Wellbore Stress Research Articles

Safe mud weight window in wellbore with mud-cake: A simple solution and verification

Under overbalanced drilling condition, a layer of particulates from drilling mud, called mud-cake or filter-cake, is often formed on the wellbore surface as the drilling fluid seeps through the surrounding geological formation. Mud-cake acts like a soft filter reducing the fluid pressure exerted on the wellbore surface by the fluid in the well. In this work, the safe mud weight window for wellbores with mud-cake is analytically derived by combining the long-term poroelastic wellbore stress solutions with steady-state flow solution for a two-layer cylindrical well. Parametric study on mud-cake permeability and thickness verifies that a wellbore with mud-cake transits smoothly from permeable wellbore to impermeable wellbore as the mud-cake accumulates. The new solution of breakdown pressure is also validated by a hydromechanical interaction numerical simulation.

Stress corrosion phenomenon of casing in CO2 medium and magnetic memory detection

Due to being in an acidic CO2 environment and high-pressure underground, the stress corrosion phenomenon on the inner wall of the CCUS wellbore is more pronounced, with the possibility of wall thickness reduction and crack propagation, which affects the integrity and storage reliability of the wellbore. This article conducted indoor experiments on stress corrosion of oil casing, and characterized the stress corrosion through magnetic memory detection technology. Through experiments, the stress corrosion morphology of specimens under different concentrations, stresses, and defects was obtained. The microstructure of the stress corrosion site was observed using SEM electron microscopy, and the stress corrosion situation of the material in CO2 was observed, laying a foundation for magnetic memory detection; A stress corrosion detection method under CO2 environment was proposed, and the magnetic memory detection method was used to measure that the more severe the stress corrosion, the more obvious the magnetic signal mutation; The shape and morphology of different defects vary, but the main factors affecting magnetic memory signals are concentration and loading force. This article verifies the feasibility of magnetic memory in stress corrosion detection through experiments, and characterizes the stress corrosion situation using magnetic memory signals, which is of great significance for non-destructive testing of wellbore stress corrosion in CO2 storage.

Contribution of mine borehole data toward high-resolution stress mapping: An example from northern Bowen Basin, Australia

Most of in-situ stress data in the Australian continent comes from wellbore stress analysis in deep hydrocarbon reservoirs, and earthquake focal mechanism solutions near the Australian plate boundaries, where geophysical tools facilitate understanding of the present-day stress patterns. This resulted in a paucity of stress information in many other regions such as the northern Bowen Basin, which is an active mining province, but with low seismicity rates and limited deep petroleum exploration. The mining industry runs several hundred kilometres of image logs annually to characterise geotechnical attributes. These logs provide an image from the borehole wall, which facilitates analysis of stress-related borehole deformations for in-situ stress characterisation. This paper examines the orientation of horizontal in-situ stress using different types of image logs in mine boreholes across the northern Bowen Basin. Analyses of 128 km of image logs in 680 vertical boreholes resulted in the interpretation of 9046 pairs of stress-related indicators including 735 drilling induced fractures and 8311 borehole breakouts. Our comprehensive database comprises 890 quality-ranked data records for the orientation of maximum horizontal stress (SHmax), which makes the Bowen Basin as a basin with the highest data density in the world in terms of quality-ranked stress information according to the World Stress Map. Statistical analysis of SHmax orientation reveals that the mean SHmax orientation in northern Bowen Basin is N018° ± 16°. The results show that this orientation is consistent over long distances, which is in contrast with several eastern Australian basins. This uniform stress pattern agrees well with plate-scale geomechanical model predictions, which further highlights the impact of plate boundary forces in the contemporary stress pattern of this region. Detailed image log investigation did not show any systematic rotation of stress; however, some small-scale stress perturbations were observed in the vicinity of sharp stiffness contrasts and geological structures.

