Wellbore Failure Research Articles

Prediction and Application of Drilling-Induced Fracture Occurrences under Different Stress Regimes

Identifying and categorizing drilling-induced fractures is pivotal for understanding the mechanisms underlying wellbore instability, drilling fluid loss, and assessing reservoirs using imaging logging data. This study employs a linear elastic stress model around the wellbore, coupled with a tensile failure criterion, to establish a predictive framework for the orientation of drilling-induced fractures. It investigates how engineering parameters like wellbore trajectory and bottomhole pressure influence the distribution of principal stresses around the wellbore, as well as the angle and orientation of drilling-induced fractures relative to the wellbore axis, across various faulting scenarios. The results indicate that drilling-induced fractures exhibit structured arrangements and consistent patterns, often appearing at approximately 180° symmetric intervals and descending in similar orientations. This provides a theoretical basis for their systematic identification and classification. Under different stress conditions, these fractures can manifest as feather-like shapes, “J”-shaped, or transitional states between feather-like and “J”-shaped orientations, as well as “V”-shaped or “M”-shaped orientations. Accurate detection and classification of these fractures are essential for interpreting effective fractures, conducting thorough reservoir evaluations, and predicting appropriate drilling fluid densities to mitigate the wellbore failure risk. Moreover, this knowledge aids in effectively determining the magnitude and direction of in situ stress inversion.

Polyaxial failure criteria for in situ stress analysis using borehole breakouts: Review of existing methods and development of an empirical alternative

Analysis of compressive wellbore failure, or breakouts, is one of the primary methods of constraining the maximum horizontal stress in deep boreholes. To estimate stress using the observation of breakouts, one needs to measure the breakout width from image logs and use a failure theory to predict the stress that led to the development of the measured breakout. Most commonly, Mohr–Coulomb failure criterion has been used which disregards the influence of intermediate stress on strength. Hence, various polyaxial criteria have been proposed to include this effect. Here, we first review some selected polyaxial criteria: Drucker–Prager, Mogi, Modified Wiebols–Cook, and Modified Lade, and we conclude that their application in breakout analysis may be cumbersome and often unreliable. One reason for these problems is that the criteria are defined using stress invariants, while the stress estimation is most easily performed and analyzed in the principal stress space. Therefore, an alternative is to define the polyaxial criterion as a simple relation between maximum and intermediate stresses. We propose to define such an empirical criterion as a second order polynomial which fits trends observed in polyaxial laboratory strength data. Such approach allows to limit strength overestimation, often associated with the use of previous polyaxial criteria, and to easily relate uncertainties in strength estimation to uncertainty in maximum horizontal stress prediction.

Numerical investigation of wellbore damage due to drill string lateral vibration

During drilling operations, cyclic loading is exerted on the wellbore wall by the vibrations of the drill string. This loading could lead to rock fatigue, which in turn might result in wellbore failure. In this study, a numerical model is developed to simulate the effects of repeated loading on rock fatigue and failure. The simulation is based on an elasto-plastic constitutive model coupled with a damage mechanics approach, which allows us to examine the wellbore instability due to drill string vibrations. The model is verified with the existing data in the literature related to experiments on impact of a steel ball against a curved wall. The findings indicate that cyclic loading increases the development of plastic strain around the wellbore significantly compared to static conditions, promoting rock fatigue. Furthermore, the cyclic loading expands the radius of the yielded zone substantially, a critical factor for maintaining wellbore integrity. The proposed model can be used to evaluate the wellbore stability under repetitive loading caused by the drill string action.

