Abstract:To solve the problem of poor temperature resistance of oil well cement fluid loss additive under high temperature conditions，this study adopted acrylamide（AM），sodium p-styrene sulfonate（SSS），N，N-dimethylacrylamide（DMAA）and N， N-diethylacrylamide（DEAA）as organic synthesis materials through molecular structure design. A fluid loss additive LHF-1L with high temperature resistance was synthesized successfully by aqueous solution free radical polymerization method. The influence of synthetic conditions on the fluid loss reduction performance was discussed comprehensively，and then the chemical characterization and performance evaluation of LHF-1L were carried out. The results showed that the filtration reduction performance of LHF-1L was the best under the preparation condition of 4∶6∶2∶0.5 monomer ratio of AM∶SSS∶DMAA∶DEAA，0.75% initiator potassium persulfate（KPS）solution in total mass of monomer，7 pH value of reactant solution，65 ℃ reaction temperature，4 hrs reaction time. The water loss at 220 ℃ with LHF-1L dosage of 7% was 42 mL. The test results of FT-IR，TG and GPC showed that all four monomers were successfully involved in the polymerization，and then the target product was generated. Only when the temperature reached 273 ℃ ，apparent heat loss of LHF-1L appeared. The polydispersity coefficient was 1.396，meanwhile，the average molecular weight was 171 351 g/mol. In addition，LHF-1L had little influence on the development of cement slurry fluidity and cement compressive strength. At 220 ℃，the water loss after adding 7% LHF-1L to the cement slurry could still be controlled within 50 mL. At 150 ℃ and 94.4 MPa，LHF-1L would not cause the slurry to thicken sharply and super retarding. The thickening curve was normal，moreover，no abnormal gelling phenomenon occured. The preparation of LHF-1L by double temperature-sensitive monomer enhanced its thermosensitive hydrophobic association at high temperature，thus improving its fluid loss reduction performance at high temperature，and meeting the requirements of cementing technology at high temperature.

Abstract:Based on the demand of controlling fracture height and low displacement in the development of thin-layer oil and gas resources，polyacrylamide block copolymer（PMASD）was synthesized by aqueous solution free radical micelle polymerization， using acrylamide（AM），acrylic acid（AA），2-acrylamide-2-methylpropanesulfonic acid（AMPS），2-acrylamidoethylammonium bromide（DAMAB）and alkylphenol polyoxyethylene ether（NP-10）as raw materials. The critical association concentration， viscoelasticity and microstructure of PMASD were studied by fluorescence spectrophotometer，rheometer and scanning electron microscope. At the same time，the static and dynamic sand carrying properties of PMASD fracturing fluid were studied，and then the results were compared with that of polyacrylamide slick water. Finally，the PMASD fracturing fluid was applied in the field. The results showed that the PMASD fracturing fluid had a micelle structure. The critical association concentration was 0.127%. The PMASD fracturing fluid system showed good viscoelasticity. The linear viscoelastic range was 0.01—1.00 Pa. After hydrophobic association，the strength was large，meanwhile，the shear resistance was strong. In the injection process of low displacement（20 L/ min），the network structure formed by PMASD fracturing fluid was irregularly distributed and had high structural strength，which could effectively carry proppant. The static and dynamic sand carrying performance of PMASD fracturing fluid was good. Under the experimental condition of 12% sand liquid volume ratio，when the mass fraction of PMASD was equal or greater than 0.25%（147 mPa·s ），it showed good suspension and sand carrying capacity at room temperature and 80 ℃. Compared with polyacrylamide slick water，the sand carrying effect of PMASD fracturing fluid increased by 160%. In the field application of X5-X well in Jiangsu oilfield，PMASD fracturing fluid was pumped at a displacement of 2 m³/min. The daily liquid production increased from 1.4 t to 6.5 t，meanwhile，the daily oil production increased from 0.6 t to 4.2 t. The effect of increasing production was obvious. The full suspension fracturing fluid PMASD system could meet the needs of effective sand-carrying fracturing of thin-layer oil and gas resources under low construction displacement.

Abstract:In order to improve the temperature and salt resistance of the fracture fluid thickener，Oil in water emulsion PAAD with temperature and salt resistance was synthesized using acrylamide（AM），acrylic acid（AA），anionic monomer 2-acrylamide- 2-methylpropyl sulfonic acid（AMPS）and cationic monomer acryloxyethyl trimethyl ammonium chloride（DAC）as monomers. The mass ratio of monomer AM，AA，AMPS，DAC was 9∶1∶3∶1.5，and monomers with mass fraction of 30% was dissolved in water as aqueous phase. Emulsifier Span-80 and Tween-80 with mass ratio of 9∶1 and mass fraction of 10% was dissolved in oil as the oil phase，and the oil/water ratio was 1∶2.5. The viscosity average molecular weight of PAAD was 383×10⁴ g/mol. The structure of PAAD was characterized by infrared spectroscopy and H-NMR spectroscopy. The properties of the temperature resistance，salt resistance，shear resistance and gel-breaking were investigated. The viscosity of PAAD solution with mass fraction of 1.5% maintained at 51.7 mPa·s after sheared for 1.5 hours at the temperature of 90 ℃，exhibiting good temperature resistance and shear resistance. The viscosity of the PAAD solution could quickly restore when the shear rate entered the low shear region after high shear，which could ensure that the suspended sand does not settle. In the simulated seawater with salinity of 50 g/L，the viscosity of PAAD solution with mass fraction of 1.5% was 45 mPa·s，indicating that PAAD had good salt resistance. At the temperature of 90 ℃，the fluid could be broken within 3 hours at dosage of 0.2% breaker. The surface tension and oil-water interfacial tension of broken fluid was 30 and 1.9 mN/m，respectively. The insoluble residuewas 220 mg/L，and the formation damage was 9%. These properties met the requirements the standard in the petroleum industry.

