Wellbore Stability Analysis Research Articles

Wellbore stability analysis using shear wave correlation

Wellbore stability analysis using shear wave correlation

Mechanical properties of basalt, tuff and breccia in the Permian system of Sichuan Basin after water absorption–implications for wellbore stability analysis

Mechanical properties of basalt, tuff and breccia in the Permian system of Sichuan Basin after water absorption–implications for wellbore stability analysis

The thermoporoelastic coupling analysis of wellbore stability in shale formation under supercritical CO2 drilling conditions

Supercritical carbon dioxide (ScCO2) drilling can effectively protect shale formation from hydration damage and improve drilling rate comparing to conventional drilling technology. The wellbore stability of shale formation is one considerable issue under ScCO2 drilling conditions. In this study, the numerical simulations are performed to calculate collapse cycling time of shale formation under ScCO2 drilling conditions based on thermoporoelastic coupling model. The results show that comparing to water seepage condition, the variation of formation temperature is larger, pore pressure and stress are lower for ScCO2 seepage condition without adsorption effect, the comparison between water and ScCO2 seepage conditions verifies the thermoporoelastic coupling model. For ScCO2 drilling conditions, if adsorption‒induced strain is ignored, the risk of wellbore collapse will be slightly underestimated comparing to the results with adsorption effect. When adsorption‒enhanced elastic modulus is ignored, the risk of wellbore collapse will be significantly underestimated comparing to the results with adsorption effect. The wellbore collapse may occur with the increasing well depth for ScCO2 drilling conditions. This study can provide the theoretical guidance for exploiting shale reservoirs using ScCO2.

Drilling in Complex Pore Pressure Regimes: Analysis of Wellbore Stability Applying the Depth of Failure Approach

Most old oil and gas fields worldwide are depleted, making drilling in these sedimentary zones extremely difficult, especially in complex pore pressure regimes when they are accompanied by over-pressure zones. Considering that typical wellbore stability studies provide a conservative mud density curve to prevent wellbore failure, dynamic geomechanical approaches are required to provide more flexible and manageable drilling in such complex cases in order to address anticipated drilling obstacles. This study aims to apply the more dynamic concept, known as “depth of damage” (DOD), in the El Morgan oil field, Gulf of Suez Basin, to deliver a more optional mud density window that helps in the safe drilling of different pore pressure regimes within the area, as well as the implications of applying this drilling strategy in the studied basin. In this paper, well logging and downhole measurements were used to develop a 1D geomechanical earth model and infer the in situ stresses in the studied boreholes, and the modified Lade failure criterion was used to conduct the wellbore stability analysis. The study revealed that the El Morgan sedimentary succession has a complex and varied pore pressure regime. Applying the DOD approach introduces multiple mud density scenarios that can lead to successful drilling and avoid unexpected incidents while drilling. The key benefit of the DOD approach is that it widens the safe mud density window to be less than the shear failure with an acceptable amount of failure. This study provides insights into unconventional techniques such as underbalanced drilling techniques that can be used under manageable conditions in mature basins. Furthermore, the DOD approach is compared to the conventional wellbore stability analysis or breakout depth approach, and the main differences, merits, and demerits of each were discussed in this study.

3D Geomechanical Model Construction for Wellbore Stability Analysis in Algerian Southeastern Petroleum Field

The main objective of this research work was the wellbore stability evaluation of oil and gas wells based on a 3D geomechanical model, which as constructed using seismic inversion in a southeastern Algerian petroleum field. The seismic inversion model was obtained by using an iterative method and Aki and Richards approximation. Since the correlation between the inversion model and the log data was high at the wells, the reservoir was efficiently characterized and its lithology carefully discriminated in order to build a reliable 3D geomechanical model. The latter was further used to suggest the drilling mud weight window for the ongoing wells (well 5) and to examine the stability of four previously drilled wells. The main contribution of this study is providing a 3D geomechanical model that allows the optimization of drilling mud weight parameters so that a wellbore’s stability is guaranteed, on the one hand, and, on the other hand, so that the reservoir damage brought about by excessive surfactant use can be prevented. Indeed, the mud parameters are not just important for the drilling process’s effectiveness but also for logging operations. Since the tools have limited investigation diameters, with excessive use of surfactant, the invaded zone can become larger than the tools’ investigation diameter, which makes their logs unreliable. Hence, the 3D geomechanical model presented here is highly recommendable for the proposition of new wells, entailing less exploration uncertainty and more controllable productivity.

