Jianlong Wang

Drilling fluids play a critical role in efficient cuttings transport, suspension of drilled solids, hydraulic performance, and wellbore stability, making rheological control essential for safe and efficient drilling operations. However, conventional viscosifiers may have limited performance under demanding drilling conditions, motivating the development of nanocomposite–polymer systems with enhanced rheological tunability. The work in this article explores the viscosities of drilling fluid following the incorporation of a hydrothermally synthesized nanocomposite material formed through the interaction of titanium and graphene oxide, and a biopolymer, sodium alginate. A response surface methodology (RSM) approach based on concentration was employed to systematically observe the effects of these two different entities on the viscosity of the drilling fluid. During testing, 13 experimental runs were conducted to assess the influence of particle concentration on plastic viscosity and apparent viscosity. A strong correlation was established between the experimental test runs and the predictive model generated using this RSM, with R² = 96.30% (adjusted R² = 93.65% and predicted R² = 84.13%) for plastic viscosity and R² = 96.97% (adjusted R² = 94.80% and predicted R² = 85.04%) for apparent viscosity, and all 95% relative errors below 15%. ANOVA showed that the nanocomposite concentration was the significant parameter with p-value < 0.05 in both plastic viscosity and apparent viscosity, whereas the linear effect of sodium alginate was not significant as it demonstrated p-values > 0.05. Increasing the nanocomposite from 0.35 to 3.5 g at 0.35 g of sodium alginate raised the predicted plastic viscosity from 9.55 to 23.95 cP (+150%) and the apparent viscosity from 18.83 to 38.03 cP (+101%). The graphene oxide provides the anchoring sites to TiO₂ nanoparticles that ultimately increase the inter-particle contact and exert an influence on both the viscosities. Additionally, in aqueous media, TiO₂ nanoparticles hydroxylate, thus forming hydrogen bonding with graphene oxide. This interaction reduces the slippage effect of TiO₂ nanoparticles between the fluid layers and eventually increases the friction force of the system. Furthermore, the sodium alginate adsorbs onto the large surface area of the nanomaterial, minimizing nanoparticle aggregation and forming a stable suspension, which in turn increases the viscosity. However, the influence of the biopolymer was minimal compared with the nano-dimension nanocomposite material. Overall, the findings offer valuable insights into the synergistic effects of biopolymers and nanocomposites in improving the lifting and transportation of drill cuttings, and in mitigating wellbore instability issues.

Gas hydrate plugging remains a persistent flow-assurance challenge in offshore oil and gas operations. PVP, pectin, CMCS, and PASP were compared at 0.1–0.5 wt% in pure water, 3.5 wt% NaCl brine, pure water–sediment, and brine–sediment media using hydrate kinetics, Raman spectroscopy, CST, SEM/EDS, zeta potential, viscosity screening, and quantitative rheology. At 0.5 wt% and 3 °C, all sediment-containing formulations were shear-thinning. CSS ramps revealed continuous stress-dependent flow consistent with progressive yielding, while oscillatory measurements indicated weak elastic-dominant responses for polymer-containing suspensions. Pectin gave the highest storage modulus and the strongest salinity-induced increase in oscillatory flow-point stress (approximately 0.092 to 0.178 Pa), whereas PASP retained the most favorable multimetric KHI response and the highest 500 s recovery in brine–sediment. PVP shifted from an oscillatory flow point above 0.209 Pa in pure water–sediment to approximately 0.156 Pa in brine–sediment. These results show that small-deformation stiffness, steady yielding, oscillatory flow transition, post-shear recovery, and KHI performance are distinct but partially coupled material responses. The combined evidence supports weak, deformable polymer–sediment structuring rather than a single rheological strength mechanism governing hydrate inhibition.

To address the challenge of sparse monitoring data for particle sedimentation in non-Newtonian suspensions in stirred tanks and the risk of non-physical solid-phase inventory drift in purely data-driven models during long-term extrapolation, this study proposes a parametrized physics-informed neural network (P-PINN). The method embedded a two-dimensional depth-averaged sedimentation equation and a macroscopic mass conservation constraint into the neural-network framework. Specifically, to reduce the gradient competition between local data fitting and global physical constraints, a ramp strategy was designed to gradually adjust the weight of the conservation term. Furthermore, a log-time mapping was also introduced to improve the resolution of early-stage high-gradient sedimentation dynamics. The model was validated by using nine-point ultrasonic thickness measurements from bench-scale experiments under multiple operating conditions. The results showed that P-PINN successfully reconstructed the continuous spatiotemporal evolution of the sediment bed with a global root-mean-square error (RMSE) of 3.71 mm. It also exhibited stable generalization in leave-one-out tests. Compared with purely data-driven baselines, the ramp strategy substantially reduced solid-phase inventory drift during long-term extrapolation and helped maintain macroscopic mass conservation. This study offers a physically constrained surrogate modeling approach for sediment-bed prediction under sparse observations with potential for online monitoring of complex multiphase flow systems.

During drilling operations, formation water intrusion is a common and complex downhole condition, and failure to identify it promptly and accurately may lead to wellbore instability or even blowouts. Existing wellhead parameter-based monitoring methods are easily affected by operating conditions and often suffer from delayed parameter response. To address these limitations, this paper proposes an integrated multi-source data fusion framework for the identification, quantitative analysis, and operating-condition compensation of formation water intrusion in oil-based drilling fluids. First, the correlation between characteristic parameters and intrusion status is analyzed to support model construction. Then, a logistic regression-based multi-source data fusion model is established to achieve effective intrusion identification. In addition, by investigating the relationships among moisture content, outlet flow, and water influx, and introducing weighted compensation for conductivity, density, and other parameters, a quantitative water influx model is developed. In data simulation, the mean absolute error of the proposed model is 127.71 l, indicating good predictive accuracy. Furthermore, a compensation model for non-water-intrusion conditions is constructed, and the L-SHADE-XGBoost algorithm is used to classify operational scenarios and reduce interference from non-intrusion factors. The classification accuracy, precision, and recall all exceed 90%, and the compensated data agree more closely with actual measurements. Field verification further demonstrates that the proposed system can stably perform real-time monitoring and quantitative analysis of formation water intrusion. These results confirm its applicability and reliability and provide technical support for safe drilling operations in oil and gas wells.