The radial distribution of natural fracture density around the wellbore during drilled cuttings/produced water reinjection and well construction

Drilled cuttings or produced water reinjection, drilling operations, and even wellbore stimulation are operations that can exploit the knowledge of natural fractures around wellbores. However, there is currently no robust model that quantifies Natural Fracture Density (NFD) around wellbores, to manage the highlighted operations. This is a problem when one considers environmental pollution caused by drilling waste leakage through natural fractures. During wellbore construction, natural fractures may enhance lost circulation, which causes well-control problems. Existing predictive models cannot quantify the NFD (which is in units of count per meter) around the wellbore because of the limitations in handling the total strain. Hence, it becomes difficult to understand how geomechanical parameters, wellbore geometry, or petrophysical variables affect the NFD. Thus, this study was carried out to eliminate these gaps. The strain energy of poroelastic rocks, fracture-area energy, and geomechanical analysis were combined to quantify the NFD. The total strain was decomposed into deviatory strain and volumetric strain, using the principal stresses. Then, based on geomechanical analysis, the tangential, axial, and radial stresses were incorporated, using Kirsch's wellbore stresses. The model was applied to a wellbore that is near the Atlantic Ocean, on the passive continental margin of the Niger Delta Basin, and comprising paralic sandstones of the Miocene. The results showed that the NFD decreased from the walls of the wellbore exponentially. Increasing the wellbore inclination reduced the NFD, but the increase in porosity caused the NFD to increase. The increase in Poisson's Ratio (PR) showed a different relationship with the NFD. The NFD reduced slightly as PR was increased from 0 to 0.2, but increased significantly as PR was increased from 0.2 to 0.5. In addition, the NFD oscillated sinusoidally with the azimuth, at some frequency. The results were validated by different literature sources and field observations.

Rock Mechanical Properties and Wellbore Stability of Fractured Dolomite Formations.

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

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

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

Geomechanics Successfully Implemented in a Deepwater Setting

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202146, “Successful Implementation of Geomechanics in a Deepwater Setting: A Case Study From KG Offshore India,” by Sarah Bhimpalli, ONGC; Ashok Shinde, Baker Hughes; and Bayye L. Rao, ONGC; et al. The paper has not been peer reviewed. _ Geomechanics plays an important role in assessing formation integrity during well construction and completion. In the complete paper, study field K belongs to a Plio-Pleistocene sequence in a deepwater environment with hydrocarbon prospects. As a part of exploration activity, four existing offset oil wells were considered for geomechanical model construction. The geomechanical model for the field was built by integrating available drilling, geology, petrophysics, and reservoir data. The methodology adopted in this paper highlights how a reliable geomechanical model can be built for a field with data constraints. Introduction The present study block is in deep water off the eastern Indian coast in the KG basin, with several hydrocarbon discoveries in a clay formation. These reservoirs have been deposited under marine conditions, and source rock is thought to be Eocene to Oligocene marine shale. During drilling, as the rock on the wellbore track was drilled and brought out of the hole, the drilling fluid would exert a corresponding pressure on the wellbore wall and the stress of the rock surrounding the wellbore would be redistributed, generating induced stress. To maintain wellbore stability, use of a drilling fluid of appropriate density (mud weight) to control induced wellbore stress is essential. Shear and tensile failures are the major causes of mechanical instability in boreholes. If it rises past the appropriate upper limit, drilling-fluid pressure can cause tensile failure in the wellbore wall; if lower than the appropriate lower limit, drilling-fluid pressure can cause shear failure in the wellbore wall. Because of several drilling complications and nonproductive time experienced during the exploratory phase, building of a geomechanical model for safe and cost-effective drilling during the development phase is necessary. The existing four wells (W, X, Y, and Z) targeted the hydrocarbon play. Using the data from the four offset wells, a comprehensive geomechanical study was completed. The main objectives of the study included pore-pressure prediction, wellbore-stability analysis, well-trajectory optimization, and sanding prediction. 1D Geomechanical Modeling To analyze wellbore stability, well logs, laboratory test results, and drilling reports of the wellbore were used to determine geomechanical characteristics of the drilled formations. The elastic properties, rock strength characteristics, in-situ stresses, and pore pressures are the most important geomechanical characteristics to be measured or calculated. The geomechanical model was built by integrating drilling, geology, petrophysics, and reservoir engineering data. The work flow to build the geomechanical model is presented in Fig. 2 of the complete paper. Vertical stress (Sv) was estimated by integration of density logs from seabed to reservoir. Pore pressure was predicted using normal compaction trend (NCT) on log data. Minimum horizontal stress (Shmin) was constrained using leakoff tests (LOTs) and mini- and microfracturing data. No rock-mechanical testing data were available, and rock properties were estimated from petrophysical logs using regional experience. Magnitude and orientation of maximum horizontal stress (Shmax) was constrained using the presence of stress-induced wellbore failures on image and caliper logs.

