Search Results (45)

Downhole kick is one of the most severe safety hazards in deep and ultra-deep well drilling operations. Traditional monitoring methods, which rely on surface flow rate and fluid level changes, are limited by their delayed response and insufficient sensitivity, making them inadequate for early warning. This study proposes a real-time monitoring technique for gas content in drilling fluid based on the attenuation principle of Ba-133 γ-rays. By integrating laboratory static/dynamic experiments and Geant4-11.2 Monte Carlo simulations, the influence mechanism of gas–liquid two-phase media on γ-ray transmission characteristics is systematically elucidated. Firstly, through a comparative analysis of radioactive source parameters such as Am-241 and Cs-137, Ba-133 (main peak at 356 keV, half-life of 10.6 years) is identified as the optimal downhole nuclear measurement source based on a comparative analysis of penetration capability, detection efficiency, and regulatory compliance. Compared to alternative sources, Ba-133 provides an optimal energy range for detecting drilling fluid density variations, while also meeting exemption activity limits (1 × 10⁶ Bq) for field deployment. Subsequently, an experimental setup with drilling fluids of varying densities (1.2–1.8 g/cm³) is constructed to quantify the inverse square attenuation relationship between source-to-detector distance and counting rate, and to acquire counting data over the full gas content range (0–100%). The Monte Carlo simulation results exhibit a mean relative error of 5.01% compared to the experimental data, validating the physical correctness of the model. On this basis, a nonlinear inversion model coupling a first-order density term with a cubic gas content term is proposed, achieving a mean absolute percentage error of 2.3% across the full range and R² = 0.999. Geant4-based simulation validation demonstrates that this technique can achieve a measurement accuracy of ±2.5% for gas content within the range of 0–100% (at a 95% confidence interval). The anticipated field accuracy of ±5% is estimated by accounting for additional uncertainties due to temperature effects, vibration, and mud composition variations under downhole conditions, significantly outperforming current surface monitoring methods. This enables the high-frequency, high-precision early detection of kick events during the shut-in period. The present study provides both theoretical and technical support for the engineering application of nuclear measurement techniques in well control safety. Full article

Pore pressure prediction gives drillers an early warning of potential oil and gas kicks, enabling them to adjust mud weight pre-emptively. A kick causes a delay in drilling practices, blowouts, and jeopardization of the wells. Changes in pore pressure affect the type of fluid contact in the reservoir. This study predicted the pore pressure and determined fluid contacts within the Lower Cretaceous and early Upper Cretaceous (Barremian to early Cenomanian) sandstone reservoirs of the Bredasdorp Basin using well logs and repeat formation test (RFT) data from three wells: E-BK1, E-AJ1, and E-CB1. Eaton’s method of developing a depth-dependent Normal Compact Trend (NCT), using resistivity and sonic wireline logs, as well as other methods including the Mathews and Kelly, Baker and Wood, and Modified Eaton and Bowers methods, were employed for pore pressure prediction. Eaton’s method provided reliable pore pressure results in all the wells when compared to alternative methods in this study. Overburden gradient and predicted pore pressures ranged from 1.84 gm/cc to 2.07 gm/cc and from 3563.74 psi to 4310.06 psi, respectively. Eaton’s resistivity and density/neutron log method results indicated normal pressure in E-BK1 and E-AJ1, as well as overpressured zones in E-AJ1. However, in E-CB1, the results showed only overpressured zones. The E-AJ1 significant overpressures were from 2685 m to 2716 m and from 2716 m to 2735 m in the pores exceeding 7991.54 psi. Gas–water contact (GOC) was encountered at 2967.5 m in E-BK1, while oil–gas contact (OGC) was at 2523 m in E-CB1, and gas–oil and oil–water contacts (GOC and OWC) were at 2699 m and 2723 m, respectively, in E-AJ1. In E-CB1, oil–water contact (OWC) was at 2528.5 m. Fluid contacts observed from the well logs and RFT data were in close agreement in E-AJ1, whereas there was no agreement in E-CB1 because the well log observations showed a shallower depth compared to RFT data with a difference of 5.5 m. This study illustrated the significance of an integrated approach to predicting fluid contacts and pore pressure within the reservoirs by showing that fluid contacts associated with overpressures were gas–water and oil–water contacts. In contrast, gas–oil contact was associated with normal pressure and under pressure. Full article

