Hydrogel-based materials have emerged as promising candidates for lost circulation control based on their excellent injectability and sealing performances, however, they face problems such as difficult-to-control gelation times and low compressive strength after curing under high-temperature and high-pressure (HTHP) conditions. Herein, we constructed a novel curable hydrogel composed of acrylamide (AM), sodium p-styrenesulfonate (SSS) and sodium lignosulfonate (LS), denoted as P(AM-co-SS)/LS hydrogel for HTHP plugging applications. This hydrogel was synthesized via a one-pot thermal polymerization strategy under harsh conditions (150 °C/20 MPa), forming a dense three-dimensional crosslinked network, in which the mechanical performance and gelation behavior were effectively regulated by tailoring the polymer composition and the initiator–inhibitor balance. Experimental results demonstrated that the P(AM-co-SS)/LS hydrogel exhibited remarkable thermal stability, great mechanical strength (compressive strength up to 6.88 MPa and compressive strain exceeding 90

Deep marine shale gas (3500–4500 m) and ultradeep marine carbonate oil and gas (≥ 6000 m) are among the most important development areas for China's future oil and gas resources. Some key problems related to the safety and efficient drilling and completion of marine oil and gas wells are addressed in this paper: (1) a prediction method for pore pressure in deep marine reservoirs; (2) a method to solve the problems of low penetration rates and high drilling costs; (3) a method to maintain wellbore sealing integrity under cyclic loading to simulate staged fracturing; (4) a wellbore stability control method; and (5) how to carry out efficient hydraulic fracturing. To focus on the efficient drilling and completion of oil and gas wells in ultradeep shale and carbonate formations, we carried out research to solve the aforementioned problems and share our results in this paper.

Conventional plugging materials fail due to mismatched size and low strength, whereas gel-based agents offer better injectability and adaptability. However, their performance under high-temperature and high-pressure (HTHP) conditions is limited by poor thermal stability, low compressive strength and uncontrollable gelation time. To address these issues, a lignin-based gel (LBG) incorporating a dual-network polymer structure reinforced with sodium lignosulfonate (LS) was synthesized via one-pot thermal polymerization at 150 °C and 20 MPa. As a result, LBG exhibits a compressive strength of 8.24 MPa with compressive strain exceeding 90

In this study, hydrothermal carbon nanospheres (HCNs) were prepared by hydrothermal carbonization using glucose as the precursor, and introduced to improve the properties of water-based drilling fluid for the first time. The variation in rheological and filtration characteristics of water-based drilling fluid with varying concentrations of HCNs were compared between the cases before and after thermal aging. The results demonstrated that HCNs had little influence on the rheological properties of bentonite base mud, but could effectively reduce its filtration loss after thermal aging at 220 degrees C. For polymer-based drilling fluid, HCNs also exhibited minor influence on the rheology. The H-B model was the best fitting model for the rheological curves before thermal aging. After hot rolling at 220 degrees C, the viscosity retention rate increased from 29% to 63%-90% with addition of HCNs, and the filtration loss decreased by 78% with 1.0 w/v% HCNs. Meanwhile, the polymer-based drilling fluid with 0.5 w/v% HCNs maintained relatively stable rheology and low filtration loss after statically thermal aging at 200 degrees C for 96 h. For a bentonitefree water-based drilling fluid prepared mainly with modified natural polymers, the viscosity retention increased from 21% to 74% after hot rolling at 150 degrees C with 0.5 w/v% HCNs, and was further improved when HCNs and potassium formate were used in combination. The mechanism study revealed that, HCNs could trap dissolved oxygen, scavenge the free radicals and cross link with polymers, which prevented thermal oxidative degradation of polymers and improved the thermal stability of water-based drilling fluid. Meanwhile, HCNs could inhibit clay hydration and swelling in synergy with partially hydrolyzed polyacrylamide by physically sealing the micropores, contributing to shale formation stability. Furthermore, HCNs could effectively improve the lubrication and anti-wear performance of drilling fluid. This study indicated that HCNs could act as green, sustainable, and versatile additives in water-based drilling fluid. (c) 2025 The Authors. Publishing services by Elsevier B.V. on behalf of KeAi Communications Co. Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/ 4.0/).

