Abstract:In the exploration and development process of deep oil wells in Dabei，Keshen and Bozi blocks of Tarim oilfield， high-pressure salt water layer is often drilled，which makes the performance of drilling fluid worse or even damaged，seriously affecting the smooth drilling operation. Through testing the influence of salt water intrusion on the performance of oil-based drilling fluid，the mechanism of salt water intrusion was analyzed，and the corresponding salt water intrusion maintenance scheme was given. The results showed that the viscosity of the system first decreased and then increased due to salt water intrusion of oil-based drilling fluid. At 20% salt water intrusion，the viscosity decreased from 118 mPa·s to 96 mPa·s. At 30% salt water intrusion，the viscosity began to rise，and at 50% salt water intrusion，the viscosity exceeded the range of the viscometer. The emulsion-breaking voltage decreased gradually. When the salt water intrusion amount increased from 0 to 60%，the emulsion-breaking voltage drops from 468 V to 90 V. When the salt water intrusion was less than 10%，it was recommended to maintain normally and supplement appropriate main and auxiliary emulsifiers. When the salt water intrusion amount was 10%—30%，it was suggested that the drilling fluid should be separately treated and appropriate diesel oil and treating agent should be supplemented. When the salt water intrusion amount was above 30%，it is recommended to collect and treat drilling fluid on the ground. The reasonable choice the drilling fluid maintenance program was conducive to reducing the probability of occurrence of complex downhole conditions.

Abstract:Gas hydrate formation during deepwater drilling is a well-recognized operational hazard，and the rheological properties of drilling fluid will be changed at deepwater low temperature environment. In order to solve the problems of formation of gas hydrate and improve the rheological properties of the deepwater drilling fluid at low temperature，a water-based deepwater drilling fluid containing kinetic inhibitor was established in laboratory，composed of 3% bentonite，treated seawater，6% flow pattern modifier UFLOW， 0.05% viscosifier VIS-HX， 20% NaCl，7% polyol GLYCOL， 3% filtrate reducer Flocat and 0.5%thermodynamic inhibitor PVP. The hydrate phase equilibrium，rheology，filtration，temperature resistance，anti-contamination and inhibition of the drilling fluid was measured. The results showed that the drilling fluid could suppress the formation of gas hydrate effectively at the water depth of 2000 m and at the temperature of 3℃. Meanwhile，the drilling fluid could keep good rheological properties at low temperature and the PV，YP of the drilling fluid had little changes among the operating temperature ranges，which exhibited constant rheological properties. The drilling fluid could keep stable rheological and filtration properties after hot rolling at the temperature of 60—130℃ and possessed good anti-contamination and shale inhibitive properties，which indicated that the drilling fluid could satisfy the requirements of deepwater drilling.

Abstract:In order to meet the increasingly severe snubbing operation environment，a kind of plugging material with wide applicability and excellent performance was prepared by using polyacrylamide（HPAM），cross-linking agent Smel 30，corn starch and ammonium chloride as raw materials in the laboratory. The effects of coagulant，temperature，pH value，metal ions and simulated oil on the gelling properties of the system were studied by rheological method. In addition，the stability and breakability of the gel was evaluated. The experimental results showed that the optimal pH range of the gel system，composed of 3% corn starch， 0.5% cross-linking agent Smel 30，0.8% ammonium chloride and 1% HPAM，was 5—9，which is especially suitable for weakly alkaline reservoirs；metal ions had little effect on gelation time and gel strength. The gelation time of the gel could be controlled at the range of 6—20 h by adjusting the amount of coagulant，and the gel strength of the obtained gel could reach J level. Under the laboratory conditions，the gel could be effectively broken with ammonium persulfate within 2 h. The viscosity of the gel-breakingfluid reduced to 300 mPa·s，indicating the gel was easy for flowback.

Abstract:In order to reduce the risk of environmental protection and meet the drilling requirements of extended reach well and horizontal well，antifriction and resistance reducer NH-JZ was prepared by introducing a variety of active elements and metal elements into long chain polyhydric alcohol amine and reacting with fatty acids，and then adding compound emulsifier. The lubrication property，antiwear and antifriction property，foaming property，temperature resistance property，fluorescence level，biological toxicity and compatibility with drilling fluid of NH-JZ were studied. Finally，NH-JZ was applied in 17 wells of Sinopec and PetroChina. The results showed that NH-JZ had excellent lubrication property，antiwear and antifriction property. When 0.5% NH-JZ was added into the bentonite drilling fluid，the reduction rate of lubrication coefficient and the wear loss at room temperature was 90.41% and 99.98% respectively. When 2.0% NH-JZ was added into the weighted drilling fluid whose density was 2.05 g/cm3，the reduction rate of lubrication coefficient and the wear loss at room temperature was 86.87% and 88.52% respectively. NH-JZ could form high strength extreme pressure film，and the pressure capacity of NH-JZ was 360 kgf. NH-JZ had excellent resistance to temperature and the lubricity remained stable at 200℃. NH-JZ was non-toxic，low fluorescence，and had good compatibility with polyamine polymer drilling fluid system，polysulfonate drilling fluid system and organic salt drilling fluid system. Field application results showed that NH-JZ could significantly improve the lubricity of drilling fluid，effectively reduce the friction and torque，and could be used in extended reach directional well，directional well and long horizontal well.