Stress solutions for short- and long-term wellbore stability analysis

Numerous models have been proposed to address the time-delayed wellbore collapses or untimely mud losses that have been widely reported in the field. There is still reluctance in applying them in real-time field operations due to their complex mathematical appearance. In this technical note, we address the effective stress solutions for short- and long-term wellbore stability analysis. We present the poroelastic, porothermoelastic, and porochemoelastic wellbore effective stress solutions at t→0+ and t→∞. The concise expressions of these solutions are simple to implement into computational codes for the ease of engineering field data interpretation. We also improve a generic algorithm for calculating mud weight windows. Application of the asymptotic solutions and the algorithm in an example with a random set of data indicates that the long-term collapse and fracturing mud weights can be 32.5% higher and 25.6% lower than the short-term ones, respectively. Conventional time-independent elastic models cannot capture these behaviors.

Evaluation on the anisotropic brittleness index of shale rock using geophysical logging

The brittleness index plays a significant role in the hydraulic fracturing design and wellbore stability analysis of shale reservoirs. Various brittleness indices have been proposed to characterize the brittleness of shale rocks, but almost all of them ignored the anisotropy of the brittleness index. Therefore, uniaxial compression testing integrated with geophysical logging was used to provide insights into the anisotropy of the brittleness index for Longmaxi shale, the presented method was utilized to assess brittleness index of Longmaxi shale formation for the interval of 3155–3175 m in CW-1 well. The results indicated that the brittleness index of Longmaxi shale showed a distinct anisotropy, and it achieved the minimum value at β = 45°-60°. As the bedding angle increased, the observed brittleness index (BI2_β) decreased firstly and increased then, it achieved the lowest value at β = 40°–60°, and it is consistent with the uniaxial compression testing results. Compared to the isotropic brittleness index (β = 0°), the deviation of the anisotropic brittleness index ranged from 10% to 66.7%, in other words, the anisotropy of brittleness index cannot be ignored for Longmaxi shale. Organic matter content is one of the main intrinsic causes of shale anisotropy, and the anisotropy degree of the brittleness index generally increases with the increase in organic matter content. The present work is valuable for the assessment of anisotropic brittleness for hydraulic fracturing design and wellbore stability analysis.

Successful mechanical earth model construction and wellbore stability analysis using elastic and plasticity solutions, a case study

Geomechanics issues and stability of wells are essential parts of the drilling operation. If wellbore stability is not analyzed comprehensively, instability problems or failures can occur in the wellbore leading to many drilling difficulties. Many parameters such as mud weight, well trajectory, in-situ stresses, etc., could affect the wellbore instability. Wellbore stability analysis can be implemented using an elastic or a plastic solution. This paper uses both solutions to analyze wellbore stability for a well called Well-A in an Iranian southwest oil field. First, a mechanical earth model (MEM) was established and calibrated through the required information. Afterward, regarding the linear elastic solution, four rock failure criteria, including Mohr–Coulomb, Mogi–Coulomb, Hoek–Brown, and Modified Lade, were employed to predict the safe mud weight windows. In the section on plasticity, the stability analysis was executed analytically using an elastic/ideally plastic model. Then the numerical solutions using a finite difference code were applied to determine the optimum mud weight and evaluate the results of analytical computations. From the obtained results, it was found that the Mogi–Coulomb criterion provides the most reliable safe mud weight window for an elastic analysis. Numerical solution results sufficiently confirmed the authenticity of analytic elastic and elastic/perfectly plastic solutions. In addition, the numerical method was capable of determining the proper optimum mud weight using Mohr–Coulomb combined with plasticity. According to the depths of Well-A experiencing wellbore instabilities and associated geomechanical problems, the results of both numerical and linear elastic solutions demonstrated an advantageous agreement with the actual observations. Consequently, the study elucidates that in order to achieve superior drilling operations, the approaches used to analyze wellbore stability could be competently employed to determine the possibility of wellbore instabilities and design an appropriate mud weight concerning Well-A or subsequent similar wells located in the present oil field.