Abstract:The rapid pressure drop and salt deposit in wellbore after fracturing in the special reservoir containing a large amount of soluble alkali salt in the Mahu Fengcheng Formation，seriously affected the oil testing. In order to verify whether the fracturing fluid entering the well would have an impact on the dissolution of the reservoir salt mineral，the impact of different inflow fluids on the dissolution of the reservoir salt mineral was simulated，the cross-linked fracturing fluid system with on-line preparation，temperature resistance（120 ℃）and salt resistance（30×10^{4/sup> mg/L）was constructed and field tests was carried out based on the composition characteristics of the typical alkali salt mineral in the Fengcheng Formation reservoir. The results showed that the rate of dissolution high salt water to typical simulated salt was more than 60% compared with that of tap water. The“molecule interchain entanglement + association + salt effect”of suspension based hydrophobically associating polymer solution could be realized， resulting in the rapid dissolution and high viscosity increase of the base solution，and the cross-linked fracturing fluid system with on-line preparation， temperature resistance and salt resistance was formed between the thicken agent and the organic boron-zirconium-aluminum slow crosslinking agent by chemical crosslinking. The optimal formula was as follows，1.8% thickener GAF-TE+0.4% crosslinker JL-3+0.3% synergist GF15B+0.04% gel breaker APS. The shear viscosity of the system was greater than 100 mPa·s after sheared for 1 hour at the temperature of 120 ℃ and at the shear rate of 170 s-1，exhibiting good dynamic and static sand carrying capacity. The well M（three layers）fracturing were successfully constructed on site. the oil test after fracturing was successfully completed，and the maximum daily oil production was 4.4 m3. The high-salt fracturing fluid system had certain positive effect on the reduction of formation pressure drop due to reservoir dissolution.}

Abstract:In view of the problems of breakthrough of injection water and fracture after fracturing in Daqing peripheral oilfields，the high strength plugging agent of controlling channeling path was synthesized by aqueous solution polymerization method，which ensured the effective exploitation of potential placement by subsequent refracturing measures. The formula optimization and performance evaluation of the plugging agent were carried out through laboratory experiments. The optimized formula was 5%— 10% acrylamide，0.1%—0.5% N，N'-methylenebisacrylamide，0.03%—0.1% ammonium persulfate and 20%—25% coupling modified class G oil well cement. The plugging agent was suitable for the formation with the temperature of 40—65℃. The initial viscosity of the plugging agent was 10—15 mPa·s，and the gelling time was controllable within 1 —5 hours，which indicated that the plugging agent had good injectivity. The gelling strength of the plugging agent could be adjusted from 30 N to 300 N. The core plugging rate was greater than 98%，and the breakthrough pressure was more than 20 MPa，exhibiting good plugging performance. The high strength plugging agent was suitable for plugging the water exit of the original fracture and perforation，which ensured the fracture diversion and forming new fractures during the refracturing. At the same time，it was also suitable for plugging the channeling-path formed by natural fracture. It could provide favorable technical support for the effective development of subsequent refracturing measures and realizing water control and oil increment.

Abstract:Deep profile control，as an important technology to improve recovery，has been widely used for water channeling treatment in inhomogeneous reservoirs. In order to solve the contradiction between the injectivity of profile control agent and its in-depth plugging in the process of water channeling treatment，the self-assembled deep plugging technology was proposed based on the host-guest molecular recognition principle. Firstly，the host nanoparticles with a particle size of 170 nm and surface containing β-cyclodextrin group were prepared by emulsion polymerization using acrylamide，N，N'-methylene-diacrylamide，allyl group-β-cyclodextrin，and styrene as raw materials. Then，the guest polymers with a molecular weight below 4000 and a molecular weight distribution between 1.1 and 1.4 were prepared by controlled radical polymerization using cetyldimethyl allyl ammonium chloride and acrylamide as raw materials. The self-assembled profile control system was constructed by host nanoparticles and guest polymers. The self-assembly properties of nanoparticles and polymers were evaluated by the viscosity of self-assembled profile control system. Based on core displacement experiments，the injection-plugging performance of self-assembled profile control system was evaluated. The results showed that due to the host-guest recognition between the hydrophobic alkyl chain in guest polymer molecule and the β-cyclodextrin group on the surface of host nanoparticles，the β-cyclodextrin group encapsulated the hydrophobic alkyl chain to form an inclusion complex，while the guest polymer played a“bridge”role. The nano-particles self-assembled and aggregated to form clusters，which slowly increased the viscosity of profile control system to about 90 mPa·s. The injection performance of profile control system consisting of 0.1% nanoparticles and 0.2% polymer was good，with a resistance coefficient of 2.0. After self-assembly，subsequent water flooding was carried out，with a residual resistance coefficient of 3.42 and a plugging rate of 70.7%. This study provided a new approach to alleviate the contradiction between injectivity and in-depth plugging of profile control agents.

