Abstract:Aiming at the technical problems such as damage tendency and collapse tendency during drilling process in coal bed reservoir section，a new microfoam drilling fluid system with low-damage and high-performance was developed. The gemini anionic foaming agent（LHPF-1），zwitterionic foaming agent dodecyl dimethyl betaine（BS-12）and biopolymer thickener（XC） were compounded. The interaction between the three treatment agents on the comprehensive foam index was analyzed by using response surface optimization experiments. On this basis，the filter loss reduction agent and inhibitor were selected to determine the best formula of microfoam drilling fluid. The comprehensive performance of microfoam drilling fluid was studied. Finally，it was applied on Laochang exploration area in east Yunnan. The results showed that the best formula of microfoam drilling fluid was obtained as follows：0.25% LHPF-1，0.25% BS-12，0.25% XC，1% brown coal resin，1% polyacrylonitrile，0.2% potassium polyacrylate. The density of drilling fluid was 0.49 g/cm³，the foaming volume could reach 420 mL，and the half-life of foam could reach more than 33 h. The thickness of foam film reached 50% of the foam size，and the sealing rate and permeability recovery value of the core of coal seam were above 90% ，while it could resist 7% of rock chips and coal dust pollution. In the field application of drilling fluid，the drilling time was 4 days without any downhole complications. The average enlargement rate of well diameter was 5.9% in the whole well section，and the filtration loss was less than 5 mL. The microfoam drilling fluid had good rheology，rock-carrying，inhibition，plugging and reservoir protection effects.

Abstract:In order to develop small-sized nano-starch particle with high efficiency and low cost，ultrasonic treatment and sedimentation method were combined to prepare nano-starch particle by using the starch solution with a high concentration of 50 g/ L. And the effect of nano-starch particle on the performance of drilling fluid was studied. The results showed that the viscosity of starch solution with high concentration could be reduced by ultrasonic treatment，and the particle size distribution of nano-starch particle prepared by sedimentation method was 10—100 nm，mainly around 30 nm. Compared with the A-type structure of native starch，the formed nano-starch particle had C-type structure，and its solution could resist salt to 20 g/L NaCl at room temperature. With increasing dosage of nano-starch particle in base mud，the apparent viscosity，plastic viscosity and dynamic shearing force of drilling fluid increased，and the filtration decreased. Nano-starch particle could improve the temperature resistance of drilling fluid. The filtration of drilling fluid with the concentration of 10 g/L nano-starch particle was only 10.0 mL after aging at 150 °C for 16 h. Even if the aging time was increased to 72 h，the rheological properties of drilling fluid had a little change. The method of combining ultrasonic treatment and sedimentation method was easy to be operated，and the formed nano-starch particle additive of drilling fluid had excellent performance with a relatively low cost，which was easy to be popularized and applied.

Abstract:In view of the deficiency of environmental protection and application performance of weighting agent including barite， iron ore powder，ilmenite powder and calcium carbonate，the double-protection weighting agent was obtained by optimizing calcium carbonate weighting agent calcite，and compounded barite and calcite in mass ratio 7∶3. The performance of double protection weighting agent was optimized by particle size matching，dry activation treatment and surface coating modification. The compatibility of double-protection weighting agent with four kinds of drilling fluids and its protective effect on oil and gas reservoir were studied. It was applied on 10 wells in Dagang oilfield to evaluate its impact on the environment. The results showed that the double-protection weighting agent reduced the influence on the viscosity of drilling fluid，had good compatibility with drilling fluid，solved the problem of arsenic exceeding the standard requirements and had a good protection effect on oil and gas reservoir. The core permeability recovery value could be increased by 15.2 percentage points compared with that of barite. Field application results showed that the drilling of implementation wells was carried out safely. Compared with the average value of adjacent wells， the rate of penetration was increased by 49.18%，the average diameter expansion rate was reduced by 1.84 percentage points，and the single well in average had an oil increase of 0.60 t per meter in production zone. The heavy metal arsenic content of filter cake was less than 60 mg/kg，which met the requirements of national standard.