The present work examines the fluid loss volume (FLV) and shale swelling behavior of water-based mud (WBM) modified with a hydrothermally synthesized Zinc Oxide/Multiwalled Carbon Nanotubes (Zn-COM) nanocomposite and a Bio-Poly(Pure bore). A central composite design methodology (CCD) was employed to systematically evaluate the influence of these additives’ concentration on the FLV and shale swelling. The most problematic shale formation (Ranikot) was analyzed in this study. A total of 13 experimental runs were investigated in this article. The result of the study reveals that the nanocomposite material, with its high aspect ratio, penetrates and seals both micro- and Nanopores’ spacing, ultimately creating a robust bridging network. A substantial reduction in FLV from 26.0 to 6.5 mL was recorded as the concentration of the nanocomposite material increased to 4.154 g. However, the concentration of Bio-Poly does not have a significant impact on the FLV reduction. The oversaturation of Bio-Poly causes polymer chain entanglement and coagulation, which reduces the uniform dispersion of both entities. For the shale swelling, as the loading of Zn-COM increases in WBM, the shale swelling drastically reduces. The swelling dropped to 5.8% from 17.2% as the weight of the nanocomposite increased to 4.154 g. The nanocomposite material predominantly suppresses the osmotic diffusion and minimizes the water ingress into the shale sample. On the other hand, this suppression was not substantial with Bio-Poly concentration, and high swelling percentages were reflected with high Bio-Poly concentration and low Zn-COM loading. Analysis of Variance supported all the findings, with the nanocomposite demonstrating a strong statistical significance of p < 0.05 for both FLV and shale swelling. This statistical measurement confirms the effectiveness of Zn-COM in sealing the pores and in suppressing the shale hydration.

Traditional petroleum engineering materials have problems such as single functionality and poor environmental adaptability in terms of lost circulation control and enhanced oil recovery. Supramolecular gels, with their dynamic reversible non-covalent network structure, demonstrate unique advantages in this regard. This paper classifies supramolecular gels into hydrogen bond type, metal coordination type, host–guest type, and electrostatic interaction type based on differences in crosslinking structures. It explains the construction principles and characteristics of each type of gel and analyses their application progress in petroleum engineering fields, such as lost circulation control in drilling, temporary plugging in fracturing, and profile control in enhanced oil recovery. It also discusses the advantages and disadvantages of different systems and future development directions. Research has shown that the molecular design strategy of supramolecular gels can effectively address technical challenges under complex conditions, offering new insights for oil and gas field development. Further optimization of their long-term stability and large-scale production technology is needed to advance their practical application.

China has abundant shale oil and gas resources, which have become a critical pillar for future energy substitution. However, due to the highly heterogeneous nature and complex pore structures of shale reservoirs, traditional plugging agents face significant limitations in enhancing plugging efficiency and adapting to extreme wellbore environments. In response to the technical demands of nanoparticle-based plugging in shale reservoirs, this study systematically investigated the microscopic interaction mechanisms of nano-plugging agent shell polymers (Ployk) with various reservoir minerals under different temperature and salinity conditions using molecular simulation methods. Key parameters, including interfacial interaction energy, mean square displacement, and system density distribution, were calculated to thoroughly analyze the effects of temperature and salinity variations on adsorption stability and structural evolution. The results indicate that nano-plugging agent shell polymers exhibit pronounced mineral selectivity in their adsorption behavior, with particularly strong adsorption performance on SiO₂ surfaces. Both elevated temperature and increased salinity were found to reduce the interaction strength between the shell polymers and mineral surfaces and significantly alter the spatial distribution and structural ordering of water molecules near the interface. These findings not only elucidate the fundamental interfacial mechanisms of nano-plugging agents in shale reservoirs but also provide theoretical guidance for the precise design of advanced nano-plugging agent materials, laying a scientific foundation for improving the engineering application performance of shale oil and gas wellbore-plugging technologies.

Lost circulation during drilling has significantly hindered the safe and efficient development of oil and gas resources. Supramolecular polymer gel–based lost circulation materials have shown significant potential for application due to their unique molecular structures and superior performance. Herein, a high–performance supramolecular polymer gel was developed, and the influence of reservoir conditions on the performance of the supramolecular polymer gel was investigated in detail. The results identified an optimal formulation for the preparation of supramolecular polymer gel comprising 15 wt% acrylamide, 3 wt% 2-acrylamide-2-methylpropanesulfonic acid, 2.6 wt% divinylbenzene, 5 wt% polyvinyl alcohol, 0.30 wt% cellulose nanofibers, and 3 wt% laponite. The performance of the gel-forming suspension and the resulting supramolecular polymer gel was influenced by various factors, including temperature, density, pH, and the intrusion of drilling fluid, saltwater, and crude oil. Nevertheless, the supramolecular polymer gels consistently exhibited high strength under diverse environmental conditions, as confirmed by rheological measurements. Moreover, the gels exhibited strong plugging performance across various fracture widths and in permeable formations, with maximum breakthrough pressures exceeding 6 MPa. These findings establish a theoretical foundation and practical approach for the field application of supramolecular polymer gels in complex geological formations, demonstrating their effectiveness in controlling lost circulation under challenging downhole conditions.