Abstract:In order to improve the temperature resistance and salt tolerance as well as environmental performance of water-based drilling fluid viscosity enhancer，and meet the needs of shale oil drilling construction，viscosity enhancer HBZ-2 was prepared using methacrylamide （MAA），N-vinyl pyrrolidone （NVP） and polymerizable quaternary ammonium salt cationic monomer （H-12）as raw materials. The molecular structure of HBZ-2 was characterized by infrared spectroscopy and nuclear magnetic resonance hydrogen spectroscopy，and then its mechanism of action was analyzed. The thickening performance，temperature resistance，salt tolerance and environmental performance of HBZ-2，and the basic properties of drilling fluid were investigated. The results showed that under the same experimental conditions，the thickening performance，temperature resistance and salt tolerance of HBZ-2 were superior to those of the same type of viscosity enhancer HE300 and 80A51. When the dosage of HBZ-2 was 1%，the apparent viscosity of seawater based slurry could be increased from 10.5 mPa·s to 54.5 mPa·s. After high-temperature aging at 200 ℃，the viscosity of seawater based slurry containing 20% sodium chloride or 5% calcium chloride could still reach over 30 mPa·s，indicating strong temperature resistance and salt tolerance. The basic properties of drilling fluid system containing 1%HBZ-2 after high-temperature aging were relatively stable，with a shale rolling recovery rate of over 90% and a temperature resistance of up to 200 ℃. HBZ-2 and drilling fluid system had low biological toxicity and good biodegradability，with EC50 value of 204 400 mg/L and 120 500 mg/L，respectively，and BOD5/COD value of 40.9% and 33.6%，respectively. In addition，HBZ-2 did not contain heavy metals，while the content of some heavy metals in drilling fluid system was also much lower than that of the relevant industry standards， indicating excellent environmental performance. The viscosity enhancer HBZ-2 had excellent performance and was suitable for offshore shale oil drilling with high environmental performance requirements.

Abstract:When artificially synthesized polymers are used as filtrate reducers for water-based drilling fluids，it is difficult to meet the needs of drilling engineering by simply changing the type and proportion of copolymer functional groups. Increasing the usage of energetic monomers will undoubtedly increase the cost，especially under ultra-high temperature and high salinity conditions. This study prepared a filtrate reducer with dual cross-linking structure by adding salt resistant monomer 2-acrylamide-2-methylpropanesulfonic acid （AMPS） and temperature resistant monomer N-vinylpyrrolidone （NVP） to the main monomer acrylamide（AM），simultaneously using a very small amount of organic cross-linking agent N，N'-methylenebisacrylamide（MBA） and metal cross-linking agent zirconium citrate（MC）. Using the high-temperature filtration reduction effect of polymers as the evaluation index，single factor experiments were used to optimize the synthesis conditions. The particle size distribution， microstructure，surface morphology，heat resistance，and temperature resistance mechanism of copolymers were analyzed using laser particle size analyzer，Fourier transform infrared spectroscopy，scanning electron microscope，and thermogravimetric analyzer. The results showed that the optimum preparation conditions for the filtrate reducer were obtained as follows：18∶1∶1 the mass ratio of AM，AMPS and NVP monomers，1∶3 the mass ratio of MBA and MC，1.0% initiator dosage，400 r/min stirring speed，and 65 ℃ reaction temperature. The average particle size of filtrate reducer with dual cross-linking structure was 16.48 μm. Its temperature resistance could reach to 350 ℃. The high temperature and high pressure filtration loss and API filtration loss of the system containing 5000 mg/L polymer decreased from 77.6 mL and 18.8 mL to 31.4 mL and 6.8 mL respectively after 16 hours of hot rolling at 210 ℃. The high-temperature resistance mechanism of the filtrate reducer with dual cross-linking structure was that the hydrolyzed polymer molecular chains underwent secondary crosslinking with metal cross-linking agent，protecting the hydrolyzed polymer molecular chains from rapid degradation and forming a more dense and complex three-dimensional network structure，resulting in excellent temperature and salt resistance filtration reduction performance.

Abstract:High temperature deep wells have problems such as reverse thickening time of cement slurry， decline in high-temperature strength，high brittleness and low toughness of cement sheath，which can easily cause failure of cement sheath sealing. The hydrophilic adhesive flexible gel material was prepared by using epoxy resin，anhydride curing agent，dimethylol butyric acid and other raw materials. Then it was mixed with cement，formaldehyde acetone polycondensate dispersant，AMPS multi copolymer fluid loss additive，acrylic acid polyalcohol propylene ether polymer retarder，organic silicon defoamer，and high temperature resistant stabilizer（300 mesh silicon powder）to prepare high temperature resistant flexible cement slurry. The content of each component in flexible cement slurry was optimized. Then the rheological property，water loss，thickening performance and high-temperature strength stability of cement slurry，and the mechanical property and elastic toughness of cement stone were evaluated. The results showed that the flexible gel material had good elasticity，toughness and hydrophilicity，and could improve the mechanical property of cement stone. The optimum formula of flexible cement slurry was obtained as follows：100% cement， 40% water，4.5% fluid loss additive，2% retarder，0.6% dispersant，1% defoamer，10% flexible gel material，36% stabilizer. At 160—200 ℃ ，the flexible cement slurry had good rheological property，thickening property and high-temperature strength stability，with flowability index of 0.87—0.97，viscosity coefficient of 0.46—0.23 Pa·sn，water loss less than 50 mL，and thickening time greater than 300 min. Cement stone had excellent mechanical property，with flexural strength greater than 5.5 MPa and impact strength of 2.79 MPa after 28 days of curing at 200 ℃. Furthermore，cement stone had good flexibility and elastic deformation ability，with elastic modulus of 4.1 GPa at 180 ℃ and confining pressure of 21 MPa，which met the requirements of high-temperature cementing operations in oil and gas well.