The Luzhou Block in the Sichuan Basin hosts a widely distributed high-quality shale gas reservoir. However, the overlying carbonate strata pose considerable engineering challenges, including severe risks of subsurface fluid loss and wellbore collapse. These challenges are primarily attributed to inaccuracies in pore pressure prediction, which significantly constrains the safety and efficiency of drilling operations in carbonate formations. To address this issue, this study systematically investigates and compares three classical pore pressure prediction approaches—namely, the equivalent depth method, the Eaton method, and the effective stress method—within the geological context of the Luzhou Block. A novel fitting strategy based on laboratory core experimental data is introduced, whereby empirical relationships between field-measured parameters and rock mechanical properties are established to improve model robustness in geologically complex formations. The optimized effective stress model is subsequently applied to the carbonate reservoir interval, and its prediction outcomes are evaluated against measured pore pressure data. The results demonstrate that the effective stress method achieves the highest prediction accuracy, with a maximum deviation of 8.4% and an average deviation of 5.3%. In comparison, the equivalent depth and Eaton methods yield average errors of 12.5% and 12.2%, respectively. These findings suggest that the effective stress method exhibits superior adaptability and reliability for pore pressure prediction in carbonate formations of the Luzhou Block, and holds significant potential for guiding mud density design and improving the operational safety of drilling programs. 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

The lithology of the transitional facies of the Longtan Formation in the southern Sichuan Basin is complex, with soft/hard thin interlayers of mud shale, sandstone, and limestone. Drilling this layer often results in wellbore instability, including frequent blockages, tripping resistance, and sticking. This study focuses on a shale gas block in the Longtan Formation in Zigong, where a geomechanical profile was established by integrating ground stress, rock parameter tests, and logging data. The critical collapse pressure was calculated, and wellbore instability was simulated using the Mohr–Coulomb failure criterion and the discrete element method. Results indicate significant variability in the mechanical strength of the rocks, with notable longitudinal heterogeneity and a high risk of wellbore instability. The critical collapse pressure equivalent density ranges from 1.05–1.69 g/cm³. Under low-density conditions, wellbore expansion and reduction coexist due to local shear and dropping. Even when the drilling fluid density exceeds the collapse pressure equivalent, stress imbalance can still cause localized dropping at lithologic interfaces. These findings offer valuable insights into the mechanical mechanisms behind wellbore instability in formations with soft/hard thin interlayers and provide guidance for the prevention and control of wellbore instability and associated risks. Full article

Drilling fluids are vital in oil and gas well operations, ensuring borehole stability, cutting removal, and pressure control. However, fluid loss into formations during drilling can compromise formation integrity, alter permeability, and risk groundwater contamination. Water-based drilling fluids (WBDFs) are favored for their environmental and cost-effective benefits but often require additives to address filtration and rheological limitations. This study explored the feasibility of using vegetable waste, including pumpkin peel (PP), courgette peel (CP), and butternut squash peel (BSP) in fine (75 μm) and very fine (10 μm) particle sizes as biodegradable WBDF additives. Waste vegetable peels were processed using ball milling and characterized via FTIR, TGA, and EDX. WBDFs, prepared per API SPEC 13A with 3 wt% of added additives, were tested for rheological and filtration properties. Results highlighted that very fine pumpkin peel powder (PP_10) was the most effective additive, reducing fluid loss and filter cake thickness by 43.5% and 50%, respectively. PP_10 WBDF maintained mud density, achieved a pH of 10.52 (preventing corrosion), and enhanced rheological properties, including a 50% rise in plastic viscosity and a 44.2% increase in gel strength. These findings demonstrate the remarkable potential of biodegradable vegetable peels as sustainable WBDF additives. Full article

