Abstract:As the current temperature-salt resistance of the viscosifier of drilling mud system failed to meet the requirements of drilling operation，polymeric viscosifier ANAD was synthesized by using 2-methyl-2 acrylamidopropanesulfonicacid（AMPS），acrylamide （AM），N-vinylpyrrolidone （NVP），N，N-dimethyl acrylamide （DMAM） as monomer through free radical copolymerization technique. The orthogonal experiment design was used to optimize the reaction conditions. The chemical structure of the viscosifier ANAD was elucidated by Fourier transform infrared（FTIR）spectroscopy and nuclear magnetic resonancespectroscopy（1H-NMR），etc. The thermal stability of ANAD was assessed by thermogravimetric analysis. Finally the rheological properties of ANAD-modified water based drilling mud were evaluated，and the viscosity-increasing mechanism of ANAD was analyzed. The results showed that the optimum preparation condition of ANAD was obtained as follows：0.5% dosage of the initiator 2，2'-azobis isobutyl amidine dihydrochloride（AIBI），37.70∶31.10∶31.10∶0.10 monomer molar ratio of AMPS∶NVP∶AM∶DMAM，55℃ reaction temperature. ANAD had excellent temperature resistance. The initial decomposition temperature of ANAD molecular was up to 328℃. ANAD-modified water based drilling mud proved satisfactory resistance to thermal aging up to 230℃ or 180℃ when freed of electrolytes contamination or exposed to 15% brine. ANAD had macromolecular side chains，rigid groups and polar group sulfonic acid groups，which was superior to domestic commonly used tackifiers 80A51 in temperature resistance，salt resistance，viscosity increasing and shear resistance.

Abstract:Considering the characteristics of reservoir and open hole completion with horizontal well development in Iraq Missan oil fields，a non-gel breaking liquefiable drill-in fluid was designed. By examining the effect of addition of flow pattern regulator VIS-B，fluid loss reducing agent STARFLO and lubricant Lube on drill-in fluid performance，the basic formula of the non-gel breaking liquefiable drill-in fluid system was determined，and the anti-temperature performance，anti-formation water pollution ability，inhibition performance and completion fluid's ability to break mud cake of drill-in fluid system and its protection effect on reservoir were evaluated. The research results showed that the formula of drill-in fluid system was fresh water+0.2%NaOH+0.2% Na2CO3+16%NaCl + 3%KCl+1.0%VIS-B+ 3% STARFLO+0.5% DUALSEAL（alkalinity regulator）+5% JQWY（acid-soluble temporary blocking agent）+ 1.5% Lube+40%HCOONa（1.28 g/cm3），and the temperature resistance of the system could reach 130°C，the rolling recovery rate reached 95.34%，and it had a good resistance to high-mineralized formation water pollution. The filter cake formed by the system could be dissolved under acidic conditions and did not require gel breaking treatment. Reservoir protection effect evaluation showed that the permeability recovery rate of the formation cores fouled by this system could reach 97.58% after the matching completion fluid treatment. The drill-in fluid system did not require gel breaking treatment which could reduce operating procedures and operating costs，and improve production efficiency.

Abstract:Slickwater plays a crucial role in volumetric fracturing of shale gas reservoirs，and anionic polyacrylamide“water-in-oil” emulsion has been normally used as the drag reducer for slickwater. However，poor tolerance to inorganic salt，incompatibility with cationic clay stabilizers were evidenced in practical uses. To address these issues，a series of ampholytic polymers SCJZ were prepared by inverse emulsion copolymerization，and their solubility，drag reduction efficiency and compatibility with cationic clay stabilizers were examined. Then a slickwater system based on the ampholytic polymer drag reducer SCJZ-2 was developed，and its properties were tested prior to field applications. It was found the viscosity-average molecular weight of the polymer SCJZ-2 prepared with AM，AA，AMPS and DMDAAC mass ratio of 70∶20∶5∶5 was higher than 12 million，and the dissolution time of the polymer was less than 3 min，and SCJZ-2 could play a role in drag reduction within 30 s，which ensured the online continuous mixing of slickwater fracturing fluids. SCJZ-2 showed good compatibility with three commonly-used clay stabilizer，improved drag reduction behavior in both fresh water and synthetic formation brine，and the friction loss was around 75% at 10 m/s pumping rate. The slickwater systems prepared from either fresh water or synthetic formation brine with formulation of 0.1% SCJZ-2，0.1% choline chloride and 0.2% alkyl polyglucoside could satisfy the basic criteria of surface tension lower than 28 mN/m，volume expansion less than 3 mL and drag reduction higher than 70%，and good feedback from hydrofracking in shale gas reservoirs was attained.

