Wellbore Stability Model Research Articles

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.

Wellbore stability model in shale formation under the synergistic effect of stress unloading-hydration

According to the transversely isotropic theory and weak plane criterion, and considering the mechanical damages due to stress unloading and hydration during drilling, a shale wellbore stability model with the influence of stress unloading and hydration was established using triaxial test and shear test. Then, factors influencing the wellbore stability in shale were analyzed. The results indicate that stress unloading occurs during drilling in shale. The larger the confining pressure and axial stress, the more remarkable weakening of shale strength caused by stress unloading . The stress unloading range is positively correlated with the weakening degree of shale strength. Shale with a higher development degree of bedding is more prone to damage along bedding. In this case, during stress unloading, the synergistic effect of weak structural plane and stress unloading happens, leading to a higher weakening degree of shale strength and poorer mechanical stability, which brings a higher risk of wellbore instability. Fluid tends to invade shale through bedding, promoting the shale hydration. Hydration also can weaken shale mechanical stability, causing the decline of wellbore stability. Influence of stress unloading on collapse pressure of shale mainly occurs at the early stage of drilling, while the influence of hydration on wellbore stability mainly happens at the late stage of drilling. Bedding, stress unloading and hydration jointly affect the wellbore stability in shale. The presented shale wellbore stability model with the influence of stress unloading and hydration considers the influences of the three factors. Field application demonstrates that the prediction results of the model agree with the actual drilling results, verifying the reliability of the model.

Study on the Evolution Law of Wellbore Stability Interface during Drilling of Offshore Gas Hydrate Reservoirs

The study of wellbore stability in offshore gas hydrate reservoirs is an important basis for the large-scale exploitation of natural gas hydrate resources. The wellbore stability analysis model in this study considers the evolution of the reservoir mechanical strength, wellbore temperature, and pressure parameters along the depth and uses plastic strain as a new criterion for wellbore instability. The wellbore stability model couples the hydrate phase transition near the wellbore area under the effect of the wellbore temperature and pressure field and the ‘heat–fluid–solid’ multifield evolution characteristics, and then simulates the stability evolution law of the wellbore area during the drilling process in the shallow seabed. The research results show that, owing to the low temperature of the seawater section and shallow formation, the temperature of the drilling fluid in the shallow layer of the wellbore can be maintained below the formation temperature, which effectively inhibits the decomposition of hydrates in the wellbore area. When the wellbore temperature increases or pressure decreases, the hydrate decomposition rate near the wellbore accelerates, and the unstable area of the wellbore will further expand. The research results can provide a reference for the design of drilling parameters for hydrate reservoirs.

Multi-objective trajectory planning in the multiple strata drilling process:A bi-directional constrained co-evolutionary optimizer with Pareto front learning

Trajectory planning is essential to ensure the safety and efficiency of the drilling process within varying downhole geological conditions. However, numerous constraints and dispersed objectives make this task challenging, resulting in a broken constrained Pareto front (PF) in the objective space. To address this issue, we present a novel multi-objective optimization algorithm (MOEA), the Bi-directional Constrained Co-evolutionary Optimizer (BCCO), for reducing the friction torque of the drilling string system and maintaining the wellbore stability of the directional drilling process in multiple changeable strata. Inspired by dual-population co-evolutionary mechanics, BCCO is thoughtfully developed to enhance complex constraints handling. An ESOINN is introduced to guide the population in exploring the irregular PF and adaptively approximating to it. In addition, a flexible constraint dominance principle is devised to filter out non-inferior infeasible solutions that fully balance feasibility, diversity, and convergence by combining constraint violation, minimum vector angle, and angle-penalized distance. Moreover, we adopt a minimum Manhattan distance (MMD) decision-making method to select the final reference solution for trajectory tracking control. To verify the effectiveness of BCCO, we compared it with seven state-of-the-art constrained MOEAs, four latest published MOEAs used in drilling trajectory planning (DTP) applications, and three ablation MOEAs revised from original BCCO on real-world constrained test instances and four different types of designed standard benchmarks. Extensive testing confirmed adaptability to diverse constrained PFs. BCCO displayed strong convergence and diversity when applied to real-world engineering problems while maintaining feasibility. To evaluate BCCO’s DTP performance, we built a wellbore stability model on actual geological formations and empirically tested it with both composite natural curves and third-order Bézier curves in various drilling trajectory scenarios. We established a comprehensive cloud-based DTP test system with the on-site Programmable Logic Controller (PLC) and the workstation via Data Transfer Unit (DTU) communication. Actual DTP cases confirmed the feasibility of BCCO’s Pareto solutions, with MMD-selected trajectories ensuring a harmonized drilling process.