Analysis of wellbore stability for overbalanced drilling in marine methane hydrate-bearing sediments under non-hydrostatic stresses

New challenges have emerged in drilling marine methane hydrate-bearing sediments (MHBSs); these challenges are closely related to methane hydrate (MH) dissociation and complex multi-physics coupling. This study investigates wellbore stability in overbalanced drilling by proposing exact solutions for multi-physics fields, taking into account the more general non-hydrostatic far-field stresses, partial multi-field coupling and the influences of hydrate dissociation, i.e., the water/heat production/absorption and the change in the physical properties of reservoirs due to hydrate dissociation.Wellbore drilling is simplified as a non-axisymmetric plane strain problem for the mechanical field and an axisymmetric problem for the pressure/temperature/salt concentration fields, in which the drilling domain includes four annular regions with different physical properties. The closed-form solutions for the temperature, pore pressure and salt concentration fields are obtained by considering the influence of water/heat production/absorption in the compatibility conditions of the steady-state governing equations. The solutions can explain the secondary formation of MHs around the dissociation front. The stress and drilling-induced displacement are then derived for the multi-region elastic problem subjected to non-hydrostatic far-field stresses considering seepage flow, with which the initial failure zone can be addressed by considering a failure criterion. The analytical solutions are verified by the good agreement between analytical and numerical results based on the same assumptions. Furthermore, the comparison between the analytical solutions and the results from complex numerical models suggests the applicability of the proposed solutions. Based on the conditions in marine hydrate field trials in the Shenhu area of the South China Sea, the influence of key parameters on wellbore stability in drilling in MHBSs is investigated in detail by the proposed solutions. Some useful dimensionless charts are provided.

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.

Wellbore Stability Analysis of Horizontal Wells for Shale Gas With Consideration of Hydration

Abstract With the wide application of extended reach wells and horizontal wells, the geological conditions faced during the drilling process have become increasingly complicated, and the resulting wellbole collapse problem has become serious. Based on an L-1 horizontal well, this study provides a method for calculating collapse pressure considering the influence of formation hydration. This method is used to obtain the stress distribution around the well and collapse situation at 4100 m underground. The wellbore stability can be evaluated by the method. The factors affecting the stress and collapse of the well are analyzed by changing the construction parameters and geological parameters. Studies have shown that the rock near the well has collapsed to a certain extent and shale hydration increases the formation Poisson's ratio, resulting in more serious collapse. The study also found that hydration, drilling fluid density, and borehole size have the greatest impact on the stability of the borehole wall, followed by the well deviation angle, and the bedding angle the least. Carefully exploring the situation of the shale gas reservoir in the drilling design stages, considering the impact of hydration, and selecting appropriate construction parameters are necessary to avoid the collapse of the shaft wall and affect the shale gas production process. This study can provide a reference for ensuring the stability of the wellbore.

Rock Physics Modeling of Gas Hydrate Reservoirs Through Integrated Core and Well-Log Data in NGHP-02 Area in KG Offshore Basin, India

Since gas hydrates are unconventional reservoirs, they pose unique challenges for identification, characterization, quantification, and extraction. The conventional approach—elastic logs—can provide a better method for identification through attribute analysis. On the other hand, geomechanical studies for wellbore stability analysis pave the way for the effective exploitation of gas hydrates. It is crucial to predict elastic logs against gas-hydrate-bearing sediments, which requires an effective rock physics model. In the present work, a study pertaining to the National Gas Hydrate Program-02 (NGHP-02) campaign in the Krishna‐Godavari (KG) Offshore Basin, India, where gas hydrates are deposited primarily in two facies—a shale-dominated shallower one and a sand-dominated deeper one that has been identified by responses of conventional and spectroscopy logs—is discussed. It is commonly known that depositional heterogeneity impacts petrophysical and elastic properties. To address this issue, an innovative approach has been adopted to model compressional and shear log data using rock physics modeling of gas hydrate reservoirs based on the depositional type of gas hydrate. Guidance from the change of compressional velocity data from log and core with an increase of gas hydrate saturation shows gas hydrate deposition in the study area can be explained through a matrix/grain-supported model. The Jason grain-supported rock physics model appeared best suited among different available rock physics models, depending on the clay volume and porosity in our study area. Using input from a robust multimineral petrophysical evaluation and rock physics modeling, the finalized model is propagated to test wells for predicting compressional, shear, and density logs, with the predicted data validated by core-measured compressional and shear data. Model consistency is indicated by a high correlation from multiwell crossplots of modeled and recorded elastic logs (compressional and shear velocity) with acoustic impedance. The developed rock physics model better discriminates gas hydrate in the shaly sand layer and gas hydrate in the sand-dominated layer, calcite, and shale in the VpVs domain.

