ABSTRACT: Studying the changes of deep mudstone strength properties after hydration are vital for the design of well drilling and proper choice of drilling fluid for deep wellbore stability. However, the previous methods (Coupled with conventional immersion test and compressive test) for evaluating the effect of hydration on rock strength cannot simulate deep well downhole hydration environments (HPHT and drilling fluid flow). In addition, high requirements of sample preparation and destructive test make it difficult to apply the compressive test to study strength of mudstone after hydration. In this study, a new experimental apparatus for hydration of mudstone under deep well drilling conditions (high temperature: ~200°C, high pressure: ~60MPa and flushing action of drilling fluid) is designed. Furthermore, continuous scratch method, which can easily achieve repeated tests using the same core sample at different extent of hydration, is adopted to evaluate the strength properties (uniaxial compressive strength (UCS), cohesive strength and internal friction angle) of mudstone after hydration. Based on the above works, a new approach to study the effect of hydration under deep well drilling conditions on mudstone strength parameters is developed. The comparison experiments about evaluating the influence of hydration on mechanical properties of mudstone (depth 5500-7000m, Western field China) under deep well conditions and ambient conditions are conducted. Results show that the reductions of UCS and cohesive strength of mudstones under deep well downhole conditions and ambient conditions are about 70-80% and 20-40%, respectively. It reveals that deep well drilling conditions aggravate the degradation of mudstone strength and cannot be ignored in managing wellbore instability. This proposed approach can provide significant support to the performance optimization of drilling fluid and design of deep well drilling. 1. Introduction The development potential of oil and gas resources from deep reservoir in Western China is drawing significant attention as time goes by. However, due to the complex conditions (drilling fluid flush, high temperature: ~200°C and high drilling differential pressure: ~40MPa) in deep well, wellbore instability in deep mudstone formation seriously hampers the productive time (Zhou et al., 2018; Liu and Zhou, 2019; Cui et al., 2020). In order to sustain wellbore stability in deep mudstone, it is necessary to study the weakening effect of hydration on rock strength properties under the real conditions in deep formation.

ABSTRACT: The study utilized 4D finite element Geomechanical modelling coupled with reservoir dynamic simulation, laboratory rock mechanics test data and different well drilling experience models across the reservoir structure. A total of 7 faults near the proposed water injection zone are incorporated into the simulation model. At the completion of each pressure timestep, plastic shear strain distribution at the faults are evaluated. The study discussed the likelihood of fault reactivation that would lead to potential migration of hydrocarbons from injection regions within the reservoir, reduction in sweep efficiency and unintended pressure charging of shallower sand intervals. The study also provides insights to wellbore stability during drilling and sand production during life of wells. The results of the modelling are used to revisit the initial well placement, offering an enhanced insight to conventional well placement consideration. The study provides insights on geomechanical risks associated with water injection design in thinly bedded and highly faulted reservoir which added value to the field development through interactive collaborative well planning between multidiscipline. The paper also aims to share the workflow related to risk assessment which impact injection limit, hydrocarbon recovery, containment integrity and the field economics. observations and calibrations. 1. Introduction The 4D geomechanical study was conducted for a deepwater oil field development in Malaysia. The oil resources are seated in the toe thrust of a highly faulted geological structure, and thinly laminated sand and shale layers. Developing the reservoirs requires horizontal wells placement and planning to ensure maximized drainage and sweep within the thinly laminated sand bodies. However, placement of horizontal wells in low rock strength and low principal in-situ stress environment may lead to geomechanical risks such as wellbore instability, early sand production and completion integrity. These risks can lead to additional cost, compromising well and field development objectives, and environmental safety. Water injection is considered as one of viable options to maximize ultimate recovery by maintaining the reservoir pressure above bubble point from the beginning and throughout the field life. Hence, evaluation on the associated geomechanics risk is paramount on the planning and development strategy of the water injection wells. This paper discussed the role of geomechanics and modelling to provide insights on balancing and ultimate recovery trade off while not compromising hydrocarbon containment integrity from the water injection. Water injection feasibility was evaluated for fault reactivation, seal integrity, sand production and wellbore stability. Corroboration of multiple analyses are conducted in the final well placement, architecture, and design.