Phase change material paraffin was encapsulated with various Janus shell to synthesize phase change micro-capsule (PCM), which was added into waterborne coating to achieve self-stratifying coating. Leveraging the excellent water dispersibility of PCM and its density difference with aqueous epoxy resin, PCM composition spontaneously stratify to the surface and upper part of coating during its formation process. It was investigated the synergistic effect of Janus shell and encapsulated paraffin endows the coating with excellent lubrication performance, with a friction coefficient of less than 0.04. In addition, the self-stratifying coating with a layered structure combined the hydrophobicity of the paraffin in PCM with the adhesion of the epoxy resin. After the PCM was damaged, the paraffin and Janus sheets can cover and heal the damage, resulting in excellent corrosion resistance. Based on the phase change thermal storage property of PCM, the as-formed coatings can cause a temperature difference of more than 10 degrees C, which has application potential in the field of intelligent temperature regulation.

With the increasing harsh drilling environments encountered more frequently than ever before, developing environmentally benign and multifunctional additives is essential to formulate high performance drilling fluids. Herein, hydrothermal carbon/bentonite composites (HCBCs) were prepared by a hydrothermal carbonization reaction using soluble starch and sodium bentonite as raw materials. A systematic investigation was conducted into the effects of HCBC concentration on the rheological, filtration, and lubricating characteristics of xanthan gum, modified starch, and high-temperature polymer slurries. These properties were evaluated before and after exposure to hot rolling at different temperatures. The hydroxyl radical scavenging properties of HCBC were evaluated. Observation showed plentiful micro- and nano-sized carbon spheres deposited on the bentonite particles, endowing the bentonite with better dispersion. HCBCs could maintain stability of the water-based drilling fluids’ rheological profile, decrease filtration loss, and improve the lubrication with relatively low concentrations. The excellent properties were attributed to the highly efficient scavenging of free radicals and the stabilization of bentonite particle dispersion.

With the increase of well depth, more and more complex problems such as polymers high temperature degradation, wellbore instability, and high friction are encountered during the drilling operation. Developing novel eco-friendly and multifunctional materials to prepare high performance water-based drilling fluids is desirable. The main objective of this research is to systematically evaluate the properties of hydrothermal carbon spheres (HCSs) in water-based drilling fluids. HCSs were synthesized using xylose as precursors by the hydrothermal carbonization method. The thermal stability of typical polymers including xanthan gum and acrylamide (AM)/2-acrylamido-2-methylpropanesulfonic acid (AMPS)/ vinylpyrrolidone (NVP) copolymer with and without HCSs were examined by comparing the solution viscosity after thermal aging to that of before aging. The rheological and filtration properties of simplified polymer-based drilling fluid and bentonite-free water-based drilling fluids containing various concentrations of HCSs were measured before and after dynamically thermal aging at different temperatures. Shale plugging properties of HCSs were evaluated by measuring the permeability variation of filter cake for a bentonite-based mud and the filtration loss of drilling fluid flowing through an artificial stainless steel microfracture. Furthermore, the lubricity improvement by HCSs was measured by extreme pressure lubrication instrument and four-ball friction and wear testing machine. The results indicated HCSs exhibit magical multiple functions in water-based drilling fluids. The polymer degradation under high temperature can be greatly inhibited by CHSs. The addition of 0.5 w/v% HCSs improve the thermal stability of XC solution and AM/AMPS/NVP copolymer solution from 90 °C to 140°C and from 120 to 200 °C, respectively. For the simplified polymer-based drilling fluid, the addition of 0.3 w/v% HCSs achieved apparent viscosity retention of 90% and filtration loss decrease of 54% after thermal aging at 240 °C. For bentonite-free water-based drilling fluid, the incorporation of 0.5 w/v% HCSs resulted in quite stable AV and filtration loss decrease of 76% after thermal aging at 150 °C. HCSs can remove the dissolved oxygen and free radicals from the drilling fluids, preventing the thermal oxidative degradation of polymers. Regarding to sealing and lubrication properties, the presence of 1 w/v% HCSs reduces the permeability of filter cake formed by calcium bentonite slurry by 22% and the extreme pressure lubricity coefficient by 29%, respectively. The environmental-friendly and sustainable HCSs exhibit multiple functions including preventing polymers degradation under elevated temperatures, decreasing filtration loss, sealing micropores and fractures, and improving the lubricity. These properties make HCSs highly applicable in water-based drilling fluids.