Abstract:In order to meet the demands for seawater-based fracturing fluid under the temperature of 180℃，a thickener SWF-T180 of associated polymer was synthesized with acrylamide， acrylic acid， 2-acrylamido-2-methyl-propanesulfon-icacid， N-vinylpyrrolidone， dodecanol maleic anhydride sodium and N-hexadecylacrylamide as raw material， and ammonium persulfate-sodium sulfite as initiator. The increasing viscosity，salt-tolerance，swelling，temperature-resistance of SWF-T180 and the performance of seawater-based fracturing fluid prepared by SWF-T180 were evaluated. The results showed that SWF-T180 had an obvious viscosity enhancement effect. When the dosage of SWF-T180 was greater than 0.6%，the viscosity of the fluid increased rapidly. SWF-T180 had good resistance to salt，calcium and magnesium with large dissolving capacity. The viscosity of SWF-T180 after dissolving in seawater for 8 minutes reached 84.3% of its ultimate viscosity. The temperature resistance of SWF-T180 was up to 180℃. The viscosity of seawater-based fracturing fluid composed of 1% SWF-T180 and 0.6% crosslinking agent was 60—70 mPa·s under the condition of 180℃ and 90 minutes shearing time. SWF-T180 had a good shear recovery feature，which met the requirement of offshore reservoir fracturing operation at 180℃.

Abstract:In view of the problem that the traditional free radical polymerization initiation method is difficult to realize the reaction control of in-situ polymerization plugging system in the reservoir，an atom transfer radical（ARGET ATRP）initiation system was developed to replace the traditional initiator. The effects of the amount of each component including the initiator 1， 2-dibromoethane，the catalyst ferric chloride，and the complex reducing agent vitamin C on the gelation time in the ARGET ATRP initiation system were investigated. The optimal ARGET ATRP initiation system was used to evaluate the injectability and plugging properties of the in-situ polymerization gel system in the core. Experiments showed that，under the condition of 80℃，when the dosage of 1，2-dibromoethane was 0.35%—0.4%，the dosage of ferric chloride was 0.012%—0.02%，and the dosage of vitamin C was 0.18%—0.26%，the dosage of each component could be adjusted to make the gelation time of the in-situ polymerization gel system greater than 24 h，and the gel strength reached I level. When the salinity was less than 7000 mg/L，the gelation time was prolonged with the increase of salinity，while the gel strength was reduced from I level to E level. The core evaluation experiment showed that the in-situ polymerization system had good injectivity. The ARGET ATRP initiation system could initiate the cross-linking of the polymerized monomers in the core，and the overall plugging rate of the core after the gelation reached up to 77.71%. It is feasible to use the ARGET ATRP initiation system to control the gelling time of in-situ polymerization plugging system.

Abstract:In order to meet the high temperature and high salinity environment of special reservoirs，such as Qinghai and Tarim， deep oil displacement profile control agent was prepared using temperature and salt resistant polymer SD6800，cross-linking agent， improver and stabilizer. The temperature resistance，injection property，liquidity，plugging property，scour resistance and oil displacement performance of the oil displacement profile control agent were studied. Finally，field tests were conducted in Tarim oil reservoir. The research results showed that the optimum formula of the oil displacement profile control agent was obtained as follows：0.5%—2.0% SD6800，50∶1 mass ratio of SD6800 and crosslinker，0.2% improver，0.1% stabilizer. As the concentration of SD6800，cross-linking agent or improver increased，the gelation speed and the apparent viscosity increased. But if the concentration of cross-linking agent or improver was too high，the gelation was prone to cross-linking excessive and caused dehydration. The stabilizer could remove free oxygen ions and improve the stability of gel system. As the temperature increased，the gelation speed and the strength increased，but at the same time the elasticity and stability of the oil displacement profile control agent became worse. The oil displacement profile control agent could be stable for more than 60 days under the condition of 150℃ and 25×104mg/L salinity. The oil displacement profile control agent had good temperature and salt resistance，liquidity，plugging performance，and scour resistance. The field application results showed that the oil displacement profile control agent system could effectively alleviate intra- and inter-layer contradictions in the reservoir，block high-permeability channels，improve the liquid absorption profile of the reservoir，increase wellhead pressure and reduce apparent water absorption index. The effect of increasing oil and reducing water content was obvious.

Abstract:Aiming at the high temperature and high salinity oilfield with loose porosity and easy formation of large channels，the inorganic geopolymer gel plugging agent was prepared by using viscosity increasing agent montmorillonite，crosslinking agent sodium hydroxide，retarder citric acid and main agent fly ash. The gelling speed，influencing factors，temperature and salt resistance，plugging effect，liquid flow steering effect and the effect of profile control and displacement after plugging were studied. The results showed that the gelation rate of inorganic geopolymer gel increased with increasing temperature and concentration of main agent and crosslinking agent. The salinity of solution water had no effect on the gelling effect of inorganic geopolymer gel. The higher concentration of carbonate and bicarbonate in solution water would prolong the crosslinking time of polymer glue. When the permeability of rock core was greater than 18800 × 10-3 μm2，the plugging rate of inorganic geopolymer gel increased with the increase of permeability，and the plugging rate was greater than 90%. Inorganic geopolymer gel had good erosion resistance and liquid flow diversion effect. It could effectively block large pores in high permeability layer and improve the diffluence rate of low permeability core. The longer plugging length of the large pore path or super high permeability zone，the better effect of increasing oil and precipitation was. The plugging effect of inorganic geopolymer gel was better than that of conventional polymer gel and starch glue. It could be used for plugging large pores in high temperature and high salinity oilfield.