Abstract:In view of the problems of poor water washing resistance of inorganic salt clay stabilizer，easy adsorption and blocking of pores and poor temperature resistance of polymer clay stabilizer，a small molecular clay stabilizer （ZWS-1） with high temperature resistance was synthesized by using trimethylamine and γ-chloropropyl triethoxysilane. The anti-swelling performance and temperature resistance of ZWS-1 were evaluated. The synergistic effect of ZWS-1 and KCl was investigated. And the anti-swelling mechanism of ZWS-1 was analyzed. The results showed that the optimum preparation condition of ZWS-1 was obtained as follows：1∶1.1 the molar ratio of silane to trimethylamine，90 ℃ synthesis temperature，40 h reaction time，and 5% potassium iodide. The temperature resistance of ZWS-1 was good and the optimum dosage of ZWS-1 was 1.5%. A synergistic effect was observed between 1.5% ZWS-1 and 4% KCl，whose anti-swelling rate was 98.3%，and the water washing resistance was 91.4% at 150 ℃. ZWS-1 leaded to the agglomeration of clay particles and increased the stability of clay. The chemical bonds were formed through the dehydration condensation reaction between ZWS-1 and hydroxyl groups on the surface of clay，which played a role in stabilizing clay.

Abstract:In view of the problems of gas channeling and wellhead pressure caused by high pressure and fracturing in the development of oil and gas fields and periodicity pressure changing in gas storage，water-soluble resin（S-HR）and amines curing agent for medium temperature（CA-1）were used as the main cementitious materials and a resin-based well cementing fluid system applying to low and medium temperature was prepared. The engineering performance，anti-channeling performance，mechanical property，temperature resistance and curing kinetics of the system were studied. The results showed that the density of the resin system could be adjusted to 1.20—1.90 g/cm³ by changing the dosages of weighting agent barite and suspending agent micro-silica， and it had good flowing ability. The thickening time could be adjusted from 60 to 410 min between 60 ℃ and 90 ℃. When the displacement efficiency was 91.5%，the consolidation strength of cured resin was 3.01 MPa，the interface breakthrough pressure was more than 12 MPa，which was much higher than that of conventional cement stone under similar displacement efficiency. The compressive strength of cured resin was 53.2 MPa after curing at 90 ℃ for 24 h，and the elastic recovery rate was more than 85% after six cycles of alternating stress loading，which was better than that of conventional cement stone. The cured resin body had good temperature resistance and the initial decomposition temperature was 398 ℃. The curing kinetics equations of S-HR/CA-1 and S-HR/amines curing agent for high temperature（DCY）systems were determined by differential scanning calorimetry. The resin cementing fluid had high consolidation strength and strong deformation recovery ability at the cementing interface，which was conducive to ensuring the long-term integrity and sealing performance of cementing material，and preventing fluid channeling of oil and gas wells. The study of curing kinetics provided a theoretical reference for the research and application of this kind of resin working fluid system.

Abstract:In order to improve the temperature and shear resistance of linear gel fracturing fluid，the composite linear fracturing fluid LG-2 was prepared by using organic boron/zirconium composite crosslinking agent（FHBZ-1），partially hydrolyzed polyacrylamide （HPAM） and polyhydroxy alcohol. The crosslinking performance，temperature and shear resistance and gel breaking performance of LG-2 linear gel fracturing fluid system were evaluated. The field application was carried out on a shale gas well in the West. The results showed that LG-2 linear gel fracturing fluid had better crosslinking performance，temperature and shear resistance than HPAM/organic zirconium single gel system. The final viscosity of LG-2 linear gel fracturing fluid was 103 mPa·s after constant shearing 120 min at 110 ℃ and 170 s^-1，while that of HPAM/ organic zirconium gel was 48 mPa·s. The peak viscosity of LG-2 linear gel fracturing fluid was 448 mPa·s after constant shearing at 130 ℃ and 170 s^-1 . LG-2 linear gel fracturing fluid had low viscosity and residue after gel breaking at 60 ℃ and 90 ℃. The field test results of shale gas well showed that LG-2 linear gel fracturing fluid system had excellent performance of fracture making and sand carrying.

Abstract:In order to improve the damage of hydraulic fracturing flow-back fluid to reservoir and the pollution to environment，the surfactant EA was synthesized by bimolecular nucleophilic substitution reaction with stearic acid and N，N-dimethylaminopropylamine as raw materials and sodium fluoride as catalyst. An CO₂ responsive aqueous solution was constructed by mixing sodium salicylate and EA，which could be used as clean fracturing fluid and realize recycling. The reactivity and cyclic reversibility of EA aqueous solution and its compound system with counter ion were evaluated by rheometer. The responsive and reversible transformation mechanism were analyzed from mesoscopic and microscopic levels by electron microscope and molecular dynamics simulation. The results showed that EA aqueous solution and the compound system had good viscosity increasing characteristics to the response of CO₂ and pH value，and the viscosity reduction of system could be realized by introducing N₂ or high temperature. The solution system had high viscosity increasing rate to CO₂ response，fast responsive speed and high viscoelastic modulus，and could realize multiple reversible transformations. Molecular dynamics simulation and freeze electron microscope revealed the formation and transformation mechanism of wormlike aggregates in solution system，which provided a theoretical basis for the recycling of clean fracturing fluid.

