Fracture Pressure Research Articles

Pore and fracture pressures prediction — A new geomechanic approach in deepwater salt overthrusts: Case histories from the Gulf of Mexico

Along this active exploration belt, applying the conventional effective stress methods and algorithms, wherein the maximum stress ([Formula: see text]) is vertical and can be attained from the subsurface overburden (OB), would lead to unintended and unrealistic results. In the frontier active thrust belt of the Gulf of Mexico, the unique geomechanical setting of [Formula: see text] as the lateral salt creep and the minimum stress ([Formula: see text]) as the OB greatly impact the formation geopressure framework. The buoyancy of thick salt produces two different pressure gradients (PGs) above and below the salt. Moreover, the inclusion of rafted sediments in the salt and the plowing rubble zone at the salt base substantially affects the pore and fracture pressures (PP-FP) profiles. These proceeding geologic settings are the foundation for the conceptual framework. Building an alternative predrilling prediction numerical model based on these anomalous geomechanical settings and the lack of adequate seismic velocity is a challenge. All the available direct measured or pertained PP-FP data from the key wells are collected and tabulated. Prediction models are established by correlating the populated database and generating the empirical algorithm for each data gather. A substantial discrepancy occurs between above and below the salt sections where high PG in the sediment above the salt and slow PG development below the salt. There is considerable regressive pressure (average 2 ppg) in PP-FP subsalt sections. The PP within the salt is contingent on the presence of sediment inclusions, and a substantial FP drop in the rubble zone leads to the extensive loss of mud circulation. The trend lines of each data gather led to generating two depth-dependent equations for the PP-FP above and within the salt and two others for the subsalt. The prediction models are validated against a blind data set. Before drilling, this model establishes the PP-FP versus the sediment subsea depth in an abnormal geomechanical setting and the lack of coherent vertical seismic velocity for PP-FP predictions.

Characterize the influences of hydraulic fracturing on preventing rock burst from the stress and vibration fields

The thick and hard roof (THR) is a significant factor that induces rock burst incidents. Traditional deep-hole blasting methods struggle to effectively relieve pressure for the high-level THR on a large scale. Although the horizontal staged hydraulic fracturing technology can crack high-level rock stratas, its impact on roof fracture still needs to be clarified, and there need to be more effective methods to evaluate its pressure relief effect. This paper conducted a comparative engineering test of local hydraulic fracturing pressure relief and load reduction on the working face to address this gap. The key layer theory and mine earthquake distribution were used to identify potential hazards of rock strata and the fracturing strata. Revealed the spatial and temporal evolution rules of microseisms induced by mining work, the failure mechanism of high-energy mine earthquakes, the evolution characteristics of source mechanical parameters, and the evolution characteristics of the stope stress field. The results indicate that after fracturing microseisms during mining presented exhibit a uniform distribution of high frequency and low energy. The fracture fragmentation of the roof rock was reduced, and the range of mining disturbance was minimized. High-energy mine earthquakes induced by mining are transferred to the goaf. Simultaneously, the corner frequency and stress decrease while the rupture radius and the shear component of the failure mechanism increase. The integrity of the THR is compromised, and fracture propagates and slips along the pre-crack. The roof of the working face experiences localized pressure, with decreased periodicity and intensity, reducing the overall static load level of the coal seam under the fracturing area. The research findings serve as a valuable reference for further investigations into the mechanism and risk assessment of hydraulic fracturing in preventing and controlling rock burst.

Fracture Pressure Prediction in Carbonate Reservoir Using Artificial Neural Networks

Fracture Pressure Prediction in Carbonate Reservoir Using Artificial Neural Networks

Prediction of formation fracture pressure based on reinforcement learning and XGBoost

Abstract Clearly determining the magnitude of fracture pressure is a crucial indicator for fracturing design. Traditional methods for predicting fracture pressure suffer from challenges such as difficulties in obtaining required data, low prediction accuracy, and local limitations in application. In light of these issues, the article proposes a fracture pressure prediction model based on reinforcement learning and XGBoost utilizing geophysical well logging data. Based on the relevance analysis, optimal input parameters, including DEPTH, DEN, AC, GR, CRL, and RT, are selected from geophysical well logging data. We have developed a framework for a fracture pressure prediction model based on XGBoost, wherein hyperparameters are fine-tuned using an improved Q-learning algorithm. The optimized XGBoost model for fracture pressure prediction attains outstanding performance metrics, including an R 2 value of 0.992, a root mean square error of 0.006%, and a mean absolute error of 0.539%. In direct comparison with grid search, Bayesian optimization, and ant colony optimization, the improved Q-learning algorithm emerges as the most effective optimization approach. The predictions generated by the proposed method exhibit remarkable consistency with fracture pressure data measured on-site. This approach successfully addresses the shortcomings encountered with traditional fracture pressure prediction methods, such as inadequate accuracy, demanding data prerequisites, and constrained applicability.