Abstract:In view of the problem that conventional annular chemical isolation agent is easy to enter the reservoir with poor annular packing in horizontal wells without interlayers，a high thixotropic annular chemical isolation agent was developed using corn starch，acrylamide，N, N'- methylenebisacrylamide and magnesium aluminum carbonate composite materials as the main raw materials. Annular filling performance，curing performance，and annular sealing performance at different permeability levels was studied，and the pilot testing was carried out. The results showed that the chemical agent had good thixotropy and strong annulus filling ability. Curing time was adjustable from 3 hours to 10 hours. Compared with the comparative test without annulus chemical isolation，the initial water cut decreased from 97.54% to 41.28% after annulus chemical isolation，the time for water cut rising to 98% was delayed from 2 minutes to 35 minutes. when the permeability level was increased from 2.89 to 14.79，the initial water cut decreased and the time of water cut increasing to 98% was extended from 11 min to 35 min，the water control effect was obvious. The technology had been carried out in the field test of 4 wells in offshore oil field，and the water content decreased by 6.14%，the daily oil increase was 30.45 m³ ，the stage oil increase was 0.92×10⁴ m³ ，and the stage reduction of water was 0.98×106 m³ . The chemical isolation technology for the annulus of the screen tube in horizontal wells without interlayer is feasible，and it is recommended to promote its application in segmented water plugging control in screen tube completion horizontal wells.

Abstract:Aimed at the engineering problems of high pressure and limited displacement caused by high temperature and low permeability and high closure stress in deep oil and gas reservoirs，in this paper，a high-flow rate full-size resistive testing device was independently designed and constructed，and took the guar gum fracturing fluid system weighted with inorganic and organic salts as the research object，the influence of different weighting agent types and concentration on the friction characteristics of fracturing fluid was systematically explored. The experimental results showed that the friction drag of the weighted brine increased significantly with the increase of salt concentration and flow rate，and the flow rate sensitivity of the inorganic salt system was significantly higher than that of the organic salt system. The friction drag of the guar gum based fluid reduced due to ionic inhibition effect under the condition of low weighting concentration，density being of 1.20—1.35 g/cm³，and the friction drag increased under the condition of high weighting concentration，the density being higher than 1.40 g/cm³，due to the synergistic effect of the ionic strength and the cross-linking network steric hindrance. At the level of cross-linking kinetics，the organic salt could accelerate the cross-linking reaction and improve the friction drag at low concentration，while the high concentration of the organic salt inhibited the cross-linking process due to the pH value regulation，slowing down the growth rate of friction drag. The friction characteristics of the gel were significantly regulated by the concentration threshold of the weighting agent，when the density of the organic salt system was 1.40 g/cm³，the increase of friction drag was slowed down due to the transformation of flow pattern. The research results can provide data reference for the design of salt-resistant weighting and optimization of low friction drag of fracturing fluids in deep oil and gas reservoirs.

Abstract:The poor sand-carrying performance，insufficient energy enhancement capability and low imbibition displacement efficiency of conventional slickwater fracturing fluid caused by the great difficulty in entering the micro-nano scale pore throat， have been a problem in fracturing stimulation in shale reservoirs. To solve this problem，a supramolecular fracturing fluid system suitable for volumetric fracturing of shale oil was constructed based on the hydrophobic association effect between quaternary ammonium amphoteric polyacrylamide copolymer drag reducer （RW） and anionic-nonionic compound surfactant （mixture of alkylphenol polyoxyethylene ether and α-olefin sulfonate）nanoemulsion（DO-2）. The formula of slick water was 0.1% DO-2 and 0.1% RW，and then that of sand carrying fluid was 0.1% DO-2 and 0.3% RW. The properties of nanoemulsion and supramolecular fracturing fluid were evaluated by measuring the parameters such as static adsorption capacity，contact angle，drag reduction rate， residue amount and core permeability. The results showed that the adsorption loss（about 1 mg/g）on the core surface was low，and the wettability reversal ability was good. The contact angle of oil-wet core surface could be increased from 126° to 154° . The nanoemulsion could smoothly enter and pass through the small pores of reservoirs due to its nano-scale（about 10 nm），resulting in a good potential of imbibition and oil displacement effect. In addition，the viscosity was adjusted by the concentration variation of RW，which could significantly simplify the operation process by the successful realization of on-line preparation. The system had the characteristics of low friction resistance（drag reduction efficiency＞70%），low residue content（25 mg/L of sand carrying liquid），strong wettability alteration（more than 30° the contact angle increase of oil droplets），and low permeability reservoir damage（15.2% the damage rate of sand carrying breaking fluid）. The supramolecular fracturing fluid was applied in 208 horizontal wells of shale oil in Qingcheng oilfield from 2021 to 2023. The initial production of single well increased from 12.6 t/d to 14.0 t/d， while the flowback rate of initial production decreased from 10.5% to 7.1%，which demonstrated a remarkable effect of both increase of production and efficiency. This technology could provide a demonstration and reference for the efficient development of other similar unconventional shale reservoirs.

