Search Results (56)

During the drilling processes of a 10,000-meter-deep well, cutting removal becomes difficult in the 32-inch borehole, which significantly increases downhole risks and affects drilling efficiency. To address this, a numerical simulation method based on the Eulerian two-fluid model was established for cuttings transport simulation in ultra-large boreholes. This method revealed the cuttings transport behavior in the 32-inch borehole of the SDCK1 well, analyzed the actual return velocity and the critical return velocity required for cuttings transport, and examined the cuttings transport characteristics near the bottom stabilizer. The results show that under the maximum flow rate of 160 L/s, the actual return velocity in the annulus is only 0.32 m/s, while the critical return velocity for 10 mm cutting particles is 0.57 m/s. Except for the stabilizer position, the actual return velocity throughout the entire well section is lower than the critical return velocity required for 10 mm cutting particles transport, which is one of the main reasons for the poor cutting removal in the wellbore. Near the bottom stabilizer, the annular flow is altered by the large outer diameter of the stabilizer, causing drilling fluid backflow and resulting in cuttings accumulation. The cuttings backflow and accumulation are more pronounced with the double stabilizer tool combination compared to the triple stabilizer tool combination. The small annular gap near the stabilizers makes it difficult for large cuttings to pass through, leading to blockages. A low annular return velocity and cuttings accumulation near the stabilizer are the primary reasons for poor cuttings removal in the 32-inch borehole. Full article

The generation and propagation mechanisms of acoustic waves from leakage below the annular liquid level in gas wells have attracted widespread attention. To study the characteristics of acoustic sources beneath the liquid level, a physical model of leakage in the casing–tubing annulus was established by simulating the distribution patterns of the flow field and acoustic field within the annulus under tubing leakage conditions. Distinct from the traditional acoustic analysis of wellbore leakage in gas wells, this study focuses on acoustic waves generated by leaks located below the annular protection fluid level. It analyzes the flow regime and acoustic source characteristics beneath the liquid level under various operating conditions (including leakage aperture, velocity, and position). The research summarizes the evolution patterns of flow regimes when gas leaks into the annular protection fluid under different conditions and elucidates the generation mechanism of sub-liquid leakage noise and its propagation mechanism across the liquid surface. This work lays the theoretical foundation for detecting sub-liquid leakage at the wellhead using acoustic methods. Full article

Accurate detection of downhole tubing leakage in gas wells is essential for planning effective repair operations and mitigating safety risks in annulus pressure buildup wells. Current localization methods employ autocorrelation analysis to exploit the time-delay features of acoustic signals traveling through the tubing–casing annulus. This allows non-invasive wellhead detection, avoiding costly tubing retrieval or production shutdowns. However, field data show that multiphase flow noise, overlapping reflected waves, and coupled multi-leakage points in the wellbore frequently introduce multi-peak interference in acoustic autocorrelation curves. Such interference severely compromises the accuracy of time parameter extraction. To resolve this issue, our study experimentally analyzes how leakage pressure differential, aperture size, depth, and multiplicity affect the autocorrelation coefficients of acoustic signals generated by leaks. It compares the effects of different noise reduction parameters on leakage localization accuracy and proposes a characteristic time selection principle for autocorrelation curves, providing a new solution for precise leakage localization under complex downhole conditions. Full article