Experimental study on the influence of horizontal stress difference coefficient on coal rock fracture

Hydraulic fracturing is a pressure-relief and permeability-enhancing technique widely used in the mining of low-permeability coal seams. The horizontal stress difference coefficient is an important factor that affects the fracture propagation during the fracturing. To study the mechanism of the hydraulic fracturing process, in this paper, the initiation and propagation of cracks under horizontal stress difference coefficient are studied by using the developed true triaxial hydraulic fracturing system. The fracture surface morphology was obtained by 3D scanner. The experimental results are verified by the mathematical model. The results show that the fracture pressure and the peak values of AE count rate and b value increase and the cumulative AE count decreases with the increase of the horizontal stress difference coefficient. After the first pressure drop, the “pressure built-up” in the specimen increases and the peak value of AE count rate decreases with the increased horizontal stress difference coefficient. The 3D scanning results show that when the horizontal stress difference coefficient is larger, the hydraulic fracture propagation is straighter and the fracture surface area is smaller. The experimental results are in good agreement with the theoretical values. The experimental results provide a basis for engineering practice.

Utilization law of shale gas in hydraulic fracturing with the Changning–Weyuan block in China as an example

The process of extracting shale gas, particularly the study of the utilization law of shale reservoirs modified by hydraulic fracturing technology, is crucial for understanding the effective development of shale gas. This understanding can significantly influence the estimated ultimate recovery of reserves. Our study focused on Longmaxi Formation shale in the Changning–Weiyuan block. To investigate the hydraulic fracturing expansion mechanism and utilization law, we employed shale reservoir physical and mechanical characterization, indoor triaxial hydraulic fracturing experiments, and numerical simulations. The findings are as follows. The rupture pressure of hydraulic fractures increases with the peripheral pressure, and high stress is conducive to the formation of internal microfractures. Additionally, a high rate of water injection enhances fracture extensions along the direction of fluid injection. Under varying injection pressures, the length of crack extensions and number of bond damages in shale are positively correlated with the injection pressure. Conversely, under different differential ground stresses, the length of crack extensions and number of bond damages are negatively correlated with the injection pressure. The six main factors affecting the effective utilization of shale gas are as follows: the stimulated reservoir volume, number of hydraulic fracture clusters, fracture length, fracture height, number of fracture stages, and cluster spacing, accounting for 27.13%, 14.74%, 10.31%, 9.58%, 9.53%, and 9.29%, respectively, with a cumulative contribution rate of 80.58%. This study clarifies the hydraulic fracturing mechanisms of shale reservoirs and the laws governing shale gas production, providing technical support for the development of shale gas reservoirs.

The effect of rock mechanical heterogeneity on induced stress and initiation pressure of multi-cluster fracturing

The stress interference between fracturing clusters in horizontal wells is key in affecting the initiation and propagation of multi-cluster fractures. However, in reservoirs such as shale, there are often changes in the mechanical properties of the rock along the direction of the wellbore. Such changes are often not considered in models for multi-fracture propagation. As a result, the impact of rock mechanical heterogeneity on induced stress is not fully understood. Therefore, in this paper, a prediction model of the three-dimensional induced stress field of hydraulic fractures is established, taking into account mechanical heterogeneity. Combined with the prediction model of fracturing pressure, the changes in induced stress and initiation pressure under different conditions are analyzed. The results indicate a significant difference between the induced stress results considering mechanical heterogeneity and those considering only a single homogeneous region. The change in elastic modulus has a profound influence on induced stress and initiation pressure. Perforating at locations with low elastic modulus in situ can help reduce initiation pressure. Additionally, temporarily blocking the wellbore and reducing the flow rate to decrease the net pressure in the fractures can facilitate more fractures to initiate.

