Abstract:In order to improve the wellbore instability caused by mudstone hydration and slurry making in Huizhou 25-8 oilfield in the eastern South China Sea，and the sand-carrying problem affected by the thickening of drilling fluid，the development of composite salt cationic polymer drilling fluid was carried out on the basis of existing mature PLUS/KCl drilling fluid research. The formula of drilling fluid was optimized，and the rheology，inhibition，plugging and lubricity of the optimized drilling fluid were evaluated. Finally，it was applied in Huizhou oilfield. The results showed that in the formula of composite salt cationic polymer drilling fluid，the appropriate dosage of inorganic salt inhibitor，such as KCl and NaCl was 3% and 12%，and that of organic cationic polymer inhibitor PF-CPI was 2.0%. The drilling fluid had strong inhibitory property，whose anti-swelling rate was as high as 93.32%，and the drill cutting recovery rate was 87.56%. The rheological properties of the drilling fluid after being invaded by drill cutting fluctuated little. The drilling fluid still had a low viscosity and suitable cutting force，which was beneficial to carry sand in highly deviated wells.Furthermore，the plugging property and lubricity of this drilling fluid were better than that of PLUS/KCl drilling fluid system. When the drilling fluid was applied in two wells on site，the rheology was good，the average tripping speed increased，and the drilling process was smooth without complication. The composite salt cationic polymer drilling fluid could improve the stuck problem of drilling in highly deviated well in the South China Sea.

Abstract:Aiming at the reservoir characteristic and damage mechanism in low permeability gas reservoir of western Sichuan，a reservoir protective agent SMRP-1 was prepared by grafting partially crosslinked polymer onto the surface of rigid particle of heavy calcium carbonate. The low damage drilling fluid was prepared by compounding SMRP-1 with wellbore repairing and strengthening agent. The permeability resistance，acid solubility and compatibility between SMRP-1 and common water-based drilling fluid system were evaluated in laboratory，and the performance of low damage drilling fluid was investigated. The application of MRP-1 in Jiangsha 209HF well of continental low permeability gas reservoir in western Sichuan Basin was carried out. The results showed that the permeability resistance and acid solubility of SMRP-1 were good. SMRP-1 had little effect on the rheology of water-based drilling fluid and had good compatibility. The low damage drilling fluid had good performance of resistance to permeability and calcium ion pollution. The acid solubility of filter cake formed by drilling fluid containing 3% SMRP-1 in 15% HCl for 4 hours was 27%，showing good acid solubility. The reservoir protection effect of low damage drilling fluid was good. The average permeability recovery value of core was 89.59% after blockage removal. In the field application，the low damage drilling fluid had stable performance and good reservoir protection effect. The low damage drilling fluid system had strong wellbore stability and reservoir protection ability，and had a good effect on reducing the penetration effect of liquid phase in drilling fluid.

Abstract:Aimed at the problems of non-ideal rheological property，high filtration，insufficient stability，poor compatibility with conventional additives，great damage of filtrate to reservoir permeability in the application of environment-friendly water-based drilling fluids，a natural biodegradable polymer-modified tamarind seed polysaccharide（M-TSP）was prepared using maleic anhydride，tamarind seed polysaccharide（TSP）and triethylamine as main raw materials. M-TSP was added to the bentonite suspension with mass fraction of 4.5% to obtain polymer bentonite suspension，the rheological property，stability，filtration，compatibility，and damage to the core of polymer bentonite suspension were carried out. The results showed that the bentonite suspension added with 1% M-TSP had good rheological property and stability. bentonite suspension added with 1% M-TSP had good compatibility with the conventional additives of environment-friendly drilling fluids. when adding 1% M-TSP，the initial filtration time of the polymer bentonite suspension was 121 s and the filtration was only 1.7 mL within 30 min，showing good filtration loss performance. The damage rate of M-TSP to sandstone core was only 2.06%— 3.23%，indicating that M-TSP had less damage to core. The M-STP is promising to be applied in environment-friendly water-based drilling engineering.

Abstract:In order to improve the water-locking damage of low permeability oil and gas reservoir，polyol and fatty acid were used as main raw materials to prepare non-ionic surfactant. The surfactant product was mixed with dispersant and stabilizer to prepare a waterproof lock agent system. The structure of the surfactant was characterized by infrared spectroscopy，and the particle size distribution，surface tension，thermal stability of waterproof lock agent system and the effect on contact angle of shale core were studied. The results showed that the thermal decomposition temperature of the surfactant was 218℃，and the dispersion in water reached micro-nano level. At 80℃，the surface tension of the waterproof lock agent system solution was reduced to 19.68 mN/m， and the critical micelle concentration was 80 mg/L，indicating good salt resistance. After shale cores were immersed in an aqueous solution of waterproof lock agent system for 4 hours at normal temperature and pressure，the contact angle of clean water on the core surface increased from 46.1° to 80°—130°. After the waterproof lock agent system was aged at 120℃ for 8 hours，the contact angle of water on the core surface could still reach 103.9°. The waterproof lock agent system had good high temperature resistance， salt resistance and waterproof lock performance，and could be used to improve the water lock damage of low permeability oil and gas reservoir.

Abstract:In order to improve the large torque and high friction during drilling of extended reach well in Bohai region，and meet the discharge requirement of drilling fluid treatment agent in this area，an environmentally friendly and non-toxic high-efficiency anti-friction lubricant Biolube was studied indoors. The extreme pressure lubrication，anti-wear and drag reduction，compatibility， anti-pollution ability and biological toxicity of Biolube were studied，and it was applied on two extended reach wells in the southern Bohai Sea. The results showed that the lubricant Biolube prepared with vegetable oil，low-carbon alcohol，fatty acid，polyether and nanomaterial as raw materials had better lubricating properties than similar lubricants，and had good compatibility with drilling fluid without foaming. When the dosage of Biolube was 2%，the lubrication coefficient in fresh water base slurry，seawater base slurry and drilling fluid was 0.018，0.030 and 0.07，respectively. The drilling fluid with Biolube had a wear resistance of more than 10 weights with small and uniform wear scar，indicating significant effect of anti-wear and drag reduction. It had a strong resistance of drilling cuttings and lubrication effect. Lubricant Biolube was non-toxic and biodegradable，meeting the environmental protection requirement of the Bohai Sea. The field application results showed that after adding Biolube，the torque value significantly reduced， the drilling process was successful，and there were no problems such as holding torque and difficulty in backreaming，which shortened the drilling cycle. The lubricant was safe and environmentally friendly. It did not produce floating oil，and could effectively improve the frictional resistance of contact surface between drilling tool and borehole wall.