One of the significant challenges during wellbore drilling is accurately predicting frictional pressure losses in symmetrical drill pipes. In this work, a Bayesian regularized neural network (BRANN) and multivariate adaptive regression splines (MARS) are employed to develop accurate and interpretable models for predicting frictional pressure losses during drilling. Utilizing data of frictional pressure loss collected through experimentation, the models are created. The model inputs include mud flow rate, mud density, pipe diameter (inside and outside diameters), and viscometer dial readings, while pressure loss is the output. Statistical comparisons between the model predictions and the actual values demonstrate the models’ ability to reasonably forecast frictional pressure losses in wells. The performance of the models, as measured by error metrics, is as follows: BRANN (0.999, 0.076, 16.76, and 11.67) and MARS (0.998, 0.0989, 21.32, and 16.499) with respect to the coefficient of determination, average absolute percentage error, root mean square error, and mean absolute error, respectively. Additionally, a parametric importance study reveals that, among the input variables, internal and external pipe diameters are the top predictors, with a relevancy factor of −0.784 for each, followed by the mud flow rate, with a relevancy factor of 0.553. The trend analysis further confirms the physical validity of the proposed models. The explicit nature of the models, together with their physical validation through trend analysis and interpretability via a sensitivity analysis, adds to the novelty of this study. The precise and robust estimations provided by the models make them valuable virtual tools for the development of drilling hydraulics simulators for frictional pressure loss estimations in the field. Full article

The Kuqa Foreland Basin is an important hydrocarbon-producing basin in western China. The Dabei area is an important zone for hydrocarbon accumulation. High fluid overpressures in the Lower Cretaceous Bashijiqike Formation are related to multi-genetic processes. However, the formation and evolution of pressure remain unclear, hindering the further development of oil and gas migration and accumulation. In this study, the overpressure distribution is described based on a drill stem test and mud density data. The formation and quantification of multi-genetic overpressure were evaluated based on well-logging data and basin simulation technology (Ansys Workbench). The coupling evolution of multi-genetic overpressure was examined based on the basin simulation technique. Finally, the influence of overpressure on hydrocarbon accumulation was explored. The results showed that the residual pressure of the Bashijiqike Formation in the Dabei area ranged from 40 to 60 MPa. The main causes of pressure in the Bashijiqike Formation in the Dabei area were disequilibrium compaction overpressure (2–6 MPa, contribution of 8–15%), tectonic compression overpressure (10 MPa, contribution of 30%), and fracture transfer overpressure (15–20 MPa, contribution of 8–15%). With respect to the evolution process of multiple pressures in the Bashijiqike Formation in the Dabei region, at 0–23.3 Ma, the overpressure due to disequilibrium compaction was <10 MPa and increased slowly to 18 MPa at 2.48–23.3 Ma. At 2.48 Ma, the tectonic compression was enhanced, and the residual pressure reached ~50 MPa. At 1.75–2.48 Ma, fracture activity was enhanced, leading to the generation of fracture transfer overpressure. Under these conditions, the residual pressure exceeded 60 MPa. Finally, the Bashijiqike Formation in the Dabei area is a favorable area for vertical and lateral migration of oil and gas. This study is of great significance to the formation and evolution of multi-origin overpressure in the same basin type and its influence on oil and gas accumulation. 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

