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Methane hydrates is regarded as an important alternative energy in the future. Due to the complexity of marine environment, the mechanical parameters and initial stress state of formation have great uncertainties which can affect the wellbore stability in hydrate exploitation. In this study, a new time-dependent analytical model is proposed, considering the influence of hydrate dissociation on the mechanical properties and the partial coupling among pore pressure/temperature/mechanical field. The analytical solutions are verified and validated by numerical solutions. Based on the analytical solution and Mogi-Coulomb failure criterion, the reliability of wellbore stability during drilling in hydrate exploitation is analyzed by the Response Surface Method. Through the reliability analysis, the probability of wellbore instability increases and the safe drilling fluid pressure window range is narrowed with time, and finally tended to be stable at t = 12 h. Hydrate dissociation would lead to a more narrowed pressure window range, about by −38.75%. The most significant parameter whose uncertainty affects the instability probability is initial in-situ stress, followed by the initial internal friction angle and Biot's coefficient. [ABSTRACT FROM AUTHOR]

Shale gas, as an important unconventional oil and gas resource, its efficient development can alleviate the current severe energy demand situation. However, the water absorption and expansion characteristics and hydration effects of shale pose a great threat to the drilling safety of shale, mainly wellbore stability. Therefore, based on mechanical property experiments, the influence of hydration expansion on the mechanical property parameters of brittle shale was analyzed, and an evolution model of the mechanical property parameters of shale with hydration expansion was constructed. In addition, a finite element model for numerical simulation of wellbore stability in shale formations was established, and the effects of factors such as the addition of hydration inhibitors in drilling fluid on wellbore collapse were analyzed. Research has shown that the hydration and expansion of shale can reduce its elastic modulus and cohesive force, but the effect of hydration and expansion on Poisson's ratio and internal friction angle shows the opposite pattern. After being immersed in drilling fluid for 12 hours, the elastic modulus of shale decreased from 5.3 GPa to 3.9 GPa, and the cohesion decreased from 4.6 MPa to 3.0 MPa. In addition, wellbore collapse and instability in shale mainly occur in the early stages of drilling operations, while wellbore collapse will significantly slow down in the later stages. The wellbore enlargement rate increased to 40% within the first three hours of drilling operations. Moreover, the addition of hydration inhibitors in drilling fluids will prevent further collapse of the wellbore by inhibiting the invasion of water. When the hydration inhibitor in the drilling fluid was increased from 0 to 45 g/m3, the wellbore enlargement rate decreased from 66.2% to 27.8%. This study can provide theoretical reference for maintaining wellbore stability and drilling safety during shale drilling. [ABSTRACT FROM AUTHOR]

Copyright of Journal of Engineering Geology / Gongcheng Dizhi Xuebao is the property of Journal of Engineering Geology and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Borehole instability problems have caused non-productive time while drilling operations in the Nahr Umr shale formation. The drilling difficulties, including stuck pipe, caving, and tight holes, have been identified as significant problems in this formation. This study aims to comprehend the causes of wellbore failure and choose the most suitable drilling strategy. In this regard, a mechanical earth model (MEM) was performed using open-hole wireline logging measurements from the offset wells data. Those data included gamma ray, density log, compressional wave velocity, shear wave velocity, neutrons porosity, and image log. Moreover, there were also measured data such as leak-off tests and modular formation dynamics testers that were applied to validate the model's accuracy. The analysis exhibited that the leading cause of wellbore instability problems was improper mud weight (10.6 ppg). In addition, inappropriate drilling practices and the heterogeneity of the Nahr Umr formation have magnified the risk of drilling problems. The MEM outcome proved that the mud weight should be 11.6–13.5 ppg to safely drill a vertical well. Thus, this work can be applied as a cost-effective tool when designing future neighboring deviated wells. [ABSTRACT FROM AUTHOR]

Wellbore instability occurs when an open well cannot maintain its size, shape, or structural stability. It is a common issue especially in shale sections and can be caused by both mechanical factors, such as poor drilling technique or weak rock, and chemical factors, such as interactions between the rock and drilling fluid. This problem can lead to costly and dangerous complications. In this study data from three wells in Nahr Umr Oil Field (NR-10, NR-12, and NR-14) in southern Iraq were analyzed to determine pore pressure and rock strength parameters, as well as in situ horizontal stresses. The results showed an increase in pore pressure and horizontal stress in shale units, and various geomechanical parameters were also estimated. The study showed the fault regime in the area is a strike-slip fault and suggested the estimated pore pressure values while drilling hole sections to prevent problems at abnormal and subnormal formations. [ABSTRACT FROM AUTHOR]

Copyright of Iraqi Journal of Chemical & Petroleum Engineering is the property of Republic of Iraq Ministry of Higher Education & Scientific Research (MOHESR) and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

To address the serious issues of leakage, challenging plugging, and significant friction related to the long horizontal section construction in the Fuling shale gas field, a study was conducted to develop a suitable leak-proof agent OBMCP for oil-based drilling fluid. The difficulties of preventing leakage and plugging oil-based drilling fluid were analyzed, and the amount of reactively consolidated polymer HY-1 was controlled at 6.25 – 7.5% while considering the plugging strength requirements and plugging costs. The enhancer ZQJ was controlled at 0.4 – 0.6% to achieve high-strength rapid plugging, and the gelation time was controlled under the premise of safe construction to achieve a controllable curing time. Consequently, the oil-based drilling fluid leakage prevention and plugging technology were formed and applied in the J1 and J2 wells. The field test showed that the optimized drilling fluid had stable performance, a good plugging effect from the consolidation plugging agent, a stable borehole wall, small leakage, and strong anti-pollution ability, thereby achieving high-strength rapid plugging and a controllable curing time.