Abstract:There is no surface water injection process in the high-temperature and high-salt self-source water injection reservoirs in the east of South China Sea. The conventional profile control and flooding agent can’t be directly injected into the reservoir after mixing on the ground. It is difficult to inject into the reservoir because the conventional profile control and flooding agent has poor self-dispersion. Focusing on the A oilfield in the east of South China Sea，the self-dispersed profile control and flooding agent with high temperature and salt resistance was developed by gelation reaction and mechanical grinding miller. It was composed of polyphenol crosslinking agent，multi-branched chain alcohol polyether dispersant，and temperature-resistant and salt-resistant polymer with a content of 40% AMPS. The particle size，micro-morphology and surface electrical properties of the profile control and flooding agent were studied by laser particle size analyzer，electron microscope and dynamic light scatterer. The self-dispersion performance，injection performance and profile adjustment performance were evaluated. Finally，the field application was carried out in the X well Group of A oilfield in the east of South China Sea. The results showed that the self-dispersed profile control and flooding agent was spherical. The D₅₀ of initial particle size was 1.09—11.63 μm. It could be adjusted by changing the formula， grinding conditions or heating time. The surface of this agent was negatively charged. The Zeta potential value was -19.30—-26.1 mV. Compared with the conventional oil dispersing granule agent，the self-dispersing performance of this agent was good. It could be quickly and evenly dispersed after entering water while the self-dispersed rate in injected water was 90.0%. Furthermore，the core injection pressure was only 53.13% of that of oil dispersing granule agent. After chemical treatment，the flow ratio of high permeability core decreased from 92.6% to 20.5%，while that of low permeability core increased from 7.4% to 79.5%. The water absorption profile was obviously reversed. The field test effect was good. The increasing pressure after injecting the profile control and flooding agent was 0.5 MPa. The maximum daily oil increase was 106 m³ after field test，and then the stage increasing oil was 8900 m³. The profile control and flooding agent met the high temperature and high salt condition of target oilfield. It had good injection performance and obvious increasing oil effect，which was suitable for the self-source water injection reservoir.

Abstract:In order to solve the problems of poor temperature resistance of conventional foam resin system，great damage to chemical sand solidification reservoir and short validity period in loose sandstone heavy oil reservoir of Liaohe oilfield， nano-modified resin base liquid was prepared by using epoxy resin，phenolic resin，hydrophobic nano-SiO₂ and silane coupling agent as raw materials，and then adding curing agent，emulsifier，foaming agent，foaming stabilizer and other additives to prepare foam resin sand solidification system. The consolidation temperature，sand strength，permeability，temperature resistance and heterogeneous multilayer injection performance of the system were evaluated. A matching foam generator was developed，and then a high temperature resistant foam resin sand consolidation technology with uniform and low damage was formed. Finally，it was applied in Liaohe oilfield. The results showed that the optimum formula of the foam resin sand consolidation system was obtained as follows：20%—30% resin base solution，8%—12% phenolic amine curing agent，0.3% emulsifier OP-10，0.5% foaming agent organic silicon surfactant，0.1% solid foam stabilizer nano-SiO₂，0.1% polymer foam stabilizer polyethylene glycol，57%—71% water. The foaming volume of the system was increased by 6 times，meanwhile the half-life was greater than 20 min. It could be cured above 35 ℃，and the temperature resistance after curing could reach 280 ℃，which had the characteristics of low temperature curing and high temperature resistance. The compressive strength of the foam resin solidified core at different temperature was more than 5 MPa，and the sand consolidation strength was high，which could meet the requirements of unconsolidated sandstone. The sand permeability of the consolidated core prepared with 0.25—0.42 mm quartz sand was 4.8 μm²，which was better than that of conventional resin sand consolidation agent（1.9 μm²）. It could prevent the penetration of highly permeable layer，improve the injection profile of sand consolidation agent，and achieve uniform sand consolidation. Good sand control results were obtained in the field test，which verified that the technology could achieve uniform sand consolidation and low damage characteristic. Using the fluid characteristics of foam resin to achieve uniform sand consolidation in heterogeneous multiple reservoirs，the purpose of improving the effect of chemical sand consolidation and the validity of sand control was achieved.

Abstract:Compared with vertical and horizontal wells，fishbone wells have advantages such as high single well control reserves and large reservoir contact area. However，in the development process，it is often necessary to inject water to supplement the formation energy in a timely manner. Branch wellbore structures are complex. Irregular injection-production well networks are often constructed using vertical or horizontal wells as injection wells on-site. However，problems such as rapid water rise in branch wells，rapid decline in oil production，and difficulty in allocating water injection rates exist during actual production processes. It is necessary to research on the characteristics of oil-water movement under different injection-production methods and different wellbore types. Using two-dimensional visualization models，red dyed kerosene，and black ink，physical simulation experiments were conducted to study the oil-water movement characteristics of fishbone well groups with different branch angles（30°—90°） under different injection-production well types，and then the numerical simulation results were validated. The results showed that when horizontal wells were injected with water，the greater offset of the oil-water front towards the branch resulted in a more uniform advancement of the oil-water front. When vertical wells were injected with water，the advancement of the oil-water front was slower，but the affected area in the water-flooded state was larger. When water was injected into vertical wells，the fishbone well with a branch angle of 45° had the highest recovery rate（61.10%）. When water was injected into horizontal wells，the fishbone well with a branch angle of 30° had the highest recovery rate（57.97%），meanwhile，the distribution of remaining oil was the least in the water-flooded state. When the branch angle was less than 30°，the water injection effect of horizontal wells was better. When the branch angle was greater than 45°，the water injection effect of vertical wells was better. Comparing the oil-water movement field maps and recovery rates of physical simulation experiments and numerical simulation experiments，the results were quite consistent. The experimental results had a high matching degree with applicable reservoir characteristics. The research results provided theoretical guidance and reference basis for the deployment and parameter optimization of fishbone well injection-production networks in actual oilfields.