Abstract:In view of the problems of polymer tackifier，such as degradation failure in high temperature and high salt environment and difficulty in field maintenance，the polymer tackifier DQVIS with high relative molecular weight was synthesized by inverse emulsion polymerization with acrylamide，2-acrylamido -2- methylpropanesulfonic acid，N-vinyl pyrrolidone，white oil and matching emulsifier as main raw materials. The anti-aging，viscosity increasing and fluid loss reducing properties of the agent were evaluated，and the effects of the tackifier DQVIS on the performance of the deep water-based drilling systems were evaluated by replacing the tackifier in the original system with DQVIS. The results showed that DQVIS had outstanding temperature resistance，and the viscosity retention rate of DQVIS solution with mass fraction of 1% could still reach up to 72% after aging at 180℃ for 16 h，which could meet the requirements of viscosity enhancement in deep well drilling. DQVIS had excellent filtration reducing ability. When adding 0.6% DQVIS into fresh water-based mud，salt water-based mud and saturated salt water-based mud，the filtration loss before and after aging at 180℃ was 6.8 mL/8.2 mL，8.0 mL/14.8 mL and 10.0 mL/15.8 mL，respectively. DQVIS had good compatibility with other treating agents in the deep water-based drilling system，the dosage was small and the dissolving speed was fast，morever，DQVIS could especially meet the requirements of construction in winter.

Abstract:In order to develop a fracturing fluid system compatible with the formation treated by long-term CO2 flooding，a novel organic zirconium cross-linker，which could be cross-linked with carboxymethyl hydroxypropyl guar under acidic condition ranging from pH 1 to 6，was synthesized and screened through orthogonal design experiments using zirconium oxychloride，ethylene glycol，lactic acid，and ammonium chloride as main raw materials. The gelation time，gel strength，rheological performance， proppant-settling and gel breaking performance，microstructure and the damage to the fromation of the zirconium-CMHPG crosslinked gel acidic fracturing fluid were systematically evaluated. The results showed that the delay performance of the organic zirconium cross-linker was desirable with the gelation time of 1 to 3 min even at a low pH of 1 to 2. The gelation time shortened and gel strength increased with the increase of polymer and cross-linker concentrations. The gelation time and rheological performance of the gel system could be optimized to meet the specific fracturing operations at the polymer concentration of 0.2%—0.7% and the cross-linker concentration of 0.03%—0.06%. The gel system had a desirable shear recovery performance，a uniform and compact 3D network structure was generated within the gel，and the proppant-settling and gel breaking performance were satisfied at the pH of 1—3. The gel system could be applied in the reservoir with formation temperature of less than 145℃. the low pH fracturing fluid system produced a better return permeability than the high pH system. The damage of the acidic fracturing fluid to the formation was lower than that of the alkaline fracturing fluid.

Abstract:In Changqing oilfield，there is a wide variety of additives for acidizing liquids，which makes it impossible to apply immediately on-site after mixing. To improve this problem，two kinds of amphoteric surfactants，CQYS-1 and CQYS-2，were prepared from oleic acid and N，N-dimethyl-1，3-propanediamine，and compounded with multi-alkyl pyridine quaternary-ammonium-salts to form thickening agent. As the sole additive of the acid，this compound thickening agent was added to 15% HCl solution in proportion of 2.2%—2.6% to prepare diverting acid. The formula of thickening agent was optimized，the properties of diverting acid were studied，and the application was carried out in Sulige gas field of Changqing oilfield. The results showed that the optimum mass ratio of CQYS-1，CQYS-2 and corrosion inhibitor was 67.2∶12.8∶20. The thickening agent quickly dispersed or dissolved when exposed to water，and immediately became sticky when exposed to acid. The thickening rate was over 95% of the acid system when the temperature ranged from 0 to 30℃. The diverting acid had good resistance to high temperature and shearing. When the dosage of HCl was 15%，fresh acid viscosity was around 60 mPa·s. It rose to 110 mPa·s when the dosage of HCl decreased to 8% —10% . Finally，the acid viscosity decreased to below 5 mPa·s when the dosage of HCl was less than 6% . Intelligent steering and intelligent breaking were realized during the reaction between acid and rock. In the core flooding experiment，the permeability of core increased remarkably after diverting acid flooding. This diverting acid was successfully applied to a total of 15 wells in Sulige gas field of Changqing oilfield. The on-site application immediately after mixing was realized，indicating obvious diverting effect.

Abstract:With the increasing of water flooding in oilfields，the increase of reservoir heterogeneity and comprehensive water cut seriously restrict the production of crude oil. Water shutoff acidification can effectively plug the high permeability layer，improve the available reserves of the low permeability layer，make the acid evenly distributed in the formation，alleviate the contradiction between layers. The oil-soluble plugging agent YDJ-1 with selective plugging was prepared by optimizing water-plugging and oil-free materials，the formula was 70% C9 petroleum resin + 15% modified asphalt + 7% xanthan gum + 8% nanofibers. The solubility of YDJ-1 was investigated，and the resistance coefficient，breakthrough pressure gradient and plugging ratio of YDJ-1 in cores with different permeability were evaluated. The test results showed that the dissolution rate of YDJ-1 was over 98% in crude oil，the water plugging rate was over 95% in core，and breakthrough pressure gradient of plugging layer could reach up to more than 50 MPa/m，which indicated that the oil-soluble plugging agent YDJ-1 had a good injectivity and plugging and selectivity performance.