Abstract:In order to analyze and evaluate the characteristics of the component with good interfacial activity and emulsifying property in petroleum sulfonate of Xinjiang oilfield，the liquid chromatography was adopted to perform the fine components separation. The preparative column was a hydrophobic reversed phase column with diameter of 21 mm and length of 250 mm. Structural composition，interfacial activity and emulsifying property were also completed. The results showed that the petroleum sulfonate sample could be effectively separated into fourteen components with obvious structural differences，among which one component with the most excellent interfacial activity and emulsifying property was distinguished. The average molecular weight and distribution range of this component was 432.5（without Na+）and 390—470，respectively. And molecular weight distributing between 405 and 445 was prominent. The mass percentage of most excellent component in petroleum sulfonate was 20.34%. The performance of petroleum sulfonate sample could be improved through the rigorous screening and control for feedstock and production process.

Abstract:The polyvinyl alcohol-epichlorohydrin crosslinked polymer has a problem that the gelation time is short. And the dehydration rate is high and the viscoelasticity is poor under the condition of 130℃ and 22 × 104 mg/L salinity. The crosslinked polymer was modified by adding acrylamide（AM）-2-acrylamide-2-methylpropanesulfonic acid（AMPS）copolymer with different content of AMPS during crosslinking. By measuring the crosslinking time，dehydration rate and energy storage modulus，the preparation condition of the crosslinked polymer was optimized，and the stability and plugging ability of the crosslinked polymer were evaluated. The results showed that the best preparation condition of polyvinyl alcohol-epichlorohydrin crosslinked polymer was obtained as follows：8% polyvinyl alcohol，4% epichlorohydrin，1% AM-AMPS copolymer（AMPS > 70%），3% clay，and 30℃ reaction temperature. The crosslinking time of the modified crosslinked polymer was adjustable in 1—2 h，and the energy storage modulus was greater than 2000 Pa. Under the condition of 130℃ and 22×104 mg/L salinity，it had low dehydration rate and good viscoelasticity. The dehydration rate was less than 10% after polymer was soaked in brine for 90 days，and the viscoelastic coefficient was 0.07. Crosslinked polymer particle had good sealing effect on the crack，and the sealing rate could reach 92.61%. When the ratio of particle size to minimum pore throat diameter was between 1 and 2，the sealing effect of polymer particle was the best. The modified polyvinyl alcohol-epichlorohydrin crosslinked polymer had controllable crosslinking time，strong resistance to temperature and salinity and good viscoelasticity，which could be used for sealing cracks，caves and large channels with high temperature and salinity.

Abstract:In Bohai QHD32-6 oilfield，the heterogeneity of the reservoir is increasing，and the inefficient and ineffective circulation phenomenon is serious. In view of these problems，based on the reservoir rock and fluid of the oilfield as the simulation object，the new composite gel was prepared by using polymeric aluminum ferric sulfate，acrylamide，urea，initiator ammonium persulfate，crosslinking agent N，N'-methylene bisacrylamide. The dosage of each component was optimized，and the effects of shearing， formation water dilution，clay mineral，crude oil，acid solution and aging time on the gelling effect of composite gel were studied. The results showed that the components of the composite gel were arranged according to their influence on gelation time in following order：acrylamide>urea>polymeric aluminum ferric sulfate>initiator>crosslinking agent. The suitable formula of the composite gel was 3.4%—5.0% acrylamide，1.0%—3.0% polymeric aluminum ferric sulfate，0.4%—0.8% urea，0.04%—0.08% initiator and 0.01%—0.10% crosslinking agent. The initial viscosity of the composite gel was lower，but the gelation viscosity was higher，which indicated good injection and potential plugging ability. The composite gel had good resistance to dilute，shearing and oil，good stability and quick plugging removal ability. It was suitable for the profile control and plugging operation in heterogeneous oilfield.

Abstract:Aiming at the problem that the erosion resistance of the cation sand stabilizer system for weakly consolidated sandstone reservoir is poor and the effective period of sand stabilization is short，a MS type molecular film stabilizer system combining good strength of resin binder with small permeability damage of quaternary ammonium salt was developed，and the molecular structure， molecular film erosion resistance，sand stabilization and fluid seepage performance of the stabilizer was evaluated. The results showed that the MS molecular film stabilizer system had higher strength and erosion resistance，the tensile strength was of 2.5 MPa，the elongation at break was up to 112%. The MS molecular film stabilizer system had higher ability of sand stabilization. When the mass fraction of MS stabilizer was 2%，the treatment amount was 2.0 PV，and the treatment time was 8 h，the sand production was less than 0.15 g/L. The MS molecular film stabilizer system had the function of blocking water and not blocking oil. When the mass fraction of MS stabilizer was 2%，the treatment amount was 2.0 PV，and the treatment time was 8 h ，the core water phase permeability reduced from 510×10-3 μm2 to 450×10-3 μm2，while the oil phase permeability basically unchanged，being of 782×10-3 μm2. The MS molecular film stabilizer achieved in-situ stabilization of the weakly consolidated formation particles by physical adsorption and chemical cementation to prevent sand production.