Finite element modeling of wellbore stability in a fractured formation for the geothermal development in northern Quebec, Canada

Previous studies showed that deep geothermal energy can be a promising solution to support Canada's energy transition, which is particularly valuable for remote northern communities. Geological formations containing natural fractures in fault zones of the Canadian Shield prove advantageous for geothermal development from the perspective of permeability enhancement. However, it is crucial to ensure wellbore stabilities throughout the drilling and energy production processes. In remote communities, there is a lack of research investigating the overall performance of boreholes embedded in fractured formations under non-isothermal conditions. Both the sliding along fracture surfaces and yielding of rock matrix can contribute to a borehole failure, but there is limited research covering both in a borehole stability analysis with the consideration of thermal disturbance. In this study, a thermo-hydro-mechanical coupled finite element modeling is conducted to carry out poromechanical analysis of boreholes in fractured rock formations of a potential deep geothermal engineering site in northern Canada. Both plastic yielding in the rock matrix and sliding potential along specific fractures are quantified with the consideration of non-isothermal impacts. The simulation results indicate that the cooling effect should be given attention when drilling through rock formations containing natural fractures as excess pore pressure can be built up due to the enhanced flows through fractures. Even though the fractures are not intersecting with the borehole wall surface, sliding tends to be triggered along tilted fractures. In addition, it is also concluded that more plastic zones tend to be generated due to the cooling effect of drilling fluid. Findings from the present research are also closely relevant to deep geoenergy engineering projects in other studying areas with fractured geological formations.

Rock Mechanical Properties and Wellbore Stability of Fractured Dolomite Formations.

During the drilling process in the dolomite formation of the Leikoupo formation in western Sichuan, downhole obstruction frequently occurs, which seriously hinders the efficient development of oil and gas resources on site. In view of the problems of borehole stability existing in this type of formation, the geological characteristics, underground complexity, and fracture development of the research block were systematically identified and analyzed, and the physical parameters and mechanical properties of the rock were defined through physical and chemical tests and an understanding of the mechanical properties of the rock. These studies revealed the mechanism of borehole instability and the main factors influencing fractured dolomite formation. Finally, a model of borehole collapse pressure within fractured dolomite formation was established by selecting the appropriate strength criterion as the criterion of borehole instability. The results show that the dolomite fractures of the Leikoupo formation are relatively developed, the formation is dominated by low-angle fractures, and the core integrity is not high. The development of formation fractures has an obvious effect on the mechanical strength of rock, which decreases to different degrees with the decrease in the integrity coefficient of the rock mass, and the anisotropy of the rock's mechanical strength is obvious. The empirical parameters of the generalized Hoek-Brown (H-B) strength criterion were quantified by introducing rock mass acoustic data, and the accuracy of the improved generalized H-B strength criterion was evaluated using triaxial test data. Taking the M-C criterion, the generalized H-B criterion based on acoustic wave, the D-P criterion, and the weak surface strength criterion as wellbore instability criteria, combined with the distribution of wellbore stress, a prediction model of wellbore stability considering the degree of dolomite formation fragmentation was established. The results demonstrate that the generalized H-B criterion model based on acoustic waves can be used to evaluate the wellbore stability of dolomite fracture formation with more than one group of fractures. These research results have certain guiding significance for efficient and safe drilling in fractured dolomite formations.

The wellbore instability mechanism in hot dry rock drilling

Wellbore instability is one of the key factors limiting safe and efficient drilling in hot dry rock. A detailed understanding of the instability mechanism of hot dry rock wellbore is essential to achieve high efficiency in geothermal exploitation. Therefore, in this study, we established a numerical simulation model of wellbore stability that considers the heterogeneous properties of granite rock, and the coefficient of stability index for the wellbore of hot dry rock is proposed. The influence of heterogeneous characteristics of granite, in-situ stress, mud pressure, and temperature on the wellbore instability are analyzed. The results show that the granite heterogeneity leads to a significant disturbance of the near-wellbore stress. The degree of wellbore instability is more severe than that of the homogeneous rock formations. Radial tensile damage tends to occur at low mud pressures. High mud pressure and temperature difference between drilling mud and formation easily lead to tangential tensile failure. Shear damage occurs on the radial/tangential stress horizontal plane without temperature differences. However, a temperature difference dramatically increases the axial stress (the first principal stress), changing the direction of shear damage, which occurs mostly in the vertical plane or the wellbore's curved surface. Deeper wellbores are more severely unstable than shallow wellbores, and mud pressure can inhibit wellbore instability to a certain extent. However, increasing excess mud pressure can lead to tangential tensile failure. The temperature difference exacerbates the wellbore instability; especially after exceeding 260 °C, the wellbore shear thermal rupture is drastic. The study results are of great significance for the in-depth understanding of the mechanism of wellbore instability in deep hot dry rocks and for guiding the safe and efficient drilling of hot dry rocks.