Natural gas hydrate is an alternative potential energy source that contributes to depressurizing the pressure of energy supply and environmental pollution in the future. Field hydrate production has a close association with geological risks. In this regard, accurate estimation of strength and deformation properties is crucial to risk prevention and control during hydrate development. However, the geomechanical properties of hydrate-bearing sediments and their applications remain unclear. Herein, this work provides a comprehensive summary of studies on the mechanical characteristics of hydrate-bearing sediments and their applications in field trials. It starts with the main research methods, including laboratory tests, constitutive modeling, and numerical simulations, followed by the effects of clay content, hydrate distribution, and morphology on mechanical properties. Besides, typical applications of geomechanical parameters are examined and discussed. Finally, the challenges and perspectives of mechanical studies on hydrate-bearing sediments are presented, which is favorable for the evaluation and control of geological risks during hydrate exploration and development. [ABSTRACT FROM AUTHOR]

The problematic shale in the Mediterranean Sea such as the Kafr El Sheikh Formation, are considered as potential source of borehole instability. This study is focused on the analysis of the conventional drilling fluids used for drilling this shale and work to change its composition to prevent or reduce the borehole instability problems. Shale cuttings were collected from four different wells in Temsah concession. These wells were evaluated using X-ray diffraction, X-ray fluorescence and cation exchange capacity using methylene blue test. Swelling index of the shale was measured using linear swell meter. Nano-particles used in this study are Al2O3, TiO2, nano shield and SiO2 as inhibitors for shale swelling. The inhibitors are added to the conventional drilling fluids instead of potassium chloride. The inhibition of swelling for these shale cuttings using 7% KCl caused a dramatic decrease in swelling percentage of shale that reached to nearly one fourth the value of the drilling fluid-free inhibitor (blank fluid). These values ranged from 72% with blank fluid to 18% (with shale Temsah NW-10 well), from 50% to 12.5% (with shale Temsah SE-01 well), from 40% to 10% (with shale Temsah -03 well) and from 47.5% to 13.5% (with shale Temsah -09 well). [ABSTRACT FROM AUTHOR]

Wellbore instability constitutes potential risks during wellbore drilling operation; these risks may cause complicated states, and in some cases, can lead to costly operational issues. In this study we present the best solution by predicting and quantifying wellbore instability in Muzhil field, Gulf of Suez, using a 1-DMechanical Earth Model (1DMEM) built with well logs, pressure measurements, and drilling events reports. Firstly we created 1DMEM by calculating the pore pressure, vertical stress, rock strength, rock elastic parameters, and horizontal stresses. Mohr Coulomb, Modified Lade and Mogi Coulomb failure criteria determined the well deformation possibility. Lastly 1-DMEM can be used to conduct a comprehensive geo-mechanical wellbore stability analysis for the trouble zones of Muzhil Formation. 1-DMEM results showed that the best azimuth for Vertical and slightly inclined Wells will be (40º–60º) clockwise from the North, i.e. parallel to SHmin (NE40SW). The wellbore stability analysis showed that the vertical and low deviated wellbore (less than 40º) is safe and more stable than the horizontal and high deviated wellbore and unsuitable Mud Weight (MW) is a major cause of the wellbore instability. The optimal solution to wellbore instability is to follow the optimum wellbore path and use safe MW. The optimum MW in shale formation ranges from (13.5-15) ppg. The results contribute in development plan of the wellbores nearby the studied area and reducing nonproductive time and cost.

Currently, drilling operators focus on chemical osmosis as a mechanism to extract water out of shale in order to reduce its pore pressure and increase its strength, however, in doing so, the flux of hydrated ions into shale by means of diffusion osmosis and ionic diffusion is increased. Such practice may lead to an increase in shale's pore pressure and strength reduction which will definitely negate the beneficial impact of chemical osmosis in combatting wellbore stability problems. For the first time, this work investigated the separate impact of diffusion osmosis on shale's swelling and subsequent wellbore stability issues. The experimental set-up enabled us to isolate chemical osmosis forces which made diffusion osmosis the only force governing water exchange. Making the water activity of shale equals to that of the aqueous solution disabled chemical osmosis forces and activated ionic diffusion and diffusion osmosis owing to the imposed ionic concentration during the interaction. It was found that diffusion osmosis accompanies ionic diffusion since ions travel with their respective water clouds, also known as associated water. The transport of associated water has caused shale's swelling in the absence of a water activity gradient (chemical osmosis). This was confirmed through gravimetric water and ion measurements conducted at the end of the linear swelling tests. Results showed that the amount of water exchanged by diffusion osmosis was immense, thus one should not ignore it when designing water-based muds for drilling highly sensitive clays. Results also showed that the amount of water exchanged correlated well with the hydrated diameter of the invading ion. Moreover, results confirmed that the swelling magnitude may be related to the mineralogical composition and cation exchange capacity of shale. [ABSTRACT FROM AUTHOR]

Copyright of Journal of Engineering (17264073) is the property of Republic of Iraq Ministry of Higher Education & Scientific Research (MOHESR) and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Hot Dry Rock (HDR) is a renewable energy source that has garnered attention due to its abundant reserves, widespread distribution, and consistent energy supply. However, the injection of cold water during the drilling and production process of HDR can alter the temperature of the rock in the HDR reservoir, leading to variations in its physical and mechanical properties near the wellbore. These changes can impact the stability and safety of the HDR wellbore. This study investigated the alterations in the physical and mechanical properties of HDR under different temperature conditions. The results revealed that there were negligible changes in the physical and mechanical properties when the temperature rose from 25 °C to 400 °C. However, noticeable changes occurred as the temperature increased from 400 °C to 800 °C, establishing 400 °C as the threshold for physical and mechanical property variations in the granite. Building upon these experimental findings, a segmented wellbore instability model was developed and validated. The model demonstrated that an increased temperature difference between the drilling fluid and the borehole corresponded to an expanded range of borehole failure. Furthermore, higher wellbore temperatures led to more pronounced disparities between the maximum and minimum principal stress of the borehole, rendering it more susceptible to instability. The research also uncovered that the optimal drilling position was influenced by temperature.These research outcomes hold significant importance for understanding the mechanisms of wellbore instability in HDR with high-temperature.