Abstract:In view of the limited use of oil-based drilling fluid in environmentally sensitive areas，the biomass synthetic base fluid LAE-12 was used as the oil phase to form a biomass synthetic base drilling fluid with a density of 1.2—2.5 g/cm3 and a temperature resistance of 150℃ . The effects of the amount of each additive on the performance of drilling fluid were studied，and the temperature resistance，anti-pollution ability，inhibition and environmental protection of the drilling fluid were evaluated. The results showed that the optimum formula of biomass synthetic base drilling fluid was obtained as follows：80%—100% base fluid LAE-12，20%—0 CaCl2 aqueous solution，3%—5% organic bentonite CNL，3%—5% emulsifier SMEMUL，2%—4% wetting agent RF-1， 3% —5% filtrate reducer FA-T，3% CaO and barite. The drilling fluid had good rheology，fluid loss control ability，emulsion stability，lubricity and inhibition. The high temperature and high pressure filtration was less than 5 mL. The water pollution resistance of drilling fluid could reach 15%，drilling cuttings pollution resistance was 20%，CaSO4 pollution resistance was 15% and NaCl pollution resistance was 20%. The amount of drilling fluid adsorbed by the drill cuttings was small，and the adsorption loss rate of the drilling fluid was 60% of the oil-based drilling fluid. Drilling fluid waste could be treated as general industrial solid waste，whose comprehensive utilization cost was low. The drilling fluid was nontoxic and easy to degrade，which met the requirements of environmental protection.

Abstract:In order to study the substitution uniformity of carboxymethyl guar produced by split process，the internal cross-section element distribution of carboxymethyl guar split was analyzed by environmental scanning electron microscopy spectroscopy（ESEM-EDS），and the degrees of substitutions（DS）of different layers of carboxymethyl guar split were determined by 1H-NMR.The results showed that alkalizer NaOH diffused uniformly through the guar split，and the concentration of NaOH had no effect on its diffusion behavior. The etherifying agent sodium chloroacetate was unable to diffuse uniformly due to a large molecular. The content of sodium chloroacetate inside the split was lower than that of outside the split. The DS of the carboxymethyl guar split decreased from 0.291 for the outer layer to 0.197 for the inner layer，which revealed that the split process gave a heterogeneous product.

Abstract:In order to develop a flexible cement slurry system used for complex well cementing，the effect of powdered acrylonitrile-butadiene rubber（PNBR）on the properties of oil well cement-based composites was studied，and the micromorphology of cement sample with PNBR was observed. The results showed that surface coating of PNBR was stable，and it could reduce the water loss and improve the stability of cement slurry，while had little effect on the rheology and thickening time. After curing for 7 d，the compressive strength of cement stone with 3% PNBR was 12.9% lower than that of blank cement stone，but the flexural strength and impact strength of the samples was increased by 17.3% and 19.7%，respectively. Compared with the blank cement paste，the maximum strain of cement paste with 4% PNBR was increased by 58.1% and the elastic modulus was reduced by 49%.When PNBR was added to the cement slurry，the rubber powder was filled among the cement hydration products after the cement slurry solidification，which reduced the brittleness of the cement paste and improved the toughness of the cement paste.PNBR can be used to design flexible cement slurry system with excellent performance.

Abstract:In order to solve the problem of mechanical impurities and the secondary damage caused by direct reuse of the fracturing flowback fluid of oil and gas fields，the natural high molecular weight guar gum flocculant CG-1 was synthesized by amination cation modification reaction of guar gum with 3-chloro-2-hydroxypropyltrimethyl ammonium chloride using propylene oxide as etherification agent. The effect of the cationic degree of CG-1，CG-1 dosage，the type and dosage of coagulant and the environmental pH on flocculation performance of the system were investigated，and the treatment effect of the flocculant CG-1 system on the field neutral and acid fracturing fluid flowback fluid was investigated. The results showed that when the dosage of flocculant CG-1 with the cation degree of 14% was 0.1%，the dosage of coagulant aids B（a kind of dicarboxylic acid）was 0.2%— 0.4%，the flowback liquid was settled for 20 min and reached complete flocculation. The flocculant system had wide applicability， which had good flocculation effect on both neutral and acid fracturing fluid flowback fluid. The flowback fluid after flocculation treatment could be directly used for field fluid preparation，and the operation success rate was 100%.

Abstract:In order to overcome the problem of short crosslinking time and adsorption loss of conventional profile control system，the composite emulsion crosslinking system with multiple structure was prepared by the way of two-step emulsion，using kerosine as oil phase，crosslinking agent solution as inner water phase，polymer solution as external water phase，with Span-80 and Tween-20 being lipophilic and hydrophilic emulsifiers，respectively. According to the requirements of profile control system with controllable crosslinking time，adjustable strength and low loss in field，the delayed crosslinking，viscosity increasing and adsorption performance of the composite emulsion crosslinking system were investigated. The results showed that，compared with the uncoated crosslinking system，the crosslinking time of the composite emulsion system could be extended more than one time，reaching up to 12—48 h；under the same polymer concentration and effective crosslinker concentration，the composite emulsion crosslinking system and the uncoated crosslinking system had similar viscosity，and the complex viscosity could reach 60—700mPa·s；after adsorption treatment，the uncoated crosslinking system lost more than 25% ，while the composite emulsion crosslinking system lost only 14.4%. The experimental results of core plugging rate showed that the plugging rate of the composite emulsion crosslinking system for about 5 μm2 permeability cores could reach up to 98%，which was higher than that of the uncoated crosslinking system. The composite emulsion crosslinking system with unique multiple structural features， had good sustained-release and protection，and it could provide an effective technical means for the well profile control task.

