Search Results (27)

The existing wellbore stability models do not account for the effects of fracture seepage and pressure transmission on wellbore stability, leading to inaccurate predictions of collapse pressure. In this paper, we investigate factors such as wellbore physical parameters, anisotropy, seepage, and pressure transmission for horizontal drilling in shale reservoirs and propose a new collapse pressure prediction model that incorporates weak plane effects and mechanical anisotropy. This model revises the safe mud weight window for drilling shale gas horizontal wells. Taking a shale gas horizontal well in southern Sichuan as an example, the application of the model in the field and its improved prediction accuracy are verified. The research results show that the drilling fluid seepage action and pressure transfer under the condition of positive differential pressure in the wellbore reduce the effective radial stress around the well; with the increase in the number of shale fracture groups, the degree of well wall fragmentation increases accordingly, which reduces the effective support effect of drilling fluids on the well wall; compared with the traditional Moore–Cullen model and the weak face model, the new model of slump pressure prediction by introducing the indicator function has an average error rate of only 7.4%, with a high degree of agreement; the prediction value of the established formation fracture pressure calculation model has an error of less than 5% with the experimental results. The comparison of the field measurement data verifies the applicability and reliability of the pressure prediction model. Full article

During drilling in fractured formations, wellbore instability issues such as fluid loss and collapse frequently occur, severely compromising drilling safety. Traditional criteria such as Mohr–Coulomb often fail to adequately account for fracture effects, leading to inaccurate collapse pressure predictions. Taking the Tahe Oilfield as a case study, this research develops an enhanced model for predicting wellbore collapse pressure in fractured formations. Based on principles of elastic mechanics and Biot’s effective stress theory, a stress distribution model around deviated wellbores is established. The single weak plane strength criterion is integrated with the Mohr–Coulomb criterion to characterize failure mechanisms in both fractured zones and intact rock matrix. Newton’s iterative method, implemented in MATLAB, is employed to solve for collapse pressure, and a sensitivity analysis is conducted to evaluate the influence of factors such as in situ stresses and fracture orientation. A case study from Well THX demonstrates that neglecting fractures results in a symmetrical collapse pressure profile and an unduly narrow safe mud weight window. In contrast, accounting for fractures significantly increases the required mud weight and identifies an optimal azimuth range for enhancing wellbore stability. The Mohr–Coulomb criterion is shown to underestimate the necessary mud weight, which aligns with actual wellbore collapse incidents encountered during drilling. The single weak plane criterion offers more accurate predictions, recommending a higher minimum mud density and an optimized well trajectory to mitigate drilling risks. These findings offer theoretical and practical guidance for mitigating wellbore instability in fractured formations. Full article

To address the challenges of accurately predicting and controlling the annular equivalent circulating density (ECD) in ultra-deepwater gas hydrate-bearing formations of the Qiongdongnan Basin, where joint production of hydrates and shallow gas through dual horizontal wells faces a narrow safe pressure window and hydrate decomposition effects, this study develops an ECD prediction model that incorporates riser drilling operations. The model couples four sub-models, including the static equivalent density of drilling fluid, annular pressure loss, wellbore temperature–pressure field, and hydrate decomposition rate, and is solved iteratively using MatlabR2024a. The results show that hydrate cuttings begin to decompose in the upper section of the riser (at a depth of approximately 600 m), causing a reduction of about 2 °C in wellhead temperature, a decrease of 0.15 MPa in bottomhole pressure, and an 8 kg/m³ reduction in ECD at the toe of the horizontal section. Furthermore, sensitivity analysis indicates that increasing the rate of penetration (ROP), drilling fluid density, and flow rate significantly elevates annular ECD. When ROP exceeds 28 m/h, the initial drilling fluid density is greater than 1064 kg/m³, or the drilling fluid flow rate is higher than 21 L/s, the risk of formation loss becomes considerable. The model was validated against field data from China’s first hydrate trial production, achieving a prediction accuracy of 93%. This study provides theoretical support and engineering guidance for safe drilling and hydraulic parameter optimization in ultra-deepwater hydrate-bearing formations. Full article