Impact of long-term depletion on horizontal wellbore stability in tight reservoirs-including changes in petrophysical and geomechanical properties

The development of tight reservoirs using a horizontal well requires caution owing to the reservoir sensitivity to stress. Predicting the horizontal wellbore instability during reservoir depletion is critical for tight reservoirs. The present study investigated the wellbore failure criteria and stress orientation changes with reservoir depletion of a horizontal well in a tight reservoir, considering rock sensitivity to stress with pressure reduction. An integrated reservoir model coupled with geomechanics was used to predict pore pressure. A mechanical earth model (MEM) was constructed to examine the stability of horizontal wells. The unconfined compressive strength (UCS) was correlated with changes in porosity due to stress changes. The MEM shows that the failure criteria around the horizontal wellbore, including breakout, loss, and breakdown pressures, change considerably with reservoir depletion. A more significant response was observed in the stress-sensitive layer, which was characterised by a higher permeability. The safe mud weight window of the studied horizontal well narrowed significantly after production for five years, whereas the stability was completely absent after ten years. The deterioration of stability with depletion is governed mainly by permeability reduction, which may cause severe pressure reduction, whereas the stability improvement due to the increase in UCS caused by porosity reduction seems marginal. Relatively small changes in the direction of the stresses around the wellbore with depletion were observed, with the stress distribution concentrated in the predominant direction as the depletion continued. This study indicates that the sensitivity of petrophysical and geomechanical properties to stress amplifies the instability in tight reservoirs, particularly around wellbores.

Closed wellbore integrity failure induced by casing corrosion based on solid-chemical coupling model in CO2 sequestration

The safety and stability of carbon sequestration are key in CCS technology, and the wellbore is a critical pathway for leakage, which can lead to the failure of sequestration. In this study, the process of casing corrosion-induced closed wellbore integrity failure is investigated based on a solid-chemical coupling model. The influence of temperature and CO2 pressure on the development of cement damage is also investigated. The results show that the corrosion rate increases and then decreases with increasing depth, and the time of damage initiation gradually shifts backward. During the process of casing corrosion-induced cement damage, the corrosion scale that accumulates on the surface of the casing causes stress redistribution within the cement system. The damage initiates at the interface between the bottom of the cement system and the casing, progressing upwards to create a potential leakage pathway. Moreover, the damage in the cement sheath develops more rapidly, while the rate of damage development in the cement plug gradually decreases. This study will be helpful for understanding the initial stage of closed wellbore failure in carbon sequestration and for implementing corresponding preventive measures in engineering practice.

Study on transient prediction method of dynamic underbalanced pressure after perforation detonation in ultra-deep wells

Dynamic underbalanced pressure creates a significant transient pressure difference between the upper and lower ends of the packer and the inner and outer walls of the string below the packer, which can lead to the failure of the packer, the tubing, and the casing and is one of the main reasons for the low success rate of the perforation-acidizing-testing combined technology in ultra-deep wells. A danger caused by the dynamic underbalanced pressure is increased rapidly with an increase in the well depth. Despite the fact that researchers have a well enough understanding of the applications and benefits of the dynamic underbalanced pressure, the mechanism of the wellbore failure caused by the dynamic underbalanced pressure is inadequate. Therefore, a pressure drop model of tubing-casing annulus fluid is established, and a seepage model of reservoir rock is given. A transient prediction method of the dynamic underbalanced pressure is developed by coupling the pressure drop model and the seepage model. Then, the determining factors, key nodes of the maximum value, and derivation and propagation laws of the dynamic underbalanced pressure are revealed. An influence study focusing on an ultra-deep well is conducted. The obtained results indicated that the dynamic underbalanced pressure describes a fast drop in the annulus fluid pressure caused by the fluid flow among the annulus, the perforating guns, and the perforation tunnels since the pressures in the perforating guns and the perforation tunnels are lower than the annulus pressure after the perforation detonation. The annulus fluid pressure can slowly recover and increase due to the fluid flow between the screens and the annulus and the fluid flow between the reservoir rock and the wellbore. The main form of the wellbore failure caused by the dynamic underbalanced pressure is the casing collapse deformation. Therefore, changing perforating conditions, wellbore conditions, and reservoir rock conditions can increase the maximum for the dynamic underbalanced pressure to improve the success rate of the combined technology. The research presented in this paper can provide a new understanding and prediction method of the dynamic underbalanced pressure.