The bottom hole fluctuating pressure has a large influence on the wellbore instability. To address this problem, firstly, according to the principle of seepage mechanics, we established a calculation model of the change in pore pressure around the wellbore radius under fluctuating pressure; then, through laboratory rock mechanics test and rock damage mechanics theory analysis, the change law of formation strength under the action of static hydration and dynamic damage are determined; finally, based on the theory of rock mechanics in porous media, a quantitative evaluation method for the risk of wellbore instability under fluctuating pressure is established and the changing pattern of wellbore instability risk is analyzed. The results show that the pore pressure around the well shows a trend of fluctuation increase under fluctuating pressure, and there is a certain lag in the fluctuation of pore pressure inside the formation; the longer the muddy shale is immersed in drilling fluid, the greater the reduction in strength; the reduction is greater in the early stage of immersion, and the reduction in strength in water-based drilling fluid is greater than that in oil-based drilling fluid. At the beginning of the pressure cycle, the formation damage variable and compressive strength gradually increase and decrease with the increase of the pressure cycle number; after several cycles, the magnitude of change gradually decreases with the increase of the cycle number. When the bottom hole pressure fluctuates at a certain period, the greater the fluctuation, the shorter the period of wellbore stability; when the bottom hole pressure fluctuates at a certain range, the smaller the fluctuation period, the faster the borehole enters the high-risk period, while the shortest period of wellbore stability occurs when the fluctuation period is smallest; and when the wave cycle is in the middle, the wellbore stability period is the longest. [ABSTRACT FROM AUTHOR]

Wellbore instability is a significant problem faced during drilling operations and causes loss of circulation, caving, stuck pipe, and well kick or blowout. These problems take extra time to treat and increase the Nonproductive Time (NPT). This paper aims to review the factors that influence the stability of wellbores and know the methods that have been reached to reduce them. Based on a current survey, the factors that affect the stability of the wellbore are far-field stress, rock mechanical properties, natural fractures, pore pressure, wellbore trajectory, drilling fluid chemicals, mobile formations, naturally over-pressured shale collapse, mud weight, temperature, and time. Also, the most suitable ways to reduce wellbore instability are selecting the appropriate drilling mud and maintenance, reducing the Equivalent Circulating Density (ECD) by using suitable hydraulics, selecting hole-trajectory, and compatibility of drilling fluid with the formation being drilled. Moreover, factors such as (minimizing time spent open hole, using offset-well data, and monitoring trend changes (torque, circulating pressure, drag) must be considered. As a result of this paper, wellbore instability problems can be controlled by careful study of reservoirs to find the solutions to some issues or reduce them.

The wellbore instability caused by complex strata is a common problem in drilling engineering, which not only causes economic losses, but also reduces the field drilling efficiency. This paper has taken Block A of Junggar Basin as an example to explore the causes of wellbore instability in complex strata and establish corresponding solutions. Studying the core samples in this area and analyzing the logging data, it is concluded that the micro-fractures developed in the rock layer of the block provide natural channels for the entry of filtrate. At the same time, the water-sensitive clay minerals in the formation have hydration after encountering the filtrate. By optimizing the composition, the corresponding nano-strong inhibition and strong plugging potassium amine polysulfonate drilling fluid system (NPAP-2) was established. The overall use of asphalt anti-sloughing agent, nano-and micro-scale cracks (gaps) for physical plugging, wetting inversion control surface water absorption, chemical inhibition of internal hydration. The performance test shows that the HTHP water loss of the drilling fluid system is less than 10 mL, the recovery rate of rock sample is more than 86%, the viscosity is reasonable, the expansion rate is more than 89%, and the filtration loss is reduced from 8.0 to 5.0 mL. The results show that the NPAP-2 can reduce the liquid activity to enhance the inhibition, effectively improve the settlement stability of drilling fluid, reduce the filtration and ensure the wellbore stability. [ABSTRACT FROM AUTHOR]

One of the foremost causes of wellbore instability during drilling operations is shale swelling and hydration induced by the interaction of clay with water-based mud (WBM). Recently, the use of surfactants has received great interest for preventing shale swelling, bit-balling problems, and providing lubricity. Herein, a novel synthesized magnetic surfactant was investigated for its performance as a shale swelling inhibitor in drilling mud. The conventional WBM and magnetic surfactant mixed WBM (MS–WBM) were formulated and characterized using Fourier Transform Infrared (FTIR) and Thermogravimetric analyzer (TGA). Subsequently, the performance of 0.4 wt% magnetic surfactant as shale swelling and clay hydration inhibitor in drilling mud was investigated by conducting linear swelling and capillary suction timer (CST) tests. Afterward, the rheological and filtration properties of the MS–WBM were measured and compared to conventional WBM. Lastly, the swelling mechanism was investigated by conducting a scanning electron microscope (SEM), zeta potential measurement, and particle size distribution analysis of bentonite-based drilling mud. Experimental results revealed that the addition of 0.4 wt% magnetic surfactant to WBM caused a significant reduction (~30%) in linear swelling. SEM analysis, contact angle measurements, and XRD analysis confirmed that the presence of magnetic surfactant provides long-term swelling inhibition via hydrophobic interaction with the bentonite particles and intercalation into bentonite clay layers. Furthermore, the inhibition effect showed an increase in fluid loss and a decrease in rheological parameters of bentonite mixed mud. Overall, the use of magnetic surfactant exhibits sterling clay swelling inhibition potential and is hereby proffered for use as a drilling fluid additive. [ABSTRACT FROM AUTHOR]