During deepwater drilling operations, when influx gas invades the wellbore, gas hydrates may form through the combination of the gas with free water in the drilling fluid under favorable temperature and pressure conditions. This process can alter the physical properties and flow behavior of the wellbore fluid, potentially leading to safety incidents. To prevent natural gas hydrate formation, mitigate wellbore blockages caused by hydrates, and address the associated safety hazards, this study conducted laboratory experiments to investigate hydrate formation and remediation under multiple deepwater drilling conditions. The hydrate formation boundaries for four different drilling fluid systems—seawater-based bentonite mud, seawater polymer mud, Plus/KCl mud, and HEM mud—were determined for varying well depths and pressure–temperature conditions, and corresponding trend lines were fitted. Key results reveal that a higher carbon content promotes hydrate formation, and the phase equilibrium curves also reveal significant differences among the four drilling fluids. The hydrate aggregation states and blockage processes were clarified for three typical drilling scenarios: drilling, well killing, and drilling suspension. Hydrate formation risk is negligible during normal circulation but increases dramatically during well-killing operations, significantly shrinking the safe operational window. A comparative analysis identified that adding 1% P(M-VCL), a kinetic hydrate inhibitor, to the drilling fluid was the most effective solution, demonstrating superior performance in delaying hydrate nucleation and preventing agglomeration. The study established a complete formation–inhibition–remediation approach for hydrate management in deepwater drilling, thereby enhancing operational safety and efficiency. Full article

Accurate pre-drilling mud weight window (MWW) prediction is crucial for drilling fluid design and wellbore stability in complex geological formations. Traditional physics-based approaches suffer from subjective parameter selection and inadequate handling of multi-mechanism over-pressured formations, while machine learning methods lack physical constraints and interpretability. This study develops a novel physics-guided deep learning framework integrating rock mechanics theory with deep neural networks for enhanced MWW prediction. The framework incorporates three key components: first, a physics-driven layer synthesizing intermediate variables from rock physics calculations to embed domain knowledge while preserving interpretability; second, a geological sequence-matching algorithm enabling precise stratigraphic correlation between offset and target wells, compensating for lateral geological heterogeneity; third, a long short-term memory network capturing sequential drilling characteristics and geological structure continuity. Case study results from 12 wells in northwestern China demonstrate significant improvements over traditional methods: collapse pressure prediction error reduced by 40.96%, pore pressure error decreased by 30.43%, and fracture pressure error diminished by 39.02%. The proposed method successfully captures meter-scale pressure variations undetectable by conventional approaches, providing critical technical support for wellbore design optimization, drilling fluid formulation, and operational safety enhancement in challenging geological environments. Full article

The deep and ultra-deep oil and gas resources often have the characteristics of high temperature and high pressure, with complex pressure systems and narrow safety density windows, so risks such as gas invasion and overflow are easy to occur during the drilling. In response to the problems of low management efficiency and large gas kick by traditional gas invasion treatment methods, this paper respectively established and compared three intelligent control models for bottom hole pressure (BHP) based on a PID controller, a fuzzy PID controller, and a fuzzy neural network PID controller based on the non-isothermal gas–liquid–solid three-phase transient flow heat transfer model in the annulus. The results show that compared with the PID controller and the fuzzy PID controller, the fuzzy neural network PID controller can adjust the control parameters adaptively and optimize the control rules in real-time; the efficiency of the fuzzy neural network PID controller to deal with a gas kick is improved by 45%, and the gas kick volume in the process of gas kick is reduced by 63.12%. The principal scientific novelty of this study lies in the integration of a fuzzy neural network PID controller with a non-isothermal three-phase flow model, enabling adaptive and robust bottom hole pressure regulation under complex gas invasion conditions, which is of great significance for reducing drilling risks and ensuring safe and efficient drilling. Full article