Real-time drilling analysis requires knowledge of lithology at the drill bit. However, logging-while-drilling (LWD) sensors in the bottom hole assembly (BHA) are usually positioned 2–50 m (7–164 ft) above the bit (called the sensor offset), leading to a delay in real-time drilling analysis. The current industry solution to overcome this delay involves stopping drilling to perform a bottoms-up circulation for cuttings evaluation—a process that is both time-consuming and costly. To address this issue, our study evaluates three methodologies for real-time lithology prediction at the bit using drilling and petrophysical parameters. The first method employs a petrophysical approach, which involves using bulk density and neutron porosity predicted at the bit. The second method combines unsupervised and supervised machine learning (ML) for prediction. The third method employs classification algorithms on manually labeled lithology data from mud log reports, a novel approach used in this work. Our results show varying degrees of success: the bulk density versus neutron porosity cross-plot method achieved an accuracy of 58% with blind-well test data; the ML approach improved accuracy to 66%; and the Random Forest (RF) classification with manual labeling significantly increased accuracy to 86%. This comparative analysis of three different methodologies for lithology prediction has not been previously explored in the literature. While clustering and classification methods have been regarded as the most effective, our study demonstrates that they do not always yield the best result. These findings demonstrate that ML models, particularly the manual labeling approach, substantially outperform the petrophysical method. This new algorithm, designed for real-time applications, uses selected input parameters to effectively minimize problems associated with the sensor offset of LWD tools. It rapidly adapts to changes, offering a quicker and more cost-effective interpretation of lithology. This eliminates the need for time-consuming bottoms-up circulation to evaluate cuttings. Ultimately, this approach enhances drilling efficiency and significantly improves the accuracy of lithology prediction, notably in identifying interbedded geological layers. Full article

Addressing the high friction and torque challenges encountered in drilling processes for high-displacement wells, horizontal wells, and directional wells, we successfully synthesized OAG, a high-temperature and high-salinity drilling fluid lubricant, using materials such as oleic acid and glycerol. OAG was characterized through Fourier-transform infrared (FTIR) spectroscopy and thermogravimetric analysis (TGA). The research findings demonstrate the excellent lubricating performance of OAG under high-temperature and high-salinity conditions. After adding 1.0% OAG to a 4% freshwater-based slurry, the adhesion coefficient of the mud cake decreased to 0.0437, and at a dosage of 1.5%, the lubrication coefficient was 0.032, resulting in a reduction rate of 94.1% in the lubrication coefficient. After heating at 200 °C for 16 h, the reduction rate of the lubrication coefficient reached 93.6%. Even under 35% NaCl conditions, the reduction rate of the lubrication coefficient remained at 80.3%, indicating excellent lubrication retention performance. The lubricant OAG exhibits good compatibility with high-density drilling fluid gel systems, maintaining their rheological properties after heating at 200 °C and reducing filtration loss. The lubrication mechanism analysis indicates that OAG can effectively adsorb onto the surface of N80 steel sheets. The contact angle of the steel sheets increased from 41.9° to 83.3° before and after hot rolling, indicating a significant enhancement in hydrophobicity. This enhancement is primarily attributed to the formation of an extreme-pressure lubricating film through chemical reactions of OAG on the metal surface. Consequently, this film markedly reduces the friction between the drilling tools and the wellbore rocks, thereby enhancing lubrication performance and providing valuable guidance for constructing high-density water-based drilling fluid gel systems. Full article

