Abstract:Based on the geo-engineering integration approach，aiming at the challenges in the Dongpu Depression，such as complex geological structure，numerous faults，deep burial，thin sand body，and instability-prone sand-mudstone interbeds，a temperature-resistant 180 ℃biomass synthetic-based drilling fluid suitable for Dongpu Depression using the biomass synthetic-based fluid LAE-12 as the continuous phase，and the ultrafine calcium carbonate with multi-stage particle size was used to compound with the nano-film-forming plugging material，and natural asphalt，rigid resin and elastic graphite were introduced. By investigating the plugging，temperature resistance and lubricity of the drilling fluid system，the adaptability evaluation of biomass synthetic base drilling fluid and formation was carried out. The results showed that the drilling fluid system had a temperature resistance of 180 ℃，a high temperature and high pressure filter loss of ≤ 5 mL，and a emulsion-breaking voltage of ≥ 700 V. The shale core of the Shahejie Formation had a rolling recovery rate of 98.32% in the biomass-based fluid for 16 h and a linear expansion rate of 0.817 % for 72 h. The drilling fluid system had been successfully applied in 9 wells on site，showing strong long-term stability against high temperature，low viscosity and high shear flow pattern，good rock carrying and sand carrying capacity，rock carrying index ＞ 1.5，and the highest application temperature of 156 ℃，which effectively solves the problems of wellbore instability， difficult rock carrying and sand carrying in long horizontal section，and directional back pressure of thin layer in Shahejie formation，and had good application and promotion prospects.

Abstract:In response to the difficulty of balancing environmental performance and temperature and salt resistance with traditional water-based drilling fluids，and taking into account the characteristics of deep tight oil horizontal well drilling，a set of environmentally friendly high-performance water-based drilling fluid system suitable for deep tight oil horizontal well drilling was developed based on the synthesized environmentally friendly temperature and salt resistant filtrate reducer SLP-2 and other environmentally friendly treatment agents，through the optimization of SLP-2 dosage and the selection of inhibitors and lubricants. The basic performance，settling stability，anti-pollution performance，reservoir protection performance，and environmental performance of the drilling fluid system were evaluated. The results showed that the system had outstanding temperature resistance performance. After aging at 180 ℃ for 16 h，the high temperature and high pressure filtration loss was controlled within 10 mL， which could meet the requirements of deep well operations. The system had strong inhibitory properties，with a rock debris rolling recovery rate of over 95%，which could effectively suppress formation mud making and wellbore collapse. The density control of the system was flexible and the settlement stability was strong. When the density reached up to 2.0 g/cm³，the density difference of the system was less than 0.2 g/cm³ and the settlement factor was less than 0.52. The lubrication performance of the system was excellent，and the lubrication coefficient was as low as 0.087，which could significantly reduce the wear and friction of the drilling tool. The system had strong anti- pollution ability. After adding pollutants such as 15% NaCl，1.0% CaCl₂，or 15% rock debris powder，the rheological parameters and filtration performance of the system remained stable. The environmental advantages of the system were obvious，the biotoxicity test showed that the EC50 value reached up to 75 600 mg/L（non-toxic level），and BOD5/COD ratio was 26.8%（easily biodegradable），and heavy metal content met industry environmental standards. This environmentally friendly high-performance water-based drilling fluid had been successfully applied in the CH-1 well，a deep tight oil-water horizontal well in the target block. The on-site operation results showed that there had been no complex accidents such as drill jamming or leakage during drilling. The performance of the drilling fluid was stable and controllable throughout the process，and the environmental indicators met the standards，achieving the goals of safe，efficient，and green drilling. It provides technical support for the drilling construction of deep tight oil-water horizontal wells and has good prospects for promotion and application.

Abstract:Emulsion stability is a key parameter for oil-based and synthetic-based drilling fluids. To deeply investigate its stability mechanism and optimize formulations，the multiple light scattering method was utilized to systematically examine the effects of emulsifier type，organoclay concentration，emulsifier concentration，calcium chloride concentration，and oil-to-water ratio on the dynamic stability of a biomass synthetic-based drilling fluid. By combining multiple light scattering with electrical stability（ES） tests，the influence of each factor on emulsion stability was determined. The results showed that the emulsifier SWRH demonstrated optimal stabilizing effects due to its excellent compatibility with the LAE-12 base fluid. The emulsion exhibited better stability，was characterized by a lower turbiscan stability index （TSI） value and smaller particle size，under the following conditions：an organoclay concentration of 2.0%，an emulsifier concentration of 6%，a calcium chloride concentration of 40%，and an oil-to-water ratio no lower than 75∶25. The study also found that while the electrical stability test is convenient，it cannot comprehensively reflect the dynamic stability of the emulsion or the influence of complex factors. In contrast，the multiple light scattering method can more intuitively reveal instability mechanisms such as creaming and coalescence. The findings of this research provide a theoretical basis for the formulation optimization of biomass synthetic-based drilling fluids. It is proposed that combining multiple light scattering with electrical stability tests can establish a more comprehensive evaluation system for emulsion stability，offering theoretical support for the development and iterative improvement of high-performance biomass synthetic-based drilling fluids.