Abstract:In order to study the influencing factors on the breaking and recycling of guar gum fracturing fluid，the influence mechanism of residual thickener and crosslinking agent on the performance of fracturing fluid prepared by flow-back fluid was studied，from the aspects of performance change，existence state and content of residual thickener and crosslinking agent in flow-back fluid. The results showed that with the increase of breaking time or dosage of breaking agent，the viscosity of guar gum fracturing fluid and the extraction time decreased，and the proportion of small molecules increased. The enzymatic breaking was selective，and the ratio of mannose to galactose remained unchanged after enzymatic breaking. The oxidative breaking was not selective. With the extension of breaking time，the content of galactose decreased，and the molecular structure changed. Galactose side chain limited the helical formation ability of mannose main chain，which led to the decrease of water solubility and the formation of flocculent precipitate. The influence of residual thickener content on the swelling of guar gum was small，but the entangling and crosslinking between long-chain guar gum molecules were affected because of the small molecule crosslinking between long-chain guar gum molecules，which led to the decrease of shear resistance of fracturing fluid. The proportion of small molecules increased in multiple cycles of breaking solution，and the viscosity of breaking solution was greater than that requirement of flow-back solution. The sugar content of residual thickener should be controlled below 0.2% when the flow-back solution was recycled.

Abstract:Aiming at the problems of incomplete gel breaking and low flowback rate of fracturing fluid after fracturing in shallow low-temperature oil and gas well，the optimum reaction parameters of three autogenous heat generation systems，including nitrite and ammonium salt，chromium trioxide and glucose，and hydrogen peroxide were selected. Under the reaction parameters，the heat generation of three systems and their influence on gel breaking performance of fracturing fluid were analyzed. The results showed that the best reaction parameter for nitrate and ammonium salt system was obtained as follows：2 mol/L activator HCl，8 mol/L heat generating agent NaNO₂ and NH₄Cl（molar ratio 1∶1）. That for chromium trioxide and glucose system was obtained as follows：1mol/L activator HCl，14% heat generating agent CrO₃ and C₆H₁₂O₆（mass ratio 1∶1）. That for hydrogen peroxide system was obtained as follows：0.3% activator MnO₂，30% heat generating agent H₂O₂. Hydrogen peroxide system had the highest heat generation，and the temperature could reach 91 ℃. In the gel breaking experiment of fracturing fluid，the adding sequence of glucose and chromium trioxide system and gel breaker ammonium persulfate had no influence on gel breaking effect of fracturing fluid. The hydrogen peroxide system should be added with gel breaker at the same time. However，for the nitrite and ammonium salt system，the gel breaker was added after the heat generation system. The nitrite and ammonium salt system was the best additive for gel breaking system of fracturing fluid and had the best gel breaking performance，which could reduce the viscosity of fracturing fluid to less than 6 mPa·s.

Abstract:In view of the high solid phase content of oil-containing sludge and the lack of treatment conditions in the Zhundong oilfield，combined with the need of cracked oil storage wells，three different strength oily sludge profile agents were prepared by adding thickening agents，cross-linking agents and curing agents，and its suspension performance，blocking performance and curing strength were evaluated. The results showed that solid-phase particles of oil-containing sludge in the Zhundong oilfield， which was smaller than 425 μm，could be carried into the formation，and the utilization rate of sludge was more than 90%. The suspension time of a sludge suspension system，composed of 30% oily sludge + 0.3% thickener was greater than 60 min. The sludge gelling system，composed of 30% oily sludge + 0.3% thickener + 0.2% crosslinker，had good temperature，salt resistance performance and shear resistance. The gel strength changed little at the temperature of 40—90℃ and beyond the mineralization degree of 50 g/L，the gel strength was 26.8 Pa·s at the formation temperature of 55 ℃. Core flow experiments showed that the gelling system had over 85% plugging rate，and over 6.8 MPa breakthrough pressure. The pressure strength of the sludge curing system，composed of 30% oily sludge + 0.3% thickener + 0.2% crosslinker + 0.6%—0.7% curing agent，was 4.6 MPa. The strength of the three sludge systems was different，and the combined use could achieve effective sealing of fractured reservoir. The oily sludge profile system was applied On-site scale for 36 wells，cumulative treatment amount of oily sludge was 31186 m³，saving sludge treatment costs of 15 million yuan，well group cumulative oil increase was 7956 tons. As a result，the oily sludge profile system not only improved the effect of oil field development，but also realized resource utilization of oily sludge.