Wellbores are destabilized by the immersion of a formation in drilling fluid during deep well drilling. To address this issue, in the present study, trimethylolethane triallyl ether (TMETE), 2-acrylamide-2-methylpropanesulfonic acid (AMPS), acrylamide, and N-vinylpyrrolidone undergo free radical copolymerization to produce a PTAAN filter loss reducer. The Box-Behnken response surface method is used to optimize the synthesis of PTAAN; the optimal conditions are 1 wt% TMETE and 0.1111 wt% initiator at 60 degrees C. Fourier transform infrared spectroscopy, transmission electron microscopy, and thermogravimetric analysis are used to characterize the composition, micromorphology, and thermal stability of the PTAAN product, respectively. The synthesized product is resistant to high temperatures and salt under the optimal synthesis conditions. It has an API filtration loss of 8.2 mL for freshwater-based mud, an API filtration loss of 13.8 mL for 20% by weight brine mud after aging at 220 degrees C, and an API filtration loss of 29.5 mL at 150 degrees C under high temperatures and pressures. Incorporating PTAAN into the base slurry prevents clay particle agglomeration at elevated temperatures and high mineralization, resulting in a broader clay particle size distribution and ultimately leading to the formation of a thin and compact filter cake.

Traditional granular hydrogels showed excellent injectivity, thermal integrity, and efficient remediation of heterogeneous reservoirs. However, granular hydrogels have demonstrated their inability to adapt to fractures due to the lack of sufficient interactions. Herein, we present new nanocomposite hydrogels consisting of cationic nanogelators and anionic granular hydrogels that can chemically in situ reform bulk hydrogels in the fractures. Interestingly, our granular hydrogels showed recross-linking independence on carrying fluids, contrary to prior reported fluid-dependent recross-linking granular hydrogels. The recross-linking of nanogelators and granular hydrogels can be accomplished from room temperature to 130 °C. The nanocomposite hydrogels displayed increased shear elastic moduli compared to pristine anionic granular hydrogels, probably due to the increased covalent cross-links formed by the homogeneous regenerative approach. We found that the granular hydrogels had high salinity tolerance even in the presence of 1000 ppm divalent ions of calcium (Ca2+) since Ca2+ ions often act as the cross-linker for partially hydrolyzed acrylamide-based hydrogels. Overall, we obtained new regenerative nanocomposite hydrogels based on cationic nanogelators and anionic granular hydrogels for fracture treatments.

Abstract The strength deterioration of the wellbore rock induced by water-rock interactions would be an important cause of the delayed instability in the Leikoupo formation located in Western Sichuan Basin, Sichuan Province, China. Taking the carbonate rock sample obtained from the Leikoupo formation as the research object, this study systematically analyzed the composition and the microstructural characteristics of the rock firstly. Then, a series of rock mechanics experiments before and after immersion in deionized water, pH=9, pH=11, and water-based drilling fluid (pH=11.5) was conducted. In order to further analyze the microscopic mechanism, the change in the ion concentrations of the immersed fluid and rock microstructures were analyzed. The results indicated that the Leikoupo formation carbonate rock was mainly limestone with developed micro-fractures. After immersion in alkaline solution, the elastic modulus and compressive strength of the rock decreased obviously. The friction coefficient of the fracture surface decreased as well. The degree of the deterioration became more significant with the increasing solution pH value and the prolonged immersion time. The analysis suggests that the dolomite in the carbonate rock undergone de-dolomitization reaction in high-temperature alkaline solution. It dissolved the micro-protrusions of dolomite on the fracture surface, so as to reduce the surface roughness. The research findings preliminarily reveal that the dissolution-crystallization-expansion mechanism of de-dolomitization reaction was the driving mechanism for the deterioration of carbonate rock due to water-rock interactions, providing a theoretical basis for the development of drilling fluid technology for stable wellbore in fractured carbonate rock formations.

The development of micro cracks in shale formations can easily lead to wellbore instability caused by liquid phase invasion. In order to effectively seal the shale micropores, the surface treatment of nano-SiO2 particles was developed using the silicane coupling agent A-1891. Then, the temperature-sensitive polypenic acrylamide polymer was modified onto the surface of the nanoprocal particle through reaction to obtain the nanosomal blocking agent ASN. The infrared spectrum shows that there are chemical bonds between the generated polymer chains, rather than simple physical composites, indicating the successful synthesis of the temperature-responsive nanosealing agent ASN. The particle size analysis showed that the synthesized nanoparticles in ASN have a uniform particle size distribution and display no agglomeration phenomenon. Applying ASN as a sealing agent in drilling fluid effectively fills the nanoscale micropores and microcracks in shale, making shale denser and significantly improving the wellbore stability of shale formations. In addition, it has good temperature resistance, can adapt to reservoirs at different temperatures, is non-toxic and environmentally friendly, and has good prospects for stable applications in shale formation wellbore.