Wellbore instability causes main concerns in the oil and gas industry due to personnel safety and overall expenditure. Several signs such as wellbore spalling, the rate of penetration reduction, pipes sticking, well unnatural wash out, wellbore collapsing, induce fracture could indicate wellbore instability during drilling. A balance between stress concentration near the wellbore and rock strength is the primary condition for a wellbore stability during drilling. Thus, instability due to the failure of wellbore rocks occurs when the intensity of the effective stress exceeds rock strength. In underbalanced drilling (UBD), the wellbore is considered unstable since no pressure or maybe not enough pressure is applied on the well from the drilling fluid, and the pore pressure is considered undesirable stress on the wellbore, so the difference between these two pressures is applied on the wellbore. Consequently, the wellbore instability issue in the UBD approach is of great importance. UBD is mainly used to reduce the damage to geological formation and the risk of drilling fluid loss while increasing the drilling rate. This study has investigated the stability of a well in Iranian Oilfield using FLAC software considering yielded regions (plastic) for different mud weights. The investigation and analysis of the FLAC output plots, especially the plasticity plot, concluded that the ideal and optimal pressure for applying UBD conditions while also ensuring wellbore stability ranges 15.2–16.8 MPa. [ABSTRACT FROM AUTHOR]

Shale hydration is the primary cause of wellbore instability during drilling processes. In this study, two non-fluorinated silane-coupling agents, octyltriethoxysilane (OTES) and (3-Aminopropyl) triethoxysilane (APTES), were grafted onto the nano-silica surface to develop a hydrophobic material (SHM). Various performance characterizations, including infrared spectroscopy, thermogravimetric analysis, surface tension, wetting alteration, capillary self-suction height, bentonite expansion, and shale dispersion, were employed to investigate the shale inhibition properties of SHM comprehensively. Experimental results revealed that SHM could significantly improve shale hydration inhibition. For instance, in a 2 % SHM liquids, the shale hot rolling recovery rate increased from 25.39 % to 83.78 %, and the bentonite expansion height decreased from 7.65 mm to 2.80 mm. The inhibition performance was notably superior to potassium chloride (KCl) and polyether amine (PEA). Inhibition mechanisms analysis unveiled that the outstanding inhibitory effect of SHM was achieved through electrostatic adsorption, wettability alteration, and surface tension reduction. Firstly, SHM contained numerous amine groups that could demonstrate strong adsorption on the clay surface through electrostatic and hydrogen bonding interactions. Secondly, with long hydrophobic alkyl chains, it formed a highly hydrophobic film enveloping the shale surface, effectively preventing water from invading. Thirdly, it reduced liquid surface tension, further minimizing the water infiltration. As a result, the use of SHM significantly enhanced shale hydration inhibition during the shale drilling process. [Display omitted] • Two silane-coupling agents, OTES and APTES, were grafted onto the nano-silica surface to develop a hydrophobic material (SHM). • The shale inhibition performance of SHM was notably superior to KCl and PEA. • The water contact angle of shale exceeded 140° after interaction with 3 % SHM. • SHM shifted the capillary force in shale interior from a propelling force to a resistance. • SHM reduced liquid surface tension, further minimizing the water infiltration. [ABSTRACT FROM AUTHOR]

Unlike normal-pressure gas wells, wellbore instability is more likely to occur during testing for high-pressure gas wells. Gas acceleration effect exists in gas flow during high-pressure gas well testing, which was ignored in previous wellbore instability analysis. In this paper, the developments of effective circumferential stress and effective radial stress are analyzed in the near-wellbore area of high-pressure gas well, considering the influence of in-situ stress non-uniformity and acceleration effect. To analyze the effective circumferential stress and the effective radial stress more accurately, it is established that the fluid-structure coupling stress field of the finite large thick wall cylinder The flow field considers three cases, namely Darcy’s law, Darcy–Forchheimer model and Darcy-Forchheime model considering gas acceleration. The results show that in-situ stress non-uniformity has a similar influence on tensile failure and shear failure. It is observed that the location of occurring shear failure and tensile failure may not be on the wellbore wall. When the formation fluid is under abnormally high pressure, it is more likely to have a tensile failure, while when the formation fluid is under abnormally low pressure, it is more likely to have a shear failure. The Biot parameter has the same effect on tensile failure and shear failure. These results are helpful to control sand production during testing and production for high-pressure gas wells.

Aiming at the problem of wellbore stability caused by hydration expansion of clay minerals in shale, a water-based drilling fluid system with strong inhibition is formed by selecting polyethyleneimine as a shale inhibitor. The performance evaluation results show that compared with polyether amine and other shale inhibitors, polyethyleneimine has stronger shale inhibition. After aging at 150 ℃, cuttings roll recovery rate is as high as 96%.The water-based drilling fluid system with strong inhibition has excellent rheological performance, low filtration loss and strong inhibition at 120 ℃, with apparent viscosity of 48mPa·s, API filtration loss of 3.0mL, and the reduction rate of shale expansion height as high as 70%. The drilling fluid system is expected to be popularized and applied in the drilling and development of shale gas. [ABSTRACT FROM AUTHOR]