Abstract:In order to meet the demand of heavy oil reservoir plugging control，a konjac powder gel system was prepared by using the konjac powder as the main agent，chromium acetate as the crosslinking agent，sodium lignosulfonate as the delayed crosslinking agent，sodium sulfite as the oxygen scavenger，and partially hydrolyzed polyacrylamide（HPAM）as the structural strengthening agent. The formula of this gel system was as follows 200 g distilled water + 0.5% HPAM + 0.6% konjac powder +0.7% chromium acetate +0.4% sodium lignosulfonate +0.25% sodium sulfite. The temperature resistance，salt resistance，long-term stability and plugging performance of the gel system were investigated. The results showed that when the shear rate was 10s-1，the gel viscosity at the temperature of 120℃ was 9744.77 mPa·s；and when the temperature rised to 150℃，the gel viscosity remained about 4352.36 mPa·s；when the salinity reached up to 1.4 g/L，the gel viscosity was about 10000 mPa·s；after heating at 85℃for 10 d，the gel viscosity decreased from 3023.5 mPa·s to 2350.7 mPa·s，indicating that the gel system had good temperature resistance，salt resistance and long-term stability. The plugging experiment results showed that when 0.5 PV konjac powder gel system was injected into the core of sand-filled pipe with permeability of 4.1763 μm2，the plugging rate was as high as 98.35%，and the breakthrough pressure was as high as 5.860 MPa，which indicated that the gel system had good plugging performance and was expected to be applied to plugging adjustment in heavy oil reservoirs.

Abstract:Yanmuxi Oilfield of Tuha，a high salinity，medium and low permeability reservoir，has entered the stage of ultra-high water cut development. In order to meet the technical requirements of enhancing oil recovery of oilfield，the experimental study on the effect of inorganic gel flooding and parameter optimization in high salinity reservoir was carried out taking the geological characteristics and fluid properties of reservoir of Yanmuxi oilfield as simulation objects. The results showed that when the salinity was 151453 mg/L，the core permeability of high/middle/low permeability layer was 800×10-3/200×10-3/50×10-3μm2，the slug size of the main agent，0.03 mol/L sodium silicate solution，was 0.06—0.08 PV and the injection cycle was 5—6，the utilization degree of the low/medium permeability layer in the core was higher，the water cut decreased by 10% and the oil recovery increased by above 10%. Under the condition of the same amount of main agent，compared with the "equal concentration" injection method for each round of reagents，the“incremental injection”method had better effect on the deep fluid diversion and the recovery rate increased by 1.53%. Compared with "inorganic gel "or "Cr3+ polymer gel"，"inorganic gel + surfactant" or "Cr3+ polymer gel+surfactant" had higher efficiency of oil displacement in sweep area of profile control and flooding，and the final recovery rate increased by about 4%，however，the "output/input" ratio was smaller. Compared with the "inorganic gel"，the "Cr3+ polymer gel" had a larger increase in the recovery rate of the polymer flooding，but the preparation and injection process of the polymer solution was more complex and the technical and economic effect was poor.

Abstract:As a polymer crosslinker，water-soluble phenolic resin need to cooperate with a promoter to react with HPAM to form gel at low temperature. However，the existing promoter used was not appropriate，by which the gel reaction is too fast and the gel strength is far less than that of the chromium ion gel frequently reported. To solve the shortcomings above，the promoter GY-2 was prepared with formaldehyde，weak alkali and a cationic polymer GY containing a large number of primary and secondary amines.The phenolic resin cross-linking agent FQ-1 was obtained by increasing the mole ratio of phenol to formaldehyde and reducing the reaction temperature in its synthetic process. Further，the influence of salinity on the gelation strength of HPAM/FQ-1/GY-2 gel system was studied，and the sealing ability and field application of the gel system were investigated. The cations of GY reacted withthe anions of HPAM，the free aldehyde in the crosslinking agent，and the hydroxymethylphenol with low degree of polymerization，forming the micro crosslinking structure of the reaction system by ion adsorption; the primary and secondary amines of GY with strong activity at low temperature reacted with some amides in HPAM，enhancing the covalent crosslinking activity of HPAM at low temperature; the hydroxymethylphenol of FQ-1with lower polymerization degree could slow down autopolymerization rate of the phenolic crosslinking agent resin. The gel strength of HPAM/FQ-1/GY-2 gel system was 20000—80000 mPa·s under the salinity of 3000—10000 mg/L，the gelation time was 24—120 h，and the salt resistance was good. The HPAM/FQ-1/GY-2 gel system had good application results in the field. 10 wells in the field were profile-controlled，and the average increasing oil of a single well was 350 tons in 12 months.