Abstract:The vast majority of onshore oil fields have been developed by water injection and polymer injection for a long time， which leads to the development of large pore channels or high permeability bands，and the ineffective and inefficient circulation of injected water becomes more and more serious. Aiming at the technical problems of poor plugging effect of conventional profile control and water plugging agent，taking the reservoir and fluid characteristics of Western B oilfield as the research object，the basic performance，injection，plugging of starch graft copolymer gel（SGCG）was evaluated，and the stabilizing oil production and controlling water cut effect of SGCG under different factors was investigated. The results showed that the initial viscosity of SGCG was low，and the injection was good. However，the gel environment would affect seriously gelation. The larger the gelatin space， the higher the gelation strength. The sealing ability of SGCG to the high permeability core was stronger than that to the low permeability core，indicating that SGCG had less damage to the medium low permeability reservoir and had a selective sealing effect to a certain extent. In addition，it was found that the SGCG was not injected with PV，the more the better，there was a reasonable range. The highest recovery rate was obtained when injecting 0.1 PV SGCG. With the increase of gel dosage，the damage to the medium and low permeability increased，as a result，it was not conducive to the occurrence of fluid diversion. With the increase of displacement slug，the oil recovery increased gradually，however，the output-input ratio decreased gradually. The injection timing of SGCG also had an effect on increasing oil and decreasing water cut. The earlier the injection time was，the weaker the degree of heterogeneity was，the better the plugging effect was，and the higher the final recovery rate was.

Abstract:In BZ 34-2/4 Oilfield，the heterogeneity has been aggravated and the injection water circulation is inefficient after long-term water flooding. Therefore，profile control measures should be taken to improve the water flooding development effect. Based on the characteristics of BZ 34-2/4 reservoir，the gelation time and gelation viscosity of the phenolic gel were tested，the experiments of plugging and liquid flow diversion of the phenolic gel were carried out by using epoxy resin casting core and heterogeneous core experiment. The results showed that the curing agent（resorcine）and auxiliary（ammonium bicarbonate）could increase the reaction rate and gel strength of phenolic gel profile control agents. The gel strength could be improved by adding curing agents to polymer SD-201 phenolic gel profile control agent and adding curing agents and auxiliaries to emulsion polymer DW-R phenolic gel profile control agent. Compared with the polymer DW-R phenolic gel，the polymer SD-201 phenolic gel had better plugging effect and liquid flow diversion effect in porous media. When the permeability K_g of homogeneous core was from 300×10^-3 μm2 to 5400×10^-3 μm²，the plugging rate was 99.65% to 96.94%. When the permeability of heterogeneous core was 300× 10^-3/900×10^-3/2000 ×10^-3μm²，the oil recovery could be enhanced by 19.10% after the profile measurement.

Abstract:In order to clarify the feasibility of injection of profile control agent and profile control agent into target reservoir，the resistance coefficient，residual resistance coefficient and plugging rate of profile control agent and profile control agent in rock core was calculated through laboratory experiment，and the characteristics of pressure and diversion rate was analyzed，and the advantages and disadvantages of combination mode of profile control and displacement and target reservoir were determined. The results showed that at the temperature of 70 ℃ and at the injection rate of 0.9 mL/min，the adaptable permeability range of the initial low viscosity delayed crosslinking profile control agent should be between 1000 × 10^-3 μm² and 3000 × 10^-3 μm²，and the plugging rate was more than 95%，indicating that the plugging performance and fluid diversion effect was good. The adaptable permeability range of "Nano type" and "Supermolecule type A" polymer microsphere discontinuous profile control and flooding agent should be between 500×10^-3 μm² and 1000×10^-3μm² . In addition，compared to "Nano type" profile control and displacement agent，the "Supermolecule type A" profile control and displacement agent had better hydration expansion performance and deep profile control and displacement ability. With the increase of reservoir heterogeneity，the production degree of low-permeability reservoir decreased. When the permeability difference was greater than 8，the fluid diversion effect of profile control/profile control flooding combination mode was weakened.