Abstract:The rheological control of drilling fluids under high-temperature conditions at the bottom of deep wells remains a challenging issue. Viscosity reducers are considered as effective agents for adjusting the rheological properties of drilling fluids. However， the research on anti-high-temperature viscosity reducers is relatively limited in China. In this paper， an anti-high-temperature viscosity reducer named GMZ was synthesized，and its characterization，performance evaluation and mechanism analysis were carried out in order to provide a more reliable，efficient and environmentally friendly drilling fluid viscosity reducer product for domestic drilling operations. The results of FT-IR and 1H-NMR showed that glycerol，zirconium salt THSZ and polymaleic acid PMA reacted to obtain the target product GMZ. The results of thermogravimetric analysis showed that the thermal stability of GMZ was good，and the mass retention rate was as high as 45.57% at the end of high temperature burning. The results of performance evaluation experiments showed that GMZ could resist to high temperature of 210 ℃，and the viscosity reduction rate in the base slurry was as high as 82.61%. GMZ had good compatibility，and had good high temperature viscosity reduction and shear reduction effects in both sulfonation system and desulfonation system. Biological toxicity test indicated that the bioligical toxicity value of GMZ exceeded 40 000 mg/L，which satisfied the national standard for biological toxicity in water-based drilling fluids used in first-class marine areas. Particle size and Zeta potential analyses showed that the addition of 2% GMZ significantly reduced both the particle size and zeta potential of bentonite slurries after high-temperature aging at 210 ℃，indicating enhanced dispersion and mitigation of high-temperature-induced particle aggregation. Optical microscopy and SEM further confirmed that GMZ improved the dispersion of bentonite particles. XRD and TEM analysis revealed that the cations of GMZ replaced aluminum ions at the edges of clay layers，increasing intermolecular repulsion and contributing to its high-temperature resistance and viscosity-reducing effects. GMZ had already achieved industrial-scale production and showed promising application potential. However，its performance under high-temperature and high-density field conditions required further validation through actual field operations.

Abstract:In drilling operations of Canadian oil sands，the problem of reduced operational efficiency caused by asphalt adhering to drilling components is urgent to be addressed. However，this issue is rarely encountered domestically，and there are no effective so-lutions or relevant evaluation schemes to draw upon，making the research extremely challenging. This paper focused on asphalt cur-ing technology，drew on the mechanism of inorganic curing agents releasing active oxygen atoms at high temperatures to recon-struct oil sand components. For the first time，asphalt penetration was introduced as the main performance indicator in this study. Six typical commercially available inorganic curing agents were selected and hot-rolled with Canadian oil sands in aging tanks. The penetration of oil sands before and after curing，the adhesion of simulated steel rods，and the influence of drilling fluid performance were investigated. The results indicated that the inorganic curing agent sodium thiosulfate，anhydrous sodium acetate and potassium persulfate showed significant curing efficiency，which reduced the penetration value of asphalt from 108/0.1 mm to 25.89/0.1 mm and had long-term stability. Among them，the sodium thiosulfate system showed the best inhibition effect in the adhesion test of steel rods，and the adhesion rate of asphalt decreased significantly from 50.93% to 6.71%. Furthermore，the solidification of oil sands had little effect on the rheology of the drilling fluid system，but it would cause negative effects such as increased filter loss and simulated drilling tool corrosion. Through Fourier transform infrared spectroscopy analysis，it was found that the active ions in the curing agent，such as CH₃COO^-，SO₄^2-，had a chemical crosslinking reaction with the polar functional groups in the asphalt， such as —OH，—COOH. Four-component analysis found that the curing agent promoted the conversion of saturated hydrocarbons and aromatic hydrocarbons with low molecular weight in the asphalt component to resins and asphaltenes with high molecular weight. The results of scanning electron microscopy and polarizing optical microscopy further confirmed that the microstructure of the solidified asphalt formed a porous network skeleton，resulting in an increase in the porosity of the filter cake，furtherly aggravat-ed the increase in drilling fluid loss. This study reveals the action mechanism of inorganic curing agent and oil sand asphalt for the first time，and provides a theoretical basis for solving the adhesion problem of oil sand drilling.