The strength deterioration of wellbore rock induced by alkaline fluid-rock interactions would be an important cause of delayed instability in the Leikoupo Formation located in the Western Sichuan Basin, Sichuan Province, China. Using the carbonate rock from the Leikoupo Formation, this study systematically analyzed the composition and microstructural characteristics of the rock. Subsequently, a series of rock mechanics experiments of rock samples before and after immersion in deionized water, pH=9, pH=11, and water-based drilling fluid (pH=11.5) were conducted. To analyze the microscopic mechanism, the changes in the ion concentrations of the immersed fluid and rock microstructures were analyzed. The results indicate that the Leikoupo formation carbonate rock was mainly limestone with developed micro-fractures. After immersing the sample in alkaline solution, its elastic modulus and compressive strength decreased significantly. The friction coefficient of the fracture surface also decreased. The degree of deterioration became more significant with increasing solution pH value and prolonged immersion times. This analysis indicates that dolomite in the carbonate rock underwent a de-dolomitization reaction in high-temperature alkaline solution, dissolving the dolomite micro-protrusions on the fracture surface, and reducing the surface roughness. The dissolution-crystallization-expansion mechanism of the de-dolomitization reaction could be preliminarily concluded to be the driving mechanism for the deterioration of carbonate rock owning to alkaline fluid-rock interactions, providing a theoretical basis for the development of drilling fluid technology for stable wellbores in fractured carbonate rock formations.

Lost circulation caused by developed natural fracture occurs frequently in tight sandstone formations located in Sichuan Basin, China. Fracture -plugging wellbore strengthening by lost circulation materials (FPWSLCM) is a widely applied fluid loss control technique globally. The upper limit of the pressure -bearing capacity treated using FPWSLCM and the relevant engineering influencing factors needs to be investigated further. In this paper, a self -designed large-scale true tri-axial cell was developed to simulate the fracturing and sealing processes in a cubic sandstone sample (30 cm x 30 cm x30 cm) under anisotropic stress to investigate the effect of lost circulation materials (LCM) and the experimental processes on the formation pressure -bearing capacity. Three homogeneous cubic tight sandstone samples taken from Xujiahe Formation in Sichuan Basin with a central hole were used for the wellbore strengthening experiments with FPWSLCM, which was used to eliminate the heterogeneity effect of the rock. SRIPE (SINOPEC Research Institute of Petroleum Engineering) bridge plugging materials were used as LCM. The results show that the formation pressure -bearing capacity after treatment by FPWSLCM was affected by the initial injection pressure, the intrusion amount of LCM, the pressure holding time, and the injection rate. The formation pressure -bearing capacity did not decrease consistently with the increase of plugging zone instability times, but showed an obvious characteristic of fluctuations; the formation pressurebearing capacity exceeded the fracturing pressure in some cases. The experimental results could be explained by the stress cage theory. Finally, the modified FPWSLCM was applied as a lost circulation control approach by drilling into the tight sandstone formation in the Shunbei oil field, which has a history of severe loss of fluid circulations. The result of the field test indicated that the modified approaches were more successful than the previous approaches used in other wells in this block. The research results are of great significance for improving the success rate of lost circulation control and a reduction in drilling costs.

