Wellbore Orientation Research Articles

Effect of Wellbore Orientation and Axial Stress on Hydraulic Fracture Initiation and Propagation in Lushan Shale with Inclined Bedding Planes

Effect of Wellbore Orientation and Axial Stress on Hydraulic Fracture Initiation and Propagation in Lushan Shale with Inclined Bedding Planes

Using One-Dimensional Geomechanical Model for Determining the Safe Wellbore Orientation of Zubair Reservoir, Southern Iraq

The wellbore instability issues are firmly occurring in the Iraqi oilfield and particularly in the southern region of Iraq. It is causing a significant loss of time dealing with many types of downhole problems, as well as an increase in the operations costs because of the instability consequences. By using the well information and open-hole logging data, the One-Dimensional (1-D) geomechanical model generated with Schlumberger Techlog software (V.2015) was used to assess the mechanical stability of the wellbore. The model was calibrated and validated by using core data (Triaxial test), the formation pore pressures, and the Mini-frac test). The 1-D model was validated across the actual well conditions (i.e., the original mud weight and the actual wellbore failure) by using three criteria of failures which are Modified Lade, Mogi-Coulomb, and Mohr-Coulomb. The validation process showed that the failure criterion of Mogi-Coulomb is better than the other two criteria in presenting the actual borehole failure, and thus it can be used to develop the plans of wellbore orientation. By investigating wellbore orientation with various scenarios, ranging from a vertical trajectory to the horizontal strategy, the wellbore orientation is mainly safe (with the minimum breakout) in vertical and inclined wells up to 40º with minimum mud weight of 11.7 and 12.6 ppg. The optimum wellbore trajectory should be in the direction of minimum horizontal stress, which is North-West to South-East (130º-160º). The developed plans provide a guideline for performing stable drilling operations in the south of Iraq and the nearby areas, thus effectively contributing in reduction the overall cost.

Impact of Formation Dip Angle and Wellbore Azimuth on Fracture Propagation for Shale Reservoir

The significant vertical heterogeneity, variations in ground stress directions, and irregular bedding interfaces make it extremely challenging to predict fracture propagation in continental shale reservoirs. In this article, we conducted a series of triaxial laboratory experiments on continental shale outcrop rocks to investigate the effects of formation dip angle and wellbore orientation on crack propagation under horizontal well conditions. Our study revealed that fracture propagation features can be categorized into four distinct types: (1) hydraulic fractures pass through the bedding interface without activating it; (2) fractures pass through and activate the bedding interface; (3) hydraulic fractures open and penetrate the bedding interface while also generating secondary fractures; and (4) hydraulic fractures open but do not penetrate the bedding interface. We found that as the dip angle decreases, the likelihood of fractures penetrating through the bedding interface increases. Conversely, as the dip angle increases, fractures are more likely to simply open the interface without penetrating it. Moreover, we observed that the well azimuth significantly affects the degree of fracture distortion. Specifically, higher azimuth angles corresponded to a higher degree of fracture distortion.

Impacts of wellbore orientation with respect to bedding inclination and injection rate on laboratory hydraulic fracturing characteristics of Lushan shale

A series of hydraulic fracturing experiments were conducted using Lushan shale cores (50 mm in diameter and 100 mm in length) to unravel the formation mechanism of fracture networks under the combined effects of wellbore type (vertical or horizontal well), wellbore orientations relative to the bedding plane (0°, 30°,45°, 60°, and 90°), bedding inclinations (0°, 30°,45°, 60°, and 90°), and injection rates (0.03, 0.3, 3, and 30 mL/min). We monitored acoustic emission and surface displacements during the test and conducted post failure inspection via a fluorescent tracer and a 3D laser scanner. We show that adjusting the maximum principal stress perpendicular to the wellbore is beneficial for reducing the breakdown pressure. Inclined bedding tends to initiate along the bedding plane with relatively low fracture initiation pressure and breakdown pressure. Deploying the wellbore inclined to bedding inclination and/or adopting a low injection rate is beneficial to reduce the shale breakdown strength and create a complex fracture network. However, this will correspondingly increase the fracture surface roughness, which may impede the effective transportation of proppant. These findings can provide an important reference for field hydraulic fracturing.