Abstract:In order to improve the fracturing development efficiency of unconventional oil and gas reservoirs，a supramolecular surfactant CPA-1 was prepared using long-chain fatty acid chlorides，N，N-dimethylpropanediamine and vinyl chloride as raw materials. Supramolecular surfactant fracturing fluid was prepared by mixing 2% CPA-1 and 3% potassium chloride. The structure of CPA-1 was characterized by infrared spectroscopy and nuclear magnetic resonance hydrogen spectroscopy，and then the microstructure of CPA-1 solution and fracturing fluid was compared. The temperature and shear resistance，salt tolerance，sand carrying capacity，gel breaking ability，and reservoir protection performance of fracturing fluid were evaluated. The results showed that CPA-1 solution contained a significant amount of worm like micelles. The addition of potassium chloride could further promote the growth of worm like micelles through electrostatic shielding and hydrogen bonding，leading to the formation of complex micelle aggregate structures. The temperature resistance and shear resistance of fracturing fluid were good. The viscosity could reach 51.8 mPa s after shearing for 120 minutes at 120 ℃ and 170 s^-1. The salt tolerance of fracturing fluid was strong. The use of salt water with mineralization degrees of 25 350，101 400 and 202 800 mg/L to prepare fracturing fluid had little effect on its shear viscosity. The viscosity after shearing 120 minutes was 53.1—62.4 mPa·s. In addition，the fracturing fluid also had good sand carrying capacity，gel breaking performance and reservoir protection performance. At 90 ℃，the settling velocity of ceramic particles in fracturing fluid was only 0.091 cm/min. When the volume fraction of kerosene was 20%，the fracturing fluid could achieve rapid gel breaking within 30 minutes at 80 ℃，with no residue，low surface tension（26.2 mN/m）and oil-water interfacial tension（0.84 mN/m）. The matrix permeability damage rate of artificial and natural rock cores with a permeability of 1.08×10^-3—32.07×10^-3 μm² by fracturing and gel breaking liquid was 3.50%—8.70%，which caused less damage to the reservoir and was suitable for fracturing construction in unconventional oil and gas reservoir.

Abstract:The edge well group of Bohai B oilfield has the characteristics of low reservoir permeability and high water injection pressure，and the water flooding development effect is poor. In order to enhance oil recovery，the research on reducing oil-water interfacial tension and improving rock wettability by pressure flooding agent was carried out. On this basis，the physical simulation of synergistic pressure flooding and the optimization of process parameters of target wells were carried out. The results showed that the interfacial tension between TYT303，UST and GWQY fluid and the crude oil of the target reservoir was low，and ZF-6，SXJ-1 and SXJ-2 had strong ability to change the wettability of the core，ZF-6，SXJ-1 and SXJ-2 could reduce the contact angle by more than 60°. Through physical simulation experiments，the optimized synergistic pressure flooding process conditions were obtained as follows，the pressure flooding working fluid was 0.3% ZF-6，the reasonable slug size was 0. 3 PV，the shut-in time was 48 h，the injection round was about 3 times，and the appropriate increase of fracture length and injection rate was beneficial to enhance oil recovery. It was recommended that the target well group should adopt the stimulation measure of“fracturing-imbibition-oil displacement”. The key process parameters were injection displacement of 5 m³/min，liquid injection volume of 18000 m³ and shut-in time of 15 days.

Abstract:At present，the large-volume，high-rate acid stimulation technique is widely used for unconventional reservoirs. However，the challenges of rapidly preparing and continuously blending the acid solution have not been effectively resolved. In this paper，a cationic polymer emulsion was prepared by using acrylamide（AM），2-acrylamido-2-methylpropanesulfonic acid and N， N，N-trimethyl-dodecane-12-（ acryloyloxy ）ammonium chloride as raw materials. The structure of the polymer was analyzed by infrared spectrometer and nuclear magnetic resonance spectrometer，and a series of cationic emulsions were optimized. The swelling rate，constant temperature variable shear performance and static retardation performance of cationic emulsions were tested according to industry standards，the temperature resistance of cationic emulsions was tested by rheometer，moreover，the etching performance of cationic emulsion acid solution on rock was tested in combination with engineering parameters. The results showed that the viscosity of thickener acid solution at different cationic polymer emulsion dosage within 1 min could reach more than 90% of the viscosity after complete swelling. The viscosity of thickener acid solution with 4.0% cationic polymer emulsion could reach up to 123 mPa·s after complete swelling. The thickener acid had excellent shear sensitivity and shear recovery，which was beneficial for the thickener acid to maintain high viscosity and reach the formation smoothly under the influence of high-speed shear of the injection equipment. At the temperature of 120 ℃ and the shear rate of 170 s^-1 ，the viscosity of the thickener acid solution with 4% cationic polymer emulsion was about 52 mPa s after shearing for 120 min，and the retarding performance was more than 88%，which met the field requirements. The thickener acid could form non-uniform etching on the rock to ensure the conductivity after the transformation. The study indicated that cationic emulsions could meet the construction requirement of large-volume and high-rate operations.