Wellbore breakouts in heavily fractured rocks: A coupled discrete fracture network-distinct element method analysis

Wellbore breakout is one of the critical issues in drilling due to the fact that the related problems result in additional costs and impact the drilling scheme severely. However, the majority of such wellbore breakout analyses were based on continuum mechanics. In addition to failure in intact rocks, wellbore breakouts can also be initiated along natural discontinuities, e.g. weak planes and fractures. Furthermore, the conventional models in wellbore breakouts with uniform distribution fractures could not reflect the real drilling situation. This paper presents a fully coupled hydro-mechanical model of the SB-X well in the Tarim Basin, China for evaluating wellbore breakouts in heavily fractured rocks under anisotropic stress states using the distinct element method (DEM) and the discrete fracture network (DFN). The developed model was validated against caliper log measurement, and its stability study was carried out by stress and displacement analyses. A parametric study was performed to investigate the effects of the characteristics of fracture distribution (orientation and length) on borehole stability by sensitivity studies. Simulation results demonstrate that the increase of the standard deviation of orientation when the fracture direction aligns parallel or perpendicular to the principal stress direction aggravates borehole instability. Moreover, an elevation in the average fracture length causes the borehole failure to change from the direction of the minimum in-situ horizontal principal stress (i.e. the direction of wellbore breakouts) towards alternative directions, ultimately leading to the whole wellbore failure. These findings provide theoretical insights for predicting wellbore breakouts in heavily fractured rocks.

Wellbore Instability Analysis to Determine the Safe Mud Weight Window for Deep Well, Halfaya Oilfield

Wellbore instability is one of the most common issues encountered during drilling operations. This problem becomes enormous when drilling deep wells that are passing through many different formations. The purpose of this study is to evaluate wellbore failure criteria by constructing a one-dimensional mechanical earth model (1D-MEM) that will help to predict a safe mud-weight window for deep wells. An integrated log measurement has been used to compute MEM components for nine formations along the studied well. Repeated formation pressure and laboratory core testing are used to validate the calculated results. The prediction of mud weight along the nine studied formations shows that for Ahmadi, Nahr Umr, Shuaiba, and Zubair formations ranges between 12.5 to 15 ppg. The predicted safe mud weight value seems to be narrow with a well deviation higher than 350. Therefore, for Ahmadi, Nahr Umr, Shuaiba, and Zubair formations, the wellbore appears unstable compared to other formations. The results of stability analyses indicate that the breakout mud weight wasn’t affected by wellbore azimuth because of low-stress contrast. Furthermore, shear failure can be prevented by drilling the well with an inclination of less than 350. As well as, to prevent breakdown the well should be drilled with an inclination between 25o to 65o in the direction of minimum horizontal stress. These outcomes could be used to prevent wellbore instability and determine a safe mud-weight window when planning to drill nearby wells in the future.

Analysis of Surge and Swab ECD of Herschel Bulkley Fluids in Rumaila Iraqi Oil Field