Geomechanical analysis of the geothermal reservoir at San Emidio, Nevada

The WHOLESCALE (Water and Hole Observations Leverage Effective Stress Calculations and Lessen Expenses) project is aiming to simulate the spatial distribution and temporal evolution of stress throughout the geothermal system at San Emidio, Nevada, United States, via a thermo-hydro-mechanical reservoir model. Focal mechanisms for microseismic events during a temporary shutdown of the geothermal power plant in 2016 were analyzed through linear stress-inversion methods to infer the in-situ reservoir stress state. This analysis was supplemented by other geophysical and geological data, including focal mechanisms from regional earthquakes, slickenlines on exposed fracture surfaces, wellbore stress indicators observed in the surrounding region, and secular strain rate measurements. From the inferences of in-situ reservoir stress, 78 different realizations of stress models were generated over reasonable ranges for the values of maximum compressive horizontal stress (SHmax) azimuth and ratios of principal stress magnitudes. Evaluation of slip tendencies on fault planes determined for the microseismic events for each realization of the initial stress model suggests the reservoir stress state as transtensional with an SHmax azimuth between N and N30∘E.

Wellbore Stability in the Bazhenov Formation Considering the Anisotropy of Elastic Properties of Composing Strata

This paper offers a general approach to the modelling of the wellbore stress state in the Bazhenov formation. In modelling, strata are presented as transversely isotropic objects with a set direction of the anisotropy axis that does not coincide with the vertical line. The paper also presents results of the laboratory Bazhenov formation core analysis. The analysis of core materials yielded correlation dependences for reconstructing stress-strain parameters of a transversely isotropic medium in selected wells. Parameters of the rock anisotropy were analyzed on the basis of standard and non-standard laboratory tests. The solution of the stress state problem in a deformation bounded medium was used to suggest an algorithm of calculating the components of the regional stress state along the well path. RN-SIGMA software tools were used to construct borehole stability models for wells penetrating anisotropic rocks. The effect of the anisotropy of elasticity on a safe drilling mud density window is demonstrated. The results of the calculations show that the anisotropy effects are crucial for calculating a safe drilling window. Examples are given to demonstrate potential effects of the anisotropy in image interpretation as well as in selecting horizontal wellbore drilling directions.

Propagating Hydraulic Fractures from Wellbores: Effects of In-Situ Stress and Near-Wellbore Stress Redistribution

Summary As a mature technology to enhance the permeability of geological formations, hydraulic fracturing has widely been used in geothermal energy development and in the petroleum industry. Due to its effectiveness in practical applications, it attracts many research efforts. Because of the complexity of hydraulic fracturing itself and the complex distribution of stresses around wellbores, accurately describing the behaviors of hydraulic fractures is still a challenging task. In this study, a numerical model is developed to simulate curved propagation of hydraulic fractures from a wellbore, and emphases are placed on influence of in-situ stress and near wellbore stress redistribution. In the developed hydromechanical model, special considerations are given to its ability to simulate curved propagation of hydraulic fractures. The propagation of fractures is modeled through the phase-field method. Several cases on hydraulic fracture initiation and propagation from horizontal wellbores are studied through the proposed model. The model has been successfully verified through analytical solutions. The influence of stress redistribution caused by wellbore pressurization on hydraulic fracture initiation from wellbores is analyzed. Under different in-situ stress configurations and initial fracture orientations (perforation or flaws around wellbores are represented by the initial fractures), several patterns of hydraulic fracture propagation around the wellbores are recognized. It is found that the stress redistribution in the close vicinity of wellbores has great influences on the fracture initiation and propagation, and it makes hydraulic fractures propagate in nonplanar, complex manners. As hydraulic fractures propagate away from the stress redistribution regions around the wellbores, in-situ stress then determines the directions of fracture propagation; the curvature of fracture growth paths is mainly determined by the difference in in-situ stress, for example, σv − σhmin in this study. It has also been demonstrated that, when analyzing fracture propagation from wellbores, the wellbore stability or nonlinear deformation of a wellbore should be considered together with the fracture propagation conditions.