Abstract:In order to meet the technical requirements of high-speed and efficient development of Bohai oilfield，the expansion performance and injection performance of the dispersed profile control and drive（DPCD）system in the flasks and porous media was studied，the influence of injection speed on the migration performance and oil displacement effect of the DPCD system was as well as investigated by using the biomicroscope and core displacement experiment. The results showed that in the environment of Bohai B reservoir，the initial particle size of the super molecular type DPCD system was 3.9 μm，and the particle size expanded 3.41 times after 192 hours of hydration and expansion，which indicated that the DPCD had a good effect of hydration and expansion. In the process of injection，some supramolecular DPCD systems would stay at the end face of the core，resulting in the end face effect. The lower the permeability was，the more serious the end face effect was. The increase of injection speed could make the DPCD system enter the core deeply，which was conducive to the deep migration and sealing of the DPCD system. However，for heterogeneous reservoirs，high injection rate would make a part of the DPCD system enter into the low-permeability layer，resulting in a decrease of the suction differential pressure of the low-permeability layer and the final recovery factor. The alternative injection of water and the DPCD system could improve the final recovery to some degree.

Abstract:In consideration of the high oil content of oily sludge and a lack of oil and water removal facilities in Dongfenggang oilfield，the oily sludge mixture was directly subjected to mechanical sieving and grinding，emulsification and suspension treatment without preliminary oil-removing process. An oily sludge profile control system prepared mainly by mechanical shearing method was established. The operating conditions of oily sludge profile control system were optimized，and its injection，plugging and profile-control and displacement performances were evaluated. The results showed that the suspension time of profile control system，which was prepared by adding 0.2% acrylate copolymer suspension （SF） and 0.2% triethanolamine monostearate emulsifier（FM-20）into the oily sludge，was greater than 10 h at room temperature and 90°C. During the preparation of the oily sludge profile control system by mechanical shearing，the optimum conditions included 4%—8% the mass ratio of oil-bearing sludge to water（solid-liquid ratio），around 6400 r/min shear speed，and about 3 min shear time. The oily sludge profile control system possessed good injection and plugging properties. After the system was injected into a single sand-filled pipe，the plugging rate of sand filling pipes with different permeability reached over 90%. The recovery degree of secondary water flooding increased by 25.01% . This method possessed the advantages of simple operation，low cost and reduced secondary pollution，exhibiting excellent application prospects for the treatment and resource utilization of oily sludge

Abstract:In order to solve the problem of the high percentage of low-ineffective wells in the acidification development of Wen 33 block in upper sand reservoir，the short-term effective period of the measure and the rapid restoration of water injection pressure， the antihypertensive enhancer XH207B（non-ionic surfactant）with low concentration（0.05%）was injected into the natural core to study the change of water film thickness in pore and relative permeability，and reveal the effect of antihypertensive enhancer on the injection pressure and permeability. The results showed that the water film thickness of the core was reduced after the antihypertensive enhancer was applied，and that of two cores was reduced by 67.90% and 38.13% respectively. At the same time， the antihypertensive enhancer could reduce the injection pressure and increase the core permeability. The injection pressure of two cores was reduced by 1.2% and 4.9%，and the core permeability was increased by 1.3% and 4.1%，respectively，achieving the effect of lowering pressure and increasing injection.

Abstract:Aiming at the problem of gas（steam）channeling in offshore thermal recovery，a kind of temperature resistant， high-strength and environmental friendly channeling blockage system was investigated，and the effect of apparent viscosity，gel temperature and pH value on gel forming time and gelation strength was investigated and the thermal stability and blockage ability of the system were measured. The experimental results showed that the viscosity of the system，composed of 5% alkali lignin+2% potential aldehyde crosslinking agent HDI + 1.5% phenol crosslinking accelerator DB +0.5% amide temperature resistant modifier UR + 1% high molecular nitrile toughness modifier PL，was 4.7 mPa·s at temperature（25℃），indicated that the system had good pumpability. The gelation temperature of the system was ≥75℃，and the gelation time at 75℃ was 30 h. When the temperature increased，the gelation time of the system shortened，and the gelation strength decreased slightly. When the temperature was up to 280℃，the gelation time was 5 h and the gelation strength was 0.068 MPa. The optimal pH value of the system was 7.0—9.0. When the system was placed at 250℃ for 60 days，only a small amount of water was dehydrated，and the strength could still reach 0.067 MPa，meanwhile the weight changed within 5%，which showed that the system had strong thermal stability and could meet the demand of high temperature reservoir. Core plugging experiments showed that the residual resistance factor of the system was 114.3. And when the system was combined with foam system（2.5% sulfonate anionic foaming agent COSL-07），the residual resistance factor was 123.2，showing good plugging effect. In parallel core experiment，the composite system reduced the volume fraction of liquid produced by high permeability pipe from 80% to 55% ，and increased the volume fraction of liquid produced by low permeability pipe from 20% to 45%，the comprehensive recovery increased by 16.9%. It was indicated that the system had excellent selective channeling sealing effect and diverting ability，which could play a good role in channeling control and plugging，and effectively improve the oil displacement effect of steam flooding.

Abstract:At present，the main exploitation way of heavy oil is thermal production. Aiming at the steam channeling during the thermal production，a temperature-resistant and salt-resistant steam plugging system was studied. The best formula was determined as follows：1% asphalt powder particles + 0.7% guar gum + 0.05% surfactant compound system（mass ratio of cetyl trimethyl ammonium chloride to cetyl trimethyl ammonium bromide was 2∶3）. The temperature and salt resistance，high temperature blocking performance，erosion resistance and oil-water selective blocking ability of the system were investigated. The experimental results showed that the steam plugging system had a water separation rate of less than 20% under high temperature and high salt conditions. At the same time，the plugging agent had good salt resistance. The water separation rate of the plugging agent prepared with formation water with a salinity of 100 g/L was less than 30%. The plugging rate of asphalt powder particle high-temperature plugging agent for cores with different permeability could be maintained above 90%，and the plugging rate reduction rate after long-term scouring with steam injection was less than 3%，exhibiting a good erosion resistance. Asphalt powder particle plugging agent had good selective plugging ability，the plugging rate for water layers could reach over 85%，while the plugging rate for oil layers was less than 20%.