Abstract:Under high temperature and high-pressure water-containing gas-phase CO₂ environments，conventional silicate cements are susceptible to corrosion by acidic environments，which results in strength decline and structural deterioration. Mixing nano-SiO₂ in cement can reduce the Ca/Si ratio and permeability，thus improving the material's resistance to high temperature and corrosion. Nano-silica particles（NS）and sol-gel（SS）as the most common types of nano-SiO₂，but the application of the two materials in the cement paste has its own advantages and disadvantages. In this paper，based on the high-temperature and high-pressure vapor-phase CO₂ corrosion experiments，the compressive strength，XRD，FTIR and SEM tests were carried out to investigate the influence laws of different types of nano-SiO₂ on the mechanical strength，types of corrosion products and hydration products，and microstructures of the cement stone. The results showed that the compressive strength of cementite increased by 1.82%，9.1% and 15% sequentially at 150 ℃ with 1%，2% and 3% NS，while it decreased by 7.73%，4.09% and 2.73% with 1%，2% and 3% SS，respectively. Compared to the oil well cement，the Ca/Si ratio of C-S-H gel in the hydration product was reduced by 33.23% and 24.37%，and the Ca（OH）₂ content was reduced after mixing 3% NS and 3% SS，respectively. The addition of NS made the diffraction peak intensity of the hydration product Ca（OH）₂（001）crystal plane decrease obviously，and improved the crystal orientation of Ca （OH）2. The decline rate of the cement compressive strength was reduced by 10.35 percentage point and 10.98 percentage point，and the corrosion products CaCO₃ were reduced，the cement particles were more strongly cemented，and the corrosion resistance of cement stone was improved. Comprehensive comparing the mechanical strength and microstructure of cement stone before and after corrosion，NS had better effect on improving the high temperature resistance and corrosion resistance of cement stone than SS.

Abstract:To address the problem that the conventional mechanical bridge plugs are difficult to set and hydraulic fracturing operations are constrained under casing deformation conditions in shale gas horizontal wells in the Luzhou area of southern Sichuan，this study aims to clarify the sealing pressure-bearing capacity and engineering applicability of liquid gel plugs in deformed casing. A liquid gel plug system composed of functionally modified polyacrylamide（TSRP）and polyethyleneimine （PEI）was investigated. Through rheological and gelation performance evaluation，combined with field-derived real deformed casing samples，a sealing pressure-bearing test platform was established. Systematic pressure-bearing experiments were conducted under different casing deformation types，deformation section lengths，filling degrees，and combinations of multiple deformation types，and a prediction model for sealing pressure-bearing capacity was developed. The results showed that before gelation，the liquid gel plug exhibited an apparent viscosity of 204 mPa·s under downhole shear conditions，demonstrating pronounced shear-thinning behavior and good pumpability. At 90 ℃，gelation began after 2—3 h and was completed within 3—4 h，with the final gel strength of grade I. Pressure-bearing tests indicated that in A-，B-，and C-type deformed casing sections，the maximum sealing pressure-bearing capacities of the liquid gel plug in deformation lengths of 1，3，and 5 m were 0.57—2.06 MPa，0.77—2.50 MPa，and 0.98—3.83 MPa，respectively，showing a significant increase with increasing sealing length and deformation severity. In C-type deformed casing，when the filling degree increased from 0.1 to 1.0，the sealing pressure-bearing capacity rose from 0.15 MPa to 2.54 MPa. Under a fixed total casing length，when the deformation section length was reduced from 3 m to 0.6 m，the sealing pressure-bearing capacity was increased from 2.54 MPa to 3.20 MPa. Among multiple deformation combinations，the A-type and C-type combination exhibited the highest sealing pressure-bearing capacity，reaching up to 4.31 MPa. Based on the experimental results of liquid gel plug sealing performance，a sealing pressure-bearing prediction model was established using grey relational analysis，providing guidance for field applications.

Abstract:Aiming at the problems of difficult treatment of silicon sludge produced during silicon removal from steam injection thermal recovery sewage in Liaohe oilfield，and formation deficit and inter-well steam channeling in the later stage of heavy oil steam injection development，a kind of temperature-resistant and high-strength silicon sludge ceramsite was prepared by granulation and sintering treatment with waste silicon mud as raw material，and prepared with polymer solution to obtain silicon sludge ceramsite plugging agent. The effects of silica sludge content and sintering temperature on the compressive strength and apparent density of silica sludge ceramsite were investigated through single factor experiments，and the hydrothermal stability，suspension and blocking properties of the plugging agent were evaluated. The results showed that the apparent density of silica sludge ceramsite was＞ 2.25 g/cm³，the compressive strength of silica sludge ceramsite was ＞14 MPa and the temperature resistance was 350 ℃under the conditions of 60% silica sludge doping and 1180℃ sintering temperature. The settlement rate of silica sludge ceramsite in the polymer solution with a mass fraction of 0.3%—0.5% was lessthan 0.0075 m/min，and the high temperature plugging rate was higher than 82%，which could meet the performance requirements of plugging，channeling and filling formation deficit in heavy oil thermal oil reservoirs in Liaohe oilfield. At the same time，the discharge of pollutants from silicon sludge in oilfield could be reduced by preparing ceramsite from silicon sludge produced by silicon removal from produced sewage and reusing in oilfield.