Abstract:In order to further enhance the efficient application of nano oil displacement technology in low-permeability reservoirs，it is urgent to develop a new type of nano oil displacement products. As an environmentally friendly material，Nanostarch particles have a wide distribution in the world with the relatively low price，excellent performance，so that it has the potential to significantly improve oil recovery. In this paper，the process and mechanism of enhanced oil recovery of nano starch fluid were studied based on the basic physical properties of nano fluid，improving oil displacement effect，expanding the swept volume and other key indicators. by using the indoor static experiments，core displacement experiments，microscopic visualization experiments，CT scanning experiments，etc. The experimental results showed that，after the action of the nanostarch fluid with the concentration of 5000 mg/L and the size of 30 nm，the occurrence state of water molecules was changed. The phase transition temperature of water was increased from 102 ℃ to 110 ℃. The wetting contact angle of rock surface was reduced from 78 ° to 34.2 °，the oil-water interfacial tension was decreased from 20 mN/m to 0.56 mN/m，and the injection pressure was decreased by 39.6% . In the microscopic visualization model，nano starch fluid could significantly reduce the oil saturation，especially the amount of oil film on the solid surface of the porous media was significantly reduced，which could significantly improve the oil displacement effect. In low permeability cores，the displacement front of nanostarch solution was more uniform and had a higher sweep area than that of water flooding. Due to its large sweep volume，high oil displacement efficiency and good wettability，the nanostarch fluid could be used to enhance oil recovery in low-permeability porous media. After injection of 0.4 PV of nanostarch fluid with the concentration of 5000 mg/L，oil recovery was increased by up to 21 percentage point. The results of this study can provide a new technical approach for enhanced oil recovery in low permeability reservoirs.

Abstract:Carbon dioxide and cosolvents have synergistic effect on enhancing oil recovery. Measuring the cloud-point pressure and miscibility pressure is of great significance to improve oil recovery and CO₂ sequestration. Based on the photosensitive principle， the cloud-point pressure of diethylene glycol dimethyl ether（DDME），triethylene glycol dimethyl ether（TEDM）and tetraethylene glycol dimethyl ether（TGDE）in CO₂ and the effects of temperature，concentration and type of the cosolvents were obtained using the improved carbon dioxide phase equilibrium experimental device. Then the effects of cosolvents on decreasing the miscibility pressure of CO₂ -C₁₆ were investigated and compared with that of ethanol. The results showed that the cloud-point pressure of DDME，TEDM and TGDE all increased with the increase of temperature，and then the phase behavior of low critical solution temperature（LCST）was present. With the increase of cosolvent dosage，the cloud-point pressure of DDME，TEDM and TGDE all increased with a low increasing rate. Because the polarity became larger and larger in the order of DDME，TEDM and TGDE，the interaction force between cosolvent and CO₂ became weaker and weaker，leading to the increase of cloud-point pressure. Among the three ether cosolvents with similar structure，DDME had the lowest cloud-point pressure，while TGDE had the highest cloud-point pressure. When the mass fraction of DDME was 3.0%，the cloud-point pressure was only10.14 MPa at 60 ℃. Moreover，DDME had the best effect to decrease the miscibility pressure between CO₂ and C₁₆ . DDME with the dosage of 1% could decrease the miscibility pressure with the decreasing degree of 11.25%，which was larger than that of ethanol（10.62%）at 50 ℃. When the temperature was lower than 50 ℃，the effect of TEDM was better than that of ethanol. At a higher temperature，the effect of ethanol was slightly better than that of TEDM and TGDE. DDME，with a low cloud-point pressure value，a high ability to decrease the miscibility pressure，and a good compatibility with carbon dioxide，was also suitable for the application in the reservoir with low formation pressure.

Abstract:The asphaltene deposition of crude oil caused by CO₂ injection will damage the tight reservoir and seriously affect the ultimate recovery. In order to clarify the characteristics of asphaltene deposition and the influence on reservoir permeability under different CO₂ injection methods，the experiments of CO₂ flooding and CO₂ huff-n-puff were carried out. The characteristics of asphaltene deposition，the performance of oil recovery，and the influences on the permeability of tight cores under different injection methods were analyzed by nuclear magnetic resonance（NMR）and scanning electron microscope（SEM）. The results showed that the asphaltene deposition occurred in the tight cores under both of CO₂ flooding and huff-n-puff，which was mainly deposited on the pore surface by membrane adsorption. Influenced by the interaction time between CO₂ and crude oil，the amount of asphaltene deposition under CO₂ huff-n-puff was greater than that under CO₂ flooding. Moreover，the pore size range of asphaltene deposition under CO₂ huff-n-puff was higher than that of CO₂ flooding. The damage of asphaltene deposition to core permeability was related to the direction of crude oil production. Asphaltene deposition had greater damage to the forward（CO₂ injection direction）core permeability under CO₂ flooding，while that had greater damage to the reverse core permeability under CO₂ huff-n-puff. When the confining pressure was 10 MPa and 5 MPa，the damage of asphaltene deposition under CO₂ flooding and CO₂ huff-n-puff to the forward core permeability（average decrease of forward permeability）was 7.05% and 1.67%，while the damage degree of the reverse core permeability（average decrease of reverse permeability）was 0.41% and 2.66%，respectively. Due to the influence of injection-production mode and flow mechanisms，the recovery of CO₂ huff-n-puff was lower than that of CO₂ flooding. The research results were significant in understanding the damage caused by asphaltene deposition in different directions and selecting injection methods during CO₂ injection in tight oil reservoirs.