Abstract:During the development of Bohai J Oilfield，because of the high content of microcrystalline wax，the crude oil is more sensitive to temperature and pressure，and easily precipitates and deposits during the production process，which leads to blockages in the wellbore and near-wellbore areas of production wells，and increases in bottom hole pressure，etc. This phenomenon has seriously affected the normal production of oil fields. In response to this problem，the combination of biological enzymes and chemical plugging agents was used to carry out crude oil unplugging technology research，and the compatibility，emulsification， crude oil stripping，viscosity reduction，interfacial activity，dissolution，and reservoir permeability recovery of the compound system was studied. The results showed that the 5% bio-enzyme WZ7/1% chemical unplugging agent LV compound system could reach 42.79% and 92.03% of the scale sample at the reservoir temperature（57 ℃）and 90 ℃，respectively，and the scale sample peeled off，the efficiency being of more than 80%. The viscosity reduction rate of the crude oil was 83%—92%，and the formed oil-water emulsion had higher stability and better emulsification performance. the reservoir permeability recovery physical model experiment indicating that the permeability recovery rate at temperature（57 ℃）was 43.96%，while the permeability recovery rate at 90 ℃ was 74.97%，indicating that the system had a strong ability to remove the plugging of crude oil caused by heavy component deposition in Bohai oilfield.

Abstract:In the process of oil recovery with carbon dioxide injection，carbonic acid is formed when carbon dioxide dissolves in water，which reacts with reservoir minerals，and the mineral composition of rock and physical properties of reservoir are changed. In this paper，the changes of minerals，producing fluids，microstructure and permeability of low permeability reservoir under three different injection methods of CO₂ flooding，alternate CO₂/waterflooding and CO₂ huff-and-puff were studied by laboratory experiments. The results showed that the core permeability could be increased by these three CO₂ injection methods to some degree. Among them，alternate CO₂/water flooding had the most obvious effect on the core permeability，the concentration of calcium and sodium ions of the producing fluids increased obviously and the dissolution of carbonic acid resulted in the reduction of plagioclase and calcite in the core so that the content of calcite and feldspar in the core mineral decreased. The original microstructure of rocks was dense，and the core possessed poor connectivity and poor development of intergranular pores. After the effect of carbonic acid， the microstructure of rocks was loose，and the core possessed good connectivity，well-developed intergranular pores and obvious dissolution.

Abstract:Aiming at the characteristics of high-salt reservoirs in Yanmuxi oilfield and the technical requirements for enhanced oil recovery，the development of salt tolerant surfactant and reservoir adaptability was carried out. The results showed that the nonionic surfactant composite system DW-01 had the characteristics of low interfacial tension，strong anti-adsorption ability，excellent foaming effect and high oil displacement efficiency. When the concentration of DW-01 exceeded 0.05%，the oil-water interfacial tension could achieve ultra-low interfacial tension（10^-3 mN/m）and could still reach the order of 10^-2 mN/m after three times contact with oil sands. The injection of 0.4 PV DW-01 solution with the concentration of 0.3% could enhance oil recovery by more than 8% after water flooding，indicating that DW-01 had wonderful adaptability to the target reservoir. After water flooding，the surfactant mainly flowed along the dominant channel formed by water flooding，and unaffected area of water flooding was low. Hence，the surfactant must be used in combination with other flow diversion measures to achieve better increasing oil and decreasing water cut effect.

Abstract:Modified graphene oxide nanosheets（MGONS）is a newly developed nanomaterial based on graphene oxides for EOR applications. The size and morphology of the modified graphene oxide nanosheet was examined，the oil/water interfacial tension， emulsifying properties，viscosity，rheological properties of the MGONS/polymer system was performed and the core flooding test was carried out. The results showed that the MGONS had a typical size of 217.7 nm and piled up loosely in the aqueous solution. No matter the MGONS solution or MGONS/polymer mixed system，with a very low concentration of 10 mg/L of MGONS，they could reduce the interfacial tension to 10^-3 mN/m，while the concentration of MGONS was of 50 mg/L，the interfacial tension was 10^-4 mN/m， exhibiting higher activity and the ability to uniformly distribute at the oil/water interface. The water-oil separation time prolonged with the increase of the concentration of MGONS，whether there was polymer or not，indicating that MGONS had a certain emulsifying ability. The MGONS interacted with polymer through hydrogen bond and static interaction. After adding 100 mg/L of MGONS，the viscosity of polymer solution could be increased by 60%. The core flooding test result revealed that the MGONS/ polymer mixture system could enhance oil recovery efficiency by 26.25% based on water flooding.