ABSTRACT: As a barrier of wellbore pressure and filtrate, the performance of drilling fluid and the quality of mudcake are of great significance for the wellbore stability in fractured formations. The dynamic permeability and thickness functions of representative drilling fluid additives were provided with high temperature and high pressure (HTHP) filter testing device to investigate its effect on mudcake. Based on the influence of time-dependent mudcake, a dual-porosity/dual-permeability model was developed to analyze the pore pressure and stress state around the wellbore. The results show that the permeability of mudcake decreases with the growth of bentonite content, which increases the plugging efficiency by improving the compactness of plugging zone. The polymer additives keep the coalescence stability of clay particles and seal the pore of mudcake with the hydration layer, which increases the effective stress of compression with a thin layer of low-permeability mudcake. The addition of rigid granular plugging material increases the compactness of mudcake by matching the particle size with that of clay particles. The sensitive results have a significant effect on the optimization of drilling fluid additives. 1. Introduction Due to the existence of induced or natural fractures, the pressure bearing capacity of fractured formation is low, which is prone to result in the occurrence of lost circulation. The solid particles in the drilling fluid can build up mudcake on the wellbore and establish isolation zone to block the transmission of fluid, solid and pressure, which improves the bearing capacity of the wellbore. Thus, investigating the impact of drilling fluid on mudcake is critical for wellbore stability. For fractured formations, the matrix and fracture media have their own mechanical and physical features, there also exists interporosity flow between two media. Thus, series of works were studied with dual-porosity porous medium (Al-Ahmadi and Wattenbarger, 2011; Berryman and Wang, 1995; Li, 2003; Meng et al., 2019; Nguyen and Abousleiman, 2009; Nguyen et al., 2009; Zhang et al., 2003). Abousleiman and Nguyen (2005) established the analytical solution of dual-porosity based on the theory of poromechanics. The comparison with single porosity model illustrated that higher pore pressure was shown in fractured formation at early stage. Tran et al. (2011) established the analytical solution of single porosity wellbore stability model, which considered the dynamic permeability of mudcake. The time-dependent properties of mudcake had significant effect on safe mud weight window in permeable formation. Liu and Abousleiman (2018) developed the analytical solution of multiporosity wellbore stability model, which considered the effect of static properties of mudcake. The influence of mudcake was investigated from the aspect of thickness and permeability, which illustrated the potential for wellbore strengthening.

ABSTRACT: Borehole breakout has always been a challenging problem in drilling, especially in fractured and weak formations. Natural fractures are an important factor that affects wellbore breakout, but the traditionally used bedding plane models are not sufficient to capture borehole breakout in highly fractured formations. This paper proposes a coupled geomechanics and fluid flow model for evaluating borehole breakout in a naturally fracture network, using a discrete element method. The model considers anisotropic drilling fluid invasion within natural fractures. The effect of drilling fluid pressure, fracture density, in-situ stress, and seepage time on borehole breakout was investigated. The simulation results show that the natural fracture density does not directly control the breakout area around the wellbore. Intersection of fractures and borehole, increase in fluid seepage, and large in-situ stress ratio aggravate borehole instability. Increasing wellbore pressure without considering fluid seepage poses positive effects on preventing breakouts. The proposed numerical simulation approach provides a useful tool to understand and assess borehole breakout for drilling design in fractured formations. 1. Introduction Borehole breakout is a concerning problem of exploration and development of oil and natural gas. It is one of the most important problems in borehole stability issues, which is a type of stress-induced rock failure depending on the state of stress around the wellbore (Haimson, 2007). Generally, the borehole breakout phenomenon is caused by near-wellbore stress concentration. The breakout orientation is usually aligned with the minimum horizontal stress direction. The stress magnitude and orientation dominate the size and direction of breakout (Sahara, 2014). However, with the drilling formation becoming more complex, breakout orientation and size anomalies are constantly observed in the vicinity of the borehole. Extensive experimental and numerical studies have been conducted to investigate the mechanism of breakout and the controlling factors that affect the borehole breakout. Meier (2013) found that the critical pressure for the initiation of borehole breakout decreases when the borehole diameter is below 10 mm through experiment tests. Granites, limestones, and sandstones were used for vertical borehole drilling experiments by Haimson (2007) to explore the micromechanics of borehole instability. Yin (2018) used multi-functional triaxial geophysical apparatus to analyze the effects of intermediate principal stress for yielded plastic zone around the borehole. Haimson (2004) studied the shape and micromechanics of vertical drilling borehole of two high-porosity sandstone under far-field principal stress, and concluded that breakout size is correlated with the far-field principal stress and consequently can be used as indicators of the far-filed stress.