Prediction of Shale Gas Well Productivity Based on a Cuckoo-Optimized Neural Network

Current shale gas well production capacity predictions primarily rely on analytical and numerical simulation methods, which necessitate extensive calculations and manual parameter tuning and produce lowly accurate predictions. Although employing neural networks yields highly accurate predictions, they can easily fall into local optima. This paper suggests a new way to use Cuckoo Search (CS)-optimized neural networks to make shale gas well production capacity predictions more accurate and to solve the problem of local optima. It aims to assist engineers in devising more effective development plans and production strategies, optimizing resource allocation, and reducing risk. The method first analyzes the factors influencing the production capacity of shale gas wells in a block located in western China through correlation coefficients. It identifies the main factors affecting the gas test absolute open flow as organic carbon content, small-layer passage rate, fracture pressure, acid volume, pump-in fluid volume, brittle mineral content in the rock, and rock density. Subsequently, we used the CS algorithm to conduct the global training of the neural network, avoiding the problem of local optima, and established a neural network model for predicting shale gas well production capacity optimized by the CS algorithm. A comparative analysis with other relevant methods demonstrates that the CS-optimized neural network model can accurately predict production capacity, enabling a more rational and effective exploitation of shale gas resources, which lower development costs and increase the economic returns of oil and gas fields. Compared to numerical simulation, SVM, and BP neural network algorithms, the CS-optimized BP neural network (CS-BP) exhibits significantly lower prediction error. Its correlation coefficient between predicted and actual values reaches as high as 0.9924. Verification experiments conducted on another shale gas well also demonstrate that, in comparison to the BP neural network algorithm, CS-BP offers superior prediction performance, with model validation showing a prediction error of only 0.05. This study can facilitate more rational and efficient exploitation of shale gas resources, reduce development costs, and enhance the economic benefits of oil and gas fields.

Research on microscale displacement characteristics of supercritical CO2 fracturing in shale oil reservoirs

AbstractThe great success of CO2 fracturing in shale oil reservoirs has not only increased the production capacity of shale oil, but also effectively carried out CO2 geological storage. In this paper, focusing on the microscale displacement characteristics of CO2 fracturing in shale oil reservoirs, first, the impact of oil saturation and gas invasion pressure on gas invasion is discussed. Then, the coupling control mode of oil saturation/pressure for various mechanisms of gas invasion is revealed. Results show that: (a) at lower displacement, the rock core has a lower initiation pressure and is fractured in a shorter period of time; (b) at higher displacement, the required fracturing time is longer and the fracturing pressure increases, but the fracturing effect is good and it is easy to form complex fracture networks; and (c) under higher pressure conditions, more complex fractures can be formed, which is beneficial for reservoir transformation and production improvement.

Numerical study on Slurry-induced Fracturing Pressure of Cohesive Soil

The stability of the tunnel face during the slurry shield tunnelling is controlled by the slurry pressure in the slurry chamber, and excessive slurry pressure will cause fracturing on excavation face. In order to prevent the occurrence of slurry fracturing, it is necessary to conduct a detailed study on the slurry support pressure when the slurry fracturing occurs. In this study, the hydraulic fracturing experiment of cohesive soil samples was carried out by the self-developed hydraulic fracturing device, and the improved XFEM was used to simulate the experiment process. The influence of various factors on the fracturing pressure was analyzed, and the accuracy of the numerical simulation method was also verified. In addition, the calculation method of fracturing pressure of soft cohesive soil is obtained by fitting the influence of each factor. The results show that the improved XFEM can accurately simulate the shear failure of soft cohesive soil. The fracturing pressure increases linearly with the increase in the circumferential pressure, indicating that a higher overburden of the tunnel can help resist the initial fracturing induced by shield tunneling. The fracturing pressure increases with an increase in the unconfined compressive strength as well as the slurry viscosity. Based on the regression analysis of the numerical results, an empirical approach was proposed for estimating the slurry-induced fracturing of soil.