Mutual impact of true triaxial stress, borehole orientation and bedding inclination on laboratory hydraulic fracturing of Lushan shale

Unconventional resources like shale gas has been the focus of intense research and development for two decades. Apart from intrinsic geologic factors that control the gas shale productivity (e.g. organic matter content, bedding planes, natural fractures, porosity and stress regime among others), external factors like wellbore orientation and stimulation design play a role. In this study, we present a series of true triaxial hydraulic fracturing experiments conducted on Lushan shale to investigate the interplay of internal factors (bedding, natural fractures and in situ stress) and external factors (wellbore orientation) on the growth process of fracture networks in cubic specimens of 200 mm in length. We observe relatively low breakdown pressure and fracture propagation pressure as the wellbore orientation and/or the maximum in situ stress is subparallel to the shale bedding plane. The wellbore orientation has a more prominent effect on the breakdown pressure, but its effect is tapered with increasing angle of bedding inclination. The shale breakdown is followed by an abrupt response in sample displacement, which reflects the stimulated fracture volume. Based on fluid tracer analysis, the morphology of hydraulic fractures (HF) is divided into four categories. Among the categories, activation of bedding planes (bedding failure, BF) and natural fractures (NF) significantly increase bifurcation and fractured areas. Under the same stress regime, a horizontal wellbore is more favorable to enhance the complexity of hydraulic fracture networks. This is attributed to the relatively large surface area in contact with the bedding plane for the horizontal borehole compared to the case with a vertical wellbore. These findings provide important references for hydraulic fracturing design in shale reservoirs.

3D numerical modeling of fracture initiation from branch wellbore

ABSTRACT Branch wellbore fracturing in branch wellbore is a new technology for developing unconventional oil and gas reservoirs. In this study, we developed a 3D numerical model based on finite element method to analyze fracture initiation characteristics from branch wellbore. Two typical cases were analyzed: a branch wellbore drilled from vertical main wellbore and a branch wellbore drilled from horizontal main wellbore. Then, the effects of different factors on fracture initiation were analyzed, which includes branch wellbore orientation (intersection angle between branch wellbore axis and maximum horizontal stress/vertical stress), difference between vertical and maximum horizontal stress, branch wellbore length and branch wellbore diameter. Results show that fracture initiation from the branch wellbore is mainly controlled by the branch wellbore orientation and difference between vertical and maximum horizontal stress. Besides, for the branch wellbore drilled from vertical main wellbore, fracture always initiates from two symmetric areas at the base of branch wellbore with any branch wellbore orientation and difference between vertical and maximum horizontal stress. However, for the branch wellbore drilled from horizontal main wellbore, fracture initiates from two symmetric zones at the base of branch wellbore when branch wellbore orientation is less than 40° and difference between vertical and maximum horizontal stress is larger than 0.1, while fracture initiates from two symmetric zones on the whole branch wellbore when branch wellbore orientation is larger than 40° or difference between vertical and maximum horizontal stress is less than 0.1. Furthermore, the increase of branch wellbore diameter leads to increase of FIP by 1–4 MPa. The key findings of this work provides basis for the field application of this technology.

Numerical assessment of fault impact on caprock seals during CO[formula omitted] sequestration

Coupled fluid-flow and geomechanical analysis of caprock integrity has gained a lot of attention among scientists and researchers investigating the long-term performance of geologic carbon storage systems. Reactivation of pre-existing fractures within the caprock or re-opening of faults can create permeable pathways which can influence the seal integrity. Stability of the caprock during and after injection of super-critical CO2, and the impact of pre-existing fractures in the presence or absence of one or multiple faults have been investigated in this study. The impact of the wellbore orientation and the injection rate are among other key factors in understanding the structural trapping mechanisms within such geological formations. In this study, we numerically investigated the impact of each of these factors. This study revealed the interplay between joints and faults and how different leakage pathways are formed and under which scenario they play a dominant role in terms of CO2 leakage. This study also highlights the role of one versus multiple faults in the domain and the importance of the fault hydrological property in forming leakage pathway.

