that shale gas productivity decreased by more than 50% with intensified reservoir damage. Increasing stimulation intensity in the reservoir volume enhanced shale gas productivity. When the stimulation coefficient for the reservoir was increased from 0 to 2.5, the productivity increased by over 25%. A larger fracture spacing resulted in a smaller increase in shale gas productivity. Conversely, excessively narrow spacings significantly hindered productivity, resulting in an approximate 25% decrease. This study provides a theoretical reference for the productivity evaluation of horizontal wells in shale gas reservoirs. Full article

Deep shale formations pose significant challenges in forming high-conductivity fractures, leading to low ultimate recoverable reserves (EUR) per well under conventional fracturing techniques. Dense-cutting fracturing is a commonly employed method to enhance the EUR of individual wells; however, the critical process parameters influencing EUR remain unclear. This study develops a novel EUR calculation model tailored for deep shale gas dense-cutting, integrating the Warren-Root model with the constant-volume gas reservoir material balance equation. The model comprehensively incorporates Knudsen diffusion and adsorption-desorption phenomena in deep shale gas, corrects apparent permeability, and employs the finite element method to simulate dynamic pressure depletion during production. The study examines the impact of fracture half-lengths, cluster spacing, fracture conductivity and horizontal section lengths on EUR under tight-cutting fracturing. Orthogonal experiments combined with multiple linear regression analysis reveal the hierarchy of influence among the four factors on EUR: horizontal section length > fracture half-length > cluster spacing > fracture conductivity. The study derives EUR correlation expressions that incorporate the effects of crack half-length, cluster spacing, fracture conductivity, and horizontal segment length. The orthogonal experimental results indicate that EUR exhibits positive correlations with crack half-length, fracture conductivity, and horizontal segment length, while showing a negative correlation with cluster spacing. The multiple regression equation achieves a coefficient of determination (R²) of 0.962 and an average relative error of 3.79%, outperforming traditional prediction methods in both accuracy and computational simplicity. The findings are of substantial significance for the rapid estimation of EUR in individual wells following deep shale gas fracturing and offer valuable theoretical insights for practical engineering applications. Full article

The geological storage of CO₂ in saline aquifers is a crucial method for achieving large-scale carbon storage in the future. The saline aquifers with low porosity and permeability in the Ordos Basin exhibit high irreducible water saturation and restricted fluid mobility, necessitating further investigation of their injectivity and storage safety. The fifth member of the Shiqianfeng Formation (P₃sh₅) in the Ordos Basin serves as a key layer for geological CO₂ storage (GCS). The numerical simulation of CO₂ injection in this reservoir is an indispensable process for characterizing the migration and storage of CO₂. Injection pressure and well type (vertical well or horizontal well) are critical factors affecting GCS. The results of the numerical simulation are important preliminary preparations for promoting the GCS in the saline aquifer of the Shiqianfeng Formation in the future. This paper focuses on P₃sh₅ in the Yulin area as a case study. It investigates the injectivity and CO₂ migration characteristics of these low porosity and low permeability saline aquifers in the Ordos Basin. Relatively high-quality distributary channel sandstone bodies in integrally low porosity and permeability strata were identified for injection. As CO₂ is injected, the formation pressure gradually increases. It is essential to maintain it below the fracture pressure during CO₂ injection to ensure safety. High-pressure (8 MPa) injection could achieve volumes 2.9 times greater than those in the low-pressure scenario (4 MPa) of 2 km horizontal branch well. Under the three injection well types, the injection rate of vertical wells is the lowest. Employing a “horizontal branch well injection” strategy could potentially amplify the injection volume by 2.87 times. CO₂ predominantly migrates vertically near the horizontal interval of interest, while horizontally, the area near the interval of interest experiences a higher CO₂ saturation, with the maximum saturation reaching about 50%. Overall, CO₂ is migrated in the distributary channel sandstone bodies, indicating a higher storage safety and lower leakage risk. It is recommended that the number of drilling wells be increased and multiple horizontal branch wells implemented to enhance the injection efficiency. Overall, this study provides a geological foundation for the previous design and construction of the GCS project in the Ordos Basin’s saline aquifer. It also provides a reference for GCS in low permeability saline layers in similar regions worldwide. Full article

With the development of shale gas horizontal well-filling technology, by drilling infill wells between wells, the well spacing is continuously reduced to make shale reservoir reconstruction more effective. However, in shale gas reservoirs in China, the problem of inter-well interference is becoming increasingly serious, which not only affects the production of well groups but also causes wellbore damage. Currently, the process of interference in the production process is unclear. This study addresses the inter-well interference issue in deep shale gas reservoirs. An integrated numerical simulation method combining the Discrete Fracture Network, Finite Element Method, and Finite Difference Method is proposed. A comprehensive reservoir numerical model considering the production process is proposed. According to the actual reservoir model parameters and operation parameters, a multi-factor analysis model under multiple production conditions was established. Cumulative gas production and inter-well interference were analyzed. Finally, a field model was established, and the history matching of formation pressure was carried out. According to the history-matching results, the pressure expansion range in the production stage was analyzed. These research results provide a scientific basis and practical suggestions for the effective management and mitigation of inter-well interference and are expected to play an important role in practical engineering applications. Full article

This study delves into the complexities of fluid cleanup processes post-hydraulic fracturing in unconventional gas deposits, focusing on the pivotal role of capillary pressure (P_c) correlations in tight and ultra-tight formations. Utilising Geo2Flow software, this research evaluates the efficacy of existing P_c models, identifying the Brooks and Corey model as notably precise for these formations, albeit recommending an adjustment to the pore size distribution index for a more accurate representation of rock behaviours. Further investigation centres on the cleanup process in multiple fractured horizontal wells, examining the impact of the P_c, matrix permeability, drawdown pressure, and fracturing fluid volume. A significant portion of this study addresses the influence of interfacial tension-reducing chemicals on post-fracturing production, highlighting their utility in ultra-tight formations, but advising against their use in tight formations due to environmental concerns and limited efficacy. The findings underscore the nuanced interplay between geological parameters and fracturing fluid dynamics, advocating for tailored fluid cleanup strategies that enhance the hydraulic fracturing efficiency while minimising the environmental impact. This comprehensive analysis offers valuable insights into optimising fracture cleanup and understanding the underlying physics, thereby contributing to more effective hydraulic fracturing practices. Full article

Reliable forecasting of unconventional oil and gas well production has consistently been a hot and challenging issue. Most existing data-driven production forecasting models rely solely on a single methodology, with the application effects of other mainstream algorithms remaining unclear, which to some extent hinders the generalization and utilization of these models. To address this, this study commences with data preparation and systematically develops a novel forecasting model based on the adaptive fusion of multiple mainstream data-driven algorithms such as random forest and support vector machine. The validity of the model is verified using actual production wells in the Marcellus. A comprehensive evaluation of multiple feature engineering extraction techniques concludes that the main controlling factors affecting the production of Marcellus gas wells are horizontal segment length, fracturing fluid volume, vertical depth, fracturing section, and reservoir thickness. Evaluation models based on these primary controlling factors reveal significant differences in prediction performance among mainstream data-driven methods when applied to the dataset. The newly developed model based on adaptive fusion optimized by genetic algorithms outperforms individual models across various evaluation metrics, which can effectively improve the accuracy of production forecasting, demonstrating its potential for promoting the application of data-driven methods in forecasting unconventional oil and gas well production. Furthermore, this will assist enterprises in allocating resources more effectively, optimizing extraction strategies, and reducing potential costs stemming from inaccurate predictions. Full article