Abstract:In order to solve the problem of plugging in Bohai oilfield，through measuring interfacial tension，washing oil efficiency and wettability reversal properties，the surfactant with better performance was selected，the extractant with good performance was optimized by measuring the oil washing efficiency of extractant. The emulsion type oil wash agent was prepared by combining surfactant and extractant，and the compatibility，stability and wash oil Efficiency was measured and oil washing mechanism were analyzed. The results showed that the single surfactant with the best oil washing efficiency for oil sands was OP-10，being of 29.4%.The better extractants were petroleum ether and xylene，and the oil washing efficiency of the two extractants to the oil sands reached up to 80%. After combining surfactants and extractant，the oil washing efficiency could be significantly increased to 95%.The developed emulsion detergent，composed of 2% xylene，8% petroleum ether and 2%OP-10，had good compatibility，stability，possessing good application prospects.

Abstract:In order to study the interaction between CO2，rock and formation water in tight glutenite reservoir，based on the analysis results of X-ray diffraction（XRD）of whole rock in tight glutenite reservoir of M oilfield，calcite，feldspar，kaolinite and illite were selected to simulate formation conditions（70℃，20 MPa）by using supercritical CO2 high temperature and high pressure reactor. The interactions of CO2 with mineral and CO2 with formation water and mineral were studied based on the differences of X-ray diffraction pattern，scanning electron microscopy image of rock mineral，ion composition and concentration of reaction solution before，after the experiment. The results showed that only physical change occurred between dry pure CO2 and rock mineral，while obvious physical and chemical changes occurred between CO2 and rock mineral in formation water. Ion concentration in reaction solution also changed obviously. Four rock minerals were arranged according to their reaction strength with CO2 in formation water in following order：calcite > illite > feldspar > kaolinite. After CO2 injecting into reservoir，it reacted with water first，then with ions in formation water，and finally with rock minerals.

Abstract:In order to clear mechanism of CO2 flooding in Huaziping oildom of Yanchang oilfiled，the effects of CO2 on physical properties and phase states of crude oil for Huaziping chang 6 reservoir were studied by PVT and slim-tube test combined with phase simulation. PVT experiment showed that the crude oil was a typical undersaturated crude oil with a gas-oil ratio of only about 68m3/m3，indicating that the Huaziping chang 6 reservoir is short of stratum energy. However，under the condition of original formation temperature and pressure，the dissolved amount of CO2 in crude oil could reach 34.17 mol%，which could make the volume of saturated oil expand by more than 15% and the viscosity drop by nearly 50%. Moreover，CO2 had a strong extraction effect on crude oil and dissolving gas drive ability during the process of decompressive operation. The results of phase simulation and slim-tube test showed that the minimum miscible pressure of primary contact and multiple contact were 33.31 MPa and 14.27MPa，respectively. Therefore，CO2 flooding in Huaziping oildom of Yanchang oilfiled belonged to immiscible flooding，and its displacement mechanism was dominated by expansion，viscosity reduction，extraction and dissolution gas flooding.

Abstract:Asphalt deposits seriously affect the development of oilfields. In order to clarify the influence of colloid on asphaltene deposition in the process of CO2 flooding，taking simulated crude oil with different colloid and asphaltene mass concentration ratio as the research object，the microscopic visual experiments were carried out to simulate the asphaltene deposition and to analyze the change of composition，physical properties，and solid particles size，and the effect of the colloid concentration on the stability of asphaltene was explored. It is indicated that the asphaltene was wrapped in colloid with a spherical shape，which could keep asphaltene stable. When the mass ratio of colloid to asphaltene rose from 1∶1 to 6∶1，the asphaltene deposition and sedimention potential of the simulated crude oil increased first and then decreased，while the viscosity of the simulated crude oil decreased first and then increased. The viscosity was the lowest，and asphaltene deposition and sedimention potential were the largest when the mass ratio of colloidal to asphaltene was 2∶1. The asphaltene deposition was directly related to the colloid content. It was verified that there was a pair of forces between the colloid and the asphaltene—adsorption force and dispersing power. The amount of asphaltene precipitation was related to the effect of this pair of forces in the process of CO2 flooding.

Abstract:Aiming at the problem of water injection in the injection well of Longdong oilfield，the cationic-gemini surfactant compounding system XG-D was prepared using cationic surfactant cetyltrimethylammonium bromide and bisphosphonate dimeric surfactant XG as raw materials. The performance of XG-D was studied by oil-water interfacial tension and wetting performance test and indoor core flooding. Finally XG-D was applied in Longdong oilfield. The results showed that XG-D had good compatibility with simulated formation water. 0.25% XG-D could reduce the oil-water interfacial tension to 0.01 mN/m，indicating good performance on reducing oil-water interfacial tension. XG-D had better salt tolerance. XG-D could adsorbed on the surface of oleophilic mica，transforming the hydrophilic surface of solid into a weak hydrophilic surface with good conversion. The results of core flooding experiments showed that XG-D had better depressurization and injection characteristics，which could reduce the water injection pressure by 49.88% and increase the oil displacement efficiency by 6.4%. The field application results showed that XG-D could be used to achieve the pressure reduction and injection increase in the high pressure injection well of Longdong oilfield.

Abstract:In order to improve the stability of oil-in-water emulsifier for crude oil and solve the problem of demulsification，a kind of polymer emulsifier was synthesized using CO2 responsive monomer，hydrophilic polyether structure and acrylamide（AM）as skeleton. The interfacial activity，emulsification stability and the response to CO2 of the emulsifier were studied. The results showed that polymer emulsifier P-2 had the best emulsification performance，which was synthesized under the condition of room temperature and 87.0∶11.8∶1.2 molar ratio of acrylamide（AM），polyether methacrylate（PAM）and 2-（diethylamino）ethylmethacrylate（DEA）. The O/W emulsion formed by the mixture of 600 mg/L P-2 solution and oil phase had good stability and low interfacial tension. The particle size of the emulsion concentrated at about 700 nm. The emulsifier could respond to CO2 repeatedly， and the demulsification rate of emulsion after injecting CO2 and leaving 48 hrs was up to 87.3% . The CO2 responsive polymer emulsifier P-2 not only had good emulsification stability and CO2 repetitive response performance，but also could achieve rapid and efficient demulsification.