The aim of this study is to develop a simple and reliable laboratory testing procedure for evaluating the bond strength of cement–formation sheaths that considers cement slurry composition and contamination as well as formation strength and formation surface conditions (roughness and contamination). Additionally, a simple and practical empirical correlation is developed for predicting cement–rock bond strength based on the routine mechanical properties of hard-set cement and formation rock. Cement slurries composed of Yamama cement type 1 and 25% local Saudi sand, in addition to 40% fresh water, are used for all investigations in this study. Oil well cementing is a crucial and essential operation in the drilling and completion of oil and gas wells. Cement is used to protect casing strings, isolate zones for production purposes, and address various hole problems. To effectively perform the cementing process, the cement slurry must be carefully engineered to meet the specific requirements of the reservoir conditions. In oil well cementing, the cement sheath is a crucial component of the wellbore system, responsible for maintaining structural integrity and preventing leakage. Shear bond strength refers to the force required to initiate the movement of cement from the rock formation or movement of the steel casing pipe from the cement sheath. Cement–formation sheath bond strength is a critical issue in the field of petroleum engineering and well cementing. Cement plays a crucial role in sealing the annulus (the space between the casing and the formation) and ensuring the structural integrity of the well. The bond strength between the cement and the surrounding geological formation is key to preventing issues such as fluid migration, gas leaks, and wellbore instability. To achieve the study objectives, sandstone and sandstone–cement composite samples are tested using conventional standard mechanical tests, and the results are used to predict cement–formation sheath bond strength. The utilized tests include uniaxial compression, direct tensile, and indirect tensile (Brazilian) tests. The predicted cement–rock sheath bond strength is compared to the conventional laboratory direct cement–formation sheath strength test outcomes. The results obtained from this study show that the modified uniaxial compression test, when used to evaluate cement–formation shear bond strength using cement–rock composite samples, provides reliable predictions for cement–formation sheath bond strength with an average error of less than 5%. Therefore, modified uniaxial compression testing using cement–rock composite samples can be standardized as a practical laboratory method for evaluating cement–formation sheath bond strength. Alternatively, for a simpler and more reliable prediction of cement–formation sheath bond strength (with an average error of less than 5%), the empirical correlation developed in this study using the standard compressive strength value of hard-set cement and the standard compressive strength value of the formation rock can be employed separately. For the standardization of this methodology, more generalized research should be conducted using other types of oil well cement and formation rocks. Full article

The widespread application of horizontal drilling technology has significantly enhanced the development efficiency of unconventional resources, particularly shale gas, by overcoming key technical challenges in reservoir exploitation. However, wellbore instability remains a critical challenge during shale gas horizontal drilling, as borehole wall collapse often results in the accumulation of large-sized cuttings (or blocky cuttings), increasing the risk of stuck pipe incidents. In this study, a large-scale circulating loop experimental system was developed to investigate the hydrodynamic behavior of blocky cuttings transport under the influence of multiple factors, including rate of penetration (ROP), well inclination, flow rate, drilling fluid rheology, and block size. The experimental results reveal that when ROP exceeds 15 m/h, the annular solid-phase concentration increases non-linearly. At a well inclination of 60°, the axial and radial components of gravitational force reach a dynamic equilibrium, resulting in the maximum cuttings bed height. To enhance cuttings transport efficiency and mitigate deposition, a minimum flow rate of 35 L/s and a drill pipe rotation speed of 90 rpm are required to maintain sufficient turbulence in the annulus. Drilling fluid plastic viscosity (PV) in the range of 65–75 mPa·s optimizes suspension efficiency while minimizing circulating pressure loss. Additionally, increasing fluid density enhances the transport efficiency of large blocky cuttings. A drill pipe rotation speed of 80 rpm is recommended to prevent the formation of sand-wave-like cuttings beds. These findings provide valuable hydrodynamic insights and practical guidelines for optimizing hole-cleaning strategies, ensuring safer and more efficient drilling operations in shale gas horizontal wells. Full article

The abnormal swab pressure resulting from packer unsetting poses a great threat to the collapse resistance of production casings in deep high-pressure and high-temperature (HPHT) oil wells. This paper proposes an analytical model to predict the transient swab pressure in the A-annulus after packer unsetting based on a U-type tube and an iterative method. The model can further evaluate the collapse failure risk of the production casing in the whole wellbore. An example study and sensitivity analysis were carried out to reveal the variation characteristics of the transient swab pressure in the A-annulus and the failure risk of the production casing after packer unsetting. Furthermore, some preventative measures are proposed. The largest swab pressure occurs at the initial time of packer unsetting, which will lead to sudden collapse failure of the deeper production casing. A smaller width of the annular clearance between the packer rubber and production casing and a larger initial liquid level depth in the A-annulus can reduce the swab pressure in the A-annulus after packer unsetting and collapse failure risk of the production casing. In the example, when the width of the annular clearance decreased from 2.97 to 2 mm, the maximum swab pressure decreased from 88.71 to 27.4 MPa, a decrease of 69.1%. When the initial liquid level depth in the A-annulus increased from 700 to 900 m, the maximum swab pressure decreased from 122 to 57.05 MPa, a decrease of 53.2%. When the width of annular clearance was 2.97 mm, the collapse resistance safety factors for the production casing were less than 1.1 and may suffer from collapse failure for well depth between 3610 m and 6100 m. When the initial liquid level depth in the A-annulus was 700 m, the production casing will suffer from collapse failure for well depth between 2869 m and 6100 m. When the width of the annular clearance was less than 2.5 mm and the initial liquid level depth in the A-annulus was larger than 900 m, the collapse resistance safety factors for the production casing were all greater than 1.1 and the whole production casing was safe. To lower the collapse failure risk of the production casing because of packer unsetting, a packer rubber with a reasonable larger outer diameter and good deformation recovery ability is recommended, and the initial liquid level depth in the A-annulus should be controlled reasonably. The research results are of great significance for preventing the collapse failure of production casings during packer unsetting. Full article