Abstract:In order to clarify the basic properties of the novel C-Si quantum dots and their applicability in low-ultra-low permeability reservoirs，the interfacial properties and compatibility of the C-Si quantum dot oil displacement agent were tested and analyzed. Subsequently，the core imbibition and displacement experiments were carried out to explore the macroscopic imbibition and displacement characteristics of quantum dots. Finally，the oil displacement characteristics of quantum dots were revealed from the microscopic level by means of nuclear magnetic resonance analysis and microscopic model experiments. The results showed that the quantum dot oil-displacement agent had the ability to change the core surface to hydrophilicity，meanwhile，it exhibited strong negative charge，as well as good temperature and salt resistance. When the concentration of the quantum dot oil-displacement agent was 0.5%，the imbibition oil-displacement effect was the best，and the imbibition efficiency reached as high as 48.5%，showing a continuous effect during the core displacement process. The particle size of quantum dots was small，so the Brownian motion of quantum dots was more intense，and the quantum dots easily entered the micro-pores. The imbibition efficiency of the quantum dots in the micro-pores of the core could reach up to 30%. The quantum dots expanded the sweep range of the water phase by weakening the hydrogen-bond association of water molecules，and could effectively activate bypassed residual oil，dead-end and corner residual oil. The research results lay a theoretical foundation for improving the oil recovery of low and ultra-low permeability reservoirs using the quantum dot oil-displacement agent.

Abstract:In view of the technical problems faced by high-temperature thermal recovery technology for offshore heavy oil，such as high cost，high risk，and the limited oil-increasing effect of single hot-water flooding，a synergistic hot-water flooding technology based on self-developed temperature-resistant multifunctional polymers TMP was systematically evaluated to clarify its mechanism of enhancing oil recovery and its potential for field application. A research approach integrating laboratory experiments and numerical simulations was employed and the performance of polymer TMP in viscosity enhancement of water，viscosity reduction of oil，interfacial tension reduction，and the disassembly of asphaltene aggregates was systematically evaluated. Using the CMG numerical simulation software，an injection-production well pattern model was established，the displacement process was inversed， and the impacts of static and dynamic reservoir factors on the oil-increasing effect were investigated. The experimental results indicated that at 80 ℃ and a concentration of 1500 mg/L，the solution viscosity of the polymer was approximately 80 mPa s，and it exhibited excellent temperature resistance. It could reduce the oil-water interfacial tension to the order of 10^-1 mN/m. By disassembling asphaltene aggregates，the viscosity reduction rate of crude oil could reach 85% at 80 ℃. The numerical simulation results showed that the enhanced oil recovery rate of polymer-enhanced hot-water flooding could reach 6.0 percentage point，which was significantly higher than that of single hot-water flooding（1 percentage point—2 percentage point）. As for the oil-increasing effect，the polymer played a dominant role with a contribution rate of 80%—90%，while thermal energy played an auxiliary and synergistic role with a contribution rate of 10%—20%. The study determined that the optimal reservoir conditions suitable for this technology were as follows：average permeability＞2000×10^-3 μm²，in-situ crude oil viscosity of 200—600 mPa s，and water-body multiple＜4. The temperature-resistant multifunctional polymer-enhanced hot-water flooding technology， achieved the complementary advantages of "relying mainly on thermal energy to reduce viscosity near the well and chemical energy to reduce viscosity in deep formations" through the synergy of thermal energy and chemical energy，and had the dual effects of expanding the swept volume and improving the oil-washing efficiency. The project design for the Bohai D oilfield demonstrated that this technology could increase the oil recovery rate by 5.9 percentage point compared to water flooding，providing a promising new approach for the economic and efficient development of offshore heavy oil.

Abstract:Gas channeling during CO₂ flooding often reduces sweep efficiency and oil recovery. It is proven that foam injection was effective in controlling CO₂ breakthrough. A wormlike micellar foam system was developed using anionic surfactant sodium α-olefin sulfonate（AOS），zwitterionic surfactant erucic acid amide propyl betaine（EAB），and foam stabilizer alkylamine（TA），and its viscoelastic behavior was systematically investigated. The experimental results showed that the comprehensive index of the foam system with the formula of 0.25% AOS + 0.25% EAB + 0.1% TA could reach 107 208 mL· min. While the foam performance decreased with rising temperature，the system maintained good stability below the temperature of 70 ℃. Viscoelastic analysis revealed that at 0.5% total surfactant concentration，AOS and EAB molecules intertwined to form abundant wormlike micelles，as a result，the bulk viscosity and viscoelasticity of the system was significantly improved. The high viscoelasticity of the wormlike micelle structure could effectively retard the liquid film drainage and enhance the strength of the foam liquid film，and thereby improve the foam stability.