This study employed hydrothermal carbon microspheres (HCMs) as high-temperature stabilizers in drilling fluids. The HCMs were synthesized through a green hydrothermal carbonization method, using soluble starch as the precursor. The impact of HCMs on the thermal stability of xanthan, polyanionic cellulose and synthetic polymer solutions was assessed by comparing their rheological changes before and after thermal aging. The rheology and filtration properties of a polymer-based drilling fluid in the presence of HCMs were recorded before and after dynamic thermal aging at various temperatures for 16 h and static thermal aging at 200 °C for 96 h. The results demonstrated that HCMs effectively maintained stable rheology and low filtration loss following dynamic hot rolling at various temperatures and prolonged static thermal aging, surpassing the performance of conventional Na2SO3 and nano-SiO2 stabilizers. Mechanistic studies, including dissolved oxygen measurements, free radical detection, and cryo-scanning electron microscopy observations, revealed that HCMs can consume dissolved oxygen, scavenge free radicals, and physically crosslink polymers. This process prevents polymer thermo-oxidative degradation and ensures the stability of the drilling fluid. HCMs are novel, stable, sustainable, and highly effective high-temperature stabilizers for water-based drilling fluids. This study introduces a new application of biomass-derived hydrothermal carbonaceous materials for high-temperature drilling.

顺北油气田多口探井在奥陶系碳酸盐岩地层钻遇破碎带,井壁失稳严重,已成为制约顺北油气田安全建井的突出问题.文章在综合分析顺北奥陶系破碎性碳酸盐岩地层井壁失稳类型及理化特性、裂缝面物理—力学特性和岩石力学实验的基础上,提出了井壁稳定钻井液技术对策.研究发现,区域断裂带附近地应力方向复杂,地应力差大;地层天然多尺度裂缝发育、破碎程度大、岩体等效强度较低;钻井液易沿天然裂缝侵入地层,钻井液-裂缝面水岩作用造成缝面粗糙度减小、摩擦系数降低,易诱发地层沿裂缝面失稳,是深部破碎性地层井壁失稳的主要机理.明确"合理密度支撑+钻井液刚柔并济多级配封堵",配合使用"耐高温随钻/段塞固壁剂"是顺北油气田深部破碎性地层稳定的井壁钻井液技术对策.研究成果对促进深部破碎性地层安全高效钻井具有重要借鉴意义.

Rock strength criteria is a key step to estimate the stability of rock engineering, especially, the effect of intermediate principal stress on rock failure should be considered in formation at great depth. However, the mostly used Mohr-Coulomb criterion don't consider the effect of intermediate principal stress, besides, most rock mechanics laboratories do not have the ability to do true triaxial strength, the strength parameters in poly-axial strength criteria are difficult to be determined. In order to solve these problems, based on the least absolute deviation method, the square of the correlation coefficient, absolute difference and mean difference are adopted to verify the fitting effect of 10 strength criteria on 32 groups of true triaxial strength data. On this basis, the elliptical Lode angle shape function, hyperbolic Lode angle shape function, and the Lode angle shape function based on spatial slip plane are used to establish the modified MC strength criteria, which not only meets the requirements of smoothness and convexness, but also can be used widely in many geomaterials. Besides, strength parameters of the established criteria can be decided by conventional triaxial strength experiment, and the prediction accuracy of the modified MC strength criteria for the 32 groups of true triaxial strength data is better than or close to the lowest fitting error of the existing poly-axial strength criteria.

Nanosealing technology has become the key to overcoming the wellbore instability problem in deep and ultradeep shale formations. In this Article, the terpolymer poly(MM-EM-BM) was synthesized from methyl methacrylate, ethyl methacrylate, and butyl methacrylate by a Michael addition reaction. The poly(MM-EM-BM) nanoparticles were investigated by Fourier transform infrared spectroscopy, laser scattering analysis, and thermogravimetric analysis. The results imply that the particle size range of poly(MM-EM-BM) is between 33.90 and 135.62 nm and the average diameter is about 85.95 nm at room temperature, which can maintain excellent stability at 382.75 °C. The effects of poly(MM-EM-BM) on the properties of oil-based drilling fluids (OBDFs) were ascertained through experiments on the rheological performance, electrical stability, and high-temperature and high-pressure (HTHP) filtration loss. The results suggested that when the amount of added poly(MM-EM-BM) increases, the apparent viscosity, plastic viscosity, dynamic shear force, and demulsification voltage of the drilling fluids will increase correspondingly; in contrast, the HTHP filtration loss gradually decreased. When poly(MM-EM-BM) is added at 0.75%, the kinetic-to-plastic ratio of the drilling fluids is 0.24 and the filtration loss is 0.6 mL, showing excellent overall performance. The drilling fluids have a good rock-carrying ability and water loss wall-building property. The sealing performance and mechanism of poly(MM-EM-BM) were researched by the method of a sealing performance test under high temperature. The results indicated that the more poly(MM-EM-BM) used, the higher the sealing efficiency of the mud cake and the core as the sealing medium. When poly(MM-EM-BM) was added at 0.75%, the sealing rates of the mud cake and the core as the sealing medium reached the maximum sealing rates of 40.30% and 91.48%, respectively. When poly(MM-EM-BM) enters the core nanopore joint for a certain distance under formation pressure, a tight sealing layer will be formed to effectively prevent the entry of filtrate. Poly(MM-EM-BM) as a potential oil-based nanosealing agent is expected to solve the problem caused by wellbore instability in shale horizontal wells.