Surge and swab pressures are frequently produced during various stages of well construction, including casing running and tripping operations. Managing downhole pressure within the mud window is crucial for mitigating the risks associated with drilling operations including wellbore failure, lost circulation, kicks, and well control issues. The primary objectives of this study are to emphasize the theoretical foundation of surge and swab pressures, forecast the optimum pipe and casing tripping speeds, as well as identify the changes in surge and swab pressures (i.e., equivalent circulating density-ECD) for both open-ended and close-ended drill strings. To achieve these goals, a steady state surge and swab model was used to simulate a case study in the Rumaila oil field, located in Southern Iraq, by utilizing landmark-well plan software. The results of this study support the evidence that the string trip speed plays a substantial role in controlling the swab and surge pressures. It was found that pulling out the 5" drill string from the 12 1/4" open hole section drilled with a 9.51 ppg water-based mud at a speed of 10 sec/stand resulted in a swab ECD below the formation pore pressure against all formations, thus resulting in a kick. Moreover, it was found that the annular clearance had a significant impact on the surge and swab ECD whereas the surge ECD at the bit was bigger than that obtained at the previous hole casing shoe. For example, in our case study pulling speeds ranging from 10-190 sec/stand for the 9 5/8" casing could cause the swab ECD to be below the formation pore pressure gradient at total depth (TD), which is 9.23 ppg. While it was safe to run the same casing through the same interval within 55-190 sec/stand. Furthermore, the results emphasized high trip speeds ranging between 10-30 sec/stand, where for close-ended drill strings, greater surge ECD was observed compared to the open-ended ones. The surge ECD of a 5" close-ended drill string at 30 sec/stand (60 m/min) at bit was 9.92 ppg, while an open-ended string at the same speed was 9.9 ppg.

Building 1D Mechanical Earth Model for Subba Oilfield in Iraq

At the Subba oil field, wellbore stability is the main concern while drilling. The wellbore's instability causes several issues, including: (inefficient hole cleaning, tight hole, stuck pipe, mud losses, caving, bad cementing, and well kick or blowout). This increases Non-Productive Time (NPT) and well-drilling costs; hence the operator's main goal is to create a drilling program that reduces these problems and therefore reduce drilling cost. The study aims to build a 1D mechanical earth model to predict the wellbore failure and design optimum mud weight to improve the drilling efficiency for future wells. The model includes pore pressure, stress state, and rock mechanical parameters (such as UCS, angle of friction, Young-Modulus, and Poisson-Ratio). To achieve this aim, the study utilised offset well data including log data (Gama-Ray Logs (GR), Caliper Logs (CALI), Density Logs (RHOZ), and Compressional Sonic (DTCO) and Shear Sonic (DTSM)), Core tests, Mini-frac field tests, Drilling Reports, Mud Reports, and Mud Log Reports (master log) to estimate and calibrate the profiles of formation pore pressure, rock mechanical properties, and in-situ stresses. The 1D mechanical earth model was built using the Excel program for three wells data set, where all the necessary parameters to create the model was calculated, calibrated for the calculated variables with core data and pressure test points, and finally the safe mud window was detected. The results showed that the Eaton Slowness method to predict pore pressure perfectly matches the pressure test points. The most common fault regimes in the Subba oilfield are normal and strike-slip faults. The Modified Lade criteria showed a compatible match with drilling events and calliper log in predicting the failure zones, so it is the best criterion in determining minimum and maximum mud weight. Based on the results of this study and in comparison with the mud window used in drilling operations in the field, it is necessary to change the mud window used in drilling and adopt the safe MWW of this study in drilling new wells in this field and the area adjacent to the field.

Empirically informed convolutional neural network model for logging curve calibration

Environmental calibration of logging curves is critical for petrophysical interpretation and sweet spot characterization. Wellbore failure frequently occurs in clay-rich shale rocks during drilling, leading to biased logging interpretation and uncertainty. To reduce the biased correction or erroneous decision making in the interpreter-dominated logging curve calibration process, we develop an empirically informed convolutional neural network (EiCNN) logging curve correction strategy to calibrate the borehole failure-induced logging curve abnormity more accurately. The EiCNN method, together with high-quality logging curves as labeled samples, provides a nonlinear mapping between input logging curves and calibrations for the distorted curves. The EiCNN method completely alleviates biased correction or decision making by the interpreter-dominated method. It has a strong generalization ability, using many empirically interpreted high-quality data as input samples. The field validation wells demonstrate that the EiCNN model can precisely correct the distorted logging curves of mudstone segments with a correlation coefficient of >0.95. Moreover, the validation and test wells illustrate that the EiCNN method is capable of precisely correcting logging curves of interlayer mudstone, implying that the EiCNN method, to a certain degree, can also accurately perform environmental correction of logging curves from thin mudstone layers.