Study on the Influence of Overflow Well Shut-In Mode on Wellbore Pressure Distribution in Ultradeep Wells

Summary With the deepening of exploration and development of oil and gas resources, more complex oil and gas reservoirs have been found, and oil and gas well drilling has gradually developed to ultradeep (>8000 m). In the oil and gas exploration and development of deep and ultradeep wells, a small-size borehole is usually used to uncover the target layer. In the drilling stage, the annular space gap of slimhole construction is small, the pressure difference is large, and the tripping fluctuation pressure is large; therefore, overflow is easy to occur. Because the upward channeling speed after overflow is fast, the pressure fluctuation caused by shut-in is large, and the requirements for well control are high, making it very important to study the shut-in mode after drilling overflow and the fluctuation of annulus pressure to ensure the safety of ultradeep well drilling. However, the current research on shut-in mode only focuses on changing the length of shut-in time and does not consider the operation steps of closing different components. It is obviously not rigorous to simplify semisoft shut-in and soft shut-in into a hard shut-in process with a long time. In this paper, the pressure wave velocity model and transient flow model of multiphase flow in the annulus are established. The shut-in process of different wellhead components is considered for the first time, the corresponding wellhead opening function is constructed, and the effects of different well shut-in methods on annulus pressure distribution and water hammer effect are studied. Some conclusions can be drawn: The annulus pressure wave velocity aam decreases rapidly with the increase of void fraction and decreases gradually with the increase of solid particle concentration. After hard shut-in, the wellhead pressure increases rapidly and fluctuates periodically. The shorter the shut-in time, the greater is the wellhead pressure. The displacement of drilling fluid has little influence on the pressure peak but has a great influence on the amplitude of pressure fluctuation. When the annulus pressure rises, the casing bulges outward to produce additional tension, while the drillpipe shrinks inward to produce additional pressure. When the annulus pressure drops, the casing shrinks inward to produce additional pressure, while the drillpipe bulges outward to produce additional tension. During soft shut-in, the closing time of the blowout preventer (BOP) has a great impact on the annulus pressure of the wellhead. When the shut-in time is short, the pressure rises instantaneously and fluctuates violently and the cycle is short; during semisoft shut-in, the larger the opening of the throttle valve, the smaller is the fluctuating pressure of the wellhead when the BOP is closed. When the throttle valve is closed after the BOP is closed, then the larger the opening of the throttle valve, the greater will be the fluctuating pressure. With the calculation and discussion of wellbore stress distribution during shut-in of an overflow well in this paper, we hope to provide reference for two groups of people mainly. For one thing, it can offer a new idea, calculation method, and meaningful conclusion to other researchers who are studying in this area. For another, it will help engineers making decisions when overflow occurs.

Investigation of interference from multiple oriented hydraulic fractures while considering near-radial wellbore stress distribution