This study investigates the effect of incorporating modified calcium carbonate whiskers, treated with tetraethyl orthosilicate (TEOS), to enhance the mechanical properties and sealing integrity of oil well cement under high-temperature and high-pressure (HTHP) conditions. Traditional cement systems are prone to brittleness and cracking under dynamic loads, leading to compromised wellbore sealing performance. Our findings demonstrate that fiber-toughened cement slurry improves the toughness and sealing performance of the cement annulus, maintaining gas tightness and mechanical integrity under cyclic alternating pressures at 150 °C. Specifically, the inclusion of 5% modified whisker fibers improves compressive strength by 24.5% and flexural strength by 43.3% while maintaining stable rheological and thickening properties. These results support the hypothesis that modified whisker fibers enhance the durability and sealing integrity of cement wellbores under extreme conditions, providing a practical solution for challenging cementing applications. Full article

During the drilling of natural gas hydrate reservoirs, gas invasion may occur, which has an adverse impact on the upward return process of cuttings and the control of bottom-hole pressure. A multiphase fluid CFD simulation method based on the Eulerian model was optimized. With the help of Fluent 23R1 software, simulations of the three-phase flow of drilling fluid–cuttings–invaded gas in the vertical section, build-up section, and horizontal section of the complex annulus multiphase flow in the hydrate drilling wellbore based on particle dynamics were carried out. The characteristics of multiphase flow in the wellbore after gas invasion were revealed, and the impacts of gas invasion on the deposition and migration of cuttings and the control of bottom-hole pressure were analyzed. The research shows that after gas invades the wellbore, it has little impact on the upward return of cuttings in the build-up section. However, in the vertical and horizontal sections, with the increase in the flow rate of the invaded gas, the slip and upward return of cuttings are promoted. The gas invasion velocity has a more significant impact on the cutting migration in different well sections compared to the gas invasion volume fraction. A faster invasion velocity accelerates the upward return of cuttings in the wellbore annulus. When gas invasion occurs, it has little impact on the pressure in the build-up section, decreases the pressure gradient in the vertical section, and increases the pressure gradient in the horizontal section. At the same time, there is a high linear correlation between the pressure gradient in each well section and the density of water-based drilling fluid. By reasonably controlling the density of drilling fluid according to the gas volume fraction detected at the wellhead, the aggravation of gas invasion can be significantly prevented. The research methods and calculation results are helpful in providing a reference for the subsequent drilling process of hydrate reservoirs. Full article

This study examines the flow behavior as well as the cuttings transport of non-Newtonian drilling fluid in the geometry of an eccentric annulus, accounting for what impacts drill pipe rotation might have on fluid velocity, as well as annular eccentricity on axial and tangential distributions of velocity. A two-phase Eulerian–Eulerian model was developed by using computational fluid dynamics to simulate drilling fluid flow and cuttings transport. The kinetic theory of granular flow was used to study the dynamics and interactions of cuttings transport. Non-Newtonian fluid properties were modeled using power law and Bingham plastic formulations. The simulation results demonstrated a marked improvement in efficiency, as much as 45%, in transport by increasing the fluid inlet velocity from 0.54 m/s to 2.76 m/s, reducing the amount of particle accumulation and changing axial and tangential velocity profiles dramatically, particularly at narrow annular gaps. At a 300 rpm rotation, the drill pipe brought on a spiral flow pattern, which penetrated tangential velocities in the narrow gap that had increased transport efficiency to almost 30% more. Shear-thinning behavior characterizes fluid of which the viscosity, at nearly 50% that of the central core low-shear regions, was closer to the wall high-shear regions. Fluid velocity and drill pipe rotation play a crucial role in optimizing cuttings transport. Higher fluid velocities with controlled drill pipe rotation enhance cuttings removal and prevent particle build-up, thereby giving very useful guidance on how to clean the wellbore efficiently in drilling operations. Full article