Experimental and Modeling Investigation of Fracture Initiation from Open-Hole Horizontal Wells in Permeable Formations

To investigate the evolution of hydraulic fractures in open-hole horizontal wells, a comprehensive experimental and analytical modeling investigation of fluid-driven fracture initiation in open-hole horizontal wells is presented in this paper. A large triaxial experimental system and a three-dimensional (3D) micro-computed tomography (micro-CT) imaging setup were used to simulate and investigate hydraulic fractures similar to those produced in field tests. We used an 8-mm-diameter and 100-mm-long hollow cylinder as a borehole within a 115 mm × 115 mm × 93 mm cement sample. The samples were first loaded in three orthogonal directions at different confining pressures to reproduce in situ reservoir conditions. Subsequently, a viscous fluid used in field operations with a viscosity of 60 mPa·s was injected into the borehole at 9 cc min−1. During the tests, the injection pressure and rate were monitored. Then, the fracture morphologies were detected by 3D micro-CT scanning. The fracture initiation pressure increases as the wellbore orientation rotates toward the minimum principal stress direction. The 3D images demonstrated that an induced hydraulic fracture first extends along the horizontal wellbore and then turns to align with the preferred fracture plane. An analytical model considering the fluid penetration effect, which is represented by the injection rate, rock permeability and fluid viscosity, was also developed to predict the fracture initiation pressure in open holes in permeable formations. The modeling results of the initiation pressure and the fracture position and orientation fit well with the experimental results. During the stimulation of a permeable formation, some of the fracturing fluid being injected into the wellbore flows from the wellbore into the surrounding formation. The infiltrating fracturing fluid increases the formation pore pressure, causing a compressive circumferential stress around the borehole. This mechanism reduces the fracture initiation pressure. The initiation pressure decreases with the rock permeability and injection rate but increases with the fracturing fluid viscosity. This result is important for petroleum engineering applications, because nearly all reservoirs are permeable to fracturing fluids, and the limitations of previous models preclude them from drawing the same conclusions.

Regional tectonic state and poro-thermo-elasticity analysis of near wellbore zone in field development plan: Utilization of an uncoupled approach

The main aim of this work is to investigate the effects of temperature and pore pressure on stability of wellbore wall, considering the wellbore spatial orientation and regional tectonic state of the field in which the well is drilled. An uncoupled approach was proposed in this research study. Although the combination of fluid and temperature diffusion can be intensely alter the pore pressure and temperature of the near wellbore zone, the uncoupled approach can be considered as a primary, fast and simple method for optimization purposes at the earliest stages of field development when the technical data/information to conduct a coupled simulation is limited. The data used for this study were collected from real, literature and simulation cases. The real data are from geological and geophysical studies of gas reservoirs in Siberia, Russia. The results show that the problem of wellbore breakout (shear failure) happens in the final stages of field development however, the hydraulic fracturing and fluid loss (tensile failure) are the most common problems at the early stages of field development. Increasing wellbore temperature increases the shear failure risk for any wellbore orientation and regional tectonic state however it decreases the risk of tensile failure by increasing the tensile strength of rock. Effect of zenith angle on shear and tensile failure of wellbore depends on the regional fault regime. At the regions with normal fault regime, vertical wellbores are more stable than horizontal and vice-versa for strike-slip cases. For reverse fault regime, there is an optimum wellbore zenith angle where the shear failure is minimum and tensile failure is maximum. The results are further considered not only from drilling point of view but also for hydraulic fracturing job and hot fluid injection in field production life. Real well data from gas condensate reservoir in normal fault regime was provided for comparison and model validation purposes, showing a good agreement.

Impact of layer thickness and well orientation on caprock integrity for geologic carbon storage

Economic feasibility of geologic carbon storage demands sustaining large storage rates without damaging caprock seals. Reactivation of pre-existing or newly formed fractures may provide a leakage pathway across caprock layers. In this study, we apply an equivalent continuum approach within a finite element framework to model the fluid-pressure-induced reactivation of pre-existing fractures within the caprock, during high-rate injection of super-critical CO2 into a brine-saturated reservoir in a hypothetical system, using realistic geomechanical and fluid properties. We investigate the impact of reservoir to caprock layer thickness, wellbore orientation, and injection rate on overall performance of the system with respect to caprock failure and leakage. We find that vertical wells result in locally higher reservoir pressures relative to horizontal injection wells for the same injection rate, with high pressure inducing caprock leakage along reactivated opening-mode fractures in the caprock. After prolonged injection, leakage along reactivated fractures in the caprock is always higher for vertical than horizontal injection wells. Furthermore, we find that low ratios of reservoir to caprock thickness favor high excess pressure and thus fracture reactivation in the caprock. Injection into thick reservoir units thus lowers the risk associated with CO2 leakage.