Modified guanidine gel fracturing fluid system and performance optimization for ultra-deep and ultra-high temperature oil and gas reservoirs

The development of deep high-temperature oil and gas reservoirs gives rise to a rise in reservoir temperature along with the depth of the oil reservoir, thereby imposing higher requirements on the heat resistance of fracturing fluid. Guar gum fracturing fluid has difficulty tolerating temperatures exceeding 160 °C, thereby demanding the development of corresponding cross-linking agents, temperature stabilizers, and other additives to enhance the thermal stability of the fracturing system. Considering the distinctive characteristics of deep and ultra-deep reservoirs, such as extreme burial depth (exceeding 6000 m), ultra-high temperature (higher than 160 °C), and high fracturing pressure, an experimental modification of a guar gum fracturing fluid system was carried out, specifically tailored for ultra-high temperatures. The experiment identified and selected individual agents for ultra-high temperature fracturing fluids, including crosslinking agents, thermal stabilizers, flowback aids, and clay inhibitors. Through rigorous experimentation, these key agents for an ultra-high temperature fracturing fluid system have been successfully developed, including the optimal thickener GBA1-2, crosslinking agent BA1-1, anti-swelling agent FB-1, and gel breaker TS-1. The evaluation of diverse additive dosages has facilitated the development of an optimal guar fracturing fluid system, which exhibits outstanding high-temperature resistance while minimizing damage and friction. The outcomes of our experiments indicate that even after subjecting our ultra-high temperature fracturing fluid to 2 h of shearing at 170 s−1 at 180 °C, its viscosity remained above 200 mPa s—a distinct proof of its superior performance in withstanding high temperatures. This achievement represents a substantial progress in providing a suitable fracturing fluid system for the transformation and stimulation of ultra-deep and ultra-high temperature reservoirs, and also lays a solid foundation for further exploration and application in related fields in the future.

Wpływ niejednorodności skał na stabilność ściany odwiertu

"One of the complications that arise while drilling wells is hydraulic fracturing. Hydraulic fracturing pressure is the pressure at which the integrity of the rock in the walls of the well is compromised, leading to the formation of artificial cracks. Various authors have proposed formulas to determine the hydraulic fracturing pressure Phf in the absence of actual data. Рhf = 0.87 Рrock Рhf = 0.85 (Рrock – Рres) + Рres Phf = [μ/(1 – μ)] (Рrock – Рres) + Рres Рhf = [2μ/(1 – μ)] Рrock where: μ – Poisson's ratio, which takes values of 0.25–0.4 for dense clay, 0.33–0.4 for clay with sandstone interlayers, 0.1–0.2 for shales, 0.3–0.35 for sandstone, 0.28–0.33 for limestone; Рrock, Рres – rock and reservoir pressure, respectively. This study examines the problem of determining hydraulic fracturing pressure taking into account the heterogeneity of rocks. The work can be roughly divided into two parts. In the first part, the physical properties of porous bodies in contact with fluids are studied, treating them as a two-phase medium. When a porous body comes into contact with fluids, the fluids penetrate into them, transforming them into a two-phase medium. The term “fluids” refers to both liquids and gases, with real liquids considered incompressible and gases highly compressible. The remaining part of the porous body, excluding the pores, is called the skeleton. Pores in porous bodies are connected through capillary tubes. In the second part, the influence of the magnetic field and rock heterogeneity on the stability of the well wall is studied. Formulas are derived to determine hydraulic fracturing pressure, depending on the mechanical properties of the rocks and the reservoir pressure. Based on the theory of destruction, the critical value of excess pressure (or hydraulic fracturing pressure) is determined, which is necessary to ensure the safety of drilling oil and gas wells. The machines used in drilling operations in the oil and gas industry must be easy to operate, reliable, and capable of long-time use. When designing such machines, considerations such as being lightweight, economical, and quick and inexpensive to prepare should be taken into account from the outset.

Evaluating the Effects of Proppant Flowback on Fracture Conductivity in Tight Reservoirs: A Combined Analytical Modeling and Simulation Study

This work establishes an analytical model for determining the critical velocity for proppant flowback, and evaluates how proppant flowback affects fracture conductivity for tight reservoirs. The multiphase effects are considered for determining the critical velocity for proppant flowback before and after fracture closure, respectively. The model’s performance is demonstrated by comparing the results against previous models. A finite-element model is built to simulate the proppant flowback process for a hydraulic-fractured well completed in the Ordos Basin. The change in fracture conductivity caused by proppant flowback for several scenarios with varying saturation and net pressure in fractures is further quantitatively assessed. Our results highlight the importance of multiphase effects in determining the critical velocity for proppant flowback at relatively low water saturation in fractures. The critical velocity generally increases with increasing water saturation in fractures and net pressure in fractures. At a flowback velocity higher than the critical value, the loss in fracture conductivity becomes relatively more pronounced at a lower water saturation in fractures and a lower net pressure in fractures. The findings of this work are expected to provide insights into the mechanisms of proppant flowback and flowback drawdown management for field operations in tight reservoirs.