Stratigraphic sequences are sometimes thin, rarely ideally horizontal and juxtaposed due to faulting. Wellbore trajectories targeting such strata may not be necessarily horizontal aligning with principal stress direction. Perspective from perforation orientations typically embeds understanding of fundamental fracturing issues such as high treating pressure, premature screen-outs, and tortuous and short-circuited fracture paths among others. One or more of these issues may influence other drawbacks making the overall problem more complicated. The objective of this study is to investigate the influence of stress shadow effect of multiple fracture propagation on treating pressure and fracture geometries (apertures, lengths, heights, and tortuosity) then later introduce a new concept of controlling fluid entry into multiple oriented perforations through modification of entry elements combined with radial wellbore technology. The study demonstrates that both simple bi-wing and complex multiple bi-wing fractures are associated with low treating pressure when combination of high phase/high or low orientation angles, illustrated with 1800/900 and 1800/00, is used. It has further shown that oriented perforation reduces the extent of fracture closure zone around the crack mouth. Sequential and simultaneous techniques are implemented with their comparison demonstrating that sequential fracturing is associated with elevated fluid pressure after first injection. A maximum error as low as 0.52 MPa is recorded during the bottom hole pressure analysis. Optimized results from restricted fluid entry elements, simulated within XFEM computational domain capable of accommodating fracture-turning effect, minimized fracture choke-like effect producing relatively uniform fracture development. The new elements are validated against KGD model. The model is further validated against published experiments and Daqing Oilfield data with good match of results in both cases. The study is important for field implementation of hydraulic fracturing in stratigraphically thin reservoirs with well trajectories disoriented from principal stress direction.

Perforation location optimization through 1-D mechanical earth model for high-pressure deep formations

Optimum perforation location selection is an important study to improve well production and hence in the reservoir development process, especially for unconventional high-pressure formations such as the formations under study. Reservoir geomechanics is one of the key factors to find optimal perforation location. This study aims to detect optimum perforation location by investigating the changes in geomechanical properties and wellbore stress for high-pressure formations and studying the difference in different stress type behaviors between normal and abnormal formations. The calculations are achieved by building one-dimensional mechanical earth model using the data of four deep abnormal wells located in Southern Iraqi oil fields. The magnitude of different stress types and geomechanical properties was estimated from well-log data using the Techlog software. The directions of the horizontal stresses are determined in the current wells utilizing image-log formation micro-imager (FMI) and caliper logs. The results in terms of rock mechanical properties showed a reduction in Poisson’s ratio, Young modulus, and bulk modulus near the high-pressure zones as compared to normal pressure zones because of the presence of anhydrite, salt cycles, and shales. Low maximum and minimum horizontal stress values are also observed in high-pressure zones as compared to normal pressure zones indicating the effects of geomechanical properties on horizontal stress estimation. Around the wellbore of the studied wells, formation breakouts are the most expected situation according to the results of the wellbore stress state (effective vertical stress (σzz) > effective tangential stress (σθθ) > effective radial stress (σrr)).

Influence of the Weakening Effect of Drilling Fluid on Wellbore Stability in Anisotropic Shale Formation

For horizontal wells in Longmaxi Formation, oil-based drilling fluid that soaks for a long time is more likely to cause a wellbore collapse. Therefore, in this paper, the downhole core method of shale formation, in Longmaxi Formation, was adopted. First, rock samples were selected from different sampling angles and soaked with field drilling fluid. Second, a triaxial mechanics experiment was carried out. Based on the anisotropic wellbore stress distribution model, the stability of shale wellbore was calculated and analyzed. The results show that the compressive strength and cohesion of the shale are reduced after soaking in the drilling fluid. Hence, the reduction range of various sampling angles obviously differs as well. Shear failure occurs in vertical stratification; shear slip failure occurs along the weak plane, showing strong anisotropy. Combined with the experimental results, the collapse pressure is calculated, and it is found that the weakening effect of drilling fluid makes the overall collapse pressure rise by about 0.2 g/cm3. Finally, the shale bedding dip and dip direction have a great influence on the collapse pressure. The lower critical mud weight always takes the minimum value when the borehole axis is perpendicular to the bedding.

Uncertainty failure risk quantitative assessments for underground gas storage near-wellbore area