Designing and Testing of New Rotary-Steerable System for Use Onshore

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 173093, “Designing and Testing a New Rotary-Steerable System (RSS) for the Onshore Drilling Market,” by Andrew Gorrara, SPE, Shona Grant, Tore Kvalvik, SPE, and Stig Bakke, 2TD Drilling, and Peter Clark, SPE, Chevron, prepared for the 2015 SPE/IADC Drilling Conference and Exhibition, London, 17–19 March. The paper has not been peer reviewed. While rotary-steerable systems (RSSs) dominate the offshore directional-drilling markets, the land-based markets are still dominated by conventional directional-drilling tools. This paper presents a new RSS that is being designed and tested specifically for the onshore markets. The new tool is a short RSS that is designed to deliver a buildup rate of 15°/100 ft. It achieves this by the movement of two eccentric shafts relative to one another within the tool. Introduction For directional drilling to be successful, it is important that the drillers have information on the orientation of the tool while they are drilling so they can best align the wellbore orientation to the reservoir target. Commonly, this is achieved with a measurement-while-drilling (MWD) tool that is typically 50 ft or more behind the drill bit. In some cases, these measurements are supplemented with some form of near-bit inclination reading. A further improvement would be to have both inclination and azimuth measured close to the bit and integrated into the drilling tool’s directional response, thereby enabling precise well placement without the need to project and correct continually from the MWD tool that lags considerably behind the drilling tool. This is the method adopted by the RSS described in this paper. In many cases, a downhole positive-displacement motor will be used with the RSS to increase rate of penetration (ROP) and reduce casing wear by minimizing string rotation. The RSS described in this paper was designed to be driven directly by the topdrive or with a mud motor. Three prototypes of the new RSS have been designed and tested so far. The first prototype (Prototype A) successfully demonstrated dogleg-severity capability of 15°/100 ft. The second prototype (Prototype B) was designed to evaluate the efficiency of the selected motor-gear design in moving the eccentric shafts when applying significant side loads. The third prototype (Prototype C) was a complete rotary-steerable tool that verified all aspects of the design, culminating in the drilling of directional holes in concrete blocks. This paper describes the development of Prototype C, covering design, manufacture, and the drill tests that verified the 15°/100 ft dogleg performance through concrete-block drilling. The paper also covers the subsequent design improvements made before manufacture of the field-test prototypes (Prototype D) and the planned environmental and endurance testing of Prototype D before field testing.

Determination of a safe mud window and analysis of wellbore stability to minimize drilling challenges and non-productive time

The instability of a wellbore is still one of the common problems during drilling. The cause of such a borehole failure can often be mitigated by suitably determining the critical mud pressure as well as the best well trajectory. Therefore, we could save the time and the cost of drilling and production significantly by precluding some drilling problems. The main objective of this paper is to apply a geomechanical model based on well data including the in situ stresses, pore pressure, and rock mechanical properties coupled with suitable rock failure criteria in order to obtain a safe mud window and a safe drilling direction. The Mogi–Coulomb failure criterion was used for deriving the failure equations for tensile and compressive failure modes. For comparison, the analysis was also carried out using the traditional Mohr–Coulomb failure criterion. Variations of wellbore inclination and azimuth were also used to recommend upper and lower mud pressure bounds and the most stable borehole orientations. The best trajectory selection for the inclined borehole was also investigated. Furthermore, the effect of drilling mud pressure and wellbore orientation (θ = 0o) and (θ = 90o) on wellbore stability and stress distribution around the wellbore was assessed. The stability model has been applied to a well located in an oilfield in Iran and showed that the new model is consistent with field experience.

Comparing geology and well completions to production in the Unconventional region of the Cardium Formation (Upper Cretaceous), northwest Pembina field, Alberta, Canada