Nanomaterials find several applications in the oilfield operations. In oilwell drilling, nanomaterials are being used for mitigating wellbore instability conditions, improving thermal stability of the fluid, minimizing formation damage by preventing fluid invasion into the reservoir, improving fluid rheology, and controlling fluid loss. A wide range of nanomaterials from organic as well as inorganic and composites are being developed to accomplish the mentioned functions. Significant nanomaterials being developed include nanocellulosic particles, nanoclay, nanosilica, nanometals, nanometal oxides and nanopolymers. Improving fluid properties to develop smart fluids by the incorporation of nanomaterials is an emerging research field which is yielding promising results. This review article presents the recent development made in the applications of the nanomaterials in drilling fluids especially the nanosilica particles surface modified by organic ligands. Surface modification of nanosilica with organic ligands namely 3‐Glycidoxypropyl‐triethoxy silane (GPTS), hyperbranched polyethyleneimine (HPEI) and Moringa oleifera cationic protein (MOCP) are discussed. Applications of nanomaterials in drilling fluids to minimize wellbore instability, prevent formation damage, improve thermal stability and conductivity, stabilize fluid rheology, improve hole cleaning, and minimize the chances of downhole string sticking have been reviewed. [ABSTRACT FROM AUTHOR]

Shale swelling is vital causing instability issues with waterbased drilling fluids (WBDF). It happens because shale has reactive minerals causing swelling with water. Previously used inhibitors protected clay surface, but nanopores remained open. Physical plugging of nanopores is essential to improve swelling inhibition. Objective of this research is to identify a better shale swelling inhibitor. 0.1-1.1 wt% of Multi Walled Carbon Nanotubes (MWCNTs) is used to improve inhibition in bentonite wafers. MWCNTs is characterized by FESEM, TGA, and FTIR. Swelling inhibition, rheological, and filtration properties are determined upto 150 ℃. MWCNTs based WBDF is also characterized by XRD to study MWCNTs effect on d-spacing. Rheological model study is performed. FESEM determined 94.5% purity, TGA confirmed thermal stability up to 904 ℃, and FTIR found carbon bonds. MWCNTs has induced 57% swelling inhibition in comparison with base fluid. Rheological and filtration properties are improved potentially, that is, Rheology has improved 57% and filtration 55%. Drilling fluid samples are found following shear thinning and Bingham Plastic model with 0.933-0.97 R2 and lowest RMSE values upto 100 ℃. In future, MWCNTs can be used with other nanoparticles, polymers, and ionic liquids for swelling inhibition. [ABSTRACT FROM AUTHOR]

To address the problem of well wall instability in the mud shale formation in the Tianhuan Depression Tectonic Block, a dual-effective collaborative well wall collapse prevention countermeasure of " blocking + lubrication" was proposed through a comprehensive analysis of the mineral composition, microstructure, physical and chemical properties of the complex formation and triaxial stress experiments. The development of microfractures and microporosity in the mud shale, the easy hydration and swelling of the formation rock samples and the poor hydrophilicity of the core surface are the main causes of well wall instability. By strengthening the plugging ability of the formation and reducing the friction of the horizontal section, the purpose of stabilizing the wellbore can be achieved. The constructed high-efficiency anti sloughing drilling fluid system has a NaCl resistance of 10%, a CaCl2 resistance of 1. 0%, a poor soil resistance of 10%, and a recovery rate of 99. 6% . The invasion depth of 80 ~ 100 mesh sand bed is 8. 4 mm, which is significantly improved compared with the permeability and plugging performance of on-site water-based drilling fluid, and can seal 200 μm and 400 μm simulate the fracture, the pressure bearing capacity reaches 5 MPa, and the ability to inhibit hydration dispersion and crack sealing is excellent. In the process of field application, the average well diameter expansion rate in the horizontal section is less than 6%, the average drilling speed reaches 4. 7 m/ h, and the API filtration is controlled below 5 mL, which has played a good role in lubrication and anti sloughing, borehole purification and reservoir protection. The research results show that the anti sloughing drilling fluid system effectively solves the problem of wellbore instability during drilling in the structural block of Tianhuan Depression, saves drilling costs, and has a good promotion prospect. [ABSTRACT FROM AUTHOR]

Cataclastic coalbed methane is easy to break under the action of high fluid velocity during the development process, resulting in borehole collapse, blocking the bottom pocket, and affecting the subsequent exploitation and production of coalbed methane. For this reason, a detailed analysis is made on the borehole collapse and the impact of drilling fluid intrusion on groundwater pollution during the drilling of fragmented coal seams. The results show that: (1) The borehole collapse process of drilling in cataclastic coal reservoir is the result of the joint action of circumferential expansion and radial expansion of the yield area around the well, and the final borehole expansion rate is 24.2%. (2) Low drilling fluid density will cause borehole collapse and instability, and when the drilling fluid density reaches a certain value, micro cracks will appear on the borehole wall in the direction of the maximum horizontal principal stress, resulting in borehole fracture. By the end of the simulation, the width and length of microcracks have expanded to 0.05mm and 13.2mm, and the deflection distance has reached 4.21mm. (3) Different requirements for borehole expansion rate of drilling operation will put forward different requirements for drilling fluid density. The higher the requirements for borehole stability of drilling operation, the narrower the safety density window of drilling fluid will be. (4) The higher the density of microfracture distribution in coal reservoir, the higher the lower limit of drilling fluid safety density window. When the density of microcracks in the coal seam is increased from 10 pieces/m³ to 30 pieces/m³, the lower limit of the drilling fluid safety density window will be increased from 1.36g/cm2 to 1.67g/cm². [ABSTRACT FROM AUTHOR]