ABSTRACT: Maintaining wellbore stability remains a challenging task in the oil/gas well drilling industry, especially for wells drilled through naturally fractured shale formations. Field evidences show that some wellbores that are stable immediately after drilling may collapse after several days of exposure to the drilling mud, resulting in significant financial losses. Thus, a better understanding and prediction of the time-dependent wellbore instability behavior in naturally fractured shale formations is of high demand. In this paper, we present a poro-elasto-plastic finite element model for predicting the progressive evolution of damage zone around the wellbore drilled in naturally fractured shale formations. The Mohr Coulomb model has been employed to capture the plastic behavior of the naturally fractured shale formations, while strength reduction caused by the penetration of drilling mud into the formation is also included in the model. Permeability enhancement due to stress damage before peak strength has been experimentally tested and an empirical relationship between the permeability enhancement and the damage state has been obtained and incorporated into the model. As an example application, the model has been applied to a typical wellbore drilled in the Bohai oilfield of China, where serious wellbore instability problems have been frequently encountered when the fractured shale formations of Dongying group is drilled through. The influences of drilling fluid density and plugging capability of the drilling fluid on the time-dependent wellbore stability were investigated. Some suggestions for maintaining long term wellbore stability in these naturally fractured shale formations have been provided.

ABSTRACT: We analyze the potential for geomechanical failure and wellbore instability at the gas hydrate deposit located in the Ulleung Basin, South Kora. We employ the exact formulation of axisymmetric nonlinear elastic geomechanics and the fixed-stress sequential method for the two-way coupling between flow and geomechanics simulators. We take linear interpolation of hydrate saturation-dependent geomechanics moduli. From numerical simulation, geomechanical failure near the wellbore is more possible when depressurization of the hydrate reservoir is larger or the contrast between initial vertical and horizontal stresses is higher. Dissociation of the gas hydrates lowers Yong's modulus at the gas hydrate layer (sand layer), which induces substantial subsidence near the well. The effective stress increases significantly, too, which may result in geological failure and potential wellbore instability. Compaction at the mud layer above the hydrate layer is also large due to low Young's modulus. Thus, careful consideration of the level of depressurization for wellbore stability is required.

ABSTRACT: The thermodynamic properties of frozen soil are extremely affected by temperature. Besides the stress field, the temperature field cannot be ignored in polar drilling operations. Based on the correlation of thermodynamic properties of frozen soil with temperature, a thermal -flow-solid coupling numerical model of wellbore stability, which considering phase transformation, is established in this paper. The influence of drilling fluid temperature on the plastic yielding area around the wellbore during the drilling process in the frozen soil was analyzed. The results show that the temperature difference between the drilling fluid and the formation would seriously affect the distribution of the plastic yield area around the wellbore. When the drilling fluid temperature is greater than 0°C, as the drilling fluid temperature increases, the plasticity range will increase nonlinearly. When the drilling fluid temperature is less than 0°C, the weakening of the elastic parameters caused by the increase of the frozen soil temperature will reduce the plastic yielding area, which is beneficial to the stability of the wellbore. The study of drilling fluid temperature on the wellbore stability in the frozen soil provides a theory for the selection of drilling fluid temperature in the polar drilling operation.

ABSTRACT: Huge reserves of methane hydrate have been found in the deep waters, but the decomposition of hydrates in the formation during drilling makes it difficult to drill and exploit hydrate reservoirs. To study the effect of inorganic salts and two-phase percolation on the stability of hydrate wellbore, a multi-field coupling model including chemical-seepage-solid-thermal equations was established. The results show that after the hydrate reservoir was drilled, it began to decompose under inorganic salt intrusion, depressurization and temperature rise. After a short time, the decomposition of hydrate around the wellbore will slow down. This will cause the reduction of the cohesion of hydrate formation, which may increase the lower limit of drilling fluid density window and easily leads to collapse of wellbore. The speeds of these three effects are different. When the influence of inorganic salts and pore pressure drop is relatively slow, the influence of heat transfer is faster. The molecular diffusion in the low-permeability muddy hydrate formation is more obvious, but its speed still can't follow the advancement of hydrate decomposition. To prevent this type of drilling risk, lowering the bottomhole pressure to below the pore pressure is advised, which can help field engineers to prevent the drilling risks.