In recent years, significant breakthroughs have been made in the exploration of deep to ultra-deep oil and gas reserves onshore in China. These conventional deep to ultra-deep reservoirs are typically buried at depths exceeding 4500 m, with bottom-hole temperatures surpassing 150 °C. The high temperatures at the bottom of the well are more likely to cause deterioration in drilling fluid properties, altering its rheological properties and reducing cutting transport efficiency, which can lead to wellbore cleaning issues. In this paper, the numerical simulation method is used to analyze the influence of cutting particle size, drilling fluid flow rate, drill pipe rotation speed, and drill pipe eccentricity on the annular cutting concentration under different wellbore drilling fluid temperature conditions. The results show that at the same cutting particle size, as the drilling fluid temperature increases, the cutting concentration in the annulus increases sharply. The increase is the largest when the particle size is 3 mm, and when the drilling fluid temperature is 220 °C, the cutting concentration increases by 79.7% compared to at 200 °C and by 279% compared to at 180 °C. When the flow rate increases from 0.5 m/s to 1.0 m/s, the annular cutting concentration at drilling fluid temperatures of 220 °C and 200 °C decreases by 70.5% and 50.4%, respectively. The higher the drilling fluid temperature, the better the cutting removal effect when increasing the drill pipe rotation speed. However, when the rotation speed exceeds 120 rpm, the change in cutting concentration with increasing rotation speed becomes insignificant. When the drill pipe eccentricity is small, an increase in drilling fluid temperature leads to a significant rise in annular cutting concentration. However, when the drill pipe eccentricity is large, changes in drilling fluid temperature have a smaller impact on cutting concentration. The research findings can provide engineering guidance and theoretical support for the design of drilling fluid hydraulic parameters for cutting transport and rheological parameters in high-temperature wellbores. Full article

Poor wellbore cleaning is a significant challenge in oil drilling, primarily due to the accumulation of cuttings at the bottom of the well, particularly in deviated and horizontal wells. This study addresses this issue by employing Computational Fluid Dynamics (CFD) with the commercial software ANSYS FLUENT (2023-R1) to simulate a solid–liquid multiphase flow in an annulus. The primary objective is to analyze the cuttings concentration, pressure loss, and solid velocity profiles across various drilling parameters, including drill pipe rotation, the flow rate, rate of penetration, inclination angle, and fluid rheology. Our results underscore the critical role of these parameters in enhancing cuttings transport efficiency. Specifically, the drill pipe rotation, flow rate, and rate of penetration emerge as the most influential factors affecting the wellbore cleaning performance. With a validated model exhibiting an average error of 4.24%, this study provides insights into optimizing drilling operations to improve wellbore cleaning and increase hydrocarbon recovery. Full article

In the process of CO₂ geological storage in the salt water layer, CO₂ leakage along the wellbore will seriously affect the effective storage of CO₂ in the target geological area. To solve this problem, based on the investigation of a large number of failure cases of CO₂ storage along the wellbore and failure cases of gas storage wells in the injection stage of the wellbore, the influencing factors of CO₂ leakage risk along the wellbore were investigated in detail. Based on the analytic hierarchy process (AHP) and extension theory, 17 basic evaluation indexes were selected from 6 perspectives to establish the evaluation index system of CO₂ leakage risk along the wellbore. The established evaluation system was used to evaluate the leakage risk of a CO₂ storage well in the X gas field of BZ Block. The results showed that the influencing factors of tubing had the smallest weight, followed by cement sheath, and the influencing factors of casing–cement sheath interface and cement sheath–formation interface had the largest weight, accounting for 23.73% and 34.32%, respectively. The CO₂ storage well leakage risk evaluation grade was Ι, with minimal leakage risk. The CO₂ storage effect was excellent. The evaluation system comprehensively considers the tubing string, cement sheath, and micro-annulus interface, which can provide a scientific basis for the risk assessment of CO₂ leakage along the wellbore under the CO₂ geological storage of the salt water layer. Full article