Clay-swelling inhibitors are often used to prevent the hydration of clay minerals, which can reduce the risk of wellbore instability and reservoir damage. The molecular behaviour of clay-swelling inhibitors at the montmorillonite–water interface is crucial for revealing their inhibition mechanisms and for evaluating and designing inhibitor molecules. N1,N1’-(ethane-1,2-diyl)bis(N1-(2-aminoethyl)ethane- 1,2-diamine) (NETS), a low-molecular-weight clay-swelling inhibitor, is used widely to prevent clay swelling. Herein, the adsorption mechanism of NETS on the surface of montmorillonite (Mnt) was investigated using molecular dynamics (MD) simulations. In particular, the effects of molecular conformation and temperature on adsorption ability were investigated. The results show that the adsorption ability of NETS on the Mnt surface was affected significantly by the molecular conformation. Specifically, the dihedral angle of NETS adsorbed on the surface of Mnt decreases by ∼20° and tends to adsorb on the surface of Mnt in a plane state. In addition, the adsorption stability of NETS on the Mnt surface decreased with increasing temperature, as was found using MD simulations. Detailed analysis shows that increasing temperature can lead to more frequent conformational changes, which weaken the interaction between NETS and Mnt, thus reducing adsorption stability. These molecular insights into the interaction mechanism between NETS and Mnt are beneficial for the evaluation of inhibitory effects and for the selection and molecular design of new clay-swelling inhibitors for use in drilling fluids. [ABSTRACT FROM AUTHOR]

This research presents a comprehensive review of lost circulation and wellbore instability challenges in geothermal drilling, complemented by an original case study demonstrating the application of Expandable Profile Liner Technology (EPLT). The review synthesizes and analyzes current mitigation strategies, highlighting their limitations in complex geothermal environments. In response to the inadequacies of traditional methods and the imminent risk of well abandonment, EPLT was implemented as an innovative solution. The case study of the J-1 well demonstrates EPLT's novel application in severe lost circulation conditions, showcasing its ability to effectively seal large fractures and high-permeability zones without reducing wellbore diameter and breakthrough — a common limitation of conventional techniques. Quantitative analysis reveals significant improvements in drilling efficiency, wellbore stability, and cost-effectiveness. This research contributes to the field by introducing EPLT as a groundbreaking approach to lost circulation management and wellbore strengthening in geothermal drilling, potentially revolutionizing industry practices and enhancing drilling performance in high-temperature environments. • Comprehensively analyzing lost circulation and wellbore instability challenges in geothermal drilling. • Effectively addressing severe lost circulation with EPLT while preserving well diameter. • Demonstrating EPLT's effectiveness in handling severe lost circulation and collapse formations through J-1 well case study. • Reducing downtime and drilling costs with EPLT, enhancing geothermal project economics. [ABSTRACT FROM AUTHOR]

Wellbore instability presents a formidable challenge in drilling engineering, significantly hindering the exploitation of geothermal energy and deep oil and gas resources. However, the current comprehension of wellbore instability in high-temperature fractured granite formation remains inadequate. This study establishes a numerical model based on the DFN of heterogeneous granite under THM coupling. The numerical model incorporates the rock failure criterion and the Mohr-Coulomb friction model for fractures. This investigation delves into the stress distribution and failure modes of wellbore surrounding rock and fractures, considering fracture degree (ranging from fractured to fragmented formation), mud pressure, and temperature. Results highlight that the intersection and number of fractures with the wellbore significantly influence wellbore instability more than fracture degree. A high fracture degree induces significant pore pressure, increasing the possibility of instability. Fractures cause stress concentration, leading to damage spreading. Mud pressures and temperature differences affect stress and failure modes. Preventing mud invasion and maintaining a temperature differential within 250 °C is conducive to wellbore stability. The wellbore stability has a tolerance range for high mud pressure, exceeding the initial formation pore pressure by approximately 10 MPa. Findings are crucial for understanding and safeguarding high-temperature fractured granite wellbore stability. • Established a wellbore model of THM-coupled heterogeneous DFN granite. • Considered rock failure and Mohr-Coulomb friction criteria under fracture closure. • Discussed the stress distribution and failure modes of the wellbore and fractures. • Fracture-wellbore intersections and quantities are more likely to cause instability. • The wellbore has a tolerance range for mud pressure. [ABSTRACT FROM AUTHOR]

Wellbore instability is one of the most serious problems that can occur during drilling, mainly during drilling oil or gas wells through rocks that contain a higher proportion of clay, such as shales. To prevent wellbore instability, oil companies apply different approaches to strengthen wellbore walls, and use different shale swelling inhibitors. The aim of this research was to apply a green approach and the concept of the circular economy in mud design, and to determine whether mandarin peel powder, which is a waste material, can be used as an inhibitor of shale swelling. For that purpose, pellets consisting of bentonite and quartz in a 50:50 ratio were prepared using a compactor, and bentonite-based drilling mud (BM) with and without mandarin peel powder in concentrations of 0.5, 1, 1.5 and 2% by volume of water. The swelling of quartz–bentonite pellets after 2 and 24 h in each drilling-mud sample was determined at room temperature and 90 °C using a linear swell meter. On the basis of laboratory research, we concluded that increasing the concentration of mandarin peel powder reduces pellet swelling. By adding mandarin peel powder particles between 0.1 and 0.16 mm to the base mud at a concentration of 2% by volume of water, the following was achieved: 44% reduction in API filtration, 61.54% reduction in PPT filtration, 45% reduction in pellet swelling after 24 h at room temperature, and 48.6% reduction of pellet swelling after 24 h at 90 °C. [ABSTRACT FROM AUTHOR]

Drilling through active shale formations has been a challenging practice in the oil and gas industry for a long period of time, given the complexity of shale structure and its interaction with Water Based Muds (WBMs). Although there have been many additives and methodologies proposed for a safe drilling through shale formations using WBMs, little success has been reported to the application of these methods once tested under different field conditions. In this paper, a new WBM formulated by nanomaterials was proposed to stabilize active shale layers during drilling. A series of rheological, density, filtration loss, bentonite dispersion and shale recovery tests were conducted on the mud samples formulated by nanosilica and Nano Glass Flakes (NGFs). The results indicated that NGF, as a cheap but effective nanomaterial, is able to significantly reduce the flirtation loss without posing any significant impacts on the density and the rheology of WBMs. It also appeared that the bentonite molecules were incapable to either hydrate or disperse in the drilling fluid system in the presence of NGFs. It seems that NGFs can stabilize clay minerals and reduce the filtration loss as remarkably efficient additive, but caution must be taken to ensure that they are properly disperse in the WBMs.