In view of the complex wellbore collapse and instability during the drilling of the diabase formation in Shunbei Oil＆ Gas Field, X-ray diffraction, scanning electron microscopy（SEM）, high-pressure mercury injection,linear expansion, rolling recovery, triaxial rock mechanics tester, and other methods were used to investigate the fabric characteristics and physical and chemical properties of the diabase formation. Meanwhile, the influence of rock mechanical properties and the drilling tool vibration on the wellbore of the diabase formation were analyzed.The results indicated that the weak surface effect of micro-fractures could easily induce wellbore collapse and instability of the diabase rock mass. In addition, the torsional and lateral vibration of the drilling tool had a greater impact on the wellbore instability of the diabase formation. Then, the density, plugging performance, and rock-carrying performance of the drilling fluid were optimized, and the drilling fluid technology for wellbore stability of the diabase formation was proposed with its supporting drilling technologies developed. The technology was applied in the three-section casing of Well Shunbei X, and the diabase formation with a thickness of 22 m was drilled successfully. During the drilling process, the performance of the drilling fluid was satisfactory, and there were no obvious complications, and tripping operated normally. Furthermore, the average borehole diameter expansion rate of the well section was only 6.0%. The drilling fluid technology for wellbore stability of the diabase formation could ensure the safe and smooth drilling of diabase sections and regular boreholes. Thus, it has an excellent effect on solving the complex wellbore instability of the diabase formation.

Graphene is a material formed with carbon atoms connected by sp(2) hybridization. It is extremely strong and very ductile, and is superhydrophobic and superlipophilic. It has important application prospects in materials science, micro and nano processing, energy, aerospace and biomedicine. Graphene also has some applications in the petroleum industry. As nanoscale materials, graphene-based materials can plug nano-pores and prevent water intrusion into clay minerals during the drilling process, they are suitable for sliding between layers and can be used as lubricants due to the two-dimensional structure. The adsorption properties of graphene-based materials allow them to improve the treatment rate when treating oily wastewater. This paper compiles recent advances in the application of graphene and its derivatives in oilfield extraction, including improving drilling fluid performance, enhanced oil recovery and oily wastewater treatment. We compare the performance advantages of graphene-based materials over other additives, and summarize the mechanism of action of graphene-based materials. The shortcomings of current research are identified and future research and improvement directions are envisaged.

When the well bottom temperature rises owing to increased well depth and formation complexity, the inadequacies of naturally modified polymeric fluid loss agents were revealed one by one, and synthetic polymeric fluid loss agents emerged as the essential technology to handle these problems. Nanomaterials were gradually being employed to increase the performance of polymeric fluid loss agents. Through free radical polymerization of amide polymers with silica nanoparticles in aqueous solution, a novel nano-graft copolymer (AAN-g-SiO2) was prepared for usage as a water-based drilling fluid loss agent. Fourier transform infrared spectroscopy and thermogravimetric analyses were used to investigate the structural characteristics and thermal stability of the polymer chains. Then, 4% bentonite freshwater-based mud and different concentrations of NaCl/CaCl2-based mud were prepared and added to the fluid loss agent AAN-g-SiO2. Moreover, high-temperature aging was carried out, and the API filtration volume of base mud and rheological characteristics were assessed. The fluid loss agent was demonstrated to withstand a high temperature of 220 degrees C, with the freshwater-based mud filtration volume at this temperature being 13.25 mL. Also, at 180 degrees C, AAN-g-SiO2 could be resistant to calcium and salt. Finally, we addressed the mechanism of AAN-g-SiO2 filtration using scanning electron microscopy and zeta potential distribution. The results showed that the inclusion of AAN-g-SiO2 may increase the stability of the drilling fluid system, resulting in the production of a thin and dense filter cake with no folds or pores visible at the microscopic level.