Dynamic modeling studies of basin-scale pressure interference and CO2 plume evolution in multi-well geologic CO2 storage

Large-scale decarbonization through carbon capture and storage (CCS) may likely involve many commercial-scale CO2 storage projects located in proximity. Large volumes of CO2 injected will elevate reservoir pressures and may lead to rapid convergence of fracture pressure thresholds. This analysis employs numerical modeling to analyze how CO2 plumes and pressure fronts evolve when CO2 is injected into a single storage formation from multiple projects located in proximity. This analysis also evaluates the extent to which injection well spacing alleviates pressure buildup in the absence of active pressure management tactics. The simulation approach was based on a single, homogenous saline aquifer in which CO2 injection occurs under a one-injector baseline case and several multi-well cases where well spacing varies. Analysis results show that the extent of pressure buildup is in the range of tens or a few hundreds of kilometers and contingent upon the defining pressure buildup demarcating the front edge. For the geological setting evaluated in this paper, our analysis suggests that without active basin pressure management strategies, commercial-scale projects would likely need to be sited far apart to avoid pressure interference from one another. Analysis results show the radius of CO2 plume varies approximately from 2 to 3 km from injection wells (each injecting 1 Mt/year for 30 years) depending on cases and modeling parameters assumed. Given the pressure interference, this paper thus draws attention to the importance of greater coordination among storage operators and regulatory stakeholders. Because this analysis assumes a very specific geologic situation, this exploratory analysis bears further investigations across other geologic situations.

Coupling Upscaled Discrete Fracture Matrix and Apparent Permeability Modelling in DFNWORKS for Shale Reservoir Simulation

Modelling non-Darcy flow behaviour in shale rocks, composed of nanometer-sized pores and multi-scale fracture networks, is crucial for various subsurface energy applications. However, incorporating multiple physical mechanisms across numerous scales is not trivial. This work proposes an improved and practical upscaling workflow for coupling an Upscaled Discrete Fracture Matrix (UDFM) model and a pressure-dependent apparent permeability (Kapp) model to capture the effects of non-Darcy flow in multi-scale fractured shale reservoirs.First, a 3D DFN is upscaled into octree-refined continuum meshes, where equivalent rock parameters and rock-fluid functions are defined using the UDFM approach. Then, the flow simulation is coupled with a pressure-dependent Kapp updating scheme using an existing Kapp model and a multiple-restart technique. The effects of non-Darcy flow mechanisms (e.g., slip flow, transitional flow, Knudsen diffusion) are captured. The constructed models are then used to study the impacts of fracture network connectivity and pressure interference on production. The results of this new approach are compared against those obtained from another commercial package while preserving the advantages of DFNWORKS. Neglecting non-Darcy flow behaviours could significantly underestimate gas production and water recovery. It is illustrated that the nanoscale flow mechanisms help to enhance matrix-matrix and matrix-fracture flow. The constructed models are also utilized to study the effects of disconnected or isolated fractures, pressure interference, water retention, and shut-in durations on well performance. The proposed flexible strategies can be adopted in other commercial/open-source fractured-porous-media subsurface-flow simulation frameworks.

Three-pressure prediction method of jointing well-seismic data in JT1 well area of Sichuan Basin in China