Poroelastic response of inclined wellbore geometry in anisotropic dual-medium/media

Shale gas formations are typically characterized by anisotropic and fracture properties. Existing shale wellbore stability models have only considered the anisotropy of shale rocks and have ignored the effect of fractures. However, the mechanism of wellbore instability under the combined effects of shale anisotropy and dual-media (DM) remains unknown. Therefore, based on anisotropic poroelasticity, the DM theory, and the assumption of generalized plane strain, this study established a pseudo-3D hydraulic-mechanical coupling finite element model considering the DM and anisotropy of shale in wellbores. The effects of elastic anisotropy, fracture volume fraction, fracture permeability, mass transfer coefficient, and fluid pressure on wellbore stress were analyzed parametrically. The results showed that an anisotropic single-medium predicts that the wellbore will fail when the formation is drilled, whereas an anisotropic DM predicts periodic wellbore instability. The poroelastic effect of the matrix pore pressure is much greater than that of the fracture pore pressure. The matrix elastic anisotropy parameters control the distribution of mechanical parameters throughout the DM, further affecting the poroelastic response of the entire DM. When the drilling direction was mostly parallel to the bedding plane, the anisotropy of the matrix and fracture system of the elastic parameters were larger, and the wellbore was more stable. A larger fracture permeability leads to a larger fracture volume fraction and mass transfer coefficient, the matrix pore pressure and fracture pore pressure increase, and the instability of the wellbore also increases.

Analysis of Wellbore Stability considering the Interaction between Fluid and Shale

Reservoir shale has the characteristics of bedding planes, strong anisotropy, and strong imbibition ability under ultralow water saturation, which has an important impact on wellbore stability of horizontal wells. Therefore, the physical and chemical properties of reservoir shale were analyzed, and a mechanics model of wellbore stability was established considering the elasticity and strength anisotropy. The wellbore stability was analyzed considering the anisotropy parameters of formation elasticity and strength and imbibition conditions. The results show that the anisotropy of elasticity and strength under the condition of imbibition are important parameters for evaluating the stability of reservoir shale borehole. Considering the interaction between fluid and reservoir shale, the weakening of the strength of the bedding structure is the reason for wellbore instability of reservoir shale. Bedding planes and microfractures provide rapid imbibition channel, and the imbibition volume increases, which further causes fracture expansion and strength weakening, and then leads to wellbore instability. Multistage effective plugging of bedding, microcracks and macroholes during drilling is the key to maintain the stability of shale wellbore.

Critical Conditions for Wellbore Failure during CO2-ECBM Considering Sorption Stress

Significant stress changes caused by sorption-induced swelling raise the coal wellbore failure potential, which directly impacts the safety and sustainability of CO2 enhanced coalbed methane (CO2-ECBM). Additionally, a mixture gas (CO2/N2) injection is recommended due to the sharp decline of permeability with pure CO2 injection. In this study, incorporating the impacts of mixture gas adsorption and poroelastic effects, a semi-analytical model of coal wellbore stability during mixture gas injection is proposed. Model results indicate that the stress field is significantly influenced by the boundary condition and sorption effect. In addition, parametric studies are performed to determine the influence of adsorption parameters, mechanical properties, and gas composition on the stress distribution and then on the wellbore failure index. Furthermore, mixture gas injection with a large proportion of CO2 or N2 both cause wellbore instability. Significant compressive hoop stress and shear failure are caused by the mixture gas injection with a large proportion of CO2. In contrast, the displacement of CH4 with weakly adsorptive N2 will result in less compressive and even tensile hoop stress, so shear or tensile failure may occur. Thus, mixture gas (including pure CO2/N2) injection must be controlled by coal wellbore failure, providing an accurate estimation of in-situ coal seams’ CO2 storage capacity from the perspective of wellbore stability.

