Kaihe Lv

Traditional silica-enriched oil well cement suffers from strength retrogression at high temperatures, hindering deep geoenergy resource development. This study comprehensively evaluates novel retrogression-resistant cement systems formulated with Portland cement, silica sand, fly ash, and ground blast furnace slag. Slurries with densities of 1.9–1.6 g/cm³ were prepared by adjusting water content or adding hollow glass microspheres, and cured at 200 °C after initial setting at either 80 °C or 200 °C to simulate different field conditions. Results show that systems directly set at 200 °C maintained stable mechanical properties over 30 days, while those set at 80 °C exhibited significant strength gains. Permeability and pore structure remained stable or refined in all systems. Microscopic analyses (MIP, QXRD, TGA) reveal that low-temperature-set systems contain higher tobermorite and lower xonotlite and hydrogrossular contents, explaining their superior performance. Density reduction by water addition weakened properties, whereas hollow glass microspheres effectively preserved microstructure and strength. The C-(A)-S-H content remained stable throughout curing, and tobermorite increased over time, constituting the primary anti-retrogression mechanism. These findings provide insights into the roles of setting temperature and density regulation, supporting the design of durable cement systems for deep and ultra-deep wells.

Summary: Lost circulation in fractured formations remains a critical challenge in oil and gas drilling, particularly under high-temperature and high-pressure (HTHP) conditions. For this study, we systematically evaluated the physicochemical properties of commonly used bridging materials and optimized rigid, flexible, and fibrous lost-circulation materials (LCMs) suitable for HTHP fractured formations. Through HTHP fracture plugging experiments and visualized physical simulation tests, the bridging-and-packing plugging mechanism of rigid particles, the deformation-accumulation and destabilization behavior of flexible particles, and the synergistic plugging mechanism of rigid, flexible, and fibrous materials were elucidated. Furthermore, composite plugging formulations were optimized for fractures of varying widths. The results demonstrate that marble exhibits optimal thermal stability and compressive resistance, with a crushing percentage of merely 4.5% under 180°C/20 MPa. Among flexible materials, chloroprene rubber demonstrates the best temperature tolerance, with a thermal decomposition temperature ranging from 330°C to 487°C. Regarding fibrous materials, polypropylene fibers exhibit superior dispersion stability, with a turbidity reduction of approximately 25.9% after static settling for 60 minutes. Rigid particle plugging adheres to the “one-third bridging rule,” wherein coarse particles preferentially bridge at fracture entrances, while fine particles tend to plug within the fracture interior. Flexible particles achieve sealing through deformation, filling, and agglomerative packing. Fibers function as spatial network-forming and tensile reinforcement elements. The synergistic interaction among these three components enhances the pressure-bearing capacity and plugging efficiency of the plugging layer. For 2-mm fractures, the optimized formulation (7.0% marble + 3.0% chloroprene rubber + 0.5% polypropylene fiber) achieves a pressure-bearing value of 12.76 MPa, with sealing accomplished within 42 seconds. Furthermore, the optimized formulations for the tested discrete fracture widths of 1 mm, 2 mm, 3 mm, and 5 mm all exceeded 10 MPa in pressure-bearing capacity, demonstrating good adaptability within the present test range. This study provides both mechanistic insights and practical formulation guidelines for bridging plugging in HTHP fractured formations.

Wellbore instability caused by water-based drilling fluid (WBDF) filtrate invasion remains a major drilling challenge. Conventional shale inhibitors suppress clay hydration but offer limited control over capillary-driven water imbibition. In this study, a rock water-imbibition inhibitor (DTACS) is synthesized by modifying silica particles with dimethyloctadecyl[3-(trimethoxysilyl)propyl]ammonium chloride. Characterization confirms successful grafting, good thermal stability, and positive surface charge. DTACS exhibits good WBDF compatibility with minimal rheological effects. At 2% dosage, it reduces API filtration loss after aging at 180 °C from 23 to 14 mL. Treatment with 1% DTACS increases the shale water contact angle from 26.5° to 138.5°, reversing surface wettability and opposing capillary-driven invasion. At 180 °C and 3.5 MPa, 2% DTACS reduces rock water uptake by 65.0% relative to water and improves shale elastic modulus and hardness. Moreover, 1% DTACS decreases the final bentonite linear swelling rate from 62.0% to 32.3% and maintain high shale rolling recovery at elevated temperatures. DTACS electrostatically adsorbs onto rock and clay surfaces, forming a hydrophobic barrier that limits water ingress and clay hydration. These findings demonstrate a dual-inhibition strategy for improving wellbore stability through simultaneous control of rock water imbibition and clay swelling.