With the high yield of many wells represented by Well JT1 in the Maokou Formation, has catalyzed a surge in exploration activities along the platform margin facies of the Maokou Formation in central Sichuan and further showed the significant exploration potential of the Maokou Formation in the northern slope. However, the fracture cave body of the Maokou Formation exhibits a high degree of development, strong longitudinal and horizontal heterogeneity, large formation pressure differences, and drilling events such as gas kicks and lost circulation occur frequently, which seriously affects the efficient implementation of drilling. Understanding the spatial distribution of the three-pressure in the formation can help better deal with and solve the above problems. Therefore, in order to help the safe, high-quality and rapid drilling of the Maokou Formation in the study area, and enhance the efficiency of oil and gas development, this paper explores the research on the prediction method of the three-pressure of jointing well-seismic data based on the geomechanical experimental data and the actual drilling data. In the process of prediction of pore pressure, this study found that the pore pressure and formation velocity in the study area have an exponential relationship. In order to enhance the applicability of the Filippone’s method in the study area and improve the prediction accuracy of pore pressure, the linear relationship between pore pressure and formation velocity in the Filippone’s method is modified to an exponential relationship, and a pore pressure prediction model suitable for the work area was established. Based on the Mohr–Coulomb criterion and Huang's model, the prediction models of collapse pressure and fracture pressure applicable to the study area were established, respectively. Then, the elastic parameters were obtained through pre-stack inversion, and the three-pressure bodies were calculated based on the elastic parameter bodies. The results indicate that: (1) The three-pressure prediction method of the jointing well-seismic data in this paper can predict the formation's longitudinal and transverse pressure anomaly zones in advance. (2) The Maokou Formation in the study area is characterized by abnormally high pressure, to balance the pressure of the high-ground formation, high-density drilling fluid is necessary. (3) The prediction results of three-pressure in this paper are highly consistent with the actual drilling engineering events, which verifies the reliability of the three-pressure prediction results presented in this study. The results of the study can provide a basis for decision-making in drilling geological design, such as the determination of drilling fluid density, the evaluation of borehole stability and other engineering problems that require support from three-pressure data.

Investigation of an Indian Site with Mafic Rock for Carbon Sequestration.

The increasing extent of greenhouse gas emissions has necessitated the development of techniques for atmospheric carbon dioxide removal and storage. Various techniques are being explored for carbon storage including geological sequestration. The geological sequestration has various avenues such as depleted oil and gas reservoirs, coal-bed methane reservoirs, and mafic and ultramafic rocks. Different trapping mechanisms are in play in these subsurface storage systems. In these sequestration sites, the mafic and ultramafic rocks are best suited for long-term and effective sequestration as they comprise minerals, conducive for chemical alteration, forming stable carbonates. However, these sites often suffer from distinct disadvantages of injectivity issues due to their low permeability and porosity. This study investigates the potential of sequestration in the rock samples obtained from one such site located in India. The rock samples are first characterized using various techniques including X-ray fluorescence, X-ray diffraction, Raman spectroscopy, and field emission scanning electron microscopy (FESEM). The mineralogical characterization shows that the rock sample contains approximately 10% of diopside. The samples were put in the reactor chamber comprising CO2, which were then investigated using FESEM analysis. Additionally, a reservoir block simulation using commercial software was conducted with the representative minerals in the sample to evaluate the CO2 sequestration potential. The simulation result suggests the formation of magnesite which corresponds to a major part of CO2 mineral trapping. The reduced injectivity due to low porosity and permeability in this rock can be addressed using hydraulic fracturing. The geomechanical behavior of the rock sample for hydraulic fracturing is studied using the Brazilian disc test. The Monte Carlo-based uncertainty analysis was conducted using the tensile strength data of the sample. Results suggest that the most likely fracturing pressure is 2100 psi for this rock sample.

Optimization of fracturing technology for unconventional dense oil reservoirs based on rock brittleness index

The concept of volume fracturing has revolutionized the conventional limits of low permeability, expanded the effective resource space, and significantly enhanced oil well production in tight oil reservoir development. This paper elucidates the mechanism of volume fracturing technology for tight sandstone reservoirs by considering multiple factors such as the initiation range of multi-fractures, influence of far-well horizontal principal stress on fracture initiation and propagation, degree of natural fractures development, and mechanical parameters of reservoir rock. Through simulation based on the mechanical parameters of reservoir rock, a comparative analysis was conducted between the model-calculated rock fracture pressure value and measured data from fracturing construction wells in the study area. The results revealed that there was a discrepancy within 10% between the model calculations and actual data. By simulating the effects of different injection volumes of fracturing fluid, pumping rates, and perforation methods on the fracture geometry, optimal design parameters for volume fracturing technology were obtained. Additionally, we propose optimization ideas and suggestions for construction parameters applicable to field operations. The simulation results indicate that a minimum recommended fluid volume scale exceeding 1800 m3 is advised for the reservoir. Based on frictional calculations, it is recommended to have an on-site construction rate not less than 18.0 m3/min along with 36–48 holes/section for perforation purposes. The numerical simulation research presented in this paper provides a theoretical reference basis and practical guidance for the application of fracturing network technology in tight sandstone reservoirs.