Integration of subsurface dynamic coupled modelling and monitoring technologies for CCS: examples from existing projects


 Introduction
 Host rock injectivity and storage complex integrity (containment) for CO2 sequestration are critical factors to ensure that capacity targets are met while preventing CO2 leakage over time and confirm permanent storage.
 
 Figure 1 sketches the typical CO2 injectivity problem. Evaluating injectivity, capacity and containment requires assessing key phenomena such as: seal and faults capillary controls, non-isothermal reactive flow, geomechanical failure induced in the seal, along faults and/or fractures and in the vicinity of the wells. Additional analyses will also be needed to evaluate the completion integrity of the wells (injectors, monitoring and existing wells) under variable load conditions in terms of pressure, temperature and chemistry. The listed phenomena, and their likely effects, are analysed by means of dynamic coupled modelling, considering co-existing (geo)mechanical and dynamic flow simulations. Therefore, coupled modelling improves the risk analysis allowing to evaluate the Thermo-Hydro-Mechanical-Chemical (THMC) processes associated to CO2 injection.
 Analyses
 In this presentation we will provide some examples of integration of subsurface dynamic coupled modelling and monitoring technologies for CCS. Some of these examples are derived from existing projects.
 
 Injectivity impairment during CO2 injection is a well-known issue often observed at well and field scale (e.g. Snøhvit, Ketzin, Decatur projects [1], [2]). Loss of injectivity is governed by the interactions between CO2-brine phase behavior, CO2-solid phase (rock) behavior, salt precipitation, multi-phase flow. Characterizing zonal injectivity and developing mitigation strategies will be therefore important for project success. Figure 2 (left and center) shows an example of time-lapse CO2 saturation evolution during injection and consecutive non-isothermal processes associated to Joule-Thompson effect (H2O vaporization, cooling and induced salt precipitation due to dry-out). Temperature and pressure changes can lead to near wellbore failure (thermal and pressure induced fracturing) impacting injection performance due to near wellbore fracturing and consecutive permeability changes (Figure 2 right).
 To close the evaluation loop, the integrated subsurface characterization workflow is completed by measurements to image the subsurface before and after CO2 injection. This provides essential insights into the storage complex quality before injection and effective monitoring during injection and permanent storage, tracking the position of the CO2 pressure and concentration plumes, assessing surface heave, and detecting any risks or potential leakage paths. There is a tight link between subsurface dynamic coupled modelling and existing monitoring technologies. This link expands the well-known MMV (Measurement, Monitoring and Verification) process into a more integrated 3MV process (Modelling, Measurement, Monitoring and Verification), opening to the definition of a subsurface digital twin supporting successful CCS operations. We will briefly introduce methods and technologies enabling the subsurface dynamic modelling and monitoring of CO2 injection and storage. Seismic and borehole petrophysical and geophysical measurements for initial subsurface characterization and consecutive monitoring will be described.

Integrated Formation Evaluation for Site-Specific Evaluation, Optimization, and Permitting of Carbon Storage Projects