ABSTRACT: Wellbore instability problems play major rule in the increasing of the non-productive time (NPT) during drilling processes. In most cases, this cost can be reduced by designing a suitable operational window using geomechanical models. Several wellbore instability problems have been encountered during drilling Nahr Umr formation in an oil field in southern Iraq. These problems are including, but not limited to, mechanical stuck, caving, and tight holes. Data from more than twenty wells (vertical and deviated wells) are investigated to reveal the major factors that control the instability problems and to design an optimum mud window. In the present work, a 1-D mechanical earth model (MEM) was constructed using numerous field data for Nahr Umr formation. Based on the offset well data, open hole wireline logging measurements (e.g., density logs, gamma ray (GR) logs, sonic logs, formation micro-imager (FMI) logs, porosity logs, resistivity logs, drilling records, and mud logs (master logs)) the magnitude and orientations of the in-situ principal stresses, pore pressure, and rock mechanical properties were estimated. The 1-D-MEM was verified and calibrated using all the available data (i.e., drilling observations, caliper logs, results of image data interpretation, repeated formation test (RFT), hydraulic fracturing, and laboratory rock mechanical properties, etc.) such that it robustly and accurately predicts shear failure around given wellbores. The generated model was then coupled with three failure criteria (i.e., Mohr-Coulomb, Mogi-Coulomb, and Modified Lade) to analyze the existing wellbore stability problems for wells with directional profiles and to determine the appropriate mud weight to drill a well in any desired direction. Our analysis shows that the majority of the wellbore instability problems are mainly caused by; rock failure around the wellbore due to high stresses and low rock strength, and inappropriate drilling practice.

ABSTRACT: Wellbore stability is still a primary concern in the oil/gas well drilling industry in spite of several decades of research. Wellbore instability may incur large financial losses, especially for offshore wells or ultra-deep onshore wells. Naturally fractured shale formation has been recognized as one of the major sources of wellbore instability issues. Thus, a better understanding of the mechanisms of wellbore instability in naturally fractured shale formations is highly desirable. In this paper, we present a three-dimensional hydro-mechanical finite element model for analyzing the evolution of damage zone around the wellbore and evaluating the stability of wells drilled in naturally fractured shale formations with a single system of parallel fractures. A jointed material plasticity model is adopted to account for the strength anisotropy due to the existence of fractures. Permeability of the formation is also treated as anisotropic to honor the fact that drilling fluid infiltration along the fracture direction is easier than that along the direction normal to the fracture plane. Furthermore, an inertia-based stabilizing method that we have proposed previously is employed to overcome the numerical convergence difficulty. The finite element model has been applied to analyze the stability of an actual well drilled in Bohai oilfield of China where wellbore instability issues have been frequently encountered within the naturally fractured shale intervals. The impacts of drilling fluid density and drilling fluid infiltration on the shape and size of the damage zone around the wellbore are demonstrated, and some implications for maintaining wellbore stability in these naturally fractured shale formations have been gained.

ABSTRACT: Wellbore stability is an important issue for drilling a horizontal well or an extended reach well. In this paper, the distribution of the breakdown pressure and collapse pressure is calculated with varying well inclination and azimuth angles. Considering the formation seepage, the mud density window for wellbore stability is obtained for different cases of in situ stress. The open-hole extension limit of the horizontal section in an extended reach well can be determined using these results. The results show that when (equation) the mud density window will become narrower with increasing deviation angle. Meanwhile, the mud density window becomes narrower or disappears as the in situ stress disparity increases. In addition, when the horizontal well section is drilled along the direction of s h, the wellbore stability achieves the safest state. The extension limit length of the open-hole horizontal section in the extended reach well can also reach its maximum value. The open-hole extension limit will continue to increase as the annular wellbore friction is reduced.