Drilling of horizontal wells in the Cardium Formation in the Pembina field has abruptly increased since the successful completion of Bonterra Nexstar 4-25-47-03 W5 (surface-hole location) 1-25-47-03 W5 (bottom-hole location) in 2008. New Cardium Formation wells are targeting thinner lower quality reservoir intervals while implementing a variety of new completion techniques to improve hydrocarbon production. The purpose of this study is to compare reservoir quality, net-pay mapping, and completion techniques to production data to evaluate the successes and failures of geologic characterization and completion strategies. Well logs and routine core-analyses data were used to evaluate reservoir properties and map net-pay thicknesses. Subsequently, production data from 125 horizontal wells were compared based on the following criteria: presence of conglomerate, sandstone density porosity net-pay thickness, wellbore orientation, number of fractured stages, fracture spacing, lateral well length, base fracturing fluid, and average metric tons of proppant per stage. In the unconventional parts of the Pembina field, well-production–based evaluation of net-pay maps and reservoir characterization requires completion techniques to be considered. Conversely, reservoir thickness and quality must be considered to accurately assess the success of different completion techniques. The use of a 6% sandstone density porosity net-pay cutoff can only be shown to be effective in identifying the most productive wells if well completions are considered. Our analyses indicate that wellbore orientation has a limited impact on well performance, whereas decreasing fracture spacings and increasing lateral well length have the most significant impact on well performance.

Study on Mechanisms of Borehole Instability in Naturally Fractured Reservoir During Production Test for Horizontal Wells

During the production test for horizontal wells, down-hole pressure will drop down significantly to induce the crude oil flowing out of the wellbore, which always leads to wellbore collapse problems, especially in naturally fractured reservoirs. Hence, some special researches on this problem were carried out. Based on the mechanisms of wellbore stability and failure criterion of weak plane, the authors established the stress state around the horizontal wellbore and mathematical model of minimum down-hole pressures required to maintain the wellbore stable. This model is complex nonlinear equations, which involves several variables, including natural fracture occurrences, wellbore orientation, in situ stress, and rock strength. The combination impacts of these variables on the minimum down-hole pressure were quantified by solving this nonlinear model. The study helps deepen the understanding of the mechanisms of wellbore stability in naturally fractured reservoir.

3D Modeling of Fracture Initiation From Perforated Noncemented Wellbore

Summary A 3D numerical model of fracture initiation from a perforated wellbore in linear elastic rock is developed, which allows one to determine the fracture-initiation pressure (FIP) and the location and direction of an initial rupture. The model assumes that the fracture initiates at the point at which the local maximal tensile stress exceeds the rock tensile strength. The 3D boundary-element method (BEM) is used for stress analysis. The model aims to predict the location of initial fractures and the difference in FIP between different perforation intervals in arbitrarily oriented noncemented wellbores. There are many practical applications for this knowledge, but of particular interest for this research is the employment of differently oriented perforations for creating heterogeneity of FIP between wellbore intervals in multistage fracturing treatment. This can enable stimulation of these intervals in a sequential mode and significantly simplify current treatment diversion and completion practices. Comprehensive analysis revealed that the main parameter that can be used for controlling FIP during multistage fracturing treatment is the angle between the direction of the perforation channel and the preferred fracture plane (PFP). The model allows obtaining the range of the angles that is the most suitable for designing and implementation of diversion between the perforated wellbore intervals. The influence of geometrical parameters of perforation (such as length, diameter, and shape) on FIP is substantially less. In addition, we found that against all expectations, increase of perforation diameter can result in higher FIP. It was also discovered that the influence of the intermediate in-situ stress on FIP is comparable with the effect of perforation misalignment, especially in the situation of a horizontal wellbore and properly aligned perforations. On the basis of the model developed, an approximate approach to the evaluation of the effect of wellbore cementation on fracture initiation was suggested. It was discovered that taking into account the state of stress within the cement before well pressurization can result in both an increase and a reduction of FIP, depending on the parameters of perforating and the wellbore orientation. The presented model is a necessary step toward predictable and controllable fracture initiation, which is vital for multistage-fracturing-treatment diversion.

A wellbore stability model for formations with anisotropic rock strengths

Shale formations, due to the presence of laminations and weak planes, exhibit directional strength characteristics. In most conventional wellbore stability analyses, rock formations are typically assumed to have isotropic strength. This may cause erroneous results in anisotropic formations such as shales which show strength variations with changing loading directions with respect to the plane of weakness. Therefore a more complex wellbore stability model is required. We have developed such a model in which the anisotropic rock strength characteristic is incorporated. Applying this model to two case studies shows that shear failures occur either along or across the bedding planes depending on the relative orientation between the wellbore trajectories and the bedding planes. Additionally, the extent of failure region around the wellbore and the safe mud weights are significantly affected by the wellbore orientation with respect to the directions of bedding plane and in-situ stress field.