Participation in over 80 carbon capture and sequestration (CCS) projects spanning 25 years has led to the evolution of a recommended well-based appraisal workflow for CO2 sequestration in saline aquifers. Interpretation methods are expressly adapted for CCS applications to resolve key reservoir parameters, constrain field-scale modeling, provide answers required for the permitting process, and de-risk unique CCS evaluation challenges, such as Storage capacity Injectivity Containment. A challenge complicating all of the above is the eventual impact of three-way interaction among rock matrix, brine, and (impure) CO2 streams. Most logging, sampling, and laboratory techniques are adapted from established domains such as enhanced oil recovery, underground gas storage, and unconventional reservoir evaluation, though some CCS-specific innovation is also needed. Storage evaluation begins with established methods for lithology, porosity, permeability, and pressure, while special core analysis (SCAL) determines CO2 storage efficiency and relative permeability. Containment evaluation spans multiple disciplines and methods: the petrophysicist’s task to quantify seal capacity relies heavily on laboratory analysis, while geologists leverage downhole imaging tools to verify caprock structural/tectonic integrity. Geomechanics engineers define safe injection pressure via mechanical earth models (MEMs) built on advanced acoustic logs calibrated by core geomechanics, wellbore failure observations, and in-situ stress tests. The impact of rock-brine-CO2 interactions is studied via custom SCAL experiments and/or pore-scale digital rock simulations that rigorously represent chemical and thermal processes. Wireline formation tester samples provide representative formation brine as feedstock for SCAL. Water samples also enable operators to prove injection within regulatory limits while establishing baselines for future monitoring programs. Examples applied to recent CCS projects in North America are presented. All of the above data need to be integrated into a CCS model predicting the CO2 plume behavior across the area of interest and within multiple horizons.

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.

1D Geomechanical Model For Wellbore Stability in Z Field, Y Well Sanga Sanga Working Area, Kutai Basin

This research is about 1D geomechanical model for wellbore stability in Z Field, Y Well Sanga Sanga Working Area, Kutai Basin where wells have been drilled. The Purpose of this Research is to analyze the stability of the well starting from knowing the stress regime that occurs, predicting the occurrence of wellbore failure, and determining safe mud weight window for next drilling. The method use in this Research is a numerical modelling method using log data and drilling data that has been obtained and then managed using Techlog Software. The result of this Research show the magnitude of mechanical properties of the rock that have been obtained, then in general the stress regime that occurs in the Z Field formation is the normal regime even though the strike slip and reverse regime are inserted at a certain depth, then based on the prediction results of failure in this well is wide breakout, which in general occurs in lithology with sandstone, finaly safe mud weight window can be estimated properly, so that it can be used for further well drilling. This research is about 1D geomechanical model for wellbore stability in Z Field, Y Well Sanga Sanga Working Area, Kutai Basin where wells have been drilled. The Purpose of this Research is to analyze the stability of the well starting from knowing the value of the mechanical properties of the formation, the stress regime that occurs, predicting the occurrence of wellbore failure, and determining safe mud weight window for next drilling. The method use in this Research is a numerical modelling method using log data and drilling data that has been obtained and then managed using Techlog Software. The result of this Research show the magnitude of mechanical properties of the rock that have been obtained, then in general the stress regime that occurs in the Z Field formation is the normal regime even though the strike slip and reverse regime are inserted at a certain depth, then based on the prediction results of failure in this well is wide breakout, which in general occurs in lithology with sandstone, finaly safe mud weight window can be estimated properly, so that it can be used for further well drilling.

Coupled experimental assessment and machine learning prediction of mechanical integrity of MICP and cement paste as underground plugging materials