Abstract:Domestic and foreign theoretical studies on the effect of CO2 foam on heavy oil have been relatively mature，but there are few visualized studies on the start-up process and action mode of CO2 foam on residual oil in the process of displacement of heavy oil. In order to further explore the mechanism of action between CO2 foam and heavy oil，micro-dynamic experimental study on the start-up effect of CO2 foam on residual heavy oil in the process of displacement was carried out by using self-made two-dimensional plane model and visual experimental displacement system. The process of starting the residual oil at the blind end，eroding the oil film，and emulsifying and displacing the oil at the front end of the slug were observed. Using a high-temperature and high-pressure sample preparation device，PVT experiment of heavy oil under the action of the CO2 foam system was carried out. With the temperature rising from 30℃ to 90℃，the solubility of CO2 in the heavy oil changed little，the heavy oil volume factor increased from 1.19 to 1.42，and the viscosity reduction rate increased from 13.55% to 67.42% . On the one hand，the CO2 foam had the microscopic effect of selectively blocking the large pores and starting residual oil；on the other hand，CO2 foam fluid reduced the mobility ratio of the displacement system，which made CO2 foam fluid had the effect of improving the swept area and increasing the displacement efficiency of improving swept area.

Abstract:The implementation of water flooding for enhanced oil recovery（EOR）has certain requirements on the ion composition of injected water. In order to verify that wettability alteration was not the only factor on EOR by sulfate brine flooding，water flooding experiments were carried out to investigate the effect of sulfate concentration，temperature，injection rate and crude oil type on the total oil recovery of sulfate brine flooding under the condition of water-wet cores. The experiment results showed that the oil recovery increased with the increase of sulfate concentration. There was no obvious increment in oil recovery at 40°C and the effect of water flooding enhanced with the increase of temperature. Under high temperature condition，10% increase in oil recovery was observed in the core flooded with sulphate enriched brine as compared to the core flooded with sulphate-free brine. The crude oil type and injection rate also played a significant role on the effect of water flooding. The oil recovery of water flooding was enhanced more strongly with the higher asphaltene content or the faster injection rate. Sulfate ion could still contribute to the improvement of oil recovery under the condition of unchanged core wettability. The change of core wettability was not the only factor that improved oil recovery by sulfate flooding.

Abstract:In order to peel off the oil film adsorbed on the rock surface efficiently，a novel oil-displacing agent 9，10-dihydroxyl sodium stearate（SDHS）with the capability of interfacial wettability control was synthesized by a two-step method using oleic acid，hydrogen peroxide，acetic acid and sodium hydroxide. The final product was characterized by Fourier transform infrared spectroscopy（FT-IR）and proton nuclear magnetic resonance（1 H NMR），and their adsorption property，wettability control property，interfacial tension reduction property，and oil film peeling performance were evaluated. The results showed that SDHS was evenly absorbed onto the surface of lipophilic-treated mica sheet. When lipophilic-treated glass sheet was immersed in 0.3% SDHS solution for 48 hours，the water contact angle in air reduced from 99.2° to 27.1°，while the underwater oil contact angle increased from 18.1° to 142.3°，indicating that SDHS could regulate the surface wettability of oil-wet rock to a strong hydrophilic and under water oil-repellent state by adsorption. SDHS could reduce the oil-water interfacial tension below 1 mN/m，and 0.3% SDHS solution exhibited the best performance in reducing the interfacial tension. At 40℃，0.3% SDHS solution could reduce the area of oil film by 53.6% after soaking glass slide within 48 hours，whose oil film peeling performance was better than that of traditional surfactant such as sodium dodecyl sulfate（SDS）. SDHS could simultaneously reduce the oil-water interfacial tension and regulate the wettability of solid-liquid interface，and exhibited excellent oil film peeling performance，which could be applied for further improving the oil recovery.

Abstract:In order to reveal the influence of sodium naphthenic petroleum sulfonate on enhanced oil recovery（EOR）of polymer/ surfactant binary compound flooding in conglomerate reservoir，the laser particle size analyzer and ultraviolet spectrophotometer were used to determine the micelle size and solubilization amount of sodium naphthenic petroleum sulfonate. The emulsification effect of sodium naphthenic petroleum sulfonate on EOR was studied by microfluidic model displacement experiment and core flooding experiment. The results showed that the size and amount of solubilized crude oil in sodium naphthenic petroleum sulfonate solution were the largest under the same concentration，compared with sodium dodecyl benzene sulfonate and sodium heavy alkyl benzene sulfonate. The limited solubilization of crude oil was 350 kg in 1 t sodium naphthenic petroleum sulfonate solution. Sodium naphthenic petroleum sulfonate was easy to emulsify with crude oil. After emulsification，the viscosity of oil displacement system was increased and the fluidity was controlled，which was beneficial to EOR. In the field test of binary compound flooding in the seventh middle area of Karamay oilfield，according to the difference of core permeability and oil saturation，the oil displacement efficiency could be greatly improved by adjusting the emulsification degree of oil displacement system when the dosage of surfactant was changed.