Combined Effect of Pore Water Overpressure, Far-Field Stresses, and Strength Parameters in Wellbore Stability

Studying the stability of wellbores drilled to access reservoirs can be a challenging issue in overpressured basins because accurate estimation of the far-field stresses, overpressure, and rock strength parameters can be difficult to achieve. Unexpected overpressures can induce tensile stresses around the wellbore, and the selection of an appropriate strength criterion and rock properties play an important role in determining the limit mud pressures. This study focuses on the stability analysis of wellbores by considering the mutual interaction of far-field stresses, fluid overpressure, and strength parameters of isotropic rock. We performed sensitivity analyses with the Mohr–Coulomb and Hoek–Brown criteria in two overpressured fields (North Sea basin and Browse basin) to highlight the influence of the uncertainties related to the rock strength. We defined an effective stress path (ESP) failure line to analyze the failure limit condition in the tension and compression zone. The analysis results indicated that the Hoek–Brown criterion better describes rock failure conditions, especially in the tension zone. Furthermore, we suggested using two different frictional components of strength for the tension and compression zone because it is a conservative approach, particularly at high overpressures. The mud pressures obtained from the uniaxial radial/tangential (HF) conventional analysis give different failure limits with respect to the ESP approach suggested in this study. These differences are low, and the mud weight margin can be low. In addition, we carried out numerical simulations with FLAC to investigate the extent of failure. The results indicated that the mud weight margin between the onset of local failure and borehole collapse is very low at high overpressures. Finally, the geomechanical analysis of wellbore stability in overpressured basins indicated the need for improving the accuracy in determining the strength parameters of the rock.

A hybrid partial least squares regression-based real time pore pressure estimation method for complex geological drilling process

Accurate real-time estimation of pore pressure is essential for the geomechanical analysis of wellbore stability. Conventional empirical methods may find it difficult to capture pore pressure trends, especially in the complex geological environments. In this study, a data-driven pore pressure estimation method is developed on the basis of hybrid partial least squares regression. This method, which combines empirical methods, comprised three stages: data preprocessing, depth series segmentation, and model establishment and switching. First, concerning the existence of outliers and noises, an outlier detection and wavelet filtering algorithm are introduced to obtain reliable model parameters. Additionally, Pearson correlation-analysis is employed to determine strongly correlated attributes with pore pressure in the data preprocessing stage. Afterward, an online principal component analysis similarity method is proposed for depth series segmentation, considering the varying drilling depth. Finally, a real-time data-driven pore pressure estimation model that integrates conventional empirical methods is established on the basis of partial least squares regression, and a model switching strategy is further developed and will be activated when performance deteriorates. The proposed method can be applied to a wide range of formations, and a real case study is conducted using actual data from a drilling site in Utah. The mean absolute error and root mean square error of the proposed method achieve 0.5128 and 0.8056 in the online condition, and achieved 1.4592 and 2.0100 in the offline condition, which are at least 45% less than those of other nine well-known methods. The results indicate the superior performance of our method on this well.

Finite element analysis of wellbore stability and optimum drilling direction and applying NYZA method for a safe mud weight window

Finite element analysis of wellbore stability and optimum drilling direction and applying NYZA method for a safe mud weight window

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.

An integrated rock-mechanics tests and numerical modelling of chalk rocks: An improved integrated workflow for borehole safety

Fluid withdrawal and pore pressure reduction change the effective stresses around a borehole and cause borehole instability associated with progressive localization of the damaged zone as well as potential fines production. Experimentally, chalk exhibits a complex geomechanics behaviour (pore collapse, shear failure, time/rate dependency) and modelling the behaviour of the borehole under in-situ and operational conditions requires the constitutive model to be capable of capturing the observations. This study presents a workflow that integrates rock mechanics testing on cylindrical specimens as well as specimen with a single lateral hole (SLH) and a finite element code, developed for chalk. The code incorporates post-peak softening as well as the rate dependency of the pore collapse stress in order to accurately predict the wellbore stability under in-situ stress conditions. The tested SLH specimen was CT imaged before and after testing for identifying the damaged zone and its extension. Backward numerical simulations of the SLH test data improved the accuracy of the estimated rock mechanics properties (post-peak failure and dilatancy) compared to the properties estimated by back analyses of standard triaxial tests with a single element simulator. The workflow is applied to predict the stability of a small lateral borehole (2 cm) created with Radial Jet Drilling technique with two different geometries: one with circular geometry created by a rotating nozzle; another with a circular hole with wing shaped cracks likely to develop when a static nozzle is used. Results of the wellbore stability analyses applying the chalk properties from the back analyses highlighted the importance of using experimentally verified post-peak failure and dilatancy parameters, together with a modelling tool capable of simulating shear strain localization incorporating the Cosserat approach. • This study integrates rock-mechanic tests and numerical simulations for open hole stability in chalk rocks. • Back analysis of standard triaxial tests using the single element simulator is carried out. • A Design and predictive model for the Single Lateral Hole test is validated. • Study shows the significant development of breakout zone during creep phase near the hole.