The Huazhuang block, located on the northern slope of the Gaoyou Depression in the Subei Basin of the Jiangsu Oilfield, exhibits complex stratigraphic geomechanical characteristics. During drilling, wellbore instability-related issues, such as obstruction, sticking, pump pressure buildup, bit pressure buildup, and overflow due to abnormally high pressure, prolong the drilling cycle and significantly hinder the safe and efficient development of shale oil. In order to determine the appropriate drilling fluid density and ensure safe and efficient drilling in this block, a comprehensive wellbore profile, incorporating rock mechanical parameters, in-situ stress, and predictions of pore pressure, collapse pressure, lost circulation pressure, and fracture pressure, was established based on laboratory tests and well logging data. This study reveals the mechanisms of wellbore collapse and fluid loss in the Huazhuang block. The results indicate that the second and fourth members of the Funing Formation in the Huazhuang block have a relatively weak and unconsolidated structure with a high content of water-sensitive minerals, leading to significant hydration risks when using water-based drilling fluids. As depth increases, compressive strength, elastic modulus, and cohesion show an increasing trend, while the internal friction angle and Poisson’s ratio gradually decrease. Additionally, in-situ stress increases significantly, meeting the condition of ${\sigma }_{\mathrm{V}}$ > ${\sigma }_{\mathrm{H}}$ > ${\sigma }_h$. Above 3300 m, the equivalent density of formation pore pressure is below 1.20 g/cm³, Whereas below 3300 m, there is significant overpressure, with a maximum equivalent pore pressure density reaching 1.45 g/cm³. The deeper the formation, the narrower the safe density window, making wellbore collapse more likely. To prevent wellbore instability, both the sealing capability and density of the drilling fluid should be considered. Enhancing the sealing performance of the drilling fluid and selecting an appropriate drilling fluid density can help improve wellbore stability. The established rock mechanical parameters and four-pressure prediction profile for the Huazhuang block provide a scientific basis for optimizing wellbore structure design and selecting key engineering parameters. Full article

This study examines the distribution of pore pressure (PP) and fracture gradient (FG) within intervals of lost circulation encountered during drilling operations in the Ordovician reservoir (IV-3 unit) of the Tin Fouye Tabankort (TFT) field, located in the Illizi Basin, Algeria. The research further aims to determine an optimized drilling mud weight to mitigate mud losses and enhance overall operational efficiency. PP and FG models for the Ordovician reservoir were developed based on data collected from five vertical development wells. The analysis incorporated multiple datasets, including well logs, mud logging reports, downhole measurements, and Leak-Off Tests (LOTs). The findings revealed an average overburden gradient of 1.03 psi/ft for the TFT field. The generated pore pressure and fracture gradient (PPFG) models indicated a sub-normal pressure regime in the Ordovician sandstone IV-3 reservoir, with PP values ranging from 5.61 to 6.24 ppg and FG values between 7.40 and 9.14 ppg. The analysis identified reservoir depletion due to prolonged hydrocarbon production as the primary factor contributing to the reduction in fracture gradient, which significantly narrowed the mud weight window and increased the likelihood of lost circulation. Further examination of pump on/off cycles over time, coupled with shallow and deep resistivity variations with depth, confirmed that the observed mud losses were predominantly associated with induced fractures resulting from the application of excessive mud weight during drilling operations. Based on the established PP and FG profiles, a narrow mud weight window of 6.24–7.40 ppg was recommended to ensure the safe and efficient drilling of future wells in the TFT field and support the sustainability of drilling operations in the context of a depleted reservoir. Full article

Deep drilling can lead to the encounter of complex geological conditions, with significant overburden pressure leading to a narrow safety window for mud density. In this study, we deviated wellbore instability conditions using the Mohr–Coulomb and tensile failure criteria, solving for collapse, shear, and fracture pressure using Newton’s method. The safe mud density window is defined between the maximum value of pore and collapse pressures and the minimum value of shear and fracture pressures. The analysis of the Anderson fault stress model, utilizing this method, enables a comprehensive investigation of how the safety mud density window varies with wellbore inclination and azimuth angles under various stress conditions. Additionally, applications in Chinese oilfields illustrate that this methodology can accurately calculate and analyze extremely narrow safety mud density windows at depths ranging from 2000 to 3000 m. In conclusion, this method enables rapid and accurate prediction of mud density limits, improving wellbore stability and reducing drilling risks. Full article