The injection and withdrawal wells of underground gas storage (UGS) are prone to weakening the sealing performance of faults and cementation planes, under multiple rounds of injection-withdrawal alternations. To comprehensively quantify the stability of these weak planes under injection-withdrawal, the uncertainty quantification method is used to analyse the risk sensitivity of failure in the near-wellbore area (NWA). Based on the inversion technique of uncertain crustal stress intervals, three-dimensional Mohr-Coulomb and polar projection charts, high-precision geological modelling fault dip sampling point data and multidimensional technical evaluation index models are established. An uncertainty quantitative index of the shear slip failure risk of a borehole section under a coupled dynamic fluid pressure alternating with in-situ stress is constructed. A mechanical integrity analysis of the NWA weak planes, formation wellbore, and cement sheath is conducted. The stress change interval in NWA under alternate injection-withdrawal changes is then determined. Based on the quantitative analysis of the deterministic parameters and uncertainties, approximate results are obtained. The interval range of the wellbore stress change in the NWA provides a reference and optimization for the design of injection-withdrawal wells. The results show that a comprehensive quantitative analysis could be used to more comprehensively evaluate the sealing performance of NWA. The critical activation stress ratio and the opening angle have a high specificity for the opening and closing characteristics of the section. It is thus concluded that the proposed uncertain risk analysis method provides a comprehensive and quantitative tool for assessing the risk of slip at the fault level in the injection and withdrawal wells in UGS.

Effect of matrix shrinkage on wellbore stresses in coal seam gas: An example from Bowen Basin, east Australia

Coal matrix is subjected to shrinkage as a result of gas desorption. This can contribute to the stress distribution changes around the wellbore during the exploitation of Coal Seam Gas (CSG) resources. The knowledge of these stresses is essential for coal shear failure prediction and assessing coal fines production risks, particularly in horizontal wells which nowadays are becoming common in CSG fields.This study introduces an analytical model to estimate the stress distribution around the wellbore by coupling the effects of depletion, matrix shrinkage, and wellbore trajectory. The model is applied for coal failure analysis in both vertical and horizontal wells in Moranbah Coal Measures, in the Bowen Basin eastern Australia. The results reveal that the stress path value in CSG reservoirs, is not constant during production and it can even be more than one due to the matrix shrinkage. The shrinkage effect can significantly alter the effective horizontal stresses which accordingly can cause a considerable change to the near-wellbore stress distribution. It is shown that the stress differential may increase or decrease, depending on shrinkage/swelling magnitude and wellbore trajectory. In a normal fault stress regime, the matrix shrinkage decreases stress differential on the wellbore wall in vertical wells and consequently, reduces the coal failure potentials. However, in highly deviated and horizontal wells, the matrix shrinkage causes an extra increase of the tangential stress and reduction of radial stress on the wellbore wall (i.e., greater stress differentials on the wellbore wall). This increases the coal failure risks with depletion. The model was verified versus the observed coal failure pressure in the San Juan Basin, USA.

An Assessment of the Causes of Wellbore Instability and Stuck Pipe Occurrences in an Offshore Field, Niger Delta, Nigeria

Wellbore instability and consequential stuck pipe issues are a common challenge associated with offshore drilling. Usually, the effect of wellbore instability is an increase in nonproductive time, possible loss of tools and costly drilling operations. Hence, there is a need for wellbore stability analyses before and during drilling operations. In “Agaza Field”, offshore Niger Delta, wellbore instability problems were encountered at various depths between 3,696-4,270 ft.; 5,000-5,425 ft. and 7,600-8000 ft. intervals. Sixty-five ditch-cutting samples and composite log plots obtained from both wells were and analyzed to determine the clay swelling potential and the cationic exchange between the formation and the drilling fluid as well as causes of formation instability. Agaza-1 well showed evidence of tight hole at intervals between 4,200 and 7,600 ft. In Agaza-2, there were indications of wellbore stresses from 1,908 ft. to 2,030 ft. However, deeper than 4,225ft depth, high fluctuation of pore pressure coincided with wellbore instability between 4,810 ft. and 5,200 ft. The principal clay minerals present within the formations are Illite, Smectite and Smectite/Illite interlayered types. Result of the cation exchange analysis showed that high concentration of calcium and sodium in the shale is responsible for high dissociation of the constituent minerals hence making the shales unstable. Analysis has shown that samples at some intervals from both wells are associated with high swelling potential while average cation exchange value is 40 meq/100g. Therefore, the primary cause of wellbore instability and stuck pipe within the studied intervals are attributed to high swelling and reactivity over time due to fluidformation interaction. Keywords: Clay cationic exchange, Clay swelling potential, Offshore drilling challenges, Reactive shales. African