Abstract:In the process of CO₂ flooding，the mixing system of CO₂ and heavy oil is immiscible. The minimum miscible pressure is higher than formation fracture pressure. The molecular simulation of the mixing system of CO₂ and crude oil was carried out. The effects of the type of downmixing agent，addition amount，temperature and pressure were investigated. The aggregation degree of system of CO₂ molecules and asphaltene molecules in the miscible process was obtained by the radial distribution function，the dispersion state of various molecules was defined，and then the mechanism of action was analyzed. On this basis，PVT phase experiments at high temperature and high pressure were carried out to determine the volume expansion coefficient and CO₂ solubility of the mixed and crude oil after adding different downmixing agent，which verified the molecular simulation results. Finally， trimethyl citrate，benzyl alcohol and ethyl benzoate were optimized to obtain the optimum mixture formula，and then the performance of reducing miscible pressure was evaluated by the fine tube experiment. The results of molecular simulation showed that trimethyl citrate had the most significant reducing miscible pressure effect，which could effectively increase the aggregation degree of CO₂ molecules and reduce the aggregation degree of asphaltene molecules. Under the condition of high pressure（6.90 MPa）and low temperature（308.15 K），the downmixing agent could play its role more effectively. The results of PVT phase experiment showed that 0.23% trimethyl citrate had the best solubilization and swelling effect，which was consistent with the molecular simulation results. The optimum formula of compound downmixing agent was obtained as follows：80% trimethyl citrate，20% ethyl benzoate. The minimum miscible pressure was decreased by 21.47%，meanwhile the CO₂ solubility and oil recovery efficiency were improved by adding 0.23% compound downmixing agent to the crude oil-CO₂ system. Containing oleophilic hydrocarbon groups and CO₂ -philic ester groups，the downmixing agent could not only bind with polar molecules in crude oil system，break up the aggregates of each asphalt molecule，but also adsorb on the interface of crude oil and CO₂ under the action of both parent properties，reduce the interfacial tension between crude oil and CO₂ ，and then reduce the minimum miscible pressure.

Abstract:Low permeability reservoirs in Shengli oilfield are characterized with deep burial depth（＞3000 m），high temperature （>120 ℃），and strong heterogeneity. Aiming at the problems of low sweep efficiency of CO₂ flooding and poor profile control performance of conventional foam，a highly stable supercritical CO₂ foam system with zwitterionic surfactant（HSD）and modified SiO₂ nanoparticles as foaming agents was developed. The foaming performance and temperature resistance of the system at high temperature were studied. The effects of nano-SiO₂ on the rheological properties，plugging properties and profile control performance of supercritical CO₂ foam system were evaluated respectively. Finally，the stabilization mechanism of nanoparticle reinforced supercritical CO₂ foam was discussed. The results showed that the highly stable supercritical CO₂ foam system had good foaming performance and temperature resistance. With increasing dosage of nanoparticle in the system，the half-life of foam gradually increased first and then decreased. At 110 ℃，0.5% nanoparticle could increase the half-life of foam drainage from 17 min to 40 min，and then the stability was improved by nearly 2.5 times. At the same shearing rate，the apparent viscosity of the system increased with the increase of nanoparticle concentration，and then the consistency coefficient increased from 0.073 to 1.220. In the core flooding experiment，the steady-state apparent viscosity of foam in porous media increased with the increase of nanoparticle concentration，thereby increasing the plugging strength. Supercritical CO₂ foam was stacked and discharged in“granular”shape. The foam size was 10—20 μm. Supercritical CO₂ foam had good profile control and displacement performance，which could block high permeability channels and compel subsequent injected CO₂ into low permeability matrix，thus improving oil recovery. Surfactant molecules adsorbed on the surface of nano-SiO₂ ，which made it have interfacial activity，and then nano-SiO₂ adsorbed on the gas-liquid interface to improve the stability of foam.

Abstract:In-situ CO₂ foam flooding is a promising enhanced oil recovery technology. In this paper，the in-situ CO₂ foam flooding enhanced oil recovery was studied experimentally. The gas generation system，foam system and injection parameters were studied， and the optimal injection volume，injection rate and applicable permeability ratio range were obtained. The experimental results showed that under the condition of the temperature of 70 ℃ and the salinity of 10000 mg/L，the in-situ CO₂ foam system was composed of 2.1% ammonium bicarbonate + 1.6% acetic acid + 9.5% ammonium chloride + 0.1% sodium alpha-olefin sulfonate AOS + 0.1% DHSB. The foam volume could reach up to 810 mL，and the foam comprehensive index was 15552 mL· min. The foam formed by the system had the characteristics of higher viscosity and larger elasticity in the middle of the reservoir， and could effectively block the high permeability channel，showing good plugging ability. When the permeability difference was about 6，the injection rate of in-situ CO₂ foam system was controlled at about 1.0 mL/min and the injected slug volume was controlled at 0.3 PV，the best flooding effect could be achieved. It was also found that the foam system could enhance effectively oil recovery in heterogeneous reservoirs with the permeability ratio difference of 3.9—13.7. While the permeability ratio difference was 15.6，the system could not significantly enhance oil recovery of low-permeability layer，but still performed some washing actions in high-permeability cores. This research provides important references for the application and optimization of in-situ CO₂ foam flooding technology.