Abstract:In response to the poor water flooding effect，high water cut（≥75%），low recovery rate（14.7%），in the Chang 6 tight oil reservoir of the Yanchang oilfield，which is characterized by high salinity formation water（≥120 000 mg/L），high calcium and magnesium（Ca²⁺ content≥20 000 mg/L，Mg²⁺ content≥400 mg/L），and strong heterogeneity（permeability contrast =50），and the current foam systems' inability to adapt to these conditions，eight Gemini surfactants were evaluated for their foaming performance， half-life，and comprehensive foam index under simulated reservoir conditions using a high-temperature and high-pressure foam instrument and a tight reservoir imbibition system. The best foaming agent，auxiliary agent，and their concentrations were optimized to construct a low interfacial tension，calcium and magnesium resistant，and oxygen-reduced air foam system. The effects of different temperatures，Ca²⁺ and Mg²⁺ contents，oil saturation，and pH values on the foaming volume and half-life of the system were evaluated，and the oil displacement efficiency and imbibition efficiency of the system in heterogeneous reservoirs were investigated. The results showed that 0.4% LY-12（dodecyldodecyl hydroxysulfonate）+ 0.1% LX-14（tetradecyl amino acid salt） was the best foam system. Temperature，Ca2 + content，oil content，and pH had a significant impact on the foaming volume and foam half-life，while the effect of Mg2 + content was relatively small. The best foam performance could be guaranteed under conditions of temperature ≤45 ℃，Ca²⁺ content ≤20 000 mg/L，oil content ≤ 30%，and neutral pH，with a comprehensive foam index ≥12 000 mL min and an interfacial tension of 6.63×10^-2 mN/m. When the permeability contrast was 50，the continuous foam flooding in heterogeneous reservoirs had a 7% higher comprehensive oil displacement efficiency than the foam slug followed by water flooding. When the permeability was 0.96×10^-3 μm²，the imbibition efficiency reached up to 42.88%，demonstrating good adaptability to low-permeability reservoirs.

Abstract:Fractured-vuggy carbonate reservoirs in Tahe oilfield pose significant challenges for enhanced oil recovery during mid-to-late development，due to their high-temperature，high-salinity conditions and complex storage structures. In this paper，the adaptability evaluation of high temperature and high salinity resistant foam-assisted gas flooding technology in this kind of reservoir was carried out through the optimization of foam system，the physical model oil displacement simulation experiment of weathering crust and the field pilot test. The results showed that the temperature-resistant and salt-resistant foam system TKQP-3，composed of 0.12 % anionic-nonionic surfactant SS-163 + 0.18% anionic surfactant AES + 0.2% foam stabilizer SAV-236，could stably adapt to the harsh reservoir environment with temperature of 120 ℃，salinity of 24×10⁴ mg/L and pressure of 30 MPa. The foaming volume was 4 times that of the base fluid，and the half-life of the foam was about 30 min. The foam retention rate after cutting adsorption was still as high as 97%. At 120 ℃，the resistance factor of the foam system was more than 40 when the gas-liquid ratio was 1.5∶1 in a simple fracture-cavity sand-filled tube model with a liquid phase permeability of about 1500 × 10^-3 μm². Indoor physical simulation experiments had confirmed that the system could effectively expand the swept volume and increase the recovery rate by an average of more than 10 percentage points through the mechanisms of regulating flow steering，improving the oil-gas mobility ratio，promoting foam-gas-water three-phase synergy and reducing interfacial tension. The field test further verified its application effect，and the cumulative oil increase of the A71 well group reached up to10 373 t. In summary，the foam-assisted gas flooding technology has shown good adaptability and development potential in Tahe fractured-vuggy reservoirs.