Abstract:In order to improve the problems of steam channeling and plugging difficulty after high thermal recovery cycles，and the decrease of development profit caused by the sharp increase of produced water in thin-layer extra heavy oil reservoir with edge and bottom water，water-soluble active molecular co-polymer（AAPA）was synthesized using acrylamide（AM），sodium acrylate （AA），4-phenyl-1-butene（PB），acrylamide-2-methylpropanesulfonic acid（AMPS）as reactants and tetramethylethylenediamine as catalyst. The effects of oil to solvent ratio，AAPA dosage，pH value，Ca2 +，Mg2 + and temperature on viscosity reduction were studied. The mechanism of viscosity reduction of AAPA was analyzed. The cold field test of chemical viscosity reduction was carried out by multiple concentration and multiple slug injection method. The results showed that the best viscosity reduction effect could be obtained by mixing 1 g/L AAPA with crude oil in a mass ratio of 1∶1. The static viscosity reduction rate of degassed and dehydrated heavy oil with viscosity below 50 Pa·s at 50℃ could be more than 90%. AAPA had the characteristics of high salinity tolerance，easy demulsification and wide range of viscosity reduction temperature. The effective viscosity reduction temperature range was 50—180℃. The Ca2 + resisting concentration was less than or equal to 10 g/L，and the Mg2 + resisting concentration was less than 3 g/L. When the pH value was less than 4，the heavy oil after viscosity reduction emulsification could be quickly demulsified，and when the pH value was greater than 10，the viscosity reduction activity of AAPA could be further improved. It had been applied on 4 wells，and the effect of fluid extraction and oil increase was obvious. By injecting AAPA into reservoir with multiple concentration and multiple slug，the viscosity of crude oil could be effectively reduced，and the benefit of cold recovery development of thin-layer extra heavy oil reservoir with edge and bottom water could be significantly improved.

Abstract:The alkali/surfactant/polymer（ASP）flooding can enhance oil recovery significantly. Understanding the influence of ASP flooding on reservoir physical properties is helpful to realize the application of this technology in third class reservoir. By measuring the porosity，permeability and pore distribution parameters of third class reservoir cores before and after ASP flooding， the influence of ASP flooding on physical properties of third class reservoir was analyzed qualitatively. On the basis of experiments， the prediction model of reservoir physical property of ASP flooding was established by using neural network model to characterize quantitatively the physical property of the third class reservoir in ASP flooding process. It was revealed that the reservoir physical properties gradually become worse in the order of Ⅲ A，Ⅲ B and Ⅲ C. The ASP flooding could improve the permeability of reservoir with good physical properties in the early stage of injection，while the reservoir with poor physical properties will be damaged quickly.

Abstract:In Shengli oilfield，the reservoir heterogeneity is intensified in the extra-high water-cut period，so the effective control system must be used to realize the deep control of the formation. The field test of the existing control system SP-01 in the Gudong test area failed to achieve the expected effect，so it is urgent to conduct research on the molecular structure optimization and improvement of the existing control system. Traditional manual design is time-consuming and costly in the synthesis and verification methods. In this paper，the regulation mechanism was furtherly understanded using the computer molecular simulation method，the relationship between the molecular structure of polymer and the fluid mechanics volume or intermolecular interaction energy was studied and the optimal molecular structure was obtained. Moreover，the polymer NSP-02 was synthesized according to the optimal simulated results，and the viscosity-increasing ability of the new synthetic polymer NSP-02 was compared with that of SP-01. The molecular simulation results showed that it was not a simple linear relationship between the molecular structure of polymer and the fluid mechanics volume or intermolecular interaction energy. The optimal molecular structure of polymer should be determined according to the change of the polymer molecular weight，the hydrophobic carbon chain length and micro block length. The molecular weight and viscosity-increasing ability of the new synthetic polymer NSP-02 in the laboratory were both stronger than that of the polymer SP-01. The indoor experimental verification results are consistent with the computer molecular simulation results，so the computer molecular simulation can be faster and more effective to guide artificial synthesis.

Abstract:The hydrophobic association quaternary copolymer was synthesized by aqueous solution polymerization using acrylamide （AM），（4-acrylamide）phenyl tetradecyl dimethyl ammonium bromide（PTDAB），2-acryamido-2-methylpropanesulfonic acid （AMPS）and subsequent hydrolysis. The effects of reaction conditions on the intrinsic viscosity，solubility and increase viscosity of the synthesized polymer were investigated to determine the optimal synthesis conditions. The temperature resistance，salt resistance，shear stability and thermal stability of the synthesized polymer under the optimal synthesis condition were studied. The optimum synthesis condition was determined as follows：PTDAB content was 0.5%—0.8% of total monomer mass，2-acryamido- 2-methylpropanesulfonic acid content was 15%—20% of total monomer mass，total addition amount of the monomers was 25%， compound initiator content was 0.1% of total monomer mass，pH value was 8 and the reaction temperature was 30℃. When the solvent salinity was 100 g/L，the viscosity of the quaternary copolymer solution with the concentration of 2000 mg/L was still greater than 30 mPa·s，and when the solvent salinity was 20 g/L，the mechanical shear viscosity retention rate of the synthetic polymer solution with the concentration of 2000 mg/L could reach more than 80%，sheared at a speed of 5000 r/min for 3 min and then stood for 4 h，the viscosity of the solution aging at 85℃ for 150 days，was greater than 20 mPa·s.The results showed that the quaternary copolymer had better salt tolerance，heat resistance，ability of shear stability and thermal stability，compared to the high molecular weight salt resistant polyacrylamide P（AM-AMPS-NaAA）.

Abstract:In order to clarify the effect difference of emulsification and interface property in chemical system flooding，one composite system with weak emulsification performance and interfacial tension of 10-3mN/m and another with strong emulsification performance and interfacial tension of 10-2 mN/m were used to measure the relative permeability curve and micro displacement experiment，then the the seepage characteristics were compared. The results showed that，compared with the composite system with strong emulsification and weak interfacial activity，the composite system with weak emulsification and strong interfacial activity had larger relative permeability of oil-water phase，the isopermeability point was to the right，and the residual oil saturation was relatively 4.4% lower. When the displacement time was long and reached high water saturation，the system with strong emulsification and weak interfacial activity had enough time to play an emulsification role and had higher EOR potential.