Summary: During drilling operations, the continuous accumulation of low-gravity solids (LGSs) may progressively deteriorate the rheological properties of oil-based drilling fluids (OBDFs), thereby limiting fluid reuse. Centrifugation or dilution provides only limited rheological improvement. To identify the factors contributing to viscosity increase and develop an effective treatment strategy, we evaluated two spent OBDFs from a South China Sea drilling site in terms of rheology, electrical stability (ES), oil/water ratio, and solid content before and after centrifugation. The extracted LGSs were characterized by scanning electron microscopy, X-ray diffraction (XRD), and contact-angle measurements. Bentonite, Rev Dust, and barite were used as representative solids to assess their effects on model-system viscoelasticity. The estimated LGS contents of the two spent OBDFs were 16.41% and 12.04%, respectively. Centrifugation reduced these values by only 2.09 and 1.47 percentage points, respectively, accompanied by modest rheological improvement and a decrease in ES. Extracted LGSs contained 51.86% clay minerals and exhibited irregular and lamellar morphologies. The compressed LGS pellets were readily wetted by water, and white oil rapidly spread over their surfaces. These characteristics may increase particle/particle and particle/liquid interactions, thereby increasing flow resistance. Adding bentonite, Rev Dust, or barite increased both the storage modulus (G′) and loss modulus (G″) in the model systems. To address these issues, a viscosity reducer for OBDFs, designated as OCD, was prepared and characterized using Fourier transform infrared (FTIR) spectroscopy and thermogravimetric analysis (TGA). Its performance was evaluated through rheological and ES measurements, thermal-aging tests, and combined treatment with centrifugation. At an OCD concentration of 2.0 wt%, both G′ and G″ decreased, while the loss factor generally increased in drilling fluids containing different solid phases. For the investigated spent OBDFs, the apparent viscosity (AV) and plastic viscosity (PV) decreased by 19.98% and 16.35%, respectively, accompanied by a slight increase in ES, while a certain viscosity-reducing effect was still maintained at 160°C. The combined application of OCD and centrifugal solids control provided a greater improvement in the rheological properties of spent OBDFs than either treatment alone. The FTIR spectra of the treated solids showed additional absorption features associated with OCD, while focused beam reflectance measurement (FBRM) revealed changes in chord-length distributions and chord counts during cumulative OCD addition. These observations are consistent with possible OCD/solid interactions and changes in the particle-association state. Overall, this study provides a potential strategy for rheological control and reuse of spent OBDFs.

Deepwater drilling is characterized by strong thermal contrasts among low-temperature seawater, the circulating wellbore fluid, and high-temperature formations. In the open-hole section, drilling-fluid invasion forms a mud cake that modifies the wellbore–formation heat-transfer boundary. To represent this effect, a transient wellbore-temperature model treated invasion-induced mud cake as an additional thermal-resistance layer. The model also incorporated temperature- and pressure-dependent drilling-fluid rheology and circulation conditions. Comparisons with temperature data from two deepwater field wells yielded maximum relative errors of 2.06% and 2.13%. The model evaluated the effects of drilling conditions, drilling-fluid properties, and mud-cake heat-transfer characteristics. These factors affected different wellbore regions, whereas the mud-cake effect was concentrated mainly in the deep open-hole section and intensified with depth. At 5500 m, increasing mud-cake thermal conductivity from 0.001 to 1.0 W/(m·°C) raised the annular temperature from 56.49 to 107.81 °C. Experiments further showed that increasing the thermal-insulation material dosage from 0 to 5 wt% reduced mud-cake thermal conductivity from 0.7018 to 0.1346 W/(m·°C), an 80.8% reduction. These results identify mud-cake thermal resistance as an engineering-relevant boundary parameter for predicting and regulating the temperature field in deepwater open-hole sections.