Abstract:Microemulsion exhibits significant application potential in low-permeability reservoirs owing to its superior capabilities in reducing oil-water interfacial tension，altering wettability，enhancing solubilization，and maintaining thermal stability. Taking the low permeability reservoir in Block Chang-3 of Changqing oilfield as an example，the reservoir adaptability of the field application of microemulsion system was systematically evaluated by means of microemulsion micromorphology measurement， particle size analysis，interfacial tension measurement，crude oil component solubilization and wettability test，and its oil displacement potential was explored by means of nuclear magnetic resonance online displacement system. The experimental results demonstrated that the microemulsion exhibited an oil-in-water（O/W）structure with an average particle size of approximately 13 nm，which could effectively match with the micro-nano pore throat of low permeability reservoir. Notably，this system achieved significant interfacial activity，reducing oil-water interfacial tension to 1.71 mN/m，while the interfacial modulus increased with rising oscillation frequency. After 20 days of aging at the reservoir temperature，the key parameters including particle size and interfacial tension kept stable，while the microemulsion demonstrated exceptional solubilization capacity with an oil solubilization parameter reaching 36 mL/g，particularly，the enhanced solubilization effects were observed for saturated and aromatic fractions. Furthermore，the system effectively altered reservoir wettability，as evidenced by the substantial decrease in underwater oil droplet contact angle from 164° to 55° ，indicating a successful transition from oil-wet to water-wet conditions. The nuclear magnetic resonance online flooding experiments further revealed that injection of 1.0 PV of the microemulsion enhances oil recovery by 10.86 percentage point while reduced displacement pressure by 24.87% ，demonstrating significant pressure reducing and injection enhancing effects. The experimental results revealed that the microemulsion system exhibited considerable potential for enhanced oil recovery，providing crucial technical support for its large-scale field application in low-permeability reservoirs of Changqing oilfield.

Abstract:The Bohai high-salinity reservoir exhibits relatively high average permeability，while the salt tolerance of ordinary polymers is poor. In order to enhance the salt tolerance of conventional polymers and improve the oil-increasing and water-reducing effects of flooding agents，the effect of sodium silicate on salt tolerance of polymer in high salt reservoir and its mechanism were studied by viscosity and scanning electron microscope test combined with physical simulation evaluation method. The results indicated that the viscosity of the ordinary polymer solution with a mass concentration of 2000 mg/L was 12.4 mPa s lower than that of the salt-resistant polymer solution（32.5 mPa s）under the condition of salinity of 10 206.6 mg/L. Adding sodium silicate to the ordinary polymer solution could increase the viscosity of the system. As the concentration of sodium silicate increased，the viscosity of the 'ordinary polymer + sodium silicate' composite system gradually increased. In different dosing methods，the viscosity of the initial' polymer（2000 mg/L）+ sodium silicate（ 500 mg/L）' system（16.8 mPa·s ）was lower than that of the 'sodium silicate + polymer' composite system（19.6 mPa·s）. However，their viscosities show little difference after shearing. Polymer molecules formed a network structure，while the inorganic gels exhibited a flocculent structure. The "polymer + sodium silicate" system resulted in a denser network framework. With the increase of sodium silicate concentration，the resistance coefficient of the composite system increased，and the residual resistance coefficient increased first and then decreased. The plugging rate of the ordinary polymer system（2000 mg/L）to the core with a permeability of about 6000×10^-3 μm² was only 20%，while the plugging rate of the 'polymer（2000 mg/L）+ sodium silicate（300 mg/L）' composite system to the core with a permeability of about 6000× 10^-3 μm² was as high as 94.3%.

Abstract:The residual oil distribuion becomes complex after surfactant-polymer flooding （SP flooding）. Heterogeneous combination flooding（HC flooding）has the dual functions of profile control and oil displacement，therefore it can be used to employ the residual oil after SP flooding. In this paper，the developed limit of the residual oil at various pore throats was studied by NMR using different-permeability cores，and the CT scanning of the residual oil in the heterogeneous square cores with different permeability ratios through the heterogeneous composite flooding after SP binary composite flooding was carried out. The experimental results showed that the effective producing limitation for residual oil under HC flooding was 0.3—20 μm for the cores with permeability of 1 μm² and 0.2—800 μm for the cores with permeability of 6 μm². CT scanning of heterogeneous cubic cores with different permeabilities showed that the injectivity of viscoelastic particles（PPG）had significant influence on the enhanced oil recovery of the low-permeability zone. If the particle size was compatible with the pore-throat size of the low-permeability zone， the residual oil in the low-permeability zone could be effectively developed by HC flooding，resulting in the enhanced oil recovery by 18.3 percentage point. When the compatibility was poor，the residual oil only in the injection part could be displaced by HC flooding，the performance of profile control and oil displacement of HC flooding was limited and the enhanced recovery rate was only 9.5 percentage point.