In this study, a new polyionic polymer inhibitor, TIL-NH₂, was developed to address the instability of shale gas horizontal wells caused by water-based drilling fluids. The structural characteristics and inhibition effects of TIL-NH₂ on mud shale were comprehensively analyzed using infrared spectroscopy, NMR spectroscopy, contact angle measurements, particle size distribution, zeta potential, X-ray diffraction, thermogravimetric analysis, and scanning electron microscopy. The results demonstrated that TIL-NH₂ significantly enhances the thermal stability of shale, with a decomposition temperature exceeding 300 °C, indicating excellent high-temperature resistance. At a concentration of 0.9%, TIL-NH₂ increased the median particle size of shale powder from 5.2871 μm to over 320 μm, effectively inhibiting hydration expansion and dispersion. The zeta potential measurements showed a reduction in the absolute value of illite’s zeta potential from −38.2 mV to 22.1 mV at 0.6% concentration, highlighting a significant decrease in surface charge density. Infrared spectroscopy and X-ray diffraction confirmed the formation of a close adsorption layer between TIL-NH₂ and the illite surface through electrostatic and hydrogen bonding, which reduced the weakly bound water content to 0.0951% and maintained layer spacing of 1.032 nm and 1.354 nm in dry and wet states, respectively. Thermogravimetric analysis indicated a marked reduction in heat loss, particularly in the strongly bound water content. Scanning electron microscopy revealed that shale powder treated with TIL-NH₂ exhibited an irregular bulk shape with strong inter-particle bonding and low hydration degree. These findings suggest that TIL-NH₂ effectively inhibits hydration swelling and dispersion of shale through the synergistic effects of cationic imidazole rings and primary amine groups, offering excellent temperature and salt resistance. This provides a technical foundation for the low-cost and efficient extraction of shale gas in horizontal wells. Full article

Rock strength is an essential parameter in the design of any underground excavation, and it has become even more relevant as the focus increasingly shifts to sustainable excavations. The heterogeneous nature of rock material makes characterising the strength of rocks a difficult and challenging task. The research results presented in this article compare the impact on the strength when the classic stress paths in laboratory experiments are applied versus when in situ stress paths would be applied. In most laboratory experiments, the rock specimens are free of stress at the beginning of the tests, and the load is increased systematically until failure occurs. Opposite paths occur around an underground excavation; that is, the rock is in equilibrium under a triaxial stress state and at least one stress component decreases while another component may increase. Based on discrete element simulations, the research shows that different stress paths result in different failure envelopes. The impact of this finding is evaluated in the application of wellbore stability (e.g., the minimum or maximum mud weight), whereby it is concluded that failure envelopes, based on stress paths closer to the in situ stress paths, result in a more accurate design. Although the most critical location along the circumference is not different, the required density of the mud is significantly different if the rock strength criteria are based on the more realistic in situ stress paths. This means that a change in the way the strength of rocks is characterised improves the sustainable design of all underground excavations. Full article

This paper presents data-driven modeling and a results analysis. Group method data handling (GMDH), multivariable regression (MVR), artificial neuron network (ANN), and new proposed GMDH-featured ANN machine learning algorithms were implemented to model a field telemetry equivalent mud circulating density (ECD) dataset based on surface and subsurface drilling parameters. Unlike the standard GMDH-ANN model, the proposed GMDH-featured ANN utilizes a fully connected network. Based on the considered eighteen experimental modeling designs, all the GMDH regression results showed higher R-squared and minimum mean-square error values than the multivariable regression results. In addition, out of the considered eight experimental designs, the GMDH-ANN model predicts about 37.5% of the experiments correctly, while both algorithms have shown similar results for the remaining experiments. However, further testing with diverse datasets is necessary for better evaluation. Full article

A pumping-while-tripping method is proposed to mitigate pressure swabs during tripping out in wells with a narrow mud density window and extended reach. In the proposed tripping-out process, the fluid circulation is started by using a special pump from a customized circulation line before tripping is initiated. During the tripping out, drilling fluid is circulated in the wellbore simultaneously while the drilling string is moving. A model to simulate the dynamic pressure changes in this process is developed based on the Navier–Stokes (N-S) equations and a damped free vibration system. The model was initially developed for Herschel–Bulkley (H-B) fluid; however, it can be applied to other fluid models by eliminating the non-existing terms. An analysis was conducted to investigate the effect of tripping velocity and circulation pumping rate on the pressure changes. The results show that pumping-while-tripping is effective in mitigating the pressure swab during tripping out, which is especially useful for extended-reach wells. It can also help to increase tripping out velocity and save tripping time for drilling operations. Full article