Optimizing the wellbore trajectory of directional wells considering wellbore stability Subjected to the non-independence and uncertainty of geomechanical parameters

Effectively analyzing the wellbore stability risk in directional wells is important in exploring oil and gas resources in complex deep formations. An evaluation model of wellbore stability prefers to determine the wellbore instability pressures related to collapse pressure and fracture pressure that controls the optimized wellbore trajectory and is strongly related to the characteristics of geomechanical parameters, including the mechanical and strength parameters, in-situ stresses, and pore pressure, However, the measured errors and inherent fuzziness during the obtaining of geomechanical parameters introduce the uncertainty characteristics and further produce a probability distribution within a certain range of the wellbore instability pressures. Besides, the determination of horizontal in-situ stresses and the strength parameters also are correlated with the mechanical parameters including elastic modulus and Poisson's ratio. Therefore, an effective means of risk assessment of wellbore instability resorts to introducing uncertainty quantification, depending on the appropriate distribution function, and correlations of geomechanical parameters into the evaluation model of wellbore stability. This work proposes a risk analysis method for wellbore instability considering the uncertainty and correlation of geomechanical parameters. Firstly, the uncertainty characteristics and parameter correlations are quantified by Kolmogorov-Smirnov (K–S) test and Pearson linear coefficient through data sampling of geomechanical parameters. Then, the Monte Carlo method and the Nataf transform are combined to make the randomly generated samples restore the uncertainty and correlation characteristics of the parameters themselves. Finally, the sample is brought into the optimal model to realize the risk analysis of wellbore instability and parameter sensitivity evaluation of the target formation under parameter uncertainty and non-independent conditions. The main research shows that the uncertainty of the prediction results of collapse pressure and fracture pressure is significantly reduced by using the newly proposed method to analyze the risk of wellbore instability. In addition, the results of wellbore trajectory optimization indicate that the uncertainty of in-situ stress makes it possible for the formation rock to experience a changing type of stress state, for example, normal stress faulting changing to the strike-slip one, which significantly affects the evaluation of wellbore stability and the selection of wellbore trajectory optimization. The uncertainty range of collapse pressure prediction is greater than that of fracture pressure regardless of whether the parameters are independent or not. However, the overall value of the fracture pressure compared to the collapse pressure is significantly affected by the wellbore trajectory. Meanwhile, considering the direct effect of a single factor, the in-situ stress has a great influence on the risk analysis of wellbore instability, especially the minimum horizontal in-situ stress has the most obvious influence on the fracture pressure. The influence of geomechanical parameters such as elastic modulus, Poisson's ratio, cohesion, internal friction angle, and tensile strength on wellbore instability is relatively weak. However, the aforementioned variation ignores the correlation characteristics of the parameters themselves. With the correlation characteristics considered, weak parameters such as elastic modulus, Poisson's ratio, and pore pressure have a strong correlation with in-situ stress, and thus exert the indirect effect on wellbore instability.

Micro-fracture propagation and numerical simulation of fracture propagation under thermal simulation experiment of organic-rich shale: Chang-7 source rock in Yanchang, Ordos Basin

Organic-rich shale as a high-quality source rock which is usually deposited in a high-temperature and high-pressure environment, and its internal organic matter will gradually transform into hydrocarbon and be discharged from shale. However, shale has polar porosity and permeability, making it difficult for hydrocarbon to be discharged from the shale through the pore throat. The latest research suggests that due to the strong hydrocarbon generation potential of shale rich in organic matter, the pressure generated by hydrocarbon can cause micro-fracture in the shale, leading to the expulsion of hydrocarbon from the micro-fracture. Therefore, this article uses hydrocarbon generation simulation experiments and Comsol Multiphysics to analyze the mechanical characteristics and damage propagation of micro-fracture during shale hydrocarbon generation process. The results show that with the increase of temperature and fluid pressure, micro-fracture of different lengths have different initial fracture pressures, and during the diffusion of micro-fracture, the stress inside the shale matrix and micro-fracture exhibits different diffusion characteristics.