Abstract:To overcome the poor stability of CO₂ foam under high-temperature and high-salinity conditions，sodium α-olefin sulfonate（AOS，anionic）and octylphenol polyoxyethylene ether（OP-40，nonionic）were formulated as a mixed foaming agent， and a temperature- and salt-tolerant terpolymer（AMPA）was introduced as the foam stabilizer. The optimal composition（surfactant concentration and AOS/OP-40 mass ratio）was screened using the Waring-blender method. Foam performance was then evaluated at 80 ℃ and 100 000 mg/L salinity and benchmarked against a conventional HPAM-stabilized system. In parallel，molecular dynamics（MD）simulations were conducted by constructing a gas/liquid interfacial model to elucidate the interfacial synergy between the anionic-nonionic surfactant mixture and AMPA，and to rationalize the performance differences between AMPA and HPAM in modifying the interfacial properties. When the mass ratio of AOS to OP-40 being of 1∶1，total surfactant content being of 1.0%，and AMPA dosage being of 0.35%，the optimized AMPA-stabilized foam system achieved a foam volume of 420 mL and a drainage half-life of 35.6 min. Under the same harsh conditions，the drainage half-life of the AMPA system was 2.3 times that of the HPAM-stabilized foam. MD simulations revealed that AMPA exhibited stronger synergistic interactions with surfactants，resulting in thicker hydration and gas adsorption layers，reduced liquid film drainage rate and delayed gas diffusion. Additionally，AMPA significantly decreased interfacial tension and formation energy，leading to more stable interfaces and stronger foam stability. These findings provide a theoretical foundation for the molecular design of next-generation foam stabilizers.

Abstract:Imbibition is an important mechanism for enhancing oil recovery in tight reservoirs. Both nanoparticles and nanobubbles can penetrate nanoscale pores to modify oil-water properties. Furthermore，nanobubbles can additionally provide microscopic energy supplementation，making them ideal systems for permeability enhancement and recovery improvement in tight reservoirs. Taking core samples from the Chang-6 reservoir in Wuqi area as research subjects， this study investigated the permeability-enhancing characteristics of active nanofluid（nanobubbles + nano-SiO₂ particles）and simulated field application effects. The results showed that 0.1% active nanofluid enhanced core water wettability by 48.3% and reduced oil-water interfacial tension by 17.8%，which significantly decreased flow resistance and facilitated imbibition. Synergistic effects between nanoparticles and nanobubbles enhanced imbibition efficiency. The imbibition recovery of 0.1% active nanofluid was 5.47 percentage points higher than that of formation water and 2.37 percentage points superior to pure SiO₂ nanofluid. The effectiveness of the system containing nanobubbles increased by 1.76 times compared to pure nano-SiO₂ system. Differential pore mobilization mechanisms were observed between oil-wet and water-wet formations. Oil-wet reservoirs primarily mobilized crude oil from medium pores （27.8 nm＜r≤203.9 nm），while water-wet formations predominantly target large pores （r≥126.9 nm）. Simulation results indicated significant operational improvements within 3 years of active nanofluid injection，reducing water cut from 60% to 40%and achieving up to 150% daily production increase compared with non-enhanced recovery scenarios. Over a 6-year simulation period，the adjusted recovery factor surpassed conventional waterflooding by 15%. These findings provided valuable insights for imbibition recovery in tight and shale ultra-low permeability reservoirs.

Abstract:The traditional research on the seepage characteristics of polymer flooding systems mostly adopts static adsorption method and small model method. The chromatographic separation phenomenon is not obvious，which cannot reflect the real seepage law of the reservoir. In order to study the real migration law of the new temperature-resistant and salt-tolerant binary flooding system in the Class Ⅲ reservoir of Shengli oilfield，a 10 m ultra-long sand-packed model was used to investigate the dynamic performance changes and long-distance migration of the binary system under the conditions of reservoir temperature of 90 ℃ and salinity of 58 002 mg/L. Meanwhile，the oil displacement efficiency and residual oil distribution of conventional binary and temperature-resistant salt-tolerant binary systems were studied. The research results showed that，with the increase of migration distance，the viscosity of the system gradually decreased，and the viscosity loss was greater in the early stage of injection. After a certain distance of migration，the viscosity loss gradually leveled off. With the increase of injection volume，the viscosity of the system showed a gradient distribution，and the peak of the viscosity curve continued to shift to the right. The oil displacement test results of conventional binary and temperature-resistant salt-tolerant binary systems showed that the 0.6 PV conventional binary flooding system enhanced oil recovery degree by 16.65 percentage point，while the 0.6 PV temperature-resistant salt-tolerant binary flooding system enhanced oil recovery by 21.72 percentage point，which was 5.07 percentage points higher than the former，and 4.41 percentage points higher in the 0.6 PV stage of chemical flooding. The residual oil distribution test results showed that the startup effect of residual oil in the near-well zone（0—2 m）was good；in the middle（3.33—7.33 m）of the model，the residual oil saturation of temperature-resistant salt-tolerant binary flooding increased slightly；while in the deep part（7.33—10 m）of the model，due to the serious loss of system performance，the residual oil saturation was significantly higher. From the perspective of residual oil saturation after oil displacement by the two systems，the temperature-resistant salt-tolerant binary system had better overall propulsion performance and mobility control ability；the injection of flooding system with large slug in homogeneous reservoir was more conducive to enhancing oil recovery.