Compromised integrity of cementitious materials can lead to potential geo-hazards such as detrimental fluid flow to the wellbore (borehole), potential leakage of underground stored fluids, contamination of water aquifers, and other issues that could impact environmental sustainability during underground construction operations. The mechanical integrity of wellbore cementitious materials is critical to prevent wellbore failure and leakages, and thus, it is imperative to understand and predict the integrity of oilwell cement (OWC) and microbial-induced calcite precipitation (MICP) to maintain wellbore integrity and ensure zonal isolation at depth. Here, we investigated the mechanical integrity of two cementitious materials (MICP and OWC), and assessed their potential for plugging leakages around the wellbore. Further, we applied Machine Learning (ML) models to upscale and predict near-wellbore mechanical integrity at macro-scale by adopting two ML algorithms, Artificial Neural Network (ANN) and Random Forest (RF), using 100 datasets (containing 100 observations). Fractured portions of rock specimens were treated with MICP and OWC, respectively, and their resultant mechanical integrity (unconfined compressive strength, UCS; fracture toughness, Ks) were evaluated using experimental mechanical tests and ML models. The experimental results showed that although OWC (average UCS = 97 MPa, Ks = 4.3 MPa·√m) has higher mechanical integrity over MICP (average UCS = 86 MPa, Ks = 3.6 MPa·√m), the MICP showed an edge over OWC in sealing microfractures and micro-leakage pathways. Also, the OWC can provide a greater near-wellbore seal than MICP for casing-cement or cement-formation delamination with relatively greater mechanical integrity. The results show that the degree of correlation between the mechanical integrity obtained from lab tests and the ML predictions is high. The best ML algorithm to predict the macro-scale mechanical integrity of a MICP-cemented specimen is the RF model (R2 for UCS = 0.9738 and Ks = 0.9988; MAE for UCS = 1.04 MPa and Ks = 0.02 MPa·√m). Similarly, for OWC-cemented specimen, the best ML algorithm to predict their macro-scale mechanical integrity is the RF model (R2 for UCS = 0.9984 and Ks = 0.9996; MAE for UCS = 0.5 MPa and Ks = 0.01 MPa·√m). This study provides insights into the potential of MICP and OWC as near-wellbore cementitious materials and the applicability of ML model for evaluating and predicting the mechanical integrity of cementitious materials used in near-wellbore to achieve efficient geo-hazard mitigation and environmental protection in engineering and underground operations.

A fully coupled thermo-poro-elastic model predicting the stability of wellbore in deep-sea drilling. Part A: Analytic solutions

Wellbore stability is important to deep-sea drilling (DSD) for exploiting offshore oil and gas resources. Accurate prediction of the mechanical behaviors of rock formation around the wellbore can effectively prevent wellbore failure via adjusting mud weight. In this paper, a fully coupled thermo-poro-elastic (THM) model is developed by combining fluid circulation in the wellbore and rock deformation in the reservoir. Transient heat transfer in the wellbore/reservoir and heat exchange between the tubing, annulus, riser, casing, cement, seawater and rock formation are considered. By decomposing the problem into axisymmetric and antisymmetric sub-problems, the analytical solutions for transient temperature, pressure and stress in the rock formation and fluid temperature changes in the drill pipe, annulus and seawater near the riser are obtained and validated against with the numerical solutions, existing fluid circulation model, field measurement data and the existing model without considering fluid circulation. After that, a typical case study is carried out to show the mechanical behavior around the wellbore. It is found that the proposed fully coupled THM model has a high accuracy with a relative error of around 1.2%. There is a large difference in the predicted bottomhole temperature (BHT) and thus the temperature in the reservoir between the models with and without considering fluid circulation in the wellbore. An assumption of constant temperature boundary condition may lead to overestimated or underestimated results depending on the selection of the assigned wellbore temperature. In the DSD case studied, the rock formation at the upper part of the reservoir (Z < 0.40) is continuously heated and the rock formation at the lower part (Z > 0.6) of the reservoir is continuously cooled during fluid circulation, which thus results in a complex heat transfer and thus mechanical behavior in the wellbore/reservoir system, especially near the wellbore. The bottomhole temperature (BHT) decreases by 38.9 K due to cold fluid circulation from 3.68 min to 25.68 days, which can lead to 14.59 MPa tensile stress that cannot be ignored for wellbore stability analysis. The proposed analytical model provides a useful tool to predict the mechanical behaviors such as the transient temperature, pressure, displacement and stresses in the wellbore/reservoir system during fluid circulation in DSD. It runs efficiently in terms of seconds per case study in a portable laptop computer and can also work a benchmark for other numerical methods. However, the fully coupled THM model and its analytical solution are based on several assumptions, such as the heat generated by the drill bit rotation is ignored and only the liquid phase is considered, which requires further investigation.