3D numerical stability analysis of multi-lateral well junctions

The most important factors in multi-lateral well stability analysis are the magnitude of in situ stresses, the relation between the amount of in situ stresses and orientation of lateral wellbore. In this research, the stability analysis of multi-lateral junction is carried out using FLAC3D numerical code by considering seven varied stress regimes and different lateral wellbore orientations. The Normalized Yielded Zone Area (NYZA, ratio of surrounding yielded cross-sectional area to initial area of well) is determined for different junction mud pressures as well as diverse orientations of lateral wellbore. Then, the junction optimum mud pressure of each lateral wellbore orientation is calculated; hence, the optimum trajectory of lateral wellbore, in which the junction has got the lowest optimum mud pressure, is selected in each stress regime. The stability analysis of multi-lateral wells by means of finite difference method shows that in each stress regime the required mud pressure for the stability of junction is much more than that of the lateral branch and the main wellbore.

Maintaining the stability of deviated and horizontal wells: Effects of mechanical, chemical and thermal phenomena on well designs

Wellbore instability, particularly in shale formations, is regarded as a major challenge in drilling operations. Many factors, such as rock properties, in-situ stresses, chemical interactions between shale and drilling fluids, and thermal effects, should be considered in well trajectory designs and drilling fluid formulations in order to mitigate wellbore instability-related problems. A comprehensive study of wellbore stability in shale formations that takes into account the three-dimensional earth stresses around the wellbore as well as chemical and thermal effects is presented in this work. The effects of borehole configuration (e.g. inclination and azimuth), rock properties (e.g. strength, Young's modulus, membrane efficiency and permeability), temperature and drilling fluid properties (e.g. mud density and chemical concentrations) on wellbore stability in shale formations have been investigated. Results from this study indicate that for low-permeability shales, chemical interactions between the shale and water-based fluids play an important role. Not only is the activity of the water important but the diffusion of ions is also a significant factor for saline fluids. The cooling of drilling fluids is found to be beneficial in preventing compressive failure. However, decreasing the mud temperature can be detrimental since it reduces the fracturing pressure of the formation, which can result in lost-circulation problems. The magnitude of thermal effects depends on shale properties, earth stresses and wellbore orientation and deviation. Conditions are identified when chemical and thermal effects play a significant role in determining the mud-weight window when designing drilling programmes for horizontal and deviated wells. The results presented in this paper will help in reducing the risks associated with wellbore instability and thereby lowering the overall non-productive times and drilling costs.

Hydraulic fracture initiation and propagation: roles of wellbore trajectory, perforation and stress regimes

This paper develops a generic model for predicting hydraulic fracture initiation from arbitrarily oriented wellbores. For a given in-situ stress condition and wellbore orientation parameters, the model predicts the fracture initiation pressure and the orientation and location of fractures on the wellbore wall. The model has been applied in a series of in-situ stress conditions to study the effect of wellbore orientation on fracture initiation using non-dimensional parameters, which have enhanced the applicability of presented results for any stress condition. Closed-form analytical solutions are also obtained for initiation of longitudinal, transverse and complex multiple fractures from vertical and horizontal wellbores with and without perforation. A numerical model is then incorporated in the study to analyze the propagation behavior of initiated fractures. Causes of fracture initiation at non-preferred locations and its effects on fracture propagation pressure and fracture volume due to twist of these initiated fractures during propagation are studied and discussed. Results from the analytical and numerical models used in this study are interpreted with a particular effort to enlighten the causes of abnormally high treating pressures during hydraulic fracture treatments.

Wellbore-Stability Predictions by Use of a Modified Lade Criterion

Summary The two most commonly used rock failure criteria in wellbore stability analyses are the Mohr–Coulomb criterion and the Drucker–Prager criterion. Neither of these is compatible with three-dimensional rock strength measurements that have explored the influence of the intermediate principal stress. This paper presents a modified Lade criterion which has the following desirable qualities: 1. it correctly describes the influence of the intermediate stress on rock strength, and therefore on wellbore stability, 2. it can be rearranged to give a closed-form solution for critical mud weight, for any wellbore orientation, and 3. only two rock strength parameters are required, such as cohesion and friction angle. The modified Lade criterion predicts critical mud weight values that are less conservative than those predicted by the Mohr–Coulomb criterion yet are not as unconservative as those predicted by the Drucker–Prager criterion. It also reveals that the required increase in mud weight when going from low hole angle to high hole angle is not as great as predicted by either the Mohr–Coulomb or Drucker–Prager criteria.