Many solutions have been executed to mitigate the wellbore instability problem including improving mud inhibition with chemical additives, raising mud weight to mechanically support the wellbore, and modifying casing design to accommodate extra-large diameter surface casing with the drawback of increasing well cost. Despite these solutions, the operator is still plagued by continuous hard reaming during tripping operations, several dill string pack-off sticking incidents, and the inability to get the casing to the bottom. This paper examines the effect of implementation of Non-retrievable drilling with casing technique to optimize drilling and overcome the hole instability problems in West of Nile (WON) field is located in the Western Desert of Egypt and operated by Qarun Petroleum Company. This solution is unique in terms of adaptability and simplicity, a few adaptations are required for a standard drilling rig to be able to get casing to bottom by rotating, reciprocating, and circulating simultaneously. Applying this technique optimize drillings, reduces cost, and improves safety. [ABSTRACT FROM AUTHOR]

The wellbore instability in the horizontal sections of continental shale gas wells in the Ordos Basin is a major engineering and technical problem that restricts the exploration and development of the shale gas resources in the Yanchang Formation of Upper Triassic of Mesozoic in the Yanchang Block. To solve this problem, this paper analyzed the characteristics of mineral components in shale by means of X-ray diffraction. In addition, its physical and chemical characteristics, specific surface area and microstructure were analyzed. On this basis, a shale water-based drilling fluid system (PSW-2) of low free water activity based on nano plugging was developed. And it was applied on site at five horizontal wells in continental shale gas reservoirs to ensure the wellbore stability of their long horizontal sections. And the following research results were obtained. First, the Yanchang Formation shale in this area has a high content of clay mineral, and it is a fractured formation of weak expansion, easy dispersion and multiple bedding, so the wellbore instability here is the result of the comprehensive action of mechanical factors, physical and chemical factors, drilling mechanical disturbance, etc. Second, the shale has average pore diameter is 4.494–8.502 nm and is characterized by obvious capillary action, strong water absorption capacity and uneven hydration, which result in the decrease of local shale strength, so sudden collapse tends to happen easily. Third, the API loss of PSW-2 system is less than 2.8 mL, the rolling recovery rate is 95.15% (close to the recovery rate of oil-based drilling fluid 98.25%), the linear expansion rate is as low as 1.38%, and the wetting angle increases from 26° of dry rock samples to 56.5°. Fourth, the compressive strength of the system after immersion increases to 95.806 MPa, which is close to the original rock strength (110.70 MPa). It is concluded that this water-based drilling fluid system can effectively ensure wellbore stability by blocking the pores of shale with micro nano components, reducing the activity of liquid phase to increase the inhibition, and weakening the multi-element collaboration of the capillary imbibition effect of shale.

The bottom hole fluctuating pressure has a large influence on the wellbore instability. To address this problem, firstly, according to the principle of seepage mechanics, we established a calculation model of the change in pore pressure around the wellbore radius under fluctuating pressure; then, through laboratory rock mechanics test and rock damage mechanics theory analysis, the change law of formation strength under the action of static hydration and dynamic damage are determined; finally, based on the theory of rock mechanics in porous media, a quantitative evaluation method for the risk of wellbore instability under fluctuating pressure is established and the changing pattern of wellbore instability risk is analyzed. The results show that the pore pressure around the well shows a trend of fluctuation increase under fluctuating pressure, and there is a certain lag in the fluctuation of pore pressure inside the formation; the longer the muddy shale is immersed in drilling fluid, the greater the reduction in strength; the reduction is greater in the early stage of immersion, and the reduction in strength in water-based drilling fluid is greater than that in oil-based drilling fluid. At the beginning of the pressure cycle, the formation damage variable and compressive strength gradually increase and decrease with the increase of the pressure cycle number; after several cycles, the magnitude of change gradually decreases with the increase of the cycle number. When the bottom hole pressure fluctuates at a certain period, the greater the fluctuation, the shorter the period of wellbore stability; when the bottom hole pressure fluctuates at a certain range, the smaller the fluctuation period, the faster the borehole enters the high-risk period, while the shortest period of wellbore stability occurs when the fluctuation period is smallest; and when the wave cycle is in the middle, the wellbore stability period is the longest.