Abstract:Fracturing and imbibition was the main method to extract matrix crude oil of ultra-low permeability reservoirs. But the oil recovery rate of water imbibition was lower than economic need，while using the surfactant combination could improve the imbibition recovery factor. The influence rules of the combined surfactant system on the imbibition recovery of ultra-low permeability reservoirs were discussed by performance analysis. For the anionic surfactant HABS，nonionic surfactant APG1214 and their combination system，the osmotic bottle test was used to determine the imbibition recovery. The effects of three factors on oil recovery rate including interfacial tension between oil and formation，contact angle of cores before-and-after soaking in surfactant and the stability of emulsion were analyzed. The results showed that the imbibition recovery rate of the compound system was the highest one（10.43%），that of HABS and KCl system was 4.57% and 2.2%，and APG1214 system couldn’t extract oil by imbibition.The interfacial tension（IFT）between combination system and oil could reach 10-2 mN/m. The combination system could exchange the wettability of cores from hydrophilic to weak hydrophobic which contact angle was nearly 90o，and the system was easy to form emulsion which was easy to coalesce. In the displacement experiments，the injected pressure of combined system was the lowest one and the enhanced oil recovery rate was the highest one. Lower IFT，intermediate-wet reservoir and unstable emulsion were favorable conditions of imbibition，while the emulsion with extremely high stability was helpless.

Abstract:Adsorption retention of the polymer in the pores of the formation can lead to a decrease of the core permeability or even blockage. For the hydrophobic association polymer（AP-P4）used in the polychlorination well of Bohai SZ 36-1 oilfield，the basis of the absorbance standard curve of polymer solution was established by using ultraviolet spectrophotometer，and the effects of polymer concentration，grain size of gravel，agent sand ratio and temperature on static adsorption were investigated. By testing the core damage rate，the dynamic retention law of core permeability and polymer concentration was obtained. The results showed that the static adsorption amount of hydrophobically associating polymer increased with the increase of the concentration of injected polymer，the decline of the grain size of gravel and the increase of ratio of solution to sand. With the increase of temperature，the adsorption amount decreased gradually. The core damage rate increased with the decrease of core permeability and the increase of the polymer concentration. The damage rate of the core with permeability of 161×10-3 μm2 after flooding with 2000 mg/L AP-P4 solution was as high as 99.58%，which indicated that the hydrophobic associating polymer AP-P4 had serious adsorption retention in the core and resulted in the obvious decline of the core permeability.

Abstract:Yanmuxi oilfield of Tuha is a high salinity and mid-low permeability reservoir，which has entered the stage of ultra-high water cut development. In order to improve the oil recovery of the oilfield，the adaptability of polymer solution and reservoir was studied by taking the geological characteristics and fluid properties of the reservoir as the simulation object. The results showed that the relative molecular weight and concentration of polymer affected the compatibility of polymer solution and core. When the mass concentration of polymer was 300—900 mg/L and the relative molecular weight was 800×104—2000×104，the permeability limit of polymer solution was 20 × 10-3—70 × 10-3μm2. When the relative molecular weight of polymer was fixed，the permeability limit increased with the increase of polymer concentration，and the molecular thread size（Dh）increased exponentially. When the polymer concentration was constant，the permeability limit and Dh increased with the increase of polymer molecular weight. According to the relationship between the mid value of core pore radius and Dh，the corresponding compatibility area and plugging area could be obtained. For Yan630 block，the reservoir permeability was 60.5×10-3 μm2 when the percentage of cumulative reservoir thickness reached 60%. The requirement of entering the prescribed reservoir thickness could be met by using polymer solution with relative molecular weight of 1700×104 and concentration of 900 mg/L. If the polymer with lower molecular weight was used，the polymer concentration should be increased accordingly.

Abstract:The sewage quality of Gudong and Gudao reservoirs in Shengli oilfield significantly affected the viscosity of prepared polymer system. It was urgent to study the effects of different inherent factors on the viscosity and seek effective water treatment agent. In this work，the effects of ferrous ion/iron ion（Fe2+/Fe3+），sulfur ion（S2-）and dissolved oxygen in the injection water on polymer viscosity were experimentally studied by the measurements of viscosity and aging stability，and the upper limitation to achieve the higher polymer viscosity was determined. According to the limitation and requirement，preferentially suitable oxygen scavenger and iron remover were obtained and the applicability was further verified under field conditions. The results showed that the contents of Fe2+/Fe3+，S2- and dissolved oxygen had noticeable effect on polymer viscosity. To achieve the higher viscosity of the polymer solutions prepared on-site，the highest content of Fe2+ and Fe3+ should not exceed 0.5 and 2 mg/L，respectively. And the content of S2- and dissolved oxygen should be separately controlled within 1 and 0.3 mg/L. Moreover，with the extension of acting time，both Fe2+/Fe3+ and S2- only had slight effect on the viscosity. Thiourea and Dagang PP-I was respectively chosen as the oxygen scavenger and iron remover，which had good compatibility with the polymer and exhibited good field adaptability. By adding chemical oxygen scavenger and iron removal agent，the contents of dissolved oxygen and Fe2+/Fe3+ in injected water could be effectively controlled at a low level，so that the formulated polymer solution had a high viscosity，which was suitable for the on-site sewage dosing of oilfields in polymer and chemical flooding.