Transient Thermo-Poroelastoplasticity Finite Element Analysis of Inclined Wellbore Stability

Wellbore instability is a crucial concern problem in highly inclined well drilling, extended reach well drilling and horizontal well drilling, particularly in high temperature and high pressure (HPHT) formations. However, few studies have concentrated on the three-dimensional inclined wellbore instability analysis considering the influence of thermo-poroelastoplasticity and filter cake. In the present study, a three-dimensional inclined wellbore stability model fully coupling thermo-poroelastoplasticity and considering filter cake is created and analyzed using finite element analysis. This model can be used for the wells with any deviation angle and azimuth angles simply by changing the far field stresses and boundary conditions. The distribution of pore pressure and wellbore stress under various deviation angles, consolidation time and temperature gradients are investigated. The research results show that, the wellbore instability problem is generally severe in the inclined wells comparing to the vertical wells. The wellbore becomes unstable as the consolidation time increases, and it is more unstable under positive temperature gradient than under negative; the filter cake can reduce the pore pressure and stress around the wellbore, it prevents the wellbore from shear failure in vertical well (deviation 0o), and prevents the wellbore from tensile failure in inclined well especially in the horizontal well (deviation 90o). The results obtained in this paper can benefit a deeper understanding of the instability mechanism of inclined wellbore.

Geomechanical wellbore stability analysis for the wells drilled in the shallow sediments of the Mediterranean Sea

Gas hydrates are considered as near-future energy resources in the world. Due to high gas hydrate potential of the Mediterranean Sea, gas hydrate exploration wells are expected to be drilled. In this study, for the first time, the caliper logs of the wells drilled during ODP (Ocean Drilling Program) Leg 160 and ODP Leg 161 in the Eastern and Western Mediterranean Sea were evaluated together with the python codes predicting wellbore stresses, unconfined compressive strength (Co) and lower-hemisphere projection. The required Co in the Eastern Mediterranean Sea ranges from 60 psia to 2250 psia from seafloor to target depth. However, the estimated Co of the sediments in the Eastern Mediterranean in this study by using the python codes developed in this study and the caliper logs of ODP Leg 160 ranges from 15 psia to 1250 psia with depth. Similarly, the required Co to keep the wells in gauge and the estimated Co of the sediments in ODP Leg 161 range between 100-12000 psi and 30-11000 psia, respectively. Mostly, Co values of the sediments were less than the required Co values for stable wellbore so extensive washouts were detected both in the wells of ODP Leg 160 and Leg 161. This is because the sediments within gas hydrate stability zone in the Mediterranean Sea are weak and almost unconsolidated. Moreover, in this study, it was shown that it is possible to reduce the degree of washouts by increasing the density of drilling fluid until fracture pressure. According to the estimations in this study, the wellbore enlargements for the wells in ODP Leg 160 and ODP Leg 161 were mostly reduced below 2 inches, below which better wellbore stability conditions, better well log data and better casing cement quality might be obtained.

The Effects of Coupling Stiffness and Slippage of Interface Between the Wellbore and Unconsolidated Sediment on the Stability Analysis of the Wellbore Under Gas Hydrate Production

Gas hydrates have great potential as future energy resources. Several productivity and stability analyses have been conducted for the Ulleung Basin, and the depressurization method is being considered for production. Under depressurization, ground settlement occurs near the wellbore and axial stress develops. For a safe production test, it is essential to perform a stability analysis for the wellbore and hydrate-bearing sediments. In this study, the development of axial stress on the wellbore was investigated considering the coupling stiffness of the interface between the wellbore and sediment. A coupling stiffness model, which can consider both confining stress and slippage phenomena, was suggested and applied in a numerical simulation. Parametric analyses were conducted to investigate the effects of coupling stiffness and slippage on axial stress development. The results show that shear coupling stiffness has a significant effect on wellbore stability, while normal coupling stiffness has a minor effect. In addition, the maximum axial stress of the well bore has an upper limit depending on the magnitude of the confining stress, and the axial stress converges to this upper limit due to slipping at the interface. The results can be used as fundamental data for the design of wellbore under depressurization-based gas production.