Summary: Under harsh high-temperature and high-salinity (HTHS) conditions, water-based drilling fluids (WBDFs) face a critical technical bottleneck in rheological control: the difficulty in simultaneously achieving yield point (YP) and gel strength enhancement without excessive viscosity increase while preventing the deterioration of rheological structures under severe thermal and saline stresses. In this work, a self-assembling low-viscosity-increment rheology modifier (SARM) based on a zwitterionic copolymer was synthesized via inverse emulsion polymerization, with a small amount of Zr4+ introduced as an auxiliary coordination reinforcement component. Its molecular structure and thermal stability were systematically characterized, and its rheological regulation behavior and mechanism in HTHS environments were investigated in detail. SARM retained rheological regulation capability after hot rolling at 180°C under 7 wt% KCl and saturated 36 wt% NaCl conditions. In high-density WBDFs, SARM regulated rheological behavior with a relatively low viscosity increment and achieved enhanced YP values and favorable YP/plastic viscosity (PV) characteristics compared with representative commercial rheology modifiers. Mechanistic analysis indicates that SARM promotes the formation of a shear-responsive 3D self-assembled network in drilling fluids through the synergistic effects of thermally stable and conformationally constrained polymer chains and salt-responsive zwitterionic structures, with Zr4+ coordination interactions providing additional network reinforcement. This design helps alleviate the common trade-off between enhancing YP and gel strength, and increasing viscosity in conventional rheology modifiers while improving the dispersion state of bentonite particles and the compactness of filter cakes. This work provides a potential material strategy for precise rheological regulation of WBDFs under HTHS conditions, particularly for drilling in long horizontal sections.

Summary: To investigate the mechanism of abnormal thickening behavior of oilwell cement slurries containing hydroxycarboxylic acid and sugar-based retarders, the effects of citric acid, maltodextrin, and glucose on the early hydration of oilwell cement were studied using isothermal calorimetry (IC) and thickening time (TT) tests at 70°C. Cement slurries with a higher dosage of any of the three retarders typically exhibited abnormal thickening (premature thickening) during the early TT test period, characterized by a “stepwise increase” in consistency. Higher dosage of any of the three retarders can fundamentally alter the typical shape of the cement hydration heat flow curve, resulting in an additional exothermic peak before the main hydration peak. Based on its timing and on previous literature, this peak is tentatively attributed to accelerated hydration of aluminate/ferrite phases. The duration of the initial hydration peak shows excellent agreement with the duration of the stepwise rise in cement slurry consistency, which establishes a clear correlation between macroscopic cement slurry thickening behavior and microscopic cement hydration kinetics. Therefore, the abnormal thickening behavior of the cement slurries is suggested to be associated with early accelerated hydration of aluminate and ferrite phases before the main hydration peak. As a result, a threshold hydration extent of aluminate and ferrite phases may exist beyond which a cement slurry will exhibit abnormal thickening regardless of the retarder’s ability to inhibit the tricalcium silicate (or alite, C3S) main hydration peak.

Conventional fluid-loss reducers lack thermal and salt resistance and exhibit a pronounced viscosity-enhancing effect in bentonite-based drilling fluids. These issues will cause severe problems during drilling operations. Herein, a branched fluid-loss reducer, BPJ, was synthesized using BPEI1₈₀₀ as the branching core and DMAA, AMPS, DMDAAC, and AN as monomers. BPJ showed good thermal stability, with less thermal degradation at 235 °C. BPJ was thermally stable up to 220 °C in drilling fluids, and it could tolerate saturated NaCl, 10% KCl, and 5% CaCl₂. Compared with commercial fluid-loss additives, BPJ had better fluid-loss reduction and lower viscosity enhancement. Under 220 °C and 36 wt% NaCl conditions, BPJ adsorbed strongly onto bentonite surfaces. Sulphonate groups increased electrostatic repulsion and maintained good colloidal stability of the bentonite. It further inhibited aggregation and detrimental dispersion of bentonite particles. BPJ was synergistic with bentonite, helping to form an impermeable filter cake and resulting in efficient filtration loss control. The study presents a novel approach to developing fluid-loss reducers for high-temperature, high-pressure drilling fluids in deep and ultra-deep formations.