Abstract:Conglomerate reservoir has typical complex mode pore structure，strong heterogeneity and is easy to form dominant channels of different grades；hence，it is difficult to achieve the effect of expanding sweep volume by single slug and general injection method. Three-pipe parallel core displacement experiments with different injection modes，including single constant viscosity，step-by-step viscosity reduction and step-by-step viscosity increase，was carried out and the enhanced oil recovery（EOR）were investigated under the same polymer dosage. In the best injection mode，three-pipe parallel core displacement experiments were carried out at different injection cycles and injection rates. The experimental results showed that，the EOR could be increased by 13.61% by using step-by-step viscosity reduction injection mode，which was 2.31% higher than that by single constant viscosity injection mode. Under the same conditions，the EOR was not related to the number of injection cycles. At the reasonable injection rate of 1.5 mL/min，the EOR could be further increased. When EOR was similar，the polymer dosage by step-by-step viscosity reduction mode was 50% lower than that by single constant viscosity injection mode. The results of the step-by-step viscosity reduction in the filed indicated the oil production was increased and the water cut was decreased obviously.

Abstract:Due to the small space of offshore platforms and the shortage of fresh water resources，traditional powder polymer and its injection allocation are difficult to be widely applied in offshore oilfield. The emulsified polymer gel and polymer microsphere agent have the dual functions of profile control and oil displacement，which has been successfully applied in some offshore oilfield platforms. In order to further clarify the law of deep migration of profile control agents，the micro structure observation and static evaluation of emulsified polymer gel，core-shell microsphere and their composite systems were carried ont. Based on the evaluation results，the dynamic blocking experiments of 1 m and 10 m sand pipes were conducted to evaluate the effect of different profile control agents. The results showed that the structure grid of the composite agent was thicker. The core-shell microsphere was embedded in the gel grid，which made the network interweaving structure of the single layer be thicker and the gel strength be higher. Meanwhile，the breakthrough pressure of the subsequent water flooding was the highest in the long-distance migration process of the composite agent. The breakthrough pressure of 2.975 m reached 8.01 MPa，moreover，the blocking rate of the majority of the measuring points along the path was more than 90%. It indicated that the blocking performance of the composite system was better than that of the single system. The study of long-distance transport characteristics of online composite profile control agents could provide technique solution and theoretical guidance for the evaluation of deep profile control agents in offshore oilfield.

Abstract:In order to deeply understand the influence law of emulsifying ability and interfacial tension on oil displacement effect of binary oil displacement system，seven systems，including 0.3% KPS + 0.1% HPAM（a）0.5%Span/0.5%Twain+0.1% HPAM（b），0.3% ZS + 0.1% HPAM（c），0.3%YC（d），0.3% HPS + 0.1% HPAM（e），0.3% SP + 0.1% HPAM（f），0.3%ZS + 0.1%HPAM +0.4%Na2CO3（g），were selected for researching on the internal correlation between dynamic emulsification characteristics，dynamicinterfacial tension and oil displacement effect. Water-separating test and interfacial tension measurement showed that emulsification index was in range of 0 to 0.38，the interfacial tension was in range of 10-3—10 mN/m. The emulsification characteristics of thesesystem could be divided into five types：“non-emulsification”（system f），“emulsification reversal”（system e），“former-process emulsification”（system a），“rear-process emulsification”（system d）and“whole-process emulsification”（system b，c and g），interfacial tension peculiarity was divided into 7 types：“L”type（system a），“—”type（system b），“shallow dish”type（system c），“G”type（system d），“V”type（system e），“\”type（system f），“deep bowl”type（system g）. Core displacement test revealed that the stronger of emulsifying ability was，the higher recovery efficiency of the secondary water flooding had. For“\”system f with“non-emulsification”，“shallow dish”system c with“whole-process emulsion”and“G”system d with“rear-process emulsion”，the secondary water flooding recovery was 0.36%，4.25%，0%，respectively，that due to the interlaced action of the emulsify on mobility control and interfacial tension on capillary number effect. In addition，by compared the residual oil distribution after polymer and the binary compound flooding，uneven distribution of residual oil after binary flooding was found and "white spot" was prone to form because of unreasonable slug collocated，so the interfacial tension and the emulsification was not enough to offset the out of control mobility. Therefore，the displacement system with ultra-low interfacial tension and whole-process emulsion capacity should be preferred to and the fluidity control should be intensified in binary compound flooding technology