Well trajectory optimization of ultradeep and high-pressure drilling engineering based on high in situ stress as the main control factor: A case study from the Ordovician carbonate reservoir in the Shunbei area of the Tarim Basin

With increasing oil and gas exploration and development, well trajectory optimization has gradually become the focus of the oil and gas industry. Considering the wellbore instability in the Shunbei area of the Tarim Basin, the well trajectory was scientifically optimized under the guidance of rock mechanics, drilling engineering, and mathematical methods, combined with actual geologic data, and with in situ stress as the main controlling factor. In this paper, the stress state of the wellbore is analyzed by linear elastic theory to establish the stress distribution model of the wellbore. The safety window model of wellbore stability is established using different rock failure criteria to calculate the collapse pressure and fracture pressure of the formation. Based on this, the safe mud density window is defined to achieve wellbore trajectory optimization. Finally, the influence factors of wellbore stability are discussed, and the applicability of different rock failure criteria is evaluated. The results indicate that under the normal faulting stress regime condition in the study area, the direction of horizontal minimum principal stress is the best drilling direction, where the borehole inclination angle of [Formula: see text] > 50° is the optimal well trajectory. The wellbore stabilities of high-angle deviated wells and horizontal wells are better than those of low-angle deviated wells and vertical wells. The calculation results of the Mogi-Coulomb criterion can describe the conditions of the in situ stress field more accurately. The safe windows for different well trajectories are obtained directly by the numerical method, which is very practical for optimizing well trajectories and improving wellbore stability.

Geomechanical study and wellbore stability model for the Foz de Amazonas basin

Geomechanical study and wellbore stability model for the Foz de Amazonas basin

Influence of drill-string lateral collision on wellbore stability of a horizontal well

A finite element model of wellbore stability was proposed for a horizontal well, and drill-string friction and lateral collision in the process of rotary motion were taken into account. An unconfined compression test was used for model validation, the normalized yielded zone area (NYZA) was employed to analyze wellbore stability, and the influence of a lateral collision on wellbore stability was simulated. The results indicated that the stress-strain curve of numerical simulation consists with unconfined compression test, and the maximum relative error is <2.2%. The evolution of NYZA can be divided into three typical stages: stage I (static balance), stage II (dynamic growth), and stage III (dynamic balance). Both normal and shear stresses reach to the peak value in stage II, while they always fluctuate in a relatively small range in stage III, so that the wellbore stability mainly affected by the first collision of drill-string. Both lateral acceleration and friction effects have significant impact on wellbore stability. The initial collision position and the size of drilling tool have a certain influence on wellbore stability, while the revolving speed of drill-string almost has no impact. The present paper has guiding significance for wellbore collapse prevention and drilling parameter optimization.

Study on the mechanism of anisotropic wellbore instability in continental shale in Songliao Basin

Wellbore instability is frequently encountered in the process of shale oil drilling. Due to the anisotropic strength characteristics of shale, most conventional models are not suitable for wellbore stability analysis in layered formation. In this paper, taking the continental shale in the north of Songliao Basin as the research object, the anisotropic elasticity and strength parameters of shale are measured experimentally. Based on pore elastic mechanics, an anisotropic wellbore stability model of layered shale is established, and the variation of collapse pressure under different formation conditions is analyzed. The results show that considering the elastic and strength anisotropy, the collapse pressure is the largest, and the influence of strength anisotropy is significantly greater than that of elastic anisotropy. The stability of horizontal wells drilled along the horizontal maximum principal stress is the optimal, followed by vertical wells and small angle directional wells. The actual drilling conditions of G101 well are basically consistent with the prediction results, which confirms the accuracy of the model. According to the traditional wellbore stability model, the equivalent density of collapse pressure in horizontal well section is 1.58 ~ 1.76 g/cm3. It is much lower than the collapse density of 1.86 g/cm3 calculated by the anisotropic model in this study. The findings of this study can help for better understanding of the mechanism of wellbore instability in horizontal wells in shale formations. The model can be used to guide the drilling engineering design of shale oil horizontal wells and reduce the losses caused by the instability of the wellbore.