Abstract:Conventional synthetic polymer HPAM and xanthan gum exhibit poor temperature and salt tolerance，being prone to degradation and viscosity loss under high-temperature（≥80℃）and high-salinity（≥30 000 mg/L）conditions，and the residual monomer of HPAM is easy to pollute the environment，which is difficult to meet the development needs of high temperature and high salt reservoirs. To address the demands of harsh reservoir conditions，a new type of green and efficient microbial polymer FH had been developed. The effects of temperature，salinity，shear force and pH value on the rheological properties of FH polymer were investigated using a rheometer. The microstructure of FH polymer under different salinity was observed by scanning electron microscope，and the long-term thermal stability and oil displacement effect of FH polymer were evaluated. The experimental results showed that the viscosity of the FH solution，xanthan gum solution and polymer solution decreased sharply when they were sheared，and the higher the shear rate，the faster the viscosity decreased. When the shear force was eliminated，the viscosity of FH solution and xanthan gum solution became 109.3 mPa·s and 61.1 mPa·s，respectively，and the viscosity recovery rate was above 98%，indicating that the shear thinning phenomenon of the FH solution and xanthan gum solution was reversible and shear recovery was good. However，the viscosity of HPAM solution showed irreversible loss after shearing. Compared with xanthan gum，the FH polymer had a wide range of reservoir adaptability. The temperature resistance could be increased by more than 20 ℃，and the viscosity remained stable in both acidic and alkaline environments. Especially in the high salinity of formation water，the FH biopolymer could form a dense network structure，which enhanced its harsh environmental tolerance. In addition，under the treatment of high temperature and high salt for 40 days，the addition of sulfur-containing organic compound antioxidant could improve the thermal stability of FH biopolymer，and the viscosity retention reached 73.6% . In the physical simulation oil displacement experiment，the injection of the FH polymer system（50 g/L FH +0.2% antioxidant S）enhanced the oil recovery by 22 percentage points based on water flooding（oil recovery being about 44%），which demonstrated superior oil displacement performance and had broad application prospects under extreme reservoir conditions.

Abstract:This paper focused on a novel microbial polysaccharide as the research subject，using the high-temperature and high-salinity conditions in Shengli oilfield as the basis for experimental design. Based on the Micro-CT scanning results，the micro-channel pattern model was designed by QSGS technology，and the experimental microfluidic model was made by wet etching technology combined with surface modification method. The microbial polysaccharide micro-displacement experiments were conducted in high-temperature and high-salinity environments，and the overall images and microscopic phenomena at various displacement stages were captured，thereby the micro-oil displacement effectiveness of the polysaccharide system in high-temperature and high-salinity heavy oil reservoirs was evaluated. The study demonstrated that the novel microbial polysaccharide exhibited excellent temperature and salt resistance，maintaining high viscoelastic properties under reservoir conditions of 86 ℃ and salinity exceeding 45 939 mg/L，which was significantly improved compared with xanthan gum and met the requirements for injection agents in high-temperature and high-salinity reservoirs. Under the microscopic conditions，the novel polysaccharide could mobilize more clustered residual oil，which gradually transformed into porous residual oil and further into droplet-like residual oil during the displacement process，enhancing the displacement efficiency by 10.15 percentage point when injecting 0.5 PV of new microbial polysaccharide solution with viscosity of 95.6 mPa·s based on water flooding，which was 3.08 percentage point higher than that of xanthan gum. As a pure biological agent，the novel microbial polysaccharide shows promising temperature and salt resistance along with effective performance，indicating its potential application in high-temperature and high-salinity reservoirs and providing a viable technical approach for enhancing oil recovery in such environments.

Abstract:Metal-organic Frameworks（MOFs）possess a high specific surface area，adjustable pore structures，and abundant active sites. These characteristics demonstrate their unique potential in the field of viscosity reduction of heavy oil. In The paper，the research progress of MOFs used in the field of heavy oil viscosity reduction was systematically reviewed. Firstly，the types and structural characteristics of MOFs，as well as the mechanism of heavy oil viscosity，were introduced; then，by analyzing the structural characteristics of MOFs and the structure-activity relationship between heavy oil components，the synergistic mechanism of MOFs in physical adsorption，catalytic cracking，and interface regulation was revealed. The mechanism of MOFs viscosity reduction was discussed in detail. Finally，prospects for the industrial application of MOFs were proposed，providing new ideas for the green development of oil fields under the“dual carbon”goal.