ABSTRACT: Wellbore instability and formation sand production pose potential risks for wellbore drilling, completion and production operations. In many sandstone reservoirs worldwide, sand production has been observed to accompany oil and gas production. In this study, we aim to estimate, predict and quantify wellbore instability and sand production potentials in the Hajdúszoboszló field, Pannonian Basin, Hungary, using the Mechanical Earth Model (MEM). Our study relies on petrophysical log data obtained from an onshore gas well within the field as input data. Our 1-D MEM utilizes a workflow that develops wellbore and sand failure mechanisms, first creating the mechanical stratigraphy of the reservoir rock; followed by estimating the pore pressure, overburden stress, rock strength, rock elastic properties, and horizontal stresses of the reservoir rock with reference to the depth of stratigraphic column, from compressional slowness, shear slowness, density, porosity and shale volume. Lastly, we conduct a wellbore stability and sand management analysis. Our results show the mechanical stratigraphy of unconsolidated sandstone and shale distribution in the reservoir, wellbore shear and tensile failures, wellbore breakout and breakdown pressures, wellbore sensitivity analysis, sanding interval analysis, critical drawdown pressure (CDDP) profile and sand failure zones. Based on careful observation of our results, we predict the wellbore intervals with high sand production potentials and wellbore instability within the reservoir formations. Therefore, we suggest significant wellbore failure during drilling process and also a high possibility of sand production into the wellbore during well completion at a formation interval of 550-937 m. Although there is need for data from additional wells in the field to be incorporated into our model prediction, we suggest that our preliminary model can be useful for critical decision making during drilling and completion operations across the Hajdúszoboszló field, Pannonian Basin, Hungary. In addition, our study provides a platform for further investigation into wellbore stability and sanding analysis in other parts of the Pannonian Basin where available well data can also be incorporated in our model.

ABSTRACT: Analyzing offset wells is an indispensable step in designing new wells and corresponding drilling programs. Understanding past events and issues is at the core of the learning process necessary to augment operational efficiency. Large amounts of data, much of it unstructured, are used during this process. These datasets, if not handled properly, can at best substantially dampen the learning curve and at worst produce incorrect conclusions.

ABSTRACT: Rising demand in higher productivity as well as reducing drilling damages has encouraged companies to use mechanical earth modeling (MEM) for developing fields. Conventionally, in a safe mud weight window there are four different bounds which are employed by drillers to avoid possible operational challenges such as kick, loss, breakout and breakdown. However, there are sometimes zones where the boundaries are transgressed to one another and a safe mud weight window cannot be determined. In this study, we presented a numerical solution to calculate the optimum mud weight by defining an indicator for growth of the plastic zone around the borehole by using an elastoplastic model which provides more realistic evaluations of wellbore integrity than linear elastic model. Results showed the proposed method finds the mud weight which is high enough to tolerate the breakouts and yet low to attenuate mud losses. Method was utilized in a real case and results were then compared with the drilling data and verified the efficiency of the presented methodology.

ABSTRACT: DSDG-375 Drawworks TDS-11SH Top Drive ST-100 Iron Roughneck Dual FD-1600 Mud Pumps and 14P 7500 psi fluid end ZP375 Rotary Table Pipecat system PS-21 power slips STV (stand transfer vehicle) racking system 1,000 bbl (159 m 3 ) mud systems Solid control equipment Amphion Control System NOVOS Drilling Automation System A modern drilling testing facility equipped with a 375-ton, 1,500 HP drilling rig was built near Navasota in Grimes County, Texas. Starting 2014, more than 30 vertical/deviated/horizontal wellbores were successfully drilled and cemented back to shoe inside 20’’ and 13-3/8’’ casing after planned utilizations for testing were fulfilled for each individual wellbore. All the child welbores were drilled through one single parent wellbore. Non-reservoir shales and sands were penetrated in all drilled wellbores. Drilling and testing for vast amount of drilling automation, drilling optimization, rotary steerable systems, mud motor, MWD, reamer, agitator and other downhole drilling tools, surface rig-related tests and condition monitoring have been successfully conducted through these wellbores. For a new drilling field, it is imperative to build a geomechanical model to plan and execute safe and efficient drilling operations. Compensated neutron density log and sonic log were used to build the geomechanical model, together with offset and actual mud weights. Formation stress, rock strength, minimum mud weights and fracture gradients are modeled and calibrated using available drilling data such as leak off tests and lost return records. Future drilling and testing data can be used to continuously calibrate and finetune the geomechanical model. The modeling results can be used to quality control future deepened, deviated and horizontal well planning and borehole stability study.