Abstract:According to the technical idea of surfactant depressurizing and increasing injection technology for injection wells in oil reservoir，the technology is studied for sewage water injection wells in gas reservoir to solve the production problems of increasing pressure and reducing capacity of water injection. By studying the compatibility between surfactant and water injection and the wettability reversal，the hybrid Gemini surfactant ZS-11 was selected，the phase permeability experiments and the depressurizing and increasing injection experiments was carried out. The results showed that ZS-11 had a good compatibility and strong wettability reversal ability at high temperature（130℃）and high salinity（80000 mg/L）formation condition，which made the core wettability changed from hydrophilic wetting to neutral wetting. Displacement experiments showed that the ZS-11solution with effective content of 0.2% could increase the relative permeability of liquid phase by 21.2%—52.8%，widened the gas-liquid two-phase permeability range by 9.3%，and decreased the saturation of equal permeability point by 3.3%—6.2% for cores with water permeability of 1.42× 10-3，1.78×10-3，5.27×10-3 and 10.53×10-3 μm2，respectively. Moreover，the effect of depressurizing and increasing injection was more obvious especially for low-permeability core，decreasing amplitude being up to 41%. The experimental results provide a new idea and method for solving the production problem of high sewage injection pressure in gas reservoir.

Abstract:Aiming at the problem of the water-blocking damage in low permeability reservoirs，the method of using surfactant to change the wettability of the reservoir was proposed to achieve anti-water blocking effect in this paper. The effects of reducing the surface tension and changing the wettability of the reservoir by anionic（SDAS-1、SDAS-2）and amphoteric（SDAS-3、SDAS-4）surfactants and their complex system were investigated. The results showed the two surfactants could retard the strong water-wet surface of sandstone reservoirs；moreover，the complex system was better than single agent，and the reduction of quasi-adhesion work was obvious，showing synergistic effect. By optimizing the concentration and ratio，the constructed SDAS-3/SDAS-1 complex system could reduce the surface tension to 24.37 mN/m at low concentration，the quasi-adhesion work to 11.22，which made the hydrophilic surface of quartz transition to neutral wetting. The optimum ratio of complex system was 1∶1，the concentration of each component was 1×10-4 mol/L. It was found that the self-priming amount of the core to the optimized complex system was reduced to 0.85 g/24 h compared with 2.85 g/24 h of standard brine，and the permeability damage rate of was reduced to 21.4% compared with 73.4% of the standard brine，the time of the oil phase passing through the sand tube was 50% lower than that of the standard brine，which showed that the constructed complex system had a good anti-water blocking effect.

Abstract:It is difficult to profile the high temperature and high salinity heterogeneous reservoirs，and the ineffective water circulation in the high water-cut period is serious. In this paper， the temperature-resistant and salt-resistant poly （divinylbenzene-acrylamide）microspheres with particle diameter of 2.89—57.05 μm were prepared by emulsion polymerization with divinylbenzene and acrylamide as monomers by controlling the dosage of sorbitan monooleate span80. The surface morphology，thermal stability，dispersibility and expansibility in water and long-term thermal stability of the polymer microspheres were investigated，and the injection plugging and displacement experiments were carried out. The results showed that the temperature resistance of poly（divinylbenzene-acrylamide）microspheres was up to 370℃，and it had good dispersion performance in 2.69 × 105 mg/L mineralized water. The expansion rate of polymer microspheres with particle size of 10.81 μm was 12.85% after 24 hours at 90℃，and it had long-term thermal stability. In high temperature and high salt environment，the polymer microsphere with the particle size of 10.81 μm had good injectivity and sealing property in the core with the permeability of 1700 × 10-3 μm2； After water flooding，the injection mode of“microsphere profile control + CO2 flooding”could play the role in microsphere profile control and CO2 flooding more efficiently，and the oil displacement effect was better than that of“direct CO2 flooding”and “microsphere profile control + water flooding”，which could enhance oil recovery by 22.65% in high water cut period. Therefore，it is necessary to carry out“microsphere profile control + CO2 flooding”operations to enhance oil recovery during high water cut period in high-temperature and high-salt heterogeneous reservoirs.

Abstract:Although a remarkable oil increment has been obtained using CO2 huff-n-puff process in a shallow-buried heavy oil reservoir of Jidong oilfield，production problems especially wellbore corrosions also occur due to the long-term CO2 injection. N2 is a kind of gas with wide sources and stable properties，which can be used for energy supplement. Based on the respective properties of CO2 and N2，their mixture is then proposed as an alternative technique for enhanced oil recovery（EOR）after CO2 huff-n-puff process. In order to compare different EOR effect using different injecting gas media，CO2/N2 mixtures with five different CO2/N2 molar ratios（1∶0（pure CO2），4∶1，7∶3，1∶1 and 0∶1（pure N2））were designed in this paper，and PVT analysis and gas huff-n-puff experiments were conducted in the laboratory. PVT analysis results revealed that CO2 had a better interactions with the heavy oil compared with N2. The interactions of CO2/N2 mixture and formation oil were between CO2-oil interactions and N2-oil interactions，and the abilities of solubility，oil swelling and viscosity reduction for the mixture increased as the CO2 concentration increased.When the injection gas excessed 20 mol% and CO2/N2 molar ratio was higher than 7∶3，the viscosity reduction rate was higher up to 40%. Gas huff-n-puff experimental results showed that about 17.03% of oil recovery could be obtained after 4 cycles of 2∶1（CO2/N2 molar ratio is 4∶1）mixture injection，which was nearly the oil recovery obtained by pure CO2 injection. With such a design of CO2/ N2 ratio for the mixture，a synergetic effect could be achieved with viscosity reduction dominated by CO2 solubility coupled with energy supplement by N2 injection，which could then effectively enhance the heavy oil recovery