Abstract:Profile control technology in offshore oil fields is an effective treatment method for reservoirs with high water cut. Polymer gel has a high plugging strength but poor injectivity，while polymer microsphere has a good injection performance，but its plugging strength is greatly affected by concentration. To overcome the above problems，the AM/AA polymers were used as the core layer of the polymer microspheres，and the decomposable crosslinking agent PEGDA and the functional monomers AM and AA were coated to form the shell layer of the polymer microspheres，and then the organic crosslinking agent SZ was modified in the polymer shell layer to obtain a coated sustained-release profile control system using the inverse emulsion polymerization method. The factors affecting the viscosity increasing performance of the system was investigated，and its release process of viscosity components was also systematically characterized by using microscopy，transmission electron microscopy，nuclear magnetic resonance spectroscopy and Fourier transform infrared testing methods. Besides，core flooding experiments were conducted to characterize its injection performance and sealing performance in the target block. The results indicated that the system initially existed in a micrometer sized spherical state，and it swelled and released viscosity increasing components within 1—7 d. The process of releasing viscosity increasing components was influenced by several factors such as the amount of monomer and crosslinking agent，temperature，mineralization degree and shear rate. When the acrylic acid amount was 40%，the system viscosity was optimal. By adjusting the amount of crosslinking agent PEGDA（0.005%—0.300%），controllable release of the viscosity-increasing component could be achieved，2% highly active crosslinker SZ demonstrated both optimal gelation time and viscosity characteristics. The resistance coefficient of the system in the target high-permeability reservoir was ＜5，and the residual resistance coefficients at the injection end，middle，deep part reached 18，8，5，respectively，indicating good injection capacity and deep plugging capability.

Abstract:The Existing mobility control systems face technical challenges in medium-to-low permeability reservoirs，such as blocking effectively but unable to travel far，or traveling far without adequate blocking. In this paper，the nano-scale resin particle dispersions （OSR） suitable for deep mobility control in medium-to-low permeability reservoirs were prepared via a high-temperature and high-pressure melting method，using surfactants as dispersing stabilizers. The injection performance and plugging ability of OSR in medium-low permeability porous media were systematically evaluated by core displacement experiment with displacement pressure as index. The experimental results indicated that OSR exhibited good injection performance and plugging ability. As the resin concentration in OSR increased，the injection pressure of OSR also increased，but remained at a relatively low level. When the resin content in OSR was 5%，it demonstrated good injection performance in the cores with different permeability，with the maximum injection pressure of less than 0.25 MPa for injecting 1 PV of OSR. As the resin content increased， the plugging efficiency of OSR improved，but after the resin content exceeded 5%，the change in plugging efficiency became negligible. At a fixed resin content of 5%，the plugging efficiency increased as the permeability of the core decreased，with a plugging efficiency of over 90% for cores with a permeability of less than 30 × 10^-3 μm². Furthermore，OSR demonstrated good erosion resistance in the cores with different permeabilities.

Abstract:In view of the limited effect of conventional liquid-based chemical agents on inhibiting asphaltene precipitation and the difficulties in implementing the method on site，a method of preparing a solvent-free inhibitor by dissolving nanoparticles into supercritical CO₂ at high pressure was proposed. Based on the understanding of the fluid state and cloud point pressure of the nanoparticle-CO₂ mixture，the study conducted phase pressure measurement，static asphaltene precipitation measurement，and gas-drive core experiment to investigate the effects of graphene oxide（GO），silicon dioxide（SiO₂）and ferric oxide（Fe₃O₄） nanoparticles on the mixing pressure，asphaltene precipitation，and asphaltene particle size after CO₂ injection into crude oil， verifying the feasibility of nanoparticle-CO₂ mixture inhibiting asphaltene precipitation and enhancing oil recovery. The experimental results showed that the nanoparticle-CO₂ mixture was a single-phase fluid at the target reservoir temperature and pressure，and its cloud point pressure increased with the increase of nanoparticle concentration and temperature. Compared with injecting pure CO₂，the addition of GO，SiO₂ and Fe₃O₄ with mass fraction 1% into the CO₂ could reduce the mixing pressure by 16.4%，12.2% and 14.7%，respectively，reduce asphaltene precipitation by 55.4%，32.1% and 37.5%，respectively，and reduce the average particle size of precipitated asphaltene from 11.3 μm to 1.3，8.3 and 5.8 μm，respectively. During the gas drive process， the proportion of asphaltene precipitation decreased from 0.81 to 0.16，0.53 and 0.36，while the reduction in permeability of the core decreased from 88.7% to 25.2%，60.4% and 47.1%. The oil recovery rate increased from 36.7% to 47.4%，39.6% and 42.7%. In particular，GO could significantly adsorb asphaltene molecules，strengthen the stability of asphaltene molecules in colloids， inhibit their aggregation growth，delay precipitation and deposition，and avoid pore throat blockage. The research results provide reference and guidance for improving the gas injection development effect of asphaltene oil reservoirs.