Subsea wellheads and Christmas trees are commonly utilized in deepwater oil and gas development. However, the special structure of subsea wellheads makes it difficult to monitor casing–casing annular pressure buildup, which in turn poses a greater risk to the integrity of the wellbore. In order to analyze the effect of changes in the casing-free section and the sealed section on the variation in annulus volume, a new annular pressure buildup model of casing-cement sheath-formation deformation was established and verified according to the elastic deformation theory. Furthermore, the influence of casing deformation on annulus pressure buildup was analyzed. Results indicate that the error of annulus pressure buildup predicted by the multi-string mechanical model proposed in this paper that considers the deformation of the casing sealing section is approximately 13% lower than the one that does not consider this factor. This paper provides guidance for the design of casing strings in deepwater oil and gas wells, ensuring safe production. Full article

The reservoir in the Shunbei field is characterized by ultra-deep, ultra-high temperature, and ultra-high pressure. During the drilling process, the circulating temperature at the bottom of the well is higher than the temperature resistance of downhole instruments, which leads to frequent problems of device burnout and no signal. Therefore, it is of great significance to accurately predict the wellbore temperature field of ultra-deep directional wells. In this paper, the influence of the drilling string assembly, the flow channel structure and the flow pattern on the convective heat exchange coefficient is considered. Based on the energy conservation equation, a numerical model of wellbore-formation transient heat transfer is developed. Then, the model was verified by the real data of two ultra-deep wells in Shunbei block, China, and the results showed that the prediction errors of bottom-hole temperature were all within 2%. Finally, the key factors and rules of the wellbore annulus temperature are analyzed. The results show that the bottom-hole temperature decreases with the decrease of inlet temperature, the thermal conductivity of drilling fluid, and the thermal conductivity of drill pipe, and increases with the decrease of flow rate, the density of drilling fluid, viscosity of drilling fluid, and specific heat capacity of drilling fluid. The inlet temperature has the greatest influence on the outlet temperature, and the specific heat of the pipe string has a minor influence on the wellbore annulus temperature. The research results of this paper provide an accurate wellbore temperature field prediction method for ultra-deep directional wells in the Shunbei block, China, which is of great significance for temperature-controlled drilling. Full article

Natural gas hydrate (NGH) trials have been performed successfully with different development methods and gas recovery drainage technologies. Multiphase flow in a wellbore and the drainage of natural gas hydrate are two important parts for its whole extraction process. Additionally, the choice of the drainage method is linked to the development method, making the drainage of NGH more complex. Jet pump drainage is usable for NGH production wells with the combined depressurization and thermal stimulation method. The objective of this study is to shed more light on the multiphase flow behavior in jet pump drainage and NGH production wells and put forward suggestions for adjusting heat injection parameters. The mechanism of jet pump drainage recovery technology for NGH wells was analyzed and its applicability to NGH development by the combined depressurization and thermal stimulation method was demonstrated. In addition, multiphase flow models of tubing and annulus were established, respectively, for the phenomenon of the countercurrent flow of heat exchange in the process of jet pump drainage and gas production, and the corresponding multiphase flow laws were derived. On the basis of these studies, sensitivity analysis and the optimization of thermal stimulation parameters were conducted. It is demonstrated that jet pump drainage gas recovery technology is feasible for the development of onshore NGH with the combined depressurization and thermal stimulation method. The laws of multiphase flow in the tubing and annulus of jet pump drainage and NGH production wells were disclosed in this study. Numerical simulation results show that the temperature and pressure profiles along the wellbore of jet pump drainage and NGH production wells during the drainage recovery process are affected by injection conditions. Increasing injection rate and injection temperature can both improve the effect of heat injection and reduce the hydrate reformation risk in the bottom of the annulus. This study offers a theoretical basis and technical support for production optimization and hydrate prevention and control in the wellbore of jet pump drainage and NGH production wells. Full article