Abstract:To enhance the application effect of natural gas foam in oil recovery，the stability of natural gas foam generated by the combination of hydrophobic modified nanoparticle（HMNP）and different types of surfactants and the influence of temperature and inorganic salts（NaCl，CaCl₂ ）on the stability of natural gas foam were studied by injection method. The results showed that，under the condition of pure water at room temperature of 25 ℃，the natural gas foam generated by the composite system of HMNP and anionic surfactants （sodium dodecyl sulfonate （SDS），sodium dodecyl benzene sulfonate （SDBS），sodium dodecyl polyoxyethylene ether sulfate（AES））could maintain good stability within 3000 min，and had a significant synergistic effect on stabilizing the stability of natural gas foam. Moreover，at high temperature of 50 ℃ or in the presence of mineral ions，ionic strength being of 0.2 mol/L，the polyoxyethylene（EO）group in the anionic surfactant could further enhance the stability， temperature resistance and salt resistance of HMNP/AES composite natural gas foams；the benzene ring in the anionic surfactant significantly promoted the synergistic effect of HMNP and anionic surfactant，and could significantly improve the stability， temperature resistance and monovalent ion resistance of HMNP/SDBS composite natural gas foam.

Abstract:In order to solve the problem of gas channeling in the foam flooding，the enhanced foam system was constructed by adding polymer foam stabilizer to improve the stability of the foam and optimize the foam performance，resulting in improving the application effect of the foam flooding. However，while the enhanced foam system improves the stability of the foam，it also has the problem of reducing the foaming property，so it is necessary to further clarify the applicable conditions of the enhanced foam system. Therefore，the performance evaluation of polymer PAAO-1 enhanced foam system and the experimental study of core flow characteristics were carried out in this paper. The results showed that with the increase of polymer PAAO-1 concentration，the foam volume decreased and the foam half-life time increased，and the foam composite index of the enhanced foam system was always larger than that of the polymer-free foam. The concentration of PAAO-1 was determined to be 1200 mg/L. The average foam diameter of the enhanced foam system was larger than that of the polymer-free foam system，and stronger disturbance or higher energy was needed to form a fine and uniform foam. When the displacement rate was lower，less foam was generated，resulting in lower effective viscosity of the polymer enhanced foam，as a result，the critical foaming seepage velocity was 0.12 m/d. Because of the higher strength of the liquid film of the enhanced foam system，the effective viscosity of the foam reached up to 435 mPa·s，the plugging ability of the high permeability layer was strong，and the gas channeling occur to hardly. In homogeneous cores，the enhanced oil recovery of the polymer enhanced foam was 13.67 percentage point，which was similar to that of polymer-free foam system. In heterogeneous cores，the polymer enhanced foam changed fluid fraction and enhanced oil recovery more dramatically. The polymer enhanced foam is suitable for the reservoir conditions with larger seepage velocity，wider permeability range and more serious heterogeneity，which provides a basis for the reasonable selection of foam flooding system on site.

Abstract:In order to explore the effect of cladding β-cyclodextrin（β-CD）on the viscosity and viscosity-average molecular weight of amphiphilic polymers，such as acrylamide，acrylic acid，cetyl allylammonium chloride terpolymer（APC₁₆），the viscosity variation law and influencing factors of β-CD cladding APC₁₆ solution were studied by rheometer. The characteristic viscosity of APC₁₆ inclusion system was determined by Urkovinometer，and then the viscosity-average molecular weight of APC₁₆ without intermolecular interaction was accurately calculated. The results showed that under the condition of 45 ℃ and 30 g/L salinity，the critical association concentration of APC₁₆ solution shifted to 5300 mg/L when the molar ratio of β-CD and APC₁₆ was 1∶2. When the molar ratio of β-CD and APC₁₆ was 1∶1（complete inclusion ratio），the critical association behavior of APC₁₆ solution disappeared. Under the complete inclusion ratio，the viscous flow activation energy of the cladding system was smaller than that of APC₁₆ solution when the temperature increased from 25 ℃ to 90 ℃. The viscosity of the cladding system decreased more gently with the increase of NaCl concentration，while the cladding strength increased. Accordingly，the viscosity-average molecular weight of amphiphilic polymers could be determined by the β-CD inclusion method based on host-guest interaction. The viscosity-average molecular weight of APC₁₆ was 537×10⁴ Da，while that of HPAM was 1292×10⁴ Da. When the molar ratio of β-CD and APC₁₆ was 1∶1 and 2∶1，the viscosity-average molecular weight of APC₁₆ was 341×10⁴ Da and 358×10⁴ Da，respectively. When the molar ratio of β-CD and HPAM was 1∶1 and 2∶1，the viscosity-average molecular weight of HPAM was 1223×10⁴Da and 1272× 10⁴ Da，respectively. The viscosity-average molecular weight of HPAM was consistent before and after inclusion. The effectiveness of the legal determination of molecular weight of amphiphilic polymers by the β-CD inclusion method was confirmed. A new method was provided for the contribution of hydrophobic action of amphiphilic polymers to viscosity and molecular weight determination.