Abstract:In order to solve the problem of difficult injection of ordinary water-based foaming agent in the process of gas channeling control in low permeability reservoirs，taking the reservoir of 530 well area in the eighth district of Xinjiang Oilfield as the research object，a CO₂ gas-soluble foam system was constructed，and the injection performance of the system was evaluated from interfacial tension，microstructure and rheology. The plugging effect of CO₂ gas-soluble foam and water-based foam was compared by core flow experiment，and the profile control and flooding effect was evaluated by parallel core flow experiment. The foam system under reservoir conditions was determined to be 0.4% QR-1529 + 1.0% ethanol. The interfacial tension of the foam system was as low as 1.47 mN/m at 30 ℃ and 24 MPa. The foam microstructure was compact and had a good skeleton structure，and the additive molecules enhanced the solubility of the foaming agent in CO₂. In addition，the rheology of the foam system contributed to its flow in the near wellbore area，exhibiting its good injectivity. The core flow experiment showed that the resistance factor and residual resistance factor of CO₂ gas-soluble foam were 18.5 and 13.0，which was higher 7.2 and 7.0 than those of water-based foam， respectively. When the core permeability difference was 2.54，the profile control effect of CO₂ gas-soluble foam was remarkable. The foam flooding of low permeability core enhanced the oil recovery rate by 13.7 percentage point，and the subsequent gas flooding enhanced the oil recovery rate by 15.88 percentage point. The CO₂ gas-soluble foam system has good injection performance and profile control ability.

Abstract:In view of the practical problems of existing commercial foams in high temprature，high salinity and low permeability reservoirs，such as low foaming volume，poor foam stability in porous media and low oil displacement efficiency，two kinds of asymmetric amphoteric gemini surfactants PAHC and PAOC were synthesized by etherification，quaternization，and substitution reactions as foaming agents for CO₂ foam flooding. The synthesized PAHC and PAOC was used as the main foaming agent to prepare a CO₂ foaming system. The interfacial activity，temperature and shear resistance，viscoelasticity and foam properties of the foaming system were evaluated，and the displacement experiment was carried out. The critical micelle concentration c_cmc of PAHC and PAOC were 6.76×10^-5 mol/L and 5.25×10^-5 mol/L，respectively，and the corresponding surface tension γ_cmc were 31.56 mN/m and 30.71 mN/m，respectively，and the Krafft points of PAHC and PAOC were lower than 0 ℃ and 1 ℃，respectively，which indicated that the two surfactants had good surface properties. Under the conditions of Gao 21-3 well in the second oil production plant of Jiangsu oilfield，the reservoir temperature being of 80 ℃ and the salinity being of 7704 mg/L，at a constant shear rate of 170 s^-1，the temperature resistance of PAHC-C₁₆S and PAOC -C₁₈S foaming systems were 81 ℃ and 88 ℃，respectively，and the viscosity of the two systems could be maintained at 6.2 mPa s and 6.4 mPa s，respectively，which exhibited that the injection and the viscoelastic properties of the two foaming systems were good. The PAHC-C₁₆S and PAOC -C₁₈S foaming systems could reduce the oil-water interfacial tension to 2.37×10^-2 mN/m and 1.81×10^-2 mN/m，respectively. The PAHC-C₁₆S and PAOC -C₁₈S foaming system had good temperature and salt resistance，and the temperature and salt resistance of PAOC -C₁₈S foaming sysmtem was slightly better than that of PAHC-C₁₆S foaming foam，which could be used in CO₂ foam flooding in high temperature and high salinity reservoirs such as Gao 21-3 well in the second oil production plant of Jiangsu oilfield. The core oil displacement experiment results showed that the average EOR of PAHC-C₁₆S and PAOC -C₁₈S foam systems on the basis of CO₂ flooding were 20.12 percentage point and 21.91 percentage point，respectively，which showed that the foaming system had good recovery effect.