ABSTRACT: Induced stresses are one of the main factors affecting wellbore instability and associated problems in drilling operations. These stresses are significantly impacted by pore pressure variation and thermal stresses in the fields. Heat and fluid transfer capability of rock and thermal expansion coefficient are important parameters in the study of stresses using a thermo-poroelastic model. In this study, the field equations governing the problem have been derived based on the thermo-poroelastic theory and solved analytically. Afterward, the couple of 50 mm synthetics sand-cement samples are applied in laboratory experiments. The u stresses and wellbore pressure are applied on the sample in a true triaxial stress cell (TTSC). In the laboratory tests, the temperatures are controlled and cooled oil is injected into the sample. The strains are measured and calculated based on experiment and model. In the next step, a genetic algorithm has been applied to solve an inverse problem and get a match between experimental data and the modeling results. Ultimately, the important properties for the interactions of fluid and rock can be estimated. With this approach, the required thermal and flow parameters are estimated with good accuracy without using time consuming and costly tests. 1. INTRODUCTION

ABSTRACT: The main objective of this study was to investigate wellbore stability in shales after and before adding the conventional LCM particles in combination with a novel nanocomposite to a weighted water based drilling mud. A unique Pore Pressure Transmission (PPT) apparatus was used to evaluate the plugging capabilities of the mixtures. Results showed that the presence of nanocomposite was conductive to forming a thinner impermeable mud-cake to effectively reduce water invasion and prevent pore pressure transmission into the water-sensitive shales formation at an earlier stage of the shale-fluid interactions. However, the pore pressure would gradually increase over time if only LCM materials were in the existence of the drilling mud. When the test time went on for 8 hours, the downstream pressure increased to 80% of the upstream pressure. Results also showed that the combination of nanocomposites and the conventional LCM materials in appropriate proportion could create a lasting and effective sealing during drilling in shales, but the combinational material was incapable of sealing the fracture seen by the naked eye. Hence, the fast sealing developed through the combinational method was essential to resolve the problems of wellbore instability in Shales.

ABSTRACT: In this paper, the optimization model has been established to optimize 3D horizontal well trajectory in shale gas field. Two types of well trajectory have been discussed according to the whole trajectory and the correction trajectory. The sensitivity analysis of wellbore stability versus inclination angle and azimuth angle is conducted. The optimization model takes drilling depth as objective function and takes wellbore stability, dogleg severity as constraints. A new heuristic algorithm named differential search algorithm (DS) has been applied to optimize well trajectory combined with penalty function. At last, case study is presented and it demonstrates that the proposed optimization model can obtain a trajectory with minimum drilling depth under the constraints of wellbore stability and dogleg severity. It also indicates that DS has an excellent performance with high accuracy and stability for 3D well trajectory optimization. 1. INTRODUCTION

Abstract: The present paper develop an integrated geomechanical wellbore stability model that incorporates the theoretical derivation regarding Mogi-Coulomb strength criterion with the favor of Lode's parameter and stress invariants, the anisotropic rock strength characteristic associated with weak plane, the coordinates transformations pertaining to borehole and weak plane systems as well as chemo-poro-thermoelastic solutions around a pressurized inclined borehole to analyze the extent of shear failure and tensile fracture regions in horizontal boreholes. The results regarding a horizontal wellbore drilled along the direction of minimum horizontal in situ stress from present paper show that increasing the mud salinity could contribute to consolidating the formation and alleviating the wellbore instability with respect to shear failure where thermal osmosis intensifying the chemical osmosis effect. Moreover, the drilling mud with higher salinity where thermal osmosis weakening the chemical osmosis effect boosts the favorable conditions required for concurrence associated with longitudinal and transverse fractures in the top and low sides of the horizontal wellbore while the corresponding combined tensile fracture regions progressively aggrandize with time progress. Introduction Wellbore instability issues are often encountered when drilling the inert to generating mud cake due to low permeability regarding shale formation with the laminated heterogeneity and chemically active characteristics in deep high temperature environment by horizontal borehole. Accordingly, it is necessary and urgent to understand the complex wellbore instability mechanism with reference to time dependent reestablishment of stresses and pore pressure around ther wellbore determined by poroelastic effect associated with undrained loading after instantaneous bored (Detournay and Cheng, 1988), chemical effect related to the chemical osmotic flow resulting from solute transfer (Heidug and Wong, 1996; Yu et al.,2003; Ghassemi and Diek, 2003; 2009; Zhou and Ghassemi, 2009) as well as water activity difference (Chen et al., 2003) between drilling mud and pore fluid in shale formation, thermal effects arising from heat transport (McTigue, 1986; Chen and Ewy, 2005; Zhou and Ghassemi, 2009) and thermal osmotic (Ghassemi and Diek, 2002; Ghassemi and Diek, 2009). Shale formations are characterized by parallel discontinuous planes of weaknesses configurations of which may exhibit pronouncedly more potential to fail along the slip surfaces as compared to through compact rock matrix. Accordingly, the strength criteria pertaining to shale rock may be determined by different controlling factors associated with dominated failure behaviors. In regard to intact rock failure, poly-axial shear failure strength criteria, such as: Modified Lade (Ewy,1999) and Mogi-Coulomb (Al-Ajmi and Zimmerman, 2005) appropriately evaluate the strengthening effect concerning the intermediate principle stress such that efficiently guide the practical drilling designs, however, Mohr-Coulomb criterion is expected to be significantly conservative in estimating the minimum mud pressure required to ensure the wellbore stability, since the influence of intermediate principal stress on rock strength is disregarded. In another aspect, the single plane of weakness theory is expressed in the form of Mohr-Coulomb differentiating failure modes of the intact rock and weak plane by the angle between major principal stress and the normal of isotropic planes of laminated medium (Jaeger et al.2007).