Abstract:In order to improve the problems of high temperature fracture，poor salt resistance and long-term stability of polymer flooding system in high temperature and high salt reservoirs，a new nano-dispersion system composed of oleic acid modified nano-SiO₂（O-SiO₂）and hydrophobically associating polymer KAPAM was developed. The viscosity，temperature resistance，salt tolerance，shear resistance，long-term stability and oil displacement effect of the nano-dispersion system were evaluated. The results showed that compared with single KAPAM solution，the three-dimensional grid structure of nano-dispersion system increased structural stability and structural resilience of the system，which improved the properties of the system. O-SiO₂ could increase the viscosity of KAPAM solution. The viscosity of nano-dispersion system composed of 0.15% KAPAM and 0.3% O-SiO₂ was the highest，and the viscosity increasing rate was 25.73%. The viscosity retention of nano-dispersion system at 90 ℃ was 89.41%. When the mass concentration of NaCl and CaCl₂ in the system was 60 g/L and 7 g/L，the viscosity retention was 72.13% and 65.74%， respectively. The nano-dispersion system could be stably dispersed for about 20 days at 90 ℃. Under the condition of 90 ℃ and salinity of 3.3×10⁴ mg/L，injecting 0.5 PV nano-dispersion system into sand filling pipe could improve oil recovery by 23.5% on the basis of water flooding，which showed good temperature resistance and salt tolerance，long-term stability and oil displacement ability.

Abstract:In order to estimate the potential of surfactant enhancing the imbibition efficiency of shale oil and to investigate its micro-mobilization characteristics in Lucaogou formation of Jimsar Sag，the imbibition efficiency of the anionic surfactant Surf-L in natural shale cores with different wettability and the change of oil saturation in different pores with time was studied by using the low-field nuclear magnetic resonance imaging（LF-NMRI）technique. The results from NMRI T₂ spectrum showed that the 0.1% surfactant Surf-L could effectively improve the core’s imbibition efficiency. For neutral wetting and homogeneity sand core S52， guar gum solution and the Surf-L guar gum solution mainly mobilized the oil in large and middle pores. Among them，the contribution rate of large pores to imbibition efficiency was the highest. The 0.1% Surf-L guar gum solution could effectively mobilize crude oil in middle and small pores，and the final imbibition of 0.1% Surf-L guar gum solution was 6.95% higher than that of guar gum solution. For oil-wetting sandy dolomite core S39，guar gum solution mainly mobilized the crude oil in large pores， while the Surf-L guar gum solution enabled to mobilize the oil in middle and small pores. The imbibition efficiency of Surf-L guar gum solution was 18.89% higher than that of guar gum solution. The imbibition process of Surf-L guar gum solution can be divided into three stages，namely early，middle and late stage. In the early stage of imbibition，the maximum contribution rate supported by middle pores was 61.7% . In the middle and late stage of imbibition，the contribution of large pores gradually increased. The imbibition equilibrium time of guar gum solution was about 51 hours while the imbibition equilibrium time of Surf-L guar gum solution was about 100 hours. Regardless of neutral wetting or oil-wetting cores，surfactant can enhance imbibition oil recovery of shale reservoir by mobilizing the oil in the middle and small pores effectively compared with the guar gum solution.

Abstract:Injection pressure rises abruptly after well washing in low permeability reservoirs，due to back flow of fluids from formation to wellbore. Aiming at this problem，a novel system of middle-phase microemulsion generated spontaneously was developed. The influence of formation water on middle-phase microemulsion system was investigated. The efficiency of displacement efficiency and the effect of decreasing pressure and increasing injection by middle-phase microemulsion generated spontaneously were also studied. Based on the parameters of water injection and the fishlike phase diagram of microemulsion，the injection process of the middle-phase microemulsion was designed. The results showed that the formula of middle-phase microemulsion was obtained as follows：1%—8% compound surfactant（3∶1 mass ratio of nonionic surfactant to anionic surfactant）， 1.5%—3.5% C₅ alcohol and 3.5% KCl aqueous solution. The middle-phase microemulsion could generate in 15—30 min. When the proportion of formation water was less than 50% in the mixture of formation water and injected agent，the effect of formation water on the solubilizing ability and low interfacial tension of oil and water in meddle-phase microemulsion was negligible. The displacement efficiency of middle-phase microemulsion was more than 99%. In the core displacement experiment，the system could reduce the water injection pressure difference by 50% ，and the effect was remarkable. According to the minimum injection parameters of middle-phase microemulsion by calculation，the near-well region as far as 3.0 m in radial direction could be cleaned. The purpose of decreasing pressure and increasing injection would be achieved.