Abstract:In order to further investigate the synergistic effect of ZrO₂ nanoparticles and low-salinity water，the low-salinity water was obtained by diluting the formation water of Taha oilfield by 11—200 times. Meanwhile，in order to improve the dispersion of ZrO₂ nanoparticles in low-salinity water， ZrO₂ nanoparticles with 50—100 nm were modified by the coupling agent 3-aminopropyltrimethoxysilane. The structure and morphology of the particles were characterized by infrared spectroscopy，transmission electron microscopy and thermogravimetric analyzer. The dispersion stability， interfacial properties and oil displacement effect of nanofluids combined with low-salinity water and modified ZrO₂ nanoparticles were evaluated. The results showed that compared to formation water，the greatest increase in recovery（5 percentage points）was achieved by injecting 1.5 PV low-salinity water diluted 110 times. The particle size of the modified ZrO₂ nanoparticle was about 30 nm. Compared to unmodified nanofluid prepared by formation water，the index of stability of the modified nanofluid prepared by low-salinity water decreased from 22.9 to 7.6，the interfacial tension was further reduced by 2 mN/m，the wettability of rock surface was further shifted to water-wetness，and then the lowest value of work of adhesion decreased from 27.72 J/cm¹ to 8.65 J/cm¹. The increase in temperature had a positive effect on the reduction of oil-water interfacial tension，contact angle and work of adhesion. When the dosage of modified ZrO₂ nanoparticle increased from 0.005% to 0.050%，the recovery rate of nanofluid increased first and then decreased. The optimum dosage of nanoparticle was 0.020% ，with a recovery rate increment of 12.6 percent points. The synergistic oil enhancement effect of low-salinity water and modified ZrO₂ nanoparticles was remarkable，which had good application prospects.

Abstract:For high-temperature and high-salinity oil reservoirs，the traditional anionic and nonionic surfactants are easily deactivated and cannot achieve the best oil recovery effect. Anionic-nonionic surfactants have both advantages，showing good interfacial activity，high temperature resistance and high salinity resistance，which possess great potential applications in EOR. Using aliphatic alcohol polyoxyethylene ethers（AEO7，AEO9）and nonylphenol polyoxyethylene ethers（NP7，NP9）with EO number of 7 and 9 as raw materials，anionic-nonionic surfactants with sulfonic acid groups，named as AESO7，AESO9，NPSO7， NPSO9，was synthesized by sulfonylation method，with a yield of 70% . The surface activity，salt resistance，temperature resistance and other properties of products were determined. The results showed that the surface tensions of AESO7 and NPSO7 solutions at the critical micelle concentration were 27.16 and 28.67 mN/m，which were lower than that of AESO9 and NPSO9 solutions. In the seawater solution with the salinity of 10—100 g/L，four surfactants showed good salt resistance and the surface tension remained stable. As the temperature increased，the water separation rate of AESO9、NPSO9 emulsion were larger than that of AESO7、NPSO7. At the temperature of 60—80 ℃，the water separation rates of the emulsion，prepared through mixing 10 g/L surfactant solutions and kerosene with volume ratio of 1∶1，remained relatively stable，indicating the temperature resistance of the modified surfactants had been significantly improved. When AESO7，AESO9 and α-cyclodextrin（α-CD）were compounded at the mass ratio of 1∶2，the surface tension of the complex system at the critical micelle concentration was further reduced，and the emulsion stability was improved by approximately 10% compared with that of the single system under different temperatures， which also remained relatively stable in simulated seawater（10—100 g/L），and had excellent salt-resistance.

Abstract:Oil film is an important type of residual oil after water flooding，so improving its utilization will further enhance oil recovery（EOR）. To investigate the dynamic detachment characteristics of different types of surfactants on oil films，a visual physical simulation method for oil film detachment was used to quantitatively characterize the dynamic characteristic parameters. Through the use of 11 different types of typical surfactants，the effects of different molecular structures and properties of surfactants on the mobilization rules and functional mechanisms of oil films were clarified. The results showed that there were significant differences in the dynamic characteristics and detachment mechanisms of different types of surfactants for peeling oil films. The detachment of oil films by anionic surfactants，including sodium dodecyl sulfonate，sodium dodecyl benzene sulfonate，sodium tetradecyl sulfate and sodium hexadecyl sulfonate，was mainly affected by the number of lipophilic groups in molecular structure and emulsifying performance. Increasing the number of carbon chains improved the oil-water emulsion stability to accelerate the detachment of oil film. While the detachment of oil films by cationic surfactants，including dodecyl trimethyl ammonium bromide， tetradecyl trimethyl ammonium bromide and cetyl trimethyl ammonium bromide was mainly affected by the number of lipophilic groups in molecular structure，oil-water interfacial tension（IFT），emulsifying performance and wettability alteration. Increasing the number of carbon chains was beneficial for reducing IFT and changing the wettability of rock surface into hydrophilicity. The detachment of oil films by nonionic surfactants（alkyl ethoxylated ether type）was mainly affected by the number of hydrophilic groups in molecular structure，oil-water IFT and emulsifying performance. So，increasing the number of polyoxyethylene ether groups was beneficial for improving hydrophilicity，reducing IFT，improving emulsifying properties，and further promoting oil film peeling. These results could further guide the molecular structure design of surfactants and the theoretical investigation of oil displacement in water-flooding reservoir.