During deepwater drilling, the low mudline temperatures and narrow safe density window pose serious challenges to the safe and efficient performance of deepwater water-based drilling fluids. Low temperatures can lead to physical and chemical changes in the components of water-based drilling fluids and the behavior of low temperature gelation. As a coarse dispersion system, water-based drilling fluid has a complex composition of dispersed phase and dispersing medium. Further clarification of low temperature gelation would be helpful in developing technical approaches to enhance the flat rheology performance of deepwater water-based drilling fluids. In this paper, different components are separated in order to comprehensively analyze the gelation behavior of different materials in water-based drilling fluids at low temperatures. In the first place, the rheological and hydrodynamic radius alterations of inorganic salts, bentonite, and additives in aqueous solutions were examined at low temperatures. The effects of inorganic salts, bentonite, and additives on the purified water system were investigated at low (4 °C)–normal (25 °C)–high (75 °C) temperatures. The low temperature gelation of different materials in pure water systems are fully clarified. The mud containing 4% bentonite with weak low temperature gelation commonly used in deepwater water-based drilling fluids was selected as the basic test system. Inorganic salts, additives, and solid-phase materials were added to the mud containing 4% bentonite. The effects of the interactions between different materials and bentonite particles on the low temperature gelation behavior of mud were analyzed. The higher the bentonite dosage, the stronger the low temperature gelation behavior of mud. The higher the addition of inorganic salts, the more serious the low temperature gelation behavior of mud. Inorganic salts should be avoided as much as possible to add too much. The low temperature gelation behavior of mud with low-viscosity additives is weak. However, the viscosity of mud with high-viscosity additives has a small change in viscosity with increasing temperature. The low temperature gelation of mud with the addition of solid-phase particulate materials with reactive groups on the surface is strong, and the low temperature gelation with the addition of inert particles is weak. This paper elucidates the low temperature gelation mechanism of bentonite, inorganic salts, additives, and solid-phase materials in deepwater water-based drilling fluids. The conclusion can also be used to guide the construction of a drilling fluid system, which is of great significance for the research and development of deepwater water-based drilling fluid additives and the safe and efficient performance of deepwater drilling fluids. Full article

A landing string is directly exposed to seawater and subjected to significant stresses and complex deformations due to environmental loads such as wind, waves, and ocean currents during the phase in which the drill string carries the casing to the wellhead. Meanwhile, as the water depth increases, the weight of the drill string increases, leading to an increase in the tensile loads borne by the drill string, which can easily cause a risk of failure. Therefore, a quasi-static load calculation model for the deepwater insertion of the pipe column was established. Using the Ansys platform, simulations were conducted for average wind, wave, and ocean current conditions during different months throughout the year. The ultimate loads and stress distributions of the string were derived from theoretical analyses and numerical simulations for different operational sea states, and the suggested safe operating window and desired BOP trolley restraining reaction force for landing strings’ lowering are given according to the existing industry standards. The research findings can help in identifying the potential risks and failure modes of the deepwater landing string under different working conditions. Full article

In the study of borehole instability, the majority of input parameters often rely on the average values that are treated as fixed values. However, in practical engineering scenarios, these input parameters are often accompanied by a high degree of uncertainty. To address this limitation, this paper establishes a borehole stability model considering the uncertainty of input parameters, adopts the Monte Carlo method to calculate the borehole stability reliability at different drilling fluid densities, evaluates the sensitivity of borehole instability to a single parameter, and studies the safe drilling fluid density window at different borehole stability reliability values under multi-parameter uncertainties. The results show that the uncertainty of rock cohesion has a great influence on the fracture pressure of the vertical and horizontal wells. The minimum horizontal stress has the greatest influence on the fracture pressure of the vertical and horizontal wells, followed by pore pressure. In the analysis of borehole stability, the accuracy of cohesion and minimum horizontal stress parameters should be improved. In scenarios involving multiple parameter uncertainties, while the overall trend of the analysis results remains consistent with the conventional borehole stability outcomes, there is a noteworthy narrowing of the safe drilling fluid density window. This suggests that relying on conventional borehole stability analysis methods for designing the safe drilling fluid density window can considerably increase the risks of borehole instability. Uncertainty assessment is crucial to determine the uncertainties associated with the minimum required mud pressure, thereby ensuring more informed decision-making during drilling operations. To meet practical application demands, structure and boundary condition uncertainties should be implemented for a more comprehensive assessment of borehole stability. Full article