Abstract:To probe the interactions between flexible and rigid macromolecules in polymer flooding systems，the rheological properties of mixed solutions containing flexible partially hydrolyzed polyacrylamide （HPAM） and a rigid anionic exopolysaccharide（EPS）secreted by a deep-sea mesophilic bacterium Wangia profunda SM-A87 were studied in detail. Results showed that mixing of HPAM and EPS leaded to a viscosity decrease of their mixed solutions in the semidilute regime，which was rarely seen in hydrogen-bonded complex systems. With increasing electrolyte concentrations and shear rates，the viscosity decrease of HPAM/EPS solutions could turn into the viscosity increase. The viscosity increase of HPAM/EPS solutions was also observed when tuning the solution pH to be ＜5 or ＞11. The viscosity decrease or increase of the HPAM/EPS solutions resulted from variation of the molecular configuration that could be influenced by electrolyte concentrations，pH，and shear rates. Compared with the HPAM system，the HPAM/EPS complex system exhibited stronger salt resistance and thus great potential for application in tertiary oil recovery. This work can direct research on other similar systems composed of flexible and rigid anionic macromolecules.

Abstract:To investigate the flooding performance of SiO2 nanofluid in low permeability reservoirs，the self-developed modified hydrophobic nanosilica was used to study the stability of SiO2 nanofluid and its effect on interfacial tension. Series of flooding experiments in low permeability cores were conducted to evaluate the performance of SiO2 nanofluid and to optimize the injection parameters. The results showed that the average size of SiO2 nanoparticles was about 50 nm；when the particle concentration was 0.15%，the interfacial tension value was the lowest，being of 0.55 mN/m；when the concentration was below 0.15%，the stability of the system was good，and the higher the concentration，the worse the stability of the system. Flooding experiments in cores with 20×10-3 μm2 showed that SiO2 nanofluid could effectively reduce water cut and injection pressure. The injection parameters reached its optimization when the injection rate，injection volume and particle concentration was 0.1 mL/min，0.5 PV and 0.15% ， respectively. Under these conditions，oil recovery could be enhanced by 25.41%. The SiO2 nanoparticles with hydrophobicity synthesized in this study can be used to efficiently enhance oil recovery in low permeability reservoirs.

Abstract:In order to solve the serious pipeline corrosion of the third section in northern Maling oilfield，the quality of the clear water（refilled water）was analyzed，the corrosion behavior of L245N steel in clear water was researched by applying weight loss method and electrochemical method and the effect of six kinds of corrosion inhibitor was evaluated. It was indicated that electrolytes，sulfate-reducing bacteria，SO4 2-，Ca2+，dissolved oxygen and Cl- were the main causes of metal corrosion in the clear water of the north third section. Among the six corrosion inhibitors，corrosion inhibitor RX-211 had the best corrosion inhibition effect. When the dosage of RX-211 was 200 mg/L，the inhibition rate reached to 62.43%，and the corrosion rate of L245N steel was 0.0293 mm/a.

Abstract:In order to analyze the effect of nano-sized oil-displacement agent in increasing water injection in low permeability reservoir，the basic properties of nano-sized oil-displacement agent with nano-SiO2 modified by silane coupling agent as the main component were evaluated，and the flow characteristics and displacement characteristics of nano-sized oil-displacement agent were studied through natural core and microscopic model displacement experiments of Chang6 reservoir in Zaowan block.The results showed that the nano particles in nano-sized oil-displacement agent had small particle size，low oil-water interfacial tension，good hydrophilicity and certain static adsorption. At 30℃，the oil-water interfacial tension of 0.1% nano-sized oil-displacement agent was 0.784 mN/m，the wetting contact angle on hydrophilic and oil-wet slide was 22.5° and 16.2° ，and the average static adsorption capacity on the surface of long 6 core was 0.0033 mL/g. The nano-sized oil-displacement agent could displace the residual oil trapped in small pores which could not be swept by conventional water flooding，and could peel off the oil adsorbed on the pore surface. The displacement effect on flake concentrated distribution of residual oil was better than that of network dispersed distribution of residual oil. After 1 PV 0.1% nano-sized oil-displacement agent was injected into the core micro model and natural core，the water flooding permeability increased by 55.2% —56.7% and 34.3% —55.4% ，and the oil displacement efficiency increased by 10.9% —21.6% and 6.1% —10.1% ，respectively，showing good effect of increasing water injection for oil displacement.

Abstract:Wellbore integrity is of great significance to the safe and efficient production of ultra-deep well. In order to reveal the corrosion law of fracturing fluid on completion string，five fluids commonly used in ultra-deep well and super JFE 13Cr tubing test pieces were selected，and the metal coupon weight loss method and stress corrosion experiment were adopted. The corrosion of 13Cr materials by ultra-deep fracturing fluid and the corrosion inhibition performance of the new high-density salt water aggravated fracturing fluid corrosion inhibitor were evaluated. The results showed that the 5 kinds of fracturing fluids all had a certain degree of surface corrosion on the 13Cr tubing test pieces，and the corrosion rate at 140℃ was 4.8—10.6 g/（m2·h）. When 90% stress yield strength was loaded，the test pieces had different degrees of stress cracking cracks in the five fluids. The stress corrosion in the sodium nitrate aggravated fracturing fluid was more significant. After adding a high-concentration corrosion inhibitor composed of acetylenic amine compound and some metal compounds to the sodium nitrate or calcium chloride aggravated fracturing fluid，the stress corrosion was significantly alleviated. This research was useful for understanding the stress corrosion of fracturing fluid and ultra-deep well stimulation safely and efficiently.

Abstract:In order to deeply understand the mechanism responsible for the emulsifying viscosity reduction for heavy oil in chemical flooding，the interfacial tension and dilational rheological parameters between heavy oil and three polyether solutions with different structures were studied. The stability，particle size and viscosity of the emulsion that was formed by polyether solution and heavy oil were also investigated. The results showed that long flexible ethylene oxide（EO）and propylene oxide（PO）chains in polyether molecule could form a sub-layer at interface，resulting in an oil-water interfacial film with strongly elastic nature. Therefore，it was easy for polyether solution to form stable O/W emulsion with heavy oil and obviously decrease viscosity. The molecular weight and the ratio of EO/PO played the major role in affecting interfacial tension and the strength of interfacial film was mainly controlled by molecular weight. The polyether with larger molecular weight showed higher interfacial film strength and more stable O/W emulsion with heavy oil. The structure and dosage of polyether and oil-water volume ratio showed little influences on particle size of emulsion，which varied from 300 nm to 500 nm. The three polyether solutions with molecular weight of 8400，12600 and 14600 had good viscosity reduction effect on heavy oil. At oil-water volume ratio of 1∶1，the rate of viscosity reduction was over 98% when the dosage of polyether was 0.2% —0.5% . The molecular weight and the ratio of EO/PO had little effect on viscosity reduction.