Abstract:According to the problems of tertiary chemical flooding in Dagang oilfield，such as high cost，poor environmental protection and unsatisfactory effect of improving oil recovery， surfactant flooding， polymer-surfactant binary flooding， polymer-surfactant-alkali ternary flooding efficiency systems were prepared by combining the environmentally degradable circular microbial surfactant synergist，petroleum sulfonate and polymer. The surface tension，oil-water interface tension，salt resistance， biodegradability， temperature resistance， anti-adsorption resistance and oil displacement properties of the microbial oil displacement system were evaluated. Taking crude oil and the extracted water from the second area of Dagang oilfield as the medium，the adaptability between efficiency system and reservoir was evaluated，and then the oil flooding test of 1 well with binary efficiency system was carried out in 5-XX well of Yangerzhuangyang. The results showed that compared to a single petroleum sulfonate system，the performance of the microbial surfactant synergistic oil displacement system was significantly improved. The surface tension could be reduced to 18 mN/m，the oil-water interface tension could still reach the order of 10^-3 mN/m after 8 times of dilution，the sodium salt resisting concentration was up to 75 g/L，the magnesium salt resisting concentration was up to 2000 mg/L，the temperature resistance was up to 90 ℃，the biodegradation rate of 45 d was 93.9% ，and then the anti-adsorption was up to four level. Microbial surfactant synergist had good compatibility with polymer and weak base. It would not affect the oil-water interface tension and anti-adsorption performance of binary and ternary oil flooding systems. Furthermore， the viscosity stability was improved. The viscosity retention rate of binary and ternary flooding systems after closed standing at 58 ℃ for 7 d was about 72% and 68%，respectively. Microbial surfactant synergist could improve the displacement efficiency of surfactant flooding，binary flooding and ternary flooding，with more than 17% the recovery increase. Under six different reservoir conditions in Dagang oilfield，the microbial surfactant synergist had good adaptation. The oil-water interface tension of oil displacement system could reach the order of 10^-3—10^-4 mN/m. When the microbial surfactant synergist was produced in a pilot scale and used in the field oil flooding test，the moisture content decreased by 31.5% on average，the cumulative oil increase in 8 months was 491.34 t，showing good water control and oil increasing effect.

Abstract:The shale oil reservoir in the second member of Kongdian formation（Ek2）of Cangdong Sag in Dagang oilfield exhibits significant effects during the initial stage after primary fracturing，but the energy and production decline rapidly in later stages. Furthermore，the produced fluids are severely emulsified，resulting in a reduction of shale oil recovery，and increase of pipeline transportation resistance and development challenges. Through systematic analysis of the physicochemical properties of Ek2 shale oil，emulsification characteristics of shale oil-water and their influencing factors，this study revealed the reasons and mechanisms of shale oil-water emulsification，and proposed methods to mitigate emulsification-induced viscosity enhancement. The results showed that the Ek2 shale oil contained over 20% wax content on average with a pour point exceeding 35 ℃. Moreover，the high content of heavy hydrocarbons favored the occurrence of emulsification phenomenon. Nitrogen-containing polar components（e.g.，resins and asphaltenes）and wax crystals facilitated the formation of water-in-oil（W/O）emulsions during the flow of shale oil and water， resulting in emulsification-induced viscosity enhancement phenomenon. The viscosity of shale oil increased first and then decreased with increasing water content，peaking at 50%—70% water content with viscosity values 3.23—7.45 times that of dehydrated crude oil. The stability of W/O emulsions formed during shale oil-water emulsification process was enhanced by increasing emulsification temperature，water phase salinity，and intruding fracturing fluid composition. Additionally，complex O/W/O multiple emulsions generated when the emulsified shale oil was re-emulsified，further increasing the viscosity of system. However，introducing a small amount of emulsifier during the re-emulsifying process enabled phase inversion from W/O to oil-in-water（O/W）emulsion，thus effectively reducing the viscosity of shale oil and improving fluidity. Consequently， it was necessary to consider the physicochemical properties of shale oil as conducting water injections and energy enhancement for shale oil reservoirs. The development of high-activity surfactants for shale oil stimulation would be a focus for subsequent process design and product research.

Abstract:Microencapsulated polymers can achieve slow release and viscosity increase of components，avoiding the influence of rock pore throat shear and reducing ions in water on the viscosity of polyrmer solution during injection process. To clarify the dynamic release and oil displacement performance and adaptability of the microencapsulated polymer in porous media，the oil displacement experiments of microencapsulated polymer pre- and post- shell breaking were conducted in homogeneous and heterogeneous square rock cores，and CT scans were performed on the remaining oil distribution in different displacement stages to determine the oil displacement characteristics of the microencapsulated polymer. The results showed that the initial viscosity of the pre-shell breaking microencapsulated polymer system with mass concentration of 1850 mg/L was low at 0.7 mPa s，and gradually broke with time at high temperature. After shell breaking for 20 h，the viscosity significantly increased to 32.0 mPa·s. When injecting microencapsulated polymers system into the cores for oil recovery in pre- and post- shell breaking states，respectively，at the beginning of polymer injection（0—0.5 PV），the injection pressure of post-shell breaking polymer system was higher than that post-shell breaking；while in the late stage of injection（0.5—1.0 PV），the former was lower than the latter，It was indicated that the microencapsulated polymers injected in their pre-shell breaking state could indeed undergo dynamic shell breaking in porous media，causing a significant increase in injection pressure. The enhanced oil recovery of the pre-shell breaking system was stronger than that of the post-shell breaking system. The recovery rates in homogeneous and heterogeneous models were 43.5%，50.5%， 39.0%，44.5%，respectively. The initial viscosity of the pre- shell breaking polymer system was low，so the system could enter the deep part of the model to release and drive oil，as a result，the residual oil saturation in the rear part of the model was lower；however，after the shell was broken，the system was mainly displaced by the migration capacity and shear degradation of the crude oil in the front part of the model，resulting in higher residual oil saturation in the middle and rear parts，which was also the main reason why the oil recovery rate of pre- shell breaking system rate was more than that of the post- shell breaking system.