Effect of formation strength anisotropy on wellbore shear failure in bedding shale

The shale gas/oil is playing an important role in the current energy resources. However, the wellbore instability problems bring a high risk to drilling engineering especially in the formation with bedding planes. A normal wellbore stability analysis approach is based on elasticity, which is not enough to recognize the mechanisms. In this paper, the poroelasticity was adopted to present the hydro-mechanical coupling effect in shale formation, meanwhile, the permeability anisotropy which could affect the effective stresses around the well was considered. A three-dimensional finite difference model was developed to simulate arbitrary directional well in shale by the coordinate transformation method. The jointed material model was proposed to character the strength anisotropy and plastic behavior of bedding shale. Additionally, the effects of well trajectory, bedding plane orientation and mud weight on shale wellbore stability were discussed, thus some implications for improving wellbore stability in bedding shale formation were obtained from the proposed model. • The jointed material model is proposed to analyze the shear failure region in bedding shale. • The poroelastic theory is adopted to represent the hydro-mechanical coupling effect in the formation. • A finite difference three-dimensional model is established to simulate the wellbore failure behavior. • The effects of well trajectory, bedding plane orientation and mud weight on wellbore stability are evaluated.

Development of 1D-Synthetic Geomechanical Well Logs for Applications Related to Reservoir Geomechanics in Buzurgan Oil Field

Knowledge of the distribution of the rock mechanical properties along the depth of the wells is an important task for many applications related to reservoir geomechanics. Such these applications are wellbore stability analysis, hydraulic fracturing, reservoir compaction and subsidence, sand production, and fault reactivation. A major challenge with determining the rock mechanical properties is that they are not directly measured at the wellbore. They can be only sampled at well location using rock testing. Furthermore, the core analysis provides discrete data measurements for specific depth as well as it is often available only for a few wells in a field of interest. This study presents a methodology to generate synthetic-geomechanical well logs for the production section of the Buzurgan oil field, located in the south of Iraq, using an artificial neural network. An issue with the area of study is that shear wave velocities and pore pressure measurements in some wells are missing or incomplete possibly for cost and time-saving purposes. The unavailability of these data can potentially create inaccuracies in reservoir characterization n and production management. To overcome these challenges, this study presents two developed models for estimating the shear wave velocity and pore pressure using ANN techniques. The input parameters are conventional well logs including compressional wave, bulk density, and gamma-ray. Also, this study presents a construction of 1-D mechanical earth model for the production section of Buzurgan oil field which can be used for optimizing the selected mud weights with less wellbore problems (less nonproductive time. The results showed that artificial neural network is a powerful tool in determining the shear wave velocity and formation pore pressure using conventional well logs. The constructed 1D MEM revealed a high matching between the predicted wellbore instabilities and the actual wellbore failures that were observed by the caliper log. The majority of borehole enlargements can be attributed to the formation shear failures due to an inadequate selection of mud weights while drilling. Hence, this study presents optimum mud weights (1.3 to 1.35 g/cc) that can be used to drill new wells in the Buzurgan oil field with less expected drilling problems.

Failure characterization of Longmaxi shale under direct shear mode loadings

Insight into the shear failure of shale is significant for the analysis of hydraulic fracturing and wellbore stability in a shale gas reservoir. In this work, a series of direct shear tests is conducted on cubic Longmaxi shale samples with various bedding orientations, i.e., α = 0°, 30°, 60° and 90°, where the bedding orientation α is defined as the angle between the bedding and shearing direction. The anisotropies in the shear stress-displacement relation, failure pattern and shear strength are then analyzed and highlighted. Stress fluctuation is widely observed near the peak shear stress for most samples with α = 30° and 60°, and the shear displacement at the peak shear stress reaches its maximum and minimum values at α = 60° and α = 0°, respectively, for a given normal stress. The failure surface is formed by shear sliding along a weak bedding plane if α = 0°, resulting in a smooth failure surface with a much lower fractal dimension value; when α = 30°, 60° and 90°, some inclined cracks form across the failure surface during shearing, resulting in much rougher fracture surfaces. The shear strength and cohesion reach their minimum values at α = 0°, while the smallest internal friction angle is observed at α = 90°. Finally, by considering the anisotropies induced by the material microstructure and stress state, a new anisotropic shear failure criterion is presented and found to achieve good agreement with the test results. With the new criterion, the bedding angle corresponding to the maximum shear strength is found to vary with the applied normal stress.