A coupled thermal-hydraulic-mechanical model for drilling fluid invasion into hydrate-bearing sediments

Evaluation of interactions among multiple physical fields in natural gas hydrate reservoirs is the basis for risk management during drilling fluid invasion. However, variations of physical fields, especially stress states and failure behaviors of invaded formation, are still unclear, which limits the stability estimation and risk control during drilling hydrate. Herein, a coupled thermal-hydraulic-mechanical model is established to describe characteristics of geophysical fields and wellbore failure. This model has superiority in characterizing stress states and invasion-induced deformation of the near-wellbore formation, which can reflect the effect of borehole shapes and drilling operations. Results reveal that drilling fluid invasion causes both stress and strain concentrations occurring around the wellbore. Stress states depend on the borehole shapes and invasion degree, especially the downhole zones with massive dissociation of hydrate. The yield area typically appears in the flushed zone and enlarges with invasion time. Besides, a fail function Ff is introduced into this model to determine the elastoplastic deformation areas, indicating the high-risk regions of wellbore instability. Consequently, coupling effects of invasion and phase transition under various stresses can lead to unavoidable deformation and stress changes. Thus, coupled analysis of geomechanical behaviors is an indispensable part of risk control in drilling hydrate reservoirs.

Experimental study on hydraulic fracture propagation in heterogeneous glutenite rock

To understand the fracture behavior and discuss the possibility of the reservoir-stimulated volume concept on glutenite rock, true triaxial hydraulic fracturing experiments were performed on glutenite rocks with acoustic emission monitoring. Experimental results indicate that a curved hydraulic fracture (HF) can be created. In addition, in situ stress plays the greatest role in HF propagation direction regardless of gravel characteristics; however, the gravel with high mechanical strength could affect hydraulic fracture path locally. Intense fluctuate extension pressure and discrete surged acoustic emission (AE) events not only occur during the breakdown stage but also during the shut-in stage, indicating embedded gravels tend to influence HF process. The breakdown pressure is the highest for sample with low horizontal stress difference, while breakdown pressure for large-size sample with small gravel numbers is the lowest. The highest AE amplitude can be observed for sample where fracture positions on gravels are at the initial stage, while continuous high AE amplitude is observed for samples with high pump rates during the entire process, indicating intense fracture and gravel interactions. Moreover, four possible interaction behaviors between HF and gravels, namely, fracture penetration, deflection, diversion and arrest, can be identified near wellbore and far-field failure zones. In general, fracture penetration behavior is exclusively observed within the near wellbore failure zone. Additionally, the fracture width for a penetration fracture is the largest due to high fracturing energy, while fracture diversion and arrest exhibit the smallest fracture width. Given the existence of gravels, branch fractures are difficult to merge with residual fracturing energy. An extremely coarse HF surface and tortuous HF path can be found for all samples; thus, the selection of a suitable pump rate and fracturing fluid is necessary to migrate near wellbore tortuosity.

Chemical and mechanical model to analysis wellbore stability

Wellbore instability problems mainly contribute to increased nonproductive time (NPT) through drilling operation developments in the Southern Iraq oilfield. This work aims to study the impact of drilling fluid chemicals on shale formation based on lab tests. At the same time, a mechanical earth model (MEM) constructs for the wellbore failure analysis, which simulates the mechanical effect on the shale formation. The Lab tests showed that the shale formation is of many types, including illite, kaolinite, palygorskite clay mineral, montmorillonite, and non-clay minerals quartz and calcite, where kaolinite was a dominant clay mineral of the shale. The shale samples swelled slightly when sodium silicate was used with polymer mud, but they had significant swelling when potassium chloride was applied with polymer mud. The MEM showed that the leading cause of those problems is using unsuitable mud weight (10.4 ppg) during the drilling of the Tanuma formation. Thus, the model indicates that an equivalent mud weight of 11 ppg for vertical wells will be required to stabilize the Mishrif and Tanuma shale formations. This work was unique in studying chemical and mechanical effects to analyze the wellbore stability and develop the optimum solutions.