Abstract:In order to develop the application field of polymers synthesized by dispersion polymerization，amphotericcopolymer which could be used as filtrate loss reducer was synthesized in ammonium sulfate solution by acrylamide（AM），acrylic acid（AA），2-acrylamido-2-methyl propane sulfonic acid（AMPS）and methacryloyloxyethyltrimethyl ammonium chloride（DMC）as monomers，polyvinylpyrrolidone（PVPK12）as dispersing agent，and 2，2'-azobis（2-methylpropionamide）dihydrochloride（V-50）as initiator. The effects of different concentration of ammonium sulfate，AMPS，monomers on the apparent viscosity and particle size of dispersions and intrinsic viscosity of polymers were discussed. The structure was characterized by FTIR and 1H-NMR，and the filtration reduction property of copolymer in bentonite slurry was evaluated. The results showed that the structure of polymers was consistent with the designed one synthesized on following conditions：15% monomers concentration，2∶5∶1∶2 monomer ratio of AM∶AA∶DMC∶AMPS，0.0426% V50 dosage（in terms of total monomers），1.4% PVPK12 dosage（in terms of total water），55℃ temperature，5 pH value. Polymers in dispersion were spherical and distributed uniformly which had a narrow diameter distribution. The dispersion could be stored beyond one year at room temperature. The ammonium sulfate and AMPS concentration had same effects on the apparent viscosity and particle size of dispersion. With increasing dosage of ammonium sulfate and AMPS，these two variables were decreased first and then increased. When the concentration of ammonium sulfate increased，the intrinsic viscosity number of polymer increased first and then decreased，while AMPS had the contrary effect on intrinsic viscosity number.With increasing concentration of monomers，the apparent viscosity and particle size of dispersion were both increased. The polymer had a good performance on filtrate loss reducing. With increasing dosage of polymers in bentonite slurry，the API and HTHP fluid loss decreased and became stable gradually. Amphoteric copolymer synthesized by dispersion polymerization in ammonium sulfate solution could be used as filtrate loss reducer in drilling operation.

Abstract:In order to reveal the influence of oil-based drilling fluid on the filtration property of drilling fluid after invading the formation，the effect of organic soil，fluid loss reducer（sulfonated asphalt，oxidized asphalt，2-acrylamide-2-methylpropanesulfonic acid（AMPS），organic amine modified humic acid and their compound）and temperature on the filtration property of drilling fluid was studied by adjusting the oil-water ratio to simulate the drilling fluid intruding formation water. The micro-morphologies of drilling fluids with different oil-water ratio before and after addition of organic soil were observed. The results showed that with decreasing oil-water ratio，the high temperature and high pressure fluid loss of drilling fluid tended to decrease. The organic soil and fluid loss reducer would reduce the high temperature and high pressure fluid loss of drilling fluid. The filtration reduction effect of compound fluid loss reducer was better than that of single fluid loss reducer. Among them，the fluid loss reducer composed by polymer and asphalt had the best fluid loss reduction effect. With increasing temperature，the high temperature and high pressure fluid loss of drilling fluid gradually increased. The micro-morphologies of different oil-water ratio drilling fluids before and after adding organic soil were compared. With decreasing oil-water ratio，the fluid loss reduction effect of organic soil as a suspending agent and tackifier in oil-based drilling fluid system was more obvious. The high temperature and high pressure fluid loss of oil-based drilling fluid could be effectively adjusted by reasonable selection of the types and additions of fluid loss reducer and organic soil.

Abstract:In order to improve the temperature and salt resistance of polymer fluid loss additive and the compatibility with high density and high solid phase deep well drilling fluid system，the self-made hexene monomer TDED was used as a crosslinking agent， and acrylamide （AM）， 2-acrylamide-2-methylpropanesulfonic acid （AMPS） and N-vinylpyrrolidone （NVP） were subjected to free radical copolymerization to prepare a micro-crosslinking copolymer fluid loss additive PTAPN. The structure of the product was characterized by infrared spectrometer. The temperature and salt tolerance of PTAPN and the compatibility with different density drilling fluids were studied. The results showed that the molecular structure of the product was consistent with the design. PTAPN had good fluid loss performance in high temperature and high salinity environments. After adding 2% PTAPN，the viscosity of fresh water and composite brine base slurry increased before and after aging at 240℃ ，and the fluid loss greatly reduced. PTAPN had good compatibility with different density water-based drilling fluids，which could effectively control the rheology and fluid loss of heavy drilling fluid with a density of 2.30 g/cm3 in high temperature environment. When the aging temperature was 240℃，the API fluid loss and high temperature