Abstract:in this paper，the electrocatalytic oxidation degradation of fracturing flowback fluid was studied，and the effects of treatment conditions，such as treatment time，treatment temperature and current density，on the viscosity and boron form of simulated hydroxypropyl guar gum based fracturing flowback fluid，as well as the effects of direct oxidation caused by electron exchange between electrode plate and guar gum and indirect oxidation caused by an active oxide produced by an electrochemical process on the degradation of hydroxypropyl guar gum were investigated. The results showed that the viscosity reduction rate of the fracturing flowback fluid increased as follows，treatment time＞100 min，treatment temperature＞25℃，current density≥70 A/m2 and［Cl-］≥4855 mg/L. Indirect oxidation and direct oxidation played a synergistic role in the degradation process of electrocatalytic oxidation. During the viscosity reduction process of the fracturing flowback fluid，there was a decrosslinking reaction and the crosslinked boron was released.

Abstract:When conventional flocculation technology is used to treat oilfield produced water，negatively charged polymers will form oil-bearing flocs. It not only causes the waste of polymer，but also forms degraded oil（BS layer）and polymer-containing sludge deposit in oil-water treatment system， which affects crude oil dehydration and sewage purification， and breeds sulfate-reducing bacteria. In order to make full use of the polymer in oil production wastewater，a comprehensive demulsifier was used to treat polymer-containing produced liquid. While ensuring crude oil dehydration and sewage degreasing，the polymer in oil production sewage was retained in situ in molecular form. The relative molecular mass and degree of hydrolysis of the retained polymer（r-HPAM）were measured，and the interaction between r-HPAM and ions in sewage and the effect of sewage containing r-HPAM on the viscosity of high molecular weight polyacrylamide（h-HPAM）solution were studied. What’s more，the viscosity increasing mechanism of r-HPAM on the viscosity of injection solution was analyzed. The results showed that the r-HPAM in sewage was a polymer with low molecular weight（200×104）and high degree of hydrolysis（46%），and the viscosity of sewage was 1.1 mPa·s. Using sewage containing r-HPAM to prepare fresh h-HPAM solution could reduce the viscosity loss. The r-HPAM in sewage could be used as a sacrificial agent to interact with Ca2 +，Mg2 +，Fe2 + and S2- and offset the viscosity loss of h-HPAM solution by these ions. Among them，Fe2 + and S2- had the greatest impact. The preparation of high molecular weight polymer solution with polymer-containing produced water was of great significance to the recycling of polymer-containing produced water and reducing the discharge of produced water.When conventional flocculation technology is used to treat oilfield produced water，negatively charged polymers will form oil-bearing flocs. It not only causes the waste of polymer，but also forms degraded oil（BS layer）and polymer-containing sludge deposit in oil-water treatment system， which affects crude oil dehydration and sewage purification， and breeds sulfate-reducing bacteria. In order to make full use of the polymer in oil production wastewater，a comprehensive demulsifier was used to treat polymer-containing produced liquid. While ensuring crude oil dehydration and sewage degreasing，the polymer in oil production sewage was retained in situ in molecular form. The relative molecular mass and degree of hydrolysis of the retained polymer（r-HPAM）were measured，and the interaction between r-HPAM and ions in sewage and the effect of sewage containing r-HPAM on the viscosity of high molecular weight polyacrylamide（h-HPAM）solution were studied. What’s more，the viscosity increasing mechanism of r-HPAM on the viscosity of injection solution was analyzed. The results showed that the r-HPAM in sewage was a polymer with low molecular weight（200×104）and high degree of hydrolysis（46%），and the viscosity of sewage was 1.1 mPa·s. Using sewage containing r-HPAM to prepare fresh h-HPAM solution could reduce the viscosity loss. The r-HPAM in sewage could be used as a sacrificial agent to interact with Ca2 +，Mg2 +，Fe2 + and S2- and offset the viscosity loss of h-HPAM solution by these ions. Among them，Fe2 + and S2- had the greatest impact. The preparation of high molecular weight polymer solution with polymer-containing produced water was of great significance to the recycling of polymer-containing produced water and reducing the discharge of produced water.?!? ?!? ?!? ?!? ?!? ?!? ?!? ????嵨蹐??嫨曈绘?'??蛀?????憡???
7耀化学驱；聚丙烯酰胺；采出水；黏度；回注
07
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??耈?为降低高效液相色谱法中高浓度无机盐的不利影响，以低浓度的醋酸铵（NH4Ac）水溶液/甲醇混合液代替 高浓度的NaH2PO4 水溶液/甲醇混合液，对油井采出水中十二烷基苯磺酸盐的高效液相色谱检测方法进行改进， 对测试条件进行了优选，并与质谱联用。结果表明，最佳测试条件为：10 cm×4.6 mm阴离子交换色谱柱，流动相 为20 mmol/L NH4Ac水溶液/甲醇混合液（体积比2∶3），流速1.0 mL/min，等度洗脱，紫外检测波长225 nm，20 μL 进样。该方法抗干扰能力较好，在5～500 mg/L范围内的线性关系良好，线性相关系数R=0.9997，检出限2 mg/L， 在12 min 内完成一次分析，具有准确、快速、灵敏的特点，可以用于油井采出水中十二烷基苯磺酸盐的定量检 测。此外，该方法可以与质谱直接联用，分析十二烷基苯磺酸盐的结构信息。图11 参13"'#9':<'=-'?