Abstract:There are problems of high injection pressure and low recovery in the process of tight oil reservoir displacement. Olefin ester oil displacement agents was proposed to apply to the displacement development of tight oil reservoirs. Taking 9-decenoic acid methyl ester as an example，through tight core flooding experiments，the advantages of the injection pressure and oil displacement effect of olefin ester flooding agents over conventional oil flooding agents in the process of tight core flooding were studied. 9-decenoic acid methyl ester is insoluble in water and can be miscible with organic solvents such as ethanol，ether，acetic acid， etc.，and can rapidly transfer mass to the depth of the core during the displacement process. The research results showed that for the tight core with the permeability level of 0.1 × 10^-3 μm² ，the displacement pressure of 9-decenoic acid methyl ester was greatly reduced compared to conventional oil displacement agents，being of less than 1/30 of the water flooding pressure，which was suitable for the flooding of tight oil reservoirs. The flooding experiment showed that，by injecting 2 PV 9-decenoic acid methyl ester first and then water flooding，the oil recovery rate of 9-decenoic acid methyl ester flooding reached more than 80% ，and the comprehensive oil recovery rate reached more than 90%. After water flooding，0.3 PV and 1.5 PV 9-decenoic acid methyl ester slugs were injected to increase oil recovery to 20.61% and 57.52%，respectively. Ester oil-displacing agents had good injection adaptability in the development and application of tight oil reservoirs，and at the same time could greatly improve the degree of recovery，and have broad application prospects.

Abstract:In view of water sensitive heavy oil reservoirs，inhibiting the expansion of clay is the premise for effective thermal recovery. However，the mechanism of anti-clay swelling is remaining unclear after steam injection. Therefore，a scheme of inhibiting clay swelling by using Pickering microemulsion was proposed. Through the combination of Fick’s law and Langmuir adsorption theory，the mechanism of anti-clay swelling by Pickering microemulsion was quantitatively analyzed. The Pickering microemulsion was prepared by mixing hydrophobic nano SiO₂ with lauryl three methyl ammonium bromide（DTAB）. The surface tension of the microemulsion and the anti-bentonite swelling rate were determined. Then the mass ratio of SiO₂ and DTAB，and the amount of microemulsion were optimized. Additionally，the microemulsion flooding was carried out according to the best formula. The quantitative analysis of mechanism showed that it was feasible to use surface adsorption to prevent clay swelling. The best anti-swelling effect was obtained when the mass ratio of nano SiO₂ and DTAB was 1∶2 and the dosage of microemulsion was 0.6%. The best injection volume of microemulsion was 0.2 PV in sand pack flooding experiment. With increasing injection volume of Pickering microemulsion，the anti-swelling effect was enhanced，but the rate increment of water cut in outlet during sequent water flooding was also accelerated. Therefore，clay expansion should be inhibited properly in heavy oil reservoir with high permeability.

Abstract:In order to solve the problem of high development cost of heavy oil thermal recovery in Shengli oilfield，the viscosity reduction effect of a dispersive viscosity reducer L-A was investigated，the changes of molecular structure and adhesion force of heavy oil before and after viscosity reduction were analyzed. The micro-flooding mechanism was studied with microscopic visual oil displacement experimental model. The results showed that when the optimal concentration of dispersive viscosity reducer solution was 2% at formation temperature of 56 ℃，and the optimal volume ratio of viscosity reducer solution to heavy oil was 1∶6， the viscosity reduction rate reached up to 94.58%. When the viscosity reducer was mixed with heavy oil，the P—OH group and carboxylic acid —COOH in the viscosity reducer intercalated into the heavy oil molecules，as a result，the complex sheet molecular structure of gum and asphaltene was broken，and the space network structure of colloidal asphaltene was destroyed. The molecular structure became loose，the association effect was weakened，the adhesion force decreased，and the internal friction between molecules declined，which led to the viscosity of crude oil decreased obviously. On the microscopic level，the dispersive viscosity reducer L-A could disperse and separate the remaining oil from the blind end of the throat，parallel throat and small hole throat of the low permeability channel，demonstrating the ability of oil displacement efficiency and profile control.

Abstract:Ionic liquids have unique advantages as catalysts in petroleum desulfurization，especially for thiophene sulfides. In this paper，tetrahydrothiophene （THT） was selected as a model compound and hydrogen peroxide as the oxide. Using density functional theory，ionic liquid was selected as catalyst，and the catalytic mechanism in the oxidation of tetrahydrothiophene to sulfone was studied. Cationic chain length was changed，and the influence of different side chains on catalytic effect was explored. The selective complexation mode of ionic liquids with reactants and products showed that ionic liquids had stronger interaction with the oxidation product sulfone. The longer the cationic side chain，the more stable the complex structure. The charge population and the properties of Frontier Molecular Orbital of the complex showed S atom on THT had charge enrichment，while the electrons transferred from THT to the ionic liquid during the complexation process. The influence of ionic liquid on the bond energy，and charge population of the reactants was explored at molecular level. The energy barrier of the reaction process proved ionic liquid reduced the reaction energy barrier by more than 55%，and the longer cationic side chain，the more significant the effect.