Abstract:In order to regulate the test method of interfacial tention for the non-Newtonian fluid in industry standard of the SY/T 5370—2018“Test method for surface tension and interfacial tention”，the influence factors of oil and water interfacial tension in compound flooding such as temperature，rotation speed，concentration of the non-Newtonian fluid and polymer molecular mass，testing time and surfactant concentration were regulated. It was suggested that the interfacial tension between the complex flooding and the crude oil should be measured under the optimal conditions that measurement temperature was the target reservoir temperature，the rotation speed was 5000~ 6000 r/min，at which the instrument could produce clearly image，and the polymer concentration was 0.1%，the molecular mass of the polymer should be chosen according to the property of the target reservoir，however，it was recommended to apply the polymer with the molecular mass of 10 million to 15 million during arbitration or sampling. The interfacial tension value was determined according to equilibrium interfacial tension at different time，and when retraction or fracture happened during the measurement process，the interfacial tension before retraction or fracture should be measured three times and calculated mean value. When the surfactant was evaluated，the SP flooding system of 0.2% surfactant+ 0.1% polymer was recommended，meanwhile，the ASP flooding system of 1.2% alkali+0.1% surfactant+0.15% polymer and 0.6% alkali+0.3% surfactant +0.15% polymer were recommended.

Abstract:Since bio-competitive exclusion（BCX）is low in cost，broad in processing range and simple in operation，it has becomean important technology for the management of sulfate-reducing bacteria（SRB）in the reservoir. However，the on-site injection process has remained a main bottleneck，limiting the use of BCX technology. Simulating the formation condition，the SRB inhibitor（nitrates）were injected into formation water daily or at one time during a laboratory research，which eventually facilitated the breeding of nitrate-reducing bacteria（NRB）. In this case，the amount and metabolism of SRB were under control. This research aimed to evaluate the influence of different nitrates injection on the concentration of SO42-，NO3-，NO2- and H2S and the quantities of SRB and NRB. The results showed that compared with the injection at one time，daily injection could not restrict the decrease of SO42- effectively while NO3- and NO2- remained a low level. Moreover，both methods did not produce H2S. In the early stage of management，injection at one time produced more NRB than the daily injection. In the late stage，SRB was restricted，and daily injection presented a more inhibitive effect. During the SRB management，excessive nitrate was injected in the early stage to stimulate the growth of NRB and inhibit SRB. Later，small dosage of drugs with continuous injection could be used to maintain the above inhibitive effect.

Abstract:In order to solve the problem of poor temperature and salt resistance of emulsified viscosity reducers used in chemical flooding and fracturing of heavy oil reserviors，a temperature resistant and salt tolerant emulsified viscosity reducer AFOP was synthesized using bisphenol AF（BPAF），p-hydroxybenzenesulfonic acid（PHSA）and octyl phenol polyoxylene ether（OP-10）as monomers by two steps and three stages method. The structure of AFOP was characterized by IR and GPC. The viscosity reduction effect of AFOP on several kinds of heavy oil at high temperature and high salt was investigated and compared with that of the viscosity reducer used in oil field at the same environment. The optimum synthesis conditions of AFOP was obtained as follows：monomer mass ratio of BPAF to PHSA to OP-10 was 1∶4∶6；under the alkaline condition of the hydroxymethylation stage，the reaction temperature was 80℃ and reaction time was 1.5 h；under the acid condition，reaction temperature was 80℃ and reaction time was 3 h；finally，the polycondensation reaction was carried out at the temperature of 100℃ for 6 h. In the simulated brine system with salinity of 8246 mg/L，the interfacial tension between Bohai crude oil and the AFOP solution with mass fraction of 1.0% after high temperature aging 24 h at 300℃ reduced to 10-1mN/m，and the viscosity reduction rate of heavy oil reached 98% at oil water ratio of 7∶3. AFOP had excellent temperature-resistant and salt-tolerant，and could meet the needs of heavy oil recovery in offshore high temperature and high salt reservoirs.

Abstract:In order to solve the problem of rotor coating loss and pump leakage operation after conventional acid cleaning of screw pump wells in alkali-surfactant-polymer （ASP） flooding of daqing oilfield，a neutral scale removing agent composed of organophosphate，dispersant and pH regulator was prepared. The removing effect for the field scale sample and corrosion condition for the rotor coating was studied in lab，the cleaning test was applied on the screw pump wells of Daqing oilfield. The results showed that the hard and compact scale could be changed into loose and dispersed powder，because of the good sand-carrying performance of screw pump，the removed scale particles could be lifted to the ground effectively. Since there was no hydrogen ions in the scale remover，the chrome coating of screw pump wells will not be destroyed. According to the statistical results of the scale cleaning of 17 screw pump wells，the average production current of the production wells after the measures decreased by 9.5 A. The scales on the surfaces of the stator，rotor and sucker rods of the screw pump wells were effectively removed，and all the wells resume normal production. Application showed that neutral scale remover was effective for descaling downhole equipment of screw pump wells.

Abstract:n order to prevent the formation of barium sulfate scale in the process of oilfield development and improve the temperature resistance and salt resistance of anti-scaling agent，by considering anti scaling functional group and relative molecular weight of organic matter，a new BaSO4 scale inhibitor was prepared through aqueous solution polymerization by using acrylic acid（AA），maleic anhydride（MA），2-acrylamino-2-methylpropanesulfonic acid（AMPS）and methyl methacrylate（MMA）as reaction monomer，and（NH4）2S2O8 as initiator. The proportion of raw materials was optimized，and the effects of temperature，dosage and pH value of scale inhibitor on scale prevention rate and the compatibility of scale inhibitor with formation water were studied. The results showed that when the optimal dosage of reaction monomer AA，MA，MAA，AMPS was 30%，52.5%，5%，12.5% and the dosage of（NH4）2S2O8 was 1.5% in terms of total amount of monomer，the molecular weight of the scale inhibitor was close to 9640.69，and the purity of the product was 62.3%. At the gathering and transportation pipeline temperature of 50℃，when the dosage of scale inhibitor was higher than 12.5 mg/L，it had excellent anti-scaling effect of barium sulfate. When the dosage was 100 mg/L，the scale prevention rate could reach more than 85%. The scale inhibitor had a good anti-scale effect in weak alkaline environment.The scale inhibitor had good temperature resistance and could effectively prevent the growth and adhesion of barium sulfate crystal at low concentration. The compatibility of scale inhibitor and formation water was good. The mixture of scale inhibitor and simulated formation water containing various cations could be kept at 50℃ for 24 hrs without precipitation，meeting the requirements of oilfield.