One of the foremost causes of wellbore instability during drilling operations is shale swelling and hydration induced by the interaction of clay with water-based mud (WBM). Recently, the use of surfactants has received great interest for preventing shale swelling, bit-balling problems, and providing lubricity. Herein, a novel synthesized magnetic surfactant was investigated for its performance as a shale swelling inhibitor in drilling mud. The conventional WBM and magnetic surfactant mixed WBM (MS–WBM) were formulated and characterized using Fourier Transform Infrared (FTIR) and Thermogravimetric analyzer (TGA). Subsequently, the performance of 0.4 wt% magnetic surfactant as shale swelling and clay hydration inhibitor in drilling mud was investigated by conducting linear swelling and capillary suction timer (CST) tests. Afterward, the rheological and filtration properties of the MS–WBM were measured and compared to conventional WBM. Lastly, the swelling mechanism was investigated by conducting a scanning electron microscope (SEM), zeta potential measurement, and particle size distribution analysis of bentonite-based drilling mud. Experimental results revealed that the addition of 0.4 wt% magnetic surfactant to WBM caused a significant reduction (~30%) in linear swelling. SEM analysis, contact angle measurements, and XRD analysis confirmed that the presence of magnetic surfactant provides long-term swelling inhibition via hydrophobic interaction with the bentonite particles and intercalation into bentonite clay layers. Furthermore, the inhibition effect showed an increase in fluid loss and a decrease in rheological parameters of bentonite mixed mud. Overall, the use of magnetic surfactant exhibits sterling clay swelling inhibition potential and is hereby proffered for use as a drilling fluid additive.

This work utilized electrochemical potential, linear swelling and water and ions uptake tests to correlate zeta potential (ζ) measurements with swelling results when different shales interacted with NaCl, KCl and CaCl2 solutions of different concentrations (water activities). Experimental results show that shale swelling and shrinkage seems to correlate well with changes in zeta potential and Debye Hückel length (κ−1) of shale's charged surface. I believe that reduction of zeta potential and κ−1 leads to shale shrinkage while increase in zeta potential and κ−1 translates into shale swelling. Results also show that zeta potential and κ−1 of Pierre and Arco shale depends strongly on water activity (concentration) difference between shale and aqueous solutions. It was found that the formation and break up of an ionic shield cloud determines swelling and shrinkage of shale depending on the direction of water and ions transport. Results also suggest that, for constant temperature and medium viscosity (ƞ), the term (z/r) determines the effectiveness of ions to screen particle surface charge and it represents two opposing forces (electrostatic force and viscous force). The (z/r) for NaCl equals 0.28 m−1 which is lower than that of CaCl2 (z/r = 0.46 m−1) and KCl (z/r = 0.303 m−1). [ABSTRACT FROM AUTHOR]

Wellbore instability problems cause nonproductive time, especially during drilling operations in the shale formations. These problems include stuck pipe, caving, lost circulation, and the tight hole, requiring more time to treat and therefore additional costs. The extensive hole collapse problem is considered one of the main challenges experienced when drilling in the Zubair shale formation. In turn, it is caused by nonproductive time and increasing well drilling expenditure. In this study, geomechanical modeling was used to determine a suitable mud weight window to overpass these problems and improve drilling performance for well development. Three failure criteria, including Mohr–Coulomb, modified Lade, and Mogi–Coulomb, were used to predict a safe mud weight window. The geomechanical model was constructed using offset well log data, including formation micro-imager (FMI) logs, acoustic compressional wave, shear wave, gamma ray, bulk density, sonic porosity, and drilling events. The model was calibrated using image data interpretation, modular formation dynamics tester (MDT), leak-off test (LOT), and formation integrity test (FIT). Furthermore, a comparison between the predicted wellbore instability and the actual wellbore failure was performed to examine the model's accuracy. The results showed that the Mogi–Coulomb failure and modified Lade criterion were the most suitable for the Zubair formation. These criteria were given a good match with field observations. In contrast, the Mohr–Coulomb criterion was improper because it does not match shear failure from the caliper log. In addition, the obtained results showed that the inappropriate mud weight (10.6 ppg) was the main cause behind wellbore instability problems in this formation. The optimum mud weight window should apply in Zubair shale formation ranges from 11.5 to 14 ppg. Moreover, the inclination angle should be less than 25 degrees, and azimuth ranges from 115 to 120 degrees northwest-southeast (NE–SW) can be presented a less risk. The well azimuth of NE–SW direction, parallel to minimum horizontal stress (Shmin), will provide the best stability for drilling the Zubair shale formation. This study's findings can help understand the root causes of wellbore instability in the Zubair shale formation. Thus, the results of this research can be applied as expenditure effectiveness tools when designing for future neighboring directional wells to get high drilling performance by reducing the nonproductive time and well expenses. [ABSTRACT FROM AUTHOR]

In this study, the effect of creep behavior of salt zone of Gachsaran Formation was investigated on the phenomenon of wellbore tightening during drilling and also casing collapse during production in one of the oil fields in the southwest of Iran. In the desired oil field, 3 wells (A, B, and C) with the necessary characteristics were selected and investigated. To address this, a three-dimensional numerical ground-well-fluid coupled model was developed using the finite difference method (FDM) in FLAC3D for basis of this research. First, the deformation of the wellbore wall was investigated during drilling operations without running the casings and considering different mud weights within 10 days. The results demonstrated that increasing the mud weight to a certain extent reduces the deformation and convergence of the wellbore wall and by increasing it excessively, it causes the divergence and tensile fractures on the wellbore wall, and ultimately mud loss and wellbore instability. The optimal mud weight for wells A and B (with a convergence of 3.76 cm and 3.93 cm, respectively) and also for well C (with a convergence of 3.94 cm) was estimated as 145 and 140 pcf, respectively. Then, in order to investigate the casing impact on wellbore wall deformation (wells B and C), the analyses were performed in two cases; one is a cement-free wellbore, and the other is a cased and cemented well. By applying cement to the back of the casing, the maximum value of stress applied to the wall of well B was reduced from 446.90 MPa (cement-free wellbore) to 350 MPa (0.2 mm convergence). Also, for well C, the maximum stress on its wall was reduced from 434.4 MPa (cement-free wellbore) to 387.1 MPa (0.12 mm convergence). As the stress on the wellbore wall decreases, the value of deformation diminishes, resulting in a significant increase in wellbore stability against the casing collapse. [ABSTRACT FROM AUTHOR]