Summary: Deep oil and gas resources have become a key strategic frontier for future reserve replacement and production growth. However, the complex downhole conditions in deep formations tend to reduce hole-cleaning efficiency and increase the risk of wellbore instability, making precise regulation of drilling fluid rheology essential for safe and efficient drilling operations. At present, field rheology control still relies largely on empirical judgment and therefore suffers from a clear time lag. Although data-driven methods can improve the efficiency of rheology prediction, existing models are generally limited by insufficient automation in model development, cumbersome hyperparameter optimization, and inadequate engineering interpretability, which restricts their use in accurate field prediction and sound operational decision-making. To address these limitations, this study proposes an intelligent prediction method for oil-based drilling fluid rheology by integrating an automated machine learning (AutoML) framework with Shapley additive explanations (SHAP). Built on the AutoGluon framework, the proposed method can automatically perform data processing, hyperparameter optimization, and multimodel-stacked ensembling, enabling the development of high-accuracy predictive models for apparent viscosity (AV), plastic viscosity (PV), and yield point (YP) with limited manual intervention. The results show that the optimal ensemble model, WeightedEnsemble_L3, achieved coefficients of determination (R2) of 0.875, 0.884, and 0.862 for AV, PV, and YP, respectively, on the independent test set, with corresponding root mean square error (RMSE) of 2.722, 2.359, and 0.612. Its predictive accuracy and generalization performance were superior to those of mainstream machine learning models, such as Bayesian-optimized categorical boosting (CatBoost), and AutoML frameworks, such as fast and lightweight AutoML (FLAML). Global SHAP interpretation showed that funnel viscosity, drilling fluid density (DY), and solids content were the dominant factors controlling rheological variation, with overall positive contributions. Local SHAP interpretation further quantified the contribution direction and relative weight of each feature under representative operating conditions, thereby improving the transparency and engineering credibility of the model predictions. This study provides a methodological basis for building accurate and trustworthy intelligent rheology-prediction systems for drilling fluids, with practical value for rheology risk warning and fine control under deep and complex drilling conditions.

With the continuous expansion of ultra-deep and deep well drilling toward complex geological formations, the performance stability of water-based drilling fluids and wellbore stability under ultra-high temperature and high-salinity conditions have become critical challenges. High temperature and salt contamination can induce the degradation or failure of drilling fluid additives, while the development of pores and fractures in complex formations further increases the risk of filtrate invasion. Conventional polymer and inorganic plugging agents often suffer from insufficient thermal stability, poor salt tolerance, or limited adaptability to complex pore structures. In this study, an organic–inorganic hybrid gel microsphere plugging agent (HGP) with a core–shell structure was developed by in situ polymerization of AMPS, styrene (St), and sodium styrene sulfonate (SSS) on KH570-modified nano-SiO₂. The hybrid microspheres consisted of a rigid SiO₂ core and a flexible polymer shell, providing synergistic thermal stability, mechanical strength, and deformation capability. Structural characterization confirmed the successful formation of the designed organic–inorganic hybrid structure. After aging at 240 °C, HGP maintained stable morphology and dispersion characteristics, while exerting minimal influence on drilling fluid rheological properties. The addition of 3 wt% HGP reduced API fluid loss by approximately 30% and decreased sand bed invasion by approximately 50% after high-temperature aging. Under 35 wt% NaCl and 5 wt% CaCl₂ contamination, HGP maintained effective filtration control, reducing fluid loss by more than 50% compared with the base fluid. Furthermore, HGP achieved core plugging efficiencies above 94% and reduced mud cake permeability by over 70%, demonstrating superior plugging performance compared with polymer microspheres NF-1 and SiO₂ particles. The enhanced performance was considered to arise from the synergistic effects of stable dispersion, pore-throat bridging, deformation filling, and structural stabilization. This study provides a rigid–flexible hybrid strategy for designing high-performance plugging agents for ultra-high temperature and high-salinity water-based drilling fluids.