Abstract:In order to accurately evaluate the oil elution ability of chemical agent and the adsorption loss of surfactant，polymer， alkali and alkali/surfactant/polymer system（ASP）in chemical flooding process，the dual polarization interferometry technology （DPI）was utilized to evaluate the oil elution ability and the adsorption characteristic of chemical agent system used in district Qidong1 of Karamay oilfield. The results showed that using the mixed solution of toluene and n-heptane with volume ratio of 1∶1 as the solvent，a crude oil film with good uniformity was obtained on the surface of silicon oxide chip under the conditions of 2000 mg/ L crude oil mass concentration，60 s homogenization time and 1000 r/min homogenization speed. When the injection time of chemical agent into the chip was 400 s，single aqueous alkali or single polymer solution could significantly reduce the mass and thickness of oil film on the chip. They had strong elution ability for crude oil. The material mass per unit area on the chip increased by 11.7% and the thickness increased by 25% after single surfactant flooding，indicating strong adsorption between surfactant and crude oil. Under the dual influence of surfactant’s adsorption and alkali and polymer’s desorption，ASP had inferior displacement efficiency. After ASP flooding，the material mass per unit area on the chip increased by 0.2% and the thickness increased by 4.43%. The four chemical agents were arranged according to the oil elution ability in following order：aqueous alkali > polymer solution > ASP > surfactant. The experiment result of core flooding with four chemical agents showed that the oil displacement efficiency of each chemical agent had good correspondence with its crude oil elution ability.

Abstract:Chemical flooding in tertiary oil recovery is the main method to increase and stabilize crude oil production in China. The development of chemical flooding is inseparable from the construction，innovation and precipitation of standardization work. In order to systematically summarize the current situation of chemical flooding technical standards in China，promote the deep integration of chemical flooding technical standards innovation and standardization construction，and lead the high-quality development，this paper analyzed the framework and content of chemical flooding technical standards，as well as the comparison of domestic and foreign technical standards and the differences of key indicators. The results showed that there were many traditional chemical flooding standards in China，such as polymer flooding and composite flooding，but lack of standard supply in emerging fields such as nano flooding and foam flooding. The evaluation system of chemical flooding technical standards in China were more perfect than that of foreign standards. Finally，the improvement and development direction of chemical flooding technical standards in China were proposed.

Abstract:Drag reducer is the key additive of fracturing fluid for unconventional reservoir reconstruction，such as tight sandstone and shale，and its performance will directly influence on the fracturing operation effect. Polymer drag reducer，surfactant drag reducer and multi-component drag reducer were introduced，and the advantages，disadvantages and research progress of the three drag reducers were analyzed. The turbulent drag reduction and drag reduction failure mechanism of drag reducer were emphatically described. The research progress of nanomaterial in fracturing drag reduction was summarized. This paper pointed out that in unconventional reservoir fracturing environment such as high temperature，high shear and complex medium，the new type of multi-functional composite drag reducer with the advantages of stability，high efficient drag reduction，low reservoir damage， strong sand carrying capacity，easy flowback and easy recycling would be an important research direction in future.

Abstract:The latest achievements in the aspects of lost circulation mechanism，types of lost circulation materials，drilling fluid formulation and technology was reviewed. In addition，the engineering methods of well prevention，such as well strengthening， and the advantages and disadvantages of the methods for determining the leakage layer was also introduced. Finally，some suggestions was given，which can be used for reference in the future.

Abstract:Through literature research，the relative concept of imbibition oil production was introduced，research results and the newest research progress of imbibition oil production method in low-permeability reservoirs were reviewed，and the development prospect of imbibition oil production in low-permeability reservoirs in lab experiments and field application was put forward.

Abstract:In the process of crude oil exploitation，due to the influence of temperature，pressure，oil phase composition variety and external fluid，the phase equilibrium state of crude oil colloid system is easy to be destroyed，resulting in continuous association and deposition of asphaltene，which brings great difficulties to crude oil extraction and post-treatment. The evaluation methods of asphaltene deposition in crude oil are reviewed，including drop diffusion method，viscosity method，optical method，conductivity method，micro analysis method，displacement experiment method and thermodynamics method. The existing problems and development trend of evaluation methods are analyzed. A universal evaluation method which can reflect the asphaltene deposition process under reservoir conditions is urgently needed. It can predict the possibility of asphaltene deposition in crude oil，and optimize the inhibition technology and unplugging technology.