Abstract:To accurately evaluate the effect of direct current（DC）voltage on oil-water interfacial tension，oil-water electrolysis experiments were conducted at 0—15 V DC voltage，taking dehydration crude oil and simulated formation water（CaCl₂ water type）of Shengli oilfield as research objects. By measuring the changes in oil-water interfacial tension，temperature and current，along with analyzing the pH value and ion content of aqueous phase，as well as the composition and functional group content of oil phase，the reduction mechanism of oil-water interfacial tension by DC voltage was explored. The results showed that with the increase of DC voltage，the interfacial tension between oil and water significantly decreased，with a maximum reduction of 42.66%. The solubility of Ca2 + in simulated formation water decreased from 2.81 mg/L to 2.25 mg/L with increasing temperature， which weakened the influence of DC voltage on oil-water interface. However，the content of Na₊ increased from 0.50 mg/L to 0.72 mg/L，which was beneficial for further reducing interfacial tension. Under the influence of electrochemical effect，the pH value of aqueous solution increased from 7.32 to 10.96. The alkaline condition promoted the reaction of acidic substances in crude oil， generating surface active substances such as carboxylic acid salts. Through infrared spectroscopy analysis，the normalized content of carboxylate was 1.40，1.51，1.90 and 4.11 at DC voltage of 0，5，10 and 15 V，respectively. The increase in carboxylate content further promoted the decrease of interfacial tension. In addition，electrochemical reactions promoted the simplification of crude oil composition. When the DC voltage increased from 0 V to 15 V，the content of asphalt and resin decreased from 18.63% and 12.96%to 12.11% and 10.06%，respectively，while that of saturated hydrocarbons increased from 47.57% to 55.89%. The research results provided theoretical support for promoting the application of DC electric fields in improving crude oil recovery efficiency.

Abstract:The aged oil is a type of oil-water solid mixture with high emulsion stability formed at the the oil-water transition layer in crude oil tanks after long-term exposure to oxygen aging. It is difficult to treat using the conventional demulsification and dehydration treatment method. In this paper，through testing the oil-water interfacial tension and interfacial film strength of the aged oil in Hongqian oilfield，the influence of solid particles，polymers，inorganic salt ions and oxygen exposure time on the emulsification stability of the aged oil system was analyzed. At the same time，the demulsifier dehydration experiments were carried out on the aged oil，and finally the optimal demulsifier formula and process parameters were obtained. The results indicated that when the dosage of solid particles and polymers was increased and the exposure time was prolonged，the emulsion stability of the aged oil was enhanced，leading to increased difficulty in demulsification treatment of the aged oil. Inorganic salt could reduce the interfacial film strength of the aged oil，which was conducive to the demulsification of the aged oil. A demulsifier composed of polyethylene glycol octylphenyl ether（X-100）and sodium dodecylbenzenesulfonate（ABS）in mass ratio of 3∶1，could achieve good dehydration effect with dehydration rate of 100% and clear water quality，when the dosage was 2%，the demulsification temperature was 60—65 ℃，and an effective settling time was more than 30 minutes. The formulation and process parameters formed by the experimental research in this article provide technical guidance for the treatment of the aged oil in Hongqian oilfield. At the same time，the emulsification characteristics of the aged oil in the oilfield and the experimental rules for selecting demulsifiers obtained from the experiment can provide reference for the treatment of the aged oil in other oilfields.

Abstract:With the global development of oil and gas resources shifting increasingly toward low-permeability，ultra-low-permeability，and ultra-deep complex reservoirs，traditional oilfield chemicals are facing significant challenges in terms of dynamic adaptability and tolerance to extreme environmental conditions. Environmentally responsive smart materials trigger autonomous performance regulation by sensing changes in reservoir environmental parameters，achieving a leap from“passive resistance”to “active adaptation”. These materials have emerged as key technologies for ensuring efficient drilling operations and enhancing hydrocarbon recovery. This paper focused on four categories of responsive smart materials，namely，temperature-responsive，shape memory，CO₂-responsive，and magneto-responsive materials. their response mechanisms and performance characteristics was reviewed，and the current state of their applications in areas such as drilling fluid rheology control，fracture adaptive plugging， intelligent oil displacement stimulation and efficient treatment of produced fluids was presented. Furthermore，the critical challenges facing the application of these materials in oil and gas development was discussed and the future prospects for their advancement was explored.