A Quantitative Evaluation Method of Anti-Sloughing Drilling Fluid Inhibition for Deep Mudstone

Wellbore instability resulting from deep mudstone hydration severely restricts the development of oil and gas resources from deep reservoir in western China. Accurate evaluation of drilling fluid inhibition properties plays an important role in selecting drilling fluid that can control deep mudstone hydration and then sustain wellbore stability. The previous evaluations are conducted by qualitative analysis and cannot consider the influence of complex hydration conditions of deep mudstone (high temperature, high pressure and flushing action). The study proposes a quantitative method to evaluate drilling fluid’s inhibition property for deep mudstone under natural drilling conditions. In this method, the cohesive strength of mudstone after hydration is adopted as the inhibition index of the tested drilling fluid. An experimental platform containing a newly designed HPHT (High pressure and high temperature) hydration experiment apparatus and mechanics characterization of mudstone after hydration based on scratch test is proposed to obtain the current inhibition index of tested drilling fluid under deep well drilling environments. Based on the mechanical–chemical wellbore stability model considering strength weakening characteristics of deep mudstone after hydration, a cross-correlation between drilling fluid density (collapse pressure) and required inhibition index (cohesive strength) for deep mudstone is provided as the quantitative evaluation criterion. Once the density of tested mud is known, one can confirm whether the inhibition property of tested mud is sufficient. In this study, the JDK mudstone of a K block in western China is selected as the application object of the proposed evaluation method. Firstly, the evaluation chart, which can demonstrate the required inhibition indexes of the tested fluids quantitatively with various densities for JDK mudstone, is constructed. Furthermore, the experimental evaluations of inhibition indexes of drilling fluids taken from two wells in K block are conducted under ambient and deep-well drilling conditions, respectively. In order to show the validity and advantage of the proposed method, a comparison between the laboratory evaluation results and field data is made. Results show that the laboratory evaluation results under deep-well drilling conditions are consistent with the field data. However, the evaluation under ambient conditions overestimates the inhibition property of the tested fluid and brings a risk of wellbore instability. The developed quantitative method can be a new way to evaluate and optimize the inhibition property of drilling fluid for deep mudstone.

Analysis of wellbore stability of gas underbalanced drilling technology

Gas underbalanced drilling technology has the advantages of high ROP and little damage to oil and gas reservoirs. In recent years, it has been widely used in the exploration and development of oil and gas fields in China. Under normal air drilling conditions, the pore pressure is basically zero, so it is necessary to establish the wellbore stability model under the condition of zero pore pressure to provide theoretical support for the wellbore stability analysis of air drilling. However, gas underbalanced drilling also has wellbore instability, more sand deposition at the bottom of the well, and even the malignant accident of sticking. Firstly, through the analysis of the traditional wellbore stability model, the influence of pore pressure is removed, and the wellbore stability model suitable for air drilling is obtained. At the same time, it is proposed that the sand deposition is mainly caused by the collapse material when the collapse ellipse is formed on the shaft wall, and the formation of the collapse ellipse is conducive to maintaining the stability of the shaft wall. For large and medium-sized gravel layers, the influence of cementation strength on wellbore stability should be considered.

A simple analytical model of wellbore stability considering methane hydrate saturation-dependent elastoplastic mechanical properties

Methane hydrates (MHs) have received widespread attention as a new clean energy resource. However, because of the sharp reduction/change in the mechanical/physical properties of methane hydrate bearing sediments (MHBS) after hydrate dissociation, as well as the strong multi-field coupling, wellbore instability is more likely to occur during drilling in MHBS under the seafloor. To fast predict the wellbore stability in MHBS, an elastoplastic analytical model is proposed in this study that fully considers the saturation-dependent mechanical properties and water/heat production/absorption due to hydrate dissociation. Axisymmetric problems at the horizontal cross-sections of the vertical wellbore are concerned. Based on an analytical model of pore pressure, temperature and salt concentration for drilling in MHBS that considers both conduction/diffusion and convection effects, the produced/absorbed water/heat at the dissociation front related to the MH dissociation rate are additional considered in the compatibility conditions in the modified models. Compared with the results of previous study, the improved solutions show a much lower temperature and slightly higher pressure around the dissociation front. Furthermore, the saturation-dependent mechanical properties of MHBS are simulated by an elastic-brittle-plastic constitutive model with unified strength criterion, where Young's modulus and cohesion are functions of hydrate saturation. The analytical solutions for the stresses, displacement and plastic radius are finally addressed under various locations of the plastic zone and principal stress orders. The analytical models are verified by their good agreement with the results from the FEM model under the same assumptions, and they are consistent with the results from complex numerical models. Through numerous calculations, the influences of the drilling fluid properties and initial conditions on the plastic radius and displacement at the wellbore wall are investigated in detail, and the analytical formula for the safest drilling fluid pressure is presented as a function of the initial pore pressure and in situ stress.