Abstract:Alkylphenolpolyethoxylate（J1），α-alkenyl sulfonate surfactant（J2），dodecyl hydroxysulfobetaine（J3）and combinational surfactants（J4）were selected as oil displacing agents，in order to study the oil displacement efficiency and pore scale enhancement mechanism of emulsification viscosity reducing oil displacing agents in water flooding for common heavy oil reservoirs with different permeability. The simulation experiments of one-dimensional displacement and micro-displacement of 4 kinds of displacement agents were carried out. The mechanism of emulsifying viscosive-reducing oil displacement agent at pore scale was clarified. The results showed that reducing interfacial tension had more effect on improving oil displacement efficiency than increasing emulsification viscosity reduction. Emulsified viscosity reducing oil displacement agents relied on the synergistic effect of emulsified viscosity reducing and interfacial tension reduction，in order to significantly improve oil displacement efficiency in reservoir. The stronger the emulsification ability and lower the interfacial tension between oil and water of emulsified viscosity reducing oil displacement agents，the greater the increase in oil displacement efficiency was. When the viscosity reduction rate of chemical emulsification reached 95%，the interfacial tension between oil and water decreased by one order of magnitude from 10^-1 mN/m，the oil displacement efficiency of chemical agents in high permeability and low permeability cores increased about 10.0%and 7.8% respectively. At the initial stage of oil displacement agent injection，the displacement pressure of high permeability and low permeability core was 1/2 and 1/3 of the water flooding pressure by reducing the interfacial tension respectively，so as to improve the injection capacity. At the later stage of injection，large blocks of crude oil were emulsified to form a large number of oil droplets with different sizes，which enhanced the fluidity of crude oil and improved the efficiency of oil displacement. The viscous oil droplets formed by emulsification with relatively stable interface could temporarily block the throat of rock and the channel formed by large heavy oil and rock particles. Through the temporary plugging superposition effect，the displacement pressure in high permeability and low permeability core was 5.2 times and 32.3 times as high as that of water flooding respectively，so the injection pressure was greatly increased and then the plane sweep area was expanded. Viscosity reducing oil displacing agent could improve oil displacement efficiency and expand the sweep range at the same time. The research results pointed out the direction of research and development of water flooding agent for heavy oil，and laid a foundation for greatly improving the recovery of water flooding for common heavy oil.

Abstract:In order to obtain a strain that could produce bioemulsifier and degrade crude oil，the bacteria that could emulsify crude oil was selected using crude oil as the sole carbon source，and the production of bioemulsifiers by Pseudomonas YZ32 was optimized by adjusting the composition of the culture medium. The optimal carbon and nitrogen sources were selected based on the emulsification index and emulsifier yield. bioemulsifiers was extracted with ethanol and purified with dialysis bags，the sugar and protein content of the emulsifiers was measured，the emulsifying active substances of the emulsifiers was tested. By Mixxing bioemulsifiers with 7 kinds of different substrates and measuring the emulsification index，the bioemulsification effect of emulsifiers on different substrates was investigated. Under different conditions，the physicochemical stability of bioemulsifiers was investigated. The crude oil degradation experiments were carried out，the components of crude oil were analyzed using GC-MS to investigate the removal rate and degradation effect of strains on crude oil. The results showed that a strain of Pseudomonas YZ32 capable of emulsifying crude oil was isolated. The maximum bioemulsifier yield could be obtained using 20 g/L of sucrose and 7 g/L of sodium glutamate as carbon and nitrogen sources for YZ32. The protein content of its metabolites was 64.29% and the sugar content was 13.89%，and the emulsifying active substances were protein-like substances. The bioemulsifier had a good emulsifying effect on liquid paraffin and toluene. The bioemulsifier produced by YZ32 could maintain good stability under the temperatures of 15—80 ℃，pH value of 4—11 and salinity of 50—350 g/L. The crude oil degradation experiment showed that YZ32 achieved 60.3% removal of crude oil within 24 d with better degradation effect for C₁₁—C₂₀ components in saturated hydrocarbons and phenanthrene in aromatic hydrocarbons of crude oil. Pseudomonas YZ32 could produce stable protein based bioemulsifiers. YZ32 had a good degradation effect on crude oil and had great potential for application in the remediation of oily sludge soil.

Abstract:The use of scale inhibitors is one of the most effective ways to inhibit scale formation in oilfield oil and gas gathering and transmission systems. The traditional evaluation method of scale inhibitor does not consider whether the suspended insoluble solid particles（clay，silt，etc.）in oilfield water affect the evaluation results. Taking CaCO₃ crystallization process as the research object， the influence of suspended solid particles （calcium carbonate powder， silicon dioxide powder， calcium-based clay） in supersaturated solution on the calcium carbonate deposition process and the effect of scale inhibitor were studied by conductivity method. The experimental results showed that at the experimental temperature of 70 ℃ and speed of 250 r/min，the scale inhibition effect of the scale inhibitor in the supersaturated solution containing suspended insoluble solid particles was reduced，mainly because the suspended solid particles in the supersaturated solution would accelerate the growth rate of calcium carbonate crystals， accelerate the formation of CaCO₃ crystals，and thus affect the scale inhibition effect. This study confirmed that the conventional scaling and scale inhibition evaluation methods are not consistent with the field water quality，which is easy to lead to large errors between the evaluation results and the field test. It is necessary to carry out targeted evaluation for the field water quality.