Abstract: The analytical poroelastic solutions for an inclined wellbore drilled through an N-porosity N-permeability porous medium were derived, taking into account the mudcake buildup on the wellbore wall. To extend the application of this general solution, a triple-porosity porous medium is studied to illustrate the pressure and stress distributions around the wellbore. Moreover, the stress cloud approach is presented to visualize the wellbore failure potentials and the Drucker-Prager criterion is applied to analyze wellbore shear failure. Each set of porosity is found to significantly influence the stress clouds at the wellbore wall and the mudweight window. Comparison analysis shows that the single porosity simulation predicts the widest mudweight window, followed by the dual-porosity simulation, and then the triple-porosity simulation. Compared to the single porosity case, the dual- and triple-porosity simulations predict 8.0% and almost 15.0% higher collapse mudweights, respectively. Mudcake also plays an essential role in the wellbore stability. Its effect could be to shift down of the stress cloud and therefore decrease the wellbore failure potential. Mudweight window is also found to be sensitive to mudcake thickness and permeability, which clearly shows that mudcake effects should be taken into account. Introduction The poroelastic solutions for an inclined wellbore have played an essential role in the wellbore stability analysis for drilling through a fluid-saturated porous medium. The wellbore stability is severely affected by the time-dependent poroelastic responses of the fluid-saturated porous medium, such as the evolutions of stresses and pore pressure around the wellbore which might lead to time-delayed failure (Cui et al. 1997; Abousleiman et al. 2000). Early analyses of the time-dependent stresses and pore pressure responses after excavation were presented by Carter and Booker (1982) who gave the analytical solutions for a circular tunnel excavated in a fluid-saturated medium. Detournay and Cheng (1988) derived the analytical solutions for a vertical wellbore under non-hydrostatic stress field and showed that shear failure could be initiated inside the formation rather than on the wellbore wall. The complete analytical solutions for an inclined wellbore drilled through an isotropic fluid-saturated porous medium was given by Cui et al. (1997). Later, the solutions were generated to account for material transverse isotropy (Abousleiman and Cui 1998) and time-dependent pore pressure and flux boundary conditions (Ekbote et al. 2004). For a naturally fractured fluid-saturated rock formation, using the dual-poroelastic formulation, Wilson and Aifantis (1982) presented the analytical solutions for a vertical wellbore under hydrostatic state of stress and Li (2003) for a vertical wellbore under non-hydrostatic state of stress. Abousleiman and Nguyen (2005) derived the complete analytical solutions for an inclined wellbore drilled through a naturally fractured rock formation and subjected to three-dimensional state of stress. Dual-porosity simulation was found to predict narrower mudweight window than single porosity simulation (Nguyen and Abousleiman 2009; Nguyen et al. 2009). Analytical solutions were also derived for inclined wellbore problem accounting for chemo-electrical and thermal effects which are found to be crucial in wellbore stability analysis (Ekbote and Abousleiman 2005; Ekbote and Abousleiman 2006; Nguyen and Abousleiman 2010).