Abstract:The carbon dioxide gas flooding has obvious advantages in the development and utilization of low permeability reservoir，but it is easy to produce gas channeling in the process of oil displacement，which causes carbon dioxide to break through the oil-bearing area prematurely. In order to control gas channeling and improve the effect of gas flooding，a foam gel plugging system was prepared by adding foaming agent and crosslinking agent in polyacrylamide solution. Its temperature resistance was evaluated by measuring gel strength，viscosity，foam volume and half-life of foam. Optical microscope and scanning electron microscope were used to study its temperature resistance mechanism，and its plugging performance was evaluated through artificial low permeability fractured core. The results showed that under the condition of 100℃ and 10 g/L salinity，the stability of the foam gel with 0.3% polyacrylamide，0.245% phenolic crosslinking agent，0.0348% aldehydes assistant crosslinking agent，3% xanthan gum foam stabilizer，0.075% non-ionic surfactant foaming agent，and 0.4% deoxidizer thiourea was excellent，and the half-life of the gel was 10 days. The morphology of the foam gel showed that the polymer in the liquid film polymerized at high temperature to form the gel phase，and the structure of the network gel liquid membrane made the foam gel have excellent temperature resistance.The foam gel could form high-strength plugs in low permeability fracture cores，and the gas breakthrough pressure could reach 1020 kPa in the artificial low permeability fractured core with an opening of 0.1 mm. The foam gel had the ability to plug and control gas channeling.

Abstract:In order to effectively improve the oil recovery of low permeability and ultra-low permeability reservoirs in China，the idea of constructing a low interfacial tension anionic Gemini surfactant viscoelastic fluid was proposed，so as to meet the requirements of oil displacement agent to improve sweep efficiency and oil washing efficiency，good injectivity and no chromatographic separation. Based on the research of the influence of the molecular structure of anionic gemini surfactant on its solution viscosity，viscoelasticity and interfacial activity，a GCET viscoelastic fluid was constructed，and its main properties and adaptability to the reservoir environment was evaluated. The results showed that the rheology and interfacial activity of carboxylate gemini surfactant solutions was better than that of sulfonate gemini surfactant solutions；the carboxylate gemini surfactant solution with a large number of carbons in the hydrophobic chain（m=18）and a moderate number of spacers（s=3）had better rheological properties；the carboxylate Gemini surfactant solution with a larger number of carbons in the hydrophobic chain（m=18）and a smaller number of carbons in the spacer group（s=2）had a higher interface activity. Based on this，the GCTE fluid optimized for molecular structure design and construction had good viscosity behavior，viscoelasticity，interfacial activity，and adaptability to reservoir temperature and mineralization. Under simulated mineralization（12000 mg/L），the viscosity of 0.5% GCTE viscoelastic fluid was 12.68 mPa·s；the solution had good viscoelasticity，being of 0.366 <1，relaxation time being of 11.302 s；the steady state oil-water interfacial tension reached up to 2.93 × 10-3 mN/m. The GCTE viscoelastic fluid have a good application prospect in improving oil recovery in unconventional reservoirs.

Abstract:In order to obtain a internal olefin sulfonate（IOS）microemulsion system with good oil displacement performance，the optimum formula of C24-28IOS/t-pentol/Na2CO3/NaCl microemulsion was determined by orthogonal test，then the displacement mechanism of the IOS microemulsion system to five kinds of remaining oil was studied through microscopic oil displacement test， and the oil displacement effect of the system was analyzed by oil displacement experiment of low permeability core. The performance of microemulsion system was evaluated，and it was applied in Daqing oilfield. The results showed that the IOS microemulsion with 0.3% C24-28IOS，0.6% t-amyl alcohol，1.25% NaCl and 1.25% Na2CO3 was close to the mesophase state. Microemulsion could form low interfacial tension with oil，reduce residual oil saturation and improve oil recovery. Microemulsion had the function of emulsification and viscosity increasing，which could control the fluidity and expand the swept volume in the process of displacement. Meanwhile，due to the elasticity of microemulsion，its deformation micro force played an important role in improving oil displacement efficiency. The results of core flooding experiment showed that IOS microemulsion had obvious effect of increasing oil and decreasing water cut. Compared with water flooding，microemulsion had 9.16% higher displacementefficiency and 8.2% lower water cut. The injection of IOS microemulsion in the later stage of high water cut development in lowpermeability reservoir could obviously increase oil production.

Abstract:High salinity polymer-bearing reinjection water is used as injection water for chemical flooding in Xinjiang oilfield. The comprehensive performance of HPAM and hydrophobic associating polymer KYPAM prepared with polymer-containing reinjection water，including viscosity，rheology，viscoelasticity，long-term stability，inaccessible pore volume（IPV）and oil displacement performance，were evaluated. The results showed that KYPAM had better viscous，rheological and viscoelastic properties due to its special network structure. The anti-aging ability of KYPAM was better than that of HPAM. After aging for 90 days，the viscosity retention rate of KYPAM solution with the concentration of 1500 mg/L was 81.4%，while that of HPAM solution was only 40.2%. In the core permeability of 150×10-3 μm2，the IPV of 1500 mg/L KYPAM solution was 19.6%，while the IPV of HPAM solution was 22.1%. Compared with HPAM，KYPAM had a higher ability of starting relative pore-throat. In the core permeability of 150× 10-3 μm2，when 0.5 PV of polymer solution with the concentration of 1200—1500 mg/L was injected after water flooding，the oil displacement efficiency of KYPAM solution was 2%—3% higher than that of HPAM solution.

Abstract:The rheological properties（zero-shear viscosities）of aqueous solutions containing partially hydrolyzed polyacrylamide （HPAM）and poly（vinyl alcohol）（PVA）were investigated by creep tests at a total mass fraction of 0.20%，and the effect of the mass fraction of HPAM in the two polymers（RPH）and electrolyte（NaCl）concentrations（cNaCl）on the rheological properties was discussed. The interaction mechanism between HPAM and PVA was probed. The results showed that the interpolymer complex could form between HPAM and PVA via hydrogen bonds，and the PVA/HPAM complex molar ratio was about 90. At 0 0.7，no obvious viscosity effect was observed. The presence of NaCl could lead to a“viscosity increase effect”for PVA/HPAM mixed solution（RPH=0.20），suggesting that the mixing of PVA with HPAM could enhance the salt resistance of HPAM solutions. This work deepened the understanding of interpolymer interaction behavior and provided important information for the application of HPAM-based composites in the enhanced oil recovery.

Abstract:After 0.5 PV polymer flooding of Xiaermen H2IV block formation，the distribution of the remaining oil is more scattered. In order to optimize a chemical flooding method with low cost and great enhancement of oil recovery，based on the analysis of the occurrence form and crude oil composition of the remaining oil in the block，according to the effects of different chemical flooding methods on the residual oil of different forms，the multi-slug combination flooding was determined for this block. The experimental results showed that，the optimized binary composite flooding system，composed of 2000 mg/L surfactant B-2 and 1500 mg/L polymer CJ-1，had good long-term thermal stability. After aging for 360 d，the interfacial tension could still maintain the order of 10-2 mN/m，and the viscosity retention rate was above 85% . At the same polymer concentration and permeability，the injection pressure of the binary system was lower than that of the polymer. When the polymer concentration was 1500 mg/L and the surfactant concentration was 500—5000 mg/L，the adsorption capacity of surfactant in the binary composite system was lower than that of a single surfactant system. When the concentration of surfactant was higher than 1000 mg/L，the oil washing efficiency of the binary system was higher than 40%. The results of the two-layer heterogeneous core flooding experiment showed that multi-slug flooding after polymer flooding could enhance the oil recovery by 21.9%，higher than that of single polymer flooding and binary composite flooding by12.69% and 5.33%，respectively. Finally，the utilization mode of remaining oil in this block was determined as a 0.05 PV profile control—0.35 PV polymer flooding—0.15 PV binary composite flooding—0.05 PV profile control multi-slug combined displacement at low cost with polymer flooding as the main and binary compound driving and profile control as the auxiliary.

Abstract:In order to solve the problem of weak activation of conventional activators in deep reservoir，Shengli oilfield petroleum engineering technology research institute has developed a long-term functional activator with long carbon chain polymer polysaccharide as carbon source. The research on the aerobic activation，anaerobic activation and oil displacement effect of functional activator was carried out. The results showed that after the activation of functional activator，the number of bacteria was more than 5×108 cells/mL and the activation time was extended more than 60 days. The emulsification index of aerobic activated microorganism was as high as 95%. After anaerobic activation of microorganism，the gas production pressure reached 0.058 MPa. After activated by functional activator，the emulsification and gas production of crude oil by microbial metabolites were obviously improved. After the core was displaced by the functional activator，the displacement efficiency was increased by 14.1% on the basis of blank，which was 4.5% higher than that of conventional activator，the remaining oil in the core obviously migrated to the outlet end of the core. The functional activators could activate effectively the aerobic and anaerobic microorganisms to displace the crude oil with a broad field application prospect.

Abstract:The 2-D smart black nano-card is a new nanosheet material which is independently developed by the institute of enhanced oil recovery from china university of Petroleum（Beijing）. The nano-card has the advantages of small size（80×60×1.2 nm）and large specific surface area（57 m2/g）. In this paper，2-D smart black nano-card displacement experiments was carried out with different porosity and permeability two-dimensional visualized models. Through analyzing the influence factors such as core permeability， particle concentration and injection rate on oil displacement effect，the migration rules and microscopic seepage mechanism of the 2-D smart black nano-card system were studied. The experiment results revealed that the nano-card had advantage hydrophile-lipophile balance（HLB）. The wettability of the rock surface could be changed，the wedge osmotic pressure could be generated by the two-phase interface，and the microscopic cyclotron could be formed. Besides that，nano-card had enormous surface contact compared with previous spherical nanoparticles such as SiO2. Therefore，nano-card could effectively displace the remaining oil from the formation，peel off the oil film on the throat wall on micro pores，expand the sweep volume of the low permeability layer，and thus，improve the degree of the crude oil recovery.

Abstract:In order to evaluate the effect of dispersant on the stability of heavy oil accurately，the improvement effects of 5 kinds of dispersants on the stability of asphaltenes or heavy oils of Gudao and Guantao were studied. The dispersants included sulfonic acid anionic dispersant AA，Span series dispersant NA1，oleic acid，lauric acid and palmitic acid. The results showed that the dispersants had certain improvement effects on the stability of asphaltenes or heavy oils. Among them，AA and NA1 could significantly reduce the degree of asphaltene aggregation，and had the strongest stable dispersion effect on asphaltenes. The improvement effect on the asphaltene was generally better than that on the overall stability of the corresponding heavy oil. The improvement effect of dispersant on asphaltene stability increased with increasing concentration of dispersant. Asphaltene completely exposed in the system，and it was easy to interact with dispersant. The improvement effect of dispersant on the overall stability of heavy oil increased first and then decreased with increasing dosage of dispersant. There was an optimum value for the amount of dispersant. The improvement of asphaltene stability had an important impact on the overall stability of heavy oil，but that of heavy oil stability was also affected by resin，aromatics and saturation，and so on.

Abstract:In order to clarify the influencing factors of oil-water interfacial film stability of polymer flooding produced liquid in Bohai S oilfield，the influence of polymer type，mass concentration of hydrophobic associating polymer and salinity of aqueous phase on thestability of crude oil emulsion was evaluated by the characterizations of oil-water interfacial rheology，Zeta potential and interfacial tension. The results showed that compared with linear polymer，hydrophobic associating polymer had obvious thickening and viscosifying effect on crude oil emulsion in BoHai S oilfield，which could significantly change the oil-water interface electrical property，increase the oil-water interface activity，enhance the strength of oil-water interface membrane，and had better emulsion stability. At the same time，there was a linear correlation between the concentration of hydrophobic associating polymer and the interfacial membrane elasticity of the emulsion. With the increase of the polymer concentration from 0 mg/L to 800 mg/L，the interfacial membrane elasticity of the emulsion increased from 4 Pa to 17 Pa. When the mass concentration of polymer increased up to 400 mg/L，the adsorption of the polymer at the oil-water interface was close to saturation. The water phase salinity also had a great influence on the stability of crude oil emulsion. When the salinity was 0—9417.7 mg/L，the stability of the emulsion was mainly affected by the electrical properties of the interface；while when the salinity of aqueous phase was 9417.7 — 18，835.4 mg/L，the stability of emulsion was mainly affected by the structural strength of oil-water interface membrane.

Abstract:Salt content of output crude oil in Missan oilfield of Iraq is often higher than 28 mg/L stipulated in the contract，which affects the production increasing plan，and therefore the demulsifier is urgent to be optimized. Based on the crude oil treatment process in Missan oilfield，the effect of dehydration temperature and emulsification times on demulsification capability was investigated，and the evaluation conditions were determined. The optimum formula HYP-243 was developed by bottle test and electric dehydration method. Finally HYP-243 was applied in Missan oilfield. The experiment results showed that when the dosage of demulsifier was 80 mg/L，the temperature was 60℃ and the emulsification times was 150，the demulsifier HYP-243 formulated by alkylphenol formaldehyde resin demulsifer YFPC-541，phenol-amine resin demulsifier YFPG-242 and aliphatic amine demulsifier YFPC-140 in mass ratio 4∶1∶0.5，had better dehydration performance than demulsifier RP-968，such as faster dehydration rate，higher final dehydration volume and cleaner water quality. The field test results showed that better salt leaching effect was achieved when the dosage of HYP-243 was 75 mg/L. The average salt content in outer wash tank site decreased from 573 mg/L to 358 mg/L，and that in output crude oil decreased from 36 mg/L to 22 mg/L，even if the dosage was reduced by 10 mg/L. The results showed that HYP-243 could meet the requirements that the salt content of output crude was lower than 28 mg/L，which was helpful for the high and stable production.

Abstract:In order to meet the harsh mining conditions of high temperature and high salinity in Northwest China oilfield，a quinoline quaternary ammonium salt corrosion inhibitor QA was synthesized. The structure of the synthesized samples were analyzed by infrared spectroscopy，the corrosion inhibition effect of the corrosion inhibitor QA under high temperature and high Cl- concentration condition was evaluated by high temperature and high pressure dynamic reactor experiment. In addition，the corrosion inhibition mechanism of QA was probed by the molecular dynamics simulations experiments. The results showed that the inhibition efficiency of quinoline quaternary ammonium salt QA on N80 and P110 steels was above 92% at 140°C and Cl- concentration of 30， 000 mg/L，exhibiting good corrosion inhibition effect. In addition，molecular dynamics simulations showed that the corrosion inhibitor could replace the Cl- on the metal surface，reduce the contact between the metal and Cl-，and delay the corrosion reaction of Cl- on the metal surface. At the same time，the presence of the corrosion inhibitor QA could reduce the adsorption energy of Clon the metal surface，so it could delay the Cl- corrosion effect on metal corrosion，as a result，the QA played a higher inhibition effect.

Abstract:EM50 polymer used in slickwater as drag reduction agents（DRA）makes the treatment of the fracturing flowback fluid more difficult. In this paper，Ligand-Fenton composed of environment-friendly chelating agent tetrasodium iminodisuccinate（IDS） and Fenton was used to reduce viscosity of EM50 solution. On the basis of single-factor design，response surface methodology （RSM）was used to research the best level and mutual effect of n（IDS）：n（Fe（Ⅱ）），Fe（Ⅱ）and H2O2 dosage affected on viscosity-reducing rate. The results showed that under neutral pH，the order of three influencing factors on the viscosity-reducing rate was n（IDS）∶n（Fe（Ⅱ））>Fe（Ⅱ）dosage>H2O2 dosage. Among these factors，Interaction between n（IDS）∶n（Fe（Ⅱ）），Fe（Ⅱ） had a signifigant impact on the oxidation efficiency. the predicted optimal conditions was obtained as follows：n（IDS）∶n（Fe（II）= 1.4，c（Fe（II））=0.3 mmol/L and φ（H2O2）=0.5%. Under this conditions，the average viscosity-reducing rate of the EM50 solution with mass fraction of 0.1% was 84.01%，which is compared with resulting in a final response，the relative deviation to the predicted value was 2.62%，indicating that the model was reliable and accurate. When being treated using chemical coagulation after viscosity reducing，the removal rates of SS and COD in fracturing fluid recovery were 94.9% and 89.2%，respectively

Abstract:The detection of nanoscale polymer microspheres in oilfield injection-production fluids is of great significance to the study of water shutoff and profile control mechanism of nanoscale polymer microspheres. However，there is still no report on this aspect. In this paper，a convenient，rapid，and accurate method for the determination of polymer microspheres in oil field injection and production fluids was developed by using high performance liquid chromatography with carefully selecting appropriate detectors，chromatographic columns and mobile phase conditions. Using a double hydroxyl hydrophilic column and 250 mg/L NaH2PO4 aqueous solution as mobile phase，the standard curve of concentration of nanoscale polymer microspheres-peak area of nanoscale polymer microspheres chromatography（retention time at 1.1 min）was drawn. The concentration of nanoscale polymer microspheres could be obtained by substituting the peak area of chromatographic peak at the retention time of 1.1 min into the standard curve. The linear range of the established detection method was 10—2000 mg/L，and the minimum detection quantity was 5 mg/L. The method had very good intraday and daytime precision（RSD<5%）and labeled recovery（>90%），which could be used for the rapid and accurate detection of nanoscle polymer microspheres in the injection and production fluids of actual oil fields.

Abstract:Foam profile-controlling and flooding system has the advantages of wide source，low cost，low damage and selective plugging ability，which can effectively improve the heterogeneity and enhance oil recovery. The current foam profile-controlling and flooding system consisted of conventional liquid foam，polymer enhanced foam，gel enhanced foam and particle enhanced foam. The characteristics of different types of foam system，the mechanism of enhancing foam stability and the percolation law of foam in formation were summarized. The field application of foam profile-controlling and flooding system was introduced. The problems and research direction of foam profile-controlling and flooding system were pointed out.

Abstract:Ionic liquid has the characteristics of low toxicity，no-corrosion，high solubility in water and organic liquid，and resistance to harsh environment. It is widely used in various fields of petroleum industry，but it is relatively less used as flooding chemical agent. This paper introduced the influencing factors，advantages and disadvantages of ionic liquid as surfactant in flooding，as well as its synergistic application with various oil displacement agents，and pointed out the development direction of ionic liquid surfactant and the problems to be solved in the future research process.

Abstract:Steam-assisted gravity drainage（SAGD）technology is widely used in the production of ultra-heavy oil，but there are problems such as severe steam channeling and low heat utilization during the development process. By summarizing the current main technical methods to improve the development effect of SAGD，such as gas-assisted SAGD technology，solvent-assisted SAGD technology，foam-assisted SAGD technology and chemical additive-assisted SAGD technology，the mechanism of improving SAGD technology and the effect of improving recovery efficiency were introduced. The existing problems and suggestions for use were put forward. The differences between reservoir geological conditions and construction conditions should be considered comprehensively，and different auxiliary SAGD technologies should be selected to maximize the economic benefits.