Abstract:Emulsified asphalt has the advantages of good injection performance and high blocking strength，which has more potential for application than other chemical agent systems as a selective plugging agent in the field of oilfield recovery enhancement. In this paper，the development history as well as the application results of the domestic emulsified asphalt water plugging system were summarized. The action mechanism of emulsified asphalt plugging was overviewed by researching domestic and international literature in recent years. First，the emulsion particles in the emulsified asphalt system are captured at the pore throats through deformation，and thus the jamin effect occurred to at the pore throats，increasing the resistance to water flow. In addition，after the emulsified asphalt is broken，the asphalt undergoes agglomeration and adheres to the rock wall to play the role of water plugging. At the same time，the main factors affecting the stability of emulsified asphalt were summarized，including temperature，electrolyte concentration in the aqueous phase，pH value and asphaltene in the dispersed phase，then the mechanism of each factor affecting the stability of emulsified asphalt was discussed. Finally，the latest research progress of emulsified asphalt applied in oilfield profile control and water plugging was described in detail. The analysis showed that emulsified asphalt not only has excellent plugging effect，but also has unique plugging selectivity. In addition，emulsified asphalt can be used in field application by combining with CO₂ huff and puff or foam modulation drive. The problems and prospects of emulsified asphalt application in the field of anatomical water plugging were pointed out.

Abstract:Gas injection is often used to maintain formation energy due to the problem of leakage in fractured conglomerate reservoirs and ultra-low porosity and matrix permeability in tight reservoirs. However，due to the existence of fractures，gas channeling is serious，so it is necessary to take anti-gas channeling measures to restrain gas channeling. By combing the research at home and abroad，the characteristics of foam drive gas were analyzed from the perspective of gas-liquid differentiation and viscous fingering. The foam mainly channeled by reducing the relative permeability of gas phase，profile control，gas floating oil displacement，oil selectivity，fluidity control and emulsification. Based on the comprehensive analysis of the characteristics of gas detection and the mechanism of foam sealing and channeling，the deep sealing and channeling technologies at home and abroad， including foam anti-gas channeling technology and foam sealing and channeling system，were discussed in detail. The influence factors of anti-gas channeling measures were analyzed from six aspects：permeability range，foaming agent concentration，injection method，injection speed，oil saturation and system composition. The construction effect of foam plugging in low permeability tight reservoir was introduced. Finally，the future development direction of this kind of reservoir sealing channeling technology was proposed. Foam system played an important role in deep reservoir sealing field，especially in low permeability and tight reservoir. Its performance evaluation index and plugging effect had been significantly improved. It also had a good adaptability in high permeability，fracture and heterogeneous reservoirs.

Abstract:Asphaltene，as the most complex solid component in crude oil，is highly susceptible to various factors due to its diverse molecular structure and weight，leading to instability and deposition. In order to establish operational guidelines for avoiding asphaltene deposition in oil reservoir exploitation，a review and summary of research on asphaltene deposition experiments and simulations both domestically and internationally were conducted. Starting from the deposition stage of asphaltene，the deposition process could be divided into three stages：precipitation，flocculation and deposition. Then a brief overview of stability evaluation methods was provided. The factors affecting the deposition of asphaltene were discussed in detail from the aspects of fluid properties （including types of precipitants，crude oil components and viscosity），reservoir properties，and production processes（including temperature，pressure，flow rate and development method）. The results showed that the critical conditions for asphaltene deposition could be accurately obtained using optical microscopy and light scattering method. And then combined with thermodynamic models of asphaltene deposition（including solubility and colloid models），effective predictions could be made for asphaltene deposition during the development process. Among them，the PC-SAFT equation of state for statistical association fluid theory considered the polarity and correlation of asphaltene particles，which could relatively accurately simulate the phase behavior of asphaltene. In response to the problems in indoor experiments and numerical simulations of asphaltene deposition，the possible directions for future research on asphaltene deposition were mainly to accurately determine the molecular weight and structure of asphaltene， establish a universal asphaltene phase equilibrium equation，and clarify the mechanism and model of asphaltene deposition in reservoir rocks. This research achievement provided reference and guidance for in-depth analysis of the deposition mechanism of asphaltene，improvement of asphaltene deposition theory，and overcoming difficult and complex problems.

Abstract:Multiple and percentage are often used in daily life and work. However，wrong usages of multiple and percentage are often found in papers written in Chinese or English. To solve this problem，this paper started with the concepts of multiple and percentage，illustrated the correct usage of them through examples，and then introduced the common translation methods of multiple increase and decrease，percentage and percentage point. When expressing an increase in multiple，attention should be paid to the difference between“increase by several times”and“increase to several times”. The former emphasized the net increase， while the latter emphasized the result after increase. When expressing a reduction in multiple，fraction should be applied. There were many ways to translate multiple increase and decrease. Attention should be paid to the differences between Chinese and English ways of thinking in translation. Percentage and percentage point were both related and different. Percentage was to compare the relative degree of two indicators（division），while percentage point was to compare the absolute degree of two indicators （subtraction）. When translating multiple decrease by percentage，it was necessary to notice the difference between net reduction and reduction to a certain amount，meanwhile，correctly use the prepositions，such as by and to.