7?耦?In order to avoid the disadvantage of inorganic salt with high concentration，the detection method of dodecylbenzene sulfonate in oilfield produced water was improved by using ammonium acetate（NH4Ac）aqueous solution at a low concentration mixed with methanol instead of the original NaH2PO4 aqueous solution at a high concentration mixed with methanol. The detection parameters were optimized，and the method was combined with mass spectra. The results showed that the optimal condition was obtained as follows：a 10 cm×4.6 mm anion exchange chromatographic column，20 mmol/L NH4Ac aqueous solution and methanol in volume ratio 2∶3 as mobile phase，1.0 mL/min flow velocity with isocratic elution，225 nm ultraviolet detection wavelength， and 20 μL injection volume. This method showed good anti-interference ability and well linearity in the range of 5—500 mg/L. The coefficient R was 0.9997 and the detection limit was 2 mg/L. Furthermore，one analysis was finished in 12 min. In general，this method showed the characteristics of accuracy，high speed and sensitivity，and could satisfy the quantitative detection of dodecylbenzene sulfonate in oilfield produced water. Moreover，the method could be directly coupled with mass spectra to analyze the structure of surfactant.L#M ?#à ?(? ?#? ?(? ?(? ?#? ?#? ?#? ?(? ?#? ?#? ?#? ?#? Φ#Χ ?#? ?#? Ф#Х ?#?
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V?耀?aqueous solution polymerization temperature-resistant and salt-resistant polymer；hydrophobic associated polymer；solution properties
7耋汪士凯1，施雷庭1，叶仲斌1，袁晨阳1，张虎1，谭林2  
07
W耋汪士凯1，施雷庭1，叶仲斌1，袁晨阳1，张虎1，谭林2  
7H耋HWANG Shikai1，SHI Leiting1，YE Zhongbin1，YUAN Chenyang1，ZHANG Hu1，TAN Lin2! ! %!& 4!5 >!? G!
07
XH耋HWANG Shikai1，SHI Leiting1，YE Zhongbin1，YUAN Chenyang1，ZHANG Hu1，TAN Lin2! ! %!& 4!5 >!? G!
7H耀H（1. 油气藏地质及开发工程国家重点实验室（西南石油大学），四川成都610500；2. 西南油气田分公司重庆天然气净化总厂， 重庆401220）
07
YH耀H（1. 油气藏地质及开发工程国家重点实验室（西南石油大学），四川成都610500；2. 西南油气田分公司重庆天然气净化总厂， 重庆401220）
7ā耀?（1. State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation，Southwest Petroleum University，Chengdu，Sichuan 610500，P R of China；2. Chongqing Natural Gas Purifying Factory，Xinan Oil and Gas Field Branch，PetroChina，Chongqing 401220，P R of China）
07
Zā耀?（1. State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation，Southwest Petroleum University，Chengdu，Sichuan 610500，P R of China；2. Chongqing Natural Gas Purifying Factory，Xinan Oil and Gas Field Branch，PetroChina，Chongqing 401220，P R of China）
7耀化学体系乳化性能和界面活性对渗流特征影响差异*
07
[耀化学体系乳化性能和界面活性对渗流特征影响差异*
7`耀`Influence of Emulsification and Interface Property on Seepage Characteristics of Chemical System
07
\`耀`Influence of Emulsification and Interface Property on Seepage Characteristics of Chemical System
7?耄?为了厘清乳化性能和界面活性在化学体系驱油过程中的作用效果差异，分别采用乳化性能较弱、界面张力 达10-3mN/m的复合体系和乳化性能较强、界面张力达10-2mN/m的复合体系进行相对渗透率曲线测定和微观驱 替实验，分析了两种体系的渗流特征。研究表明：相对于乳化性能较强而界面活性较弱的复合体系，乳化性能较 弱而界面活性较强的复合体系的油水相相对渗透率更大，等渗点偏右，残余油饱和度相对低4.4%；当驱替时间较 长而达到高含水饱和度时，乳化性能较强而界面活性较弱的体系具有足够时间充分发挥乳化作用，具有更高的 提高采收率潜力。图10参1224LN
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Abstract:In order to avoid the disadvantage of inorganic salt with high concentration，the detection method of dodecylbenzene sulfonate in oilfield produced water was improved by using ammonium acetate（NH4Ac）aqueous solution at a low concentration mixed with methanol instead of the original NaH2PO4 aqueous solution at a high concentration mixed with methanol. The detection parameters were optimized，and the method was combined with mass spectra. The results showed that the optimal condition was obtained as follows：a 10 cm×4.6 mm anion exchange chromatographic column，20 mmol/L NH4Ac aqueous solution and methanol in volume ratio 2∶3 as mobile phase，1.0 mL/min flow velocity with isocratic elution，225 nm ultraviolet detection wavelength， and 20 μL injection volume. This method showed good anti-interference ability and well linearity in the range of 5—500 mg/L. The coefficient R was 0.9997 and the detection limit was 2 mg/L. Furthermore，one analysis was finished in 12 min. In general，this method showed the characteristics of accuracy，high speed and sensitivity，and could satisfy the quantitative detection of dodecylbenzene sulfonate in oilfield produced water. Moreover，the method could be directly coupled with mass spectra to analyze the structure of surfactant.

Abstract:Nanofluid flooding is of great significance to reduce the cost of oil development and enhance oil recovery. A series of important results have been achieved about the research on the mechanism of nano-fluid flooding. This paper focuses on the basic research related to the nanofluid flooding mechanism. And the four mechanisms of nanofluid enhanced flooding are summarized based on the different academic opinions and research results. According to this，it is pointed out that under the combined effects of structural separation pressure，rock wetting change and reduced oil-water interfacial tension，the nanofluid exhibits the dual characteristics of“roll-up”and“diffusion”in the process of oil displacement，thus having enhanced oil displacement. Finally，it is pointed out that nanofluids will have a very broad application prospect in the field of enhancing oil recovery，but a lot of research is needed on the effect and influencing factors of nanofluid flooding. In addition，the effective combination of nanofluid flooding and foam flooding is a way to enhance oil recovery.