Simulation-based three-dimensional model of wellbore stability in fractured formation using discrete element method based on formation microscanner image: A case study of Tarim Basin, China

Wellbore instability in fractured formation is a major challenge in drilling engineering, especially in the oil and gas energy sector. This study aims to analyze wellbore stability in fractured formation using discrete element method. A novel fractures modeling method by using formation microscanner images (FMI) and image processing was proposed. Three wellbore models with different fracture structures, and a no fracture model are developed to simulate the wellbore drilled in X well, Tarim Basin, China. Different drilling fluid densities are applied to the four models. Failures and deformation of wellbore models are investigated. Large amounts of displacement and yielded zones around the wellbore were observed in the high and low dip intersecting fractures models. And fluid density has few effects on the wellbore stability. High dip fracture is considered a major factor in wellbore instability. The high drilling fluid density performed better in the low dip fracture model, and the low drilling fluid density performed better in the vertical fracture model and intact model. The proposed modeling method and findings have important implications for understanding the wellbore instability in fractured formation.

Wellbore stability mechanism of igneous rock in Shunbei block

Shunbei area is located in the belt structural of the northern margin of the shuntuogole low uplift. The proven oil reserves of the adjacent blocks are 142.93 million tons, which has the potential of exploration and development. In the igneous strata of Shunbei block, there are many complicated conditions, such as wellbore collapse, stucking pipe and so on, which seriously restrict the exploration and development speed and benefit of the block. In order to solve this problem, firstly, the composition, microstructure, mechanical properties and other parameters of igneous rock intrusion in Shunbei block are determined through laboratory experiments. The experimental results show that the igneous rock intrusion in Shunbei block does not contain expansive clay minerals, has weak hydration ability, and has developed micro fractures. Thirdly, the wellbore stability model considering fractures is established, and the influencing factors of wellbore instability are analyzed by combining the mechanical properties of igneous rocks, porosity and permeability characteristics, and in-situ stress state. The results show that the micro fractures and weak surfaces have a controlling effect on wellbore stability. The longer the immersion time is, the deeper the drilling fluid invasion depth is, and the higher the wellbore collapse pressure is. Finally, according to the microstructure and physicochemical properties of igneous intrusions, the main points of drilling fluid technology are determined, that is, the anti sloughing drilling fluid technology is mainly strong plugging. In this paper, through the analysis of the rock characteristics of igneous rocks and the main controlling factors of wellbore instability mechanism in Shunbei block by using the method of mechano-chemical synthesis, the clear main controlling factors of wellbore stability are of positive significance for ensuring the safe well construction, shortening the drilling cycle, reducing the drilling cost and improving the development efficiency in Shunbei block.

The impact of geomechanical units (GMUs) classification on reducing the uncertainty of wellbore stability analysis and safe mud window design

The current study proposed an improved approach for application of Geomechanical Units (GMUs) classification in reducing the uncertainty of wellbore stability models. For this purpose, the optimal drilling direction and safe mud window were modeled in the Iranian Offshore oilfield, Persian Gulf basin. Two main normal faults created a graben with three geomechanical sectors in the study area including northern, middle and southern sectors. The middle sector, which is under high compression, is the main target of this study. A set of well logs and Fullbore Formation Micro Imager (FMI) data associated with the rock mechanical tests including Uniaxial Compressive Strength (UCS), Triaxial Compressive Strength (TCS) and ultrasonic results were used to establish and tune the geomechanical models. The dynamic rock elastic moduli including UCS, Poisson's ratio, Young's modulus, shear modulus and bulk modulus were estimated from well logs data. Through appropriate correlations between well logs and laboratory results, the dynamic modules were converted to static data. Five geomechanical units were obtained based on the classification of rock elastic moduli by using multi-resolution graph-based clustering.The interpretation of FMI logs and their incorporation in the geomechanical models showed that most safe drilling direction is in the 120° azimuth which is parallel to the direction of minimum horizontal stress, σh (NW-SE direction). Higher mud weight is expected at N030E azimuth to overcome collapse pressure, which is the worst drilling direction, σH (NE-SW direction). Wellbore inclination more than 60° angle is not recommended for formations comprising of GMU E and partially GMU D (mainly shales and clayey limestones). The results of this study showed that GMUs classification is an effective way of updating the wellbore stability models and reducing the uncertainty of safe mud window design.