Formation leak-off pressure, which sets the upper limit of the safe drilling fluid density window, is crucial for preventing wellbore accidents and ensuring safe and efficient drilling operations. The paper thoroughly examines models of drilling physics alongside artificial intelligence techniques. The study introduces a dual-driven method for predicting reservoir pore pressure by integrating long short-term memory (LSTM) and backpropagation (BP) neural networks, where the core component is the LSTM-BP neural network model. The input data for the LSTM-BP model include wellbore diameter, formation density, sonic time, natural gamma, mud content, and pore pressure. The study demonstrates the practical application of the method using two vertical wells in Block M, employing the M-1 well for training and the M-2 well for validation. Two distinct input layer configurations are devised for the LSTM-BP model to evaluate the influence of formation density on prediction accuracy. Notably, Scheme 2 omits formation density as a variable in contrast to Scheme 1. The study’s results indicate that, for input layer configurations corresponding to Scenario 1 and Scenario 2, the LSTM-BP model exhibits relative error ranges of (−2.467%, 2.510%) and (−6.141%, 5.201%) on the test set, respectively. In Scenario 1, the model achieves mean squared error (MSE), mean absolute error (MAE), and R-squared (R²) values of 0.000229935, 0.011198329, and 0.92178272, respectively, on the test set. Conversely, for Scenario 2, the model demonstrates a substantial escalation of 992.393% and 240.674% in MSE and MAE, respectively, compared to Scenario 1; however, R² diminishes by 66.920%. Utilizing the trained LSTM-BP model, predictions for formation lost pressure in Well M-2 reveal linear correlation coefficients of 0.8173 and 0.6451 corresponding to Scenario 1 and Scenario 2, respectively. These findings imply that the predictions from the Scenario 1 model demonstrate stronger alignment with results derived from formulaic calculations. These observations remain consistent for both the BP neural network algorithm and the random forest algorithm. The aforementioned research results not only highlight the elevated predictive precision of the LSTM-BP model for intelligent prediction of formation lost pressure, a product of this study, thereby furnishing valuable data points to enhance the security of drilling operations in Block M, but also underscore the necessity of deliberating both physical relevance and data correlation during the selection of input layer variables. Full article

As an important drilling tool, the landing string will be directly exposed to seawater during surface riserless drilling operations, and it will undergo complex deformation under the action of environmental loads such as ocean currents and waves and the displacement, heave and vibration of the drilling platform. At the same time, with the increase in water depth, the floating weight of drill pipe and casing also increases significantly, and the landing string will bear great tensile loads, which can easily cause accidents. Therefore, in this paper, based on ANSYS software, the finite element analysis models of three stages of the landing string lowering operation were established, and finite element simulations under different combinations of working conditions were carried out. Through theoretical analysis and numerical simulation, the ultimate load and stress distribution of the string under different operating sea conditions were obtained, and the external force requirements for restraining the lateral displacement of the string were proposed according to the existing standards of the industry. Thereby, the recommended safe operating time, safe operating conditions window and the required restraint reaction force of the support mechanism are given for landing string lowering operation throughout the year. Full article

The aim of this study was to propose the workflow for integrated analysis of the 3D geostress and 1D geomechanics of an exploration in a new gas field. This integrated analysis will allow for problems associated with the inaccuracy of 1D geomechanical analysis to be overcome in a region with obvious anticline/syncline structures. The 1D geomechanical analysis of the well in the exploration of a new gas field mainly included the prediction of pore pressure and calculation of the mud weight window for safe drilling. In general, this integrated workflow included both a method for pore pressure prediction and a method for the calculation of the mud weight window, with the numerical solution of 3D geostress plus the interval velocity of formations. The procedure for the calculation of the 3D geostress of a target block was also introduced. Numerical solution of the 3D geostress of the target gas field, as well as solutions of 1D geomechanical analysis, have demonstrated the efficiency and practical use of the proposed theory in the successful drilling of the LT-1 well in the Junggar Basin, Xinjiang, China. For this LT-1 well in the target TS block, there was no logging data to refer to when predicting the pore pressure of undrilled formations. Only 3D geostress could be used to calculate the mud weight window. Influences of anticline structures were considered in the calculation of 3D geostress. Since the accuracy of the numerical solution of 3D geostress is higher than the accuracy of the 1D geostress solution for a single well analysis, the results of pore pressure and the mud weight window are more accurate than those obtained with conventional 1D geostress analysis. Details of the finite element modeling of the 3D geostress field of the TS block is presented along with the solution of the 3D geostress field. With the data of the interval velocity of formations and 3D geostress solution of the TS block, pore pressure prediction was carried out for the 7000 m-deep pilot LT-1 well. Finally, calculations were performed for the values of the mud weight window of the LT-1 well. Full article