Abstract:Aimed at the problem of wellbore paraffin deposition and chemical paraffin prevention，a type of solid particle paraffin inhibitor PI-400，which could be introduced into reservoir with fracturing fluid in hydraulic，was introduced. Combined with the characteristics of high temperature and high pressure of reservoir in a block of tarim oilfield，a high temperature and high pressure circulating displacement device was designed，and the suspension property of the PI-400 in the fracturing fluid was studied，the effect of the PI-400 on the conductivity of the fracture with proppant，and the dynamic paraffin prevention effect at high temperature，high pressure and different flow rates was evaluated. The results showed that the solid particle wax inhibitor PI-400 could be uniformly dispersed and suspended in the fracturing fluid. When the closing pressure was less than or equal to 45 MPa，after adding 2% PI-400，the reduction rate of flow conductivity of proppant-added fracture was less than 8.4%，indicating that the influence of PI-400 on the flow conductivity of proppant-added fracture was small. When the crude oil was treated with PI-400 at the temperature of 120℃ and the pressure of 40 MPa for 12 min at the discharge capacity of 2，5 and 12 mL/min，respectively，the solidification point of the crude oil decreased from 25℃ to 12℃，11℃and 8.5℃，respectively，which indicated that the solid particle wax inhibitor PI-400 had excellent paraffin prevention effect. This paper not only provides effective data support for the paraffin prevention test of solid particle paraffin inhibitor in a block of tarim oilfield，but also provides a new idea for optimization of domestic oilfield chemical paraffin inhibitor and chemical paraffin inhibitor process.

Abstract:In order to solve the emulsion problem in electric dehydrator of Bohai oilfield，the origin，cause and accumulation of the emulsion was analyzed and the resolution of emulsion accumulation of was found out. The lab tests showed the emulsion was caused by the compound of the ferric iron，colloid and asphaltenes，the formed compound could be destroyed when the hydrochloric acid or THPS were added into the emulsion，as a result，the organic ferric was transformed into inorganic ferric，making the ferric dissolve into the water. The field trial showed the emulsion accumulation problem in the electric dehydrator could be resolved when the THPS was injected at dosage of 90 mg/L.

Abstract:After CO2 was injected into the formation，it dissolved in formation water and formed carbonic acid. Various chemicalreactions occurred between carbonic acid and the formation rocks. The influence and mechanism of the reaction on reservoir physical properties were analyzed，which was of great significance for CO2 flooding in low permeability，ultra-low permeability and tight reservoirs. By analyzing the reaction characteristics and mechanisms between CO2，formation water and main single minerals，complex minerals of rock，the impacts and mechanisms of physical parameters such as porosity，permeability and wettability of rock after carbonation were reviewed. The physical and chemical interactions between CO2，formation water and rock minerals of tight reservoir would affect the physical properties of reservoir，which would provide some idea for the improvement of displacement efficiency in low permeability，ultra-low permeability and tight reservoir .

Abstract:Foam flooding technology had been widely used in the exploitation process of various reservoirs due to its excellent oil displacement mechanism. However，most reservoir environments were characterized by high temperature，high salinity and low permeability，which had adverse effects on foam stability. The stability of foam was the key factor to determine the foam flooding efficiency. Nanoparticles had special surface effect，interface effect and small-size effect，which could be used as a foam stabilizer to enhance the stability of foam，thereby improving the oil displacement effect of the foam in porous medium. This paper introduced the mechanisms of nanoparticles-stabilized foam including improving the property of foam liquid film，slowing down the rate of foam disproportionation and forming compact and stable structure. And the influences of nanoparticle concentration，nanoparticle wettability，nanoparticle size，temperature，oil saturation and salinity on the stability of nanoparticles-stabilized foam were analyzed.The oil displacement mechanisms of nanoparticles-stabilized foam including increasing the interaction between foam and oil，improving foam plugging characteristics and changing reservoir wettability were summarized. Finally the research development direction of nanoparticles-stabilized foam was proposed.

Abstract:Polymer resin could overcome the problems of insufficient gas tightness and poor rheological properties of cement materials，and had become a new technology direction of chemical leak plugging in oil and gas fields. Through carding the main foreign polymer resin systems，the structure，types and evaluation indexes of resin materials，the application status of resin plugging materials on oil casing repair，proppant coating，deep profile control and water plugging，gas well pressure plugging，loss reduction during drilling，oil and gas well pipe outflow，water plugging and other aspects were summarized. The problems faced by polymer resin leaking materials were discussed which provided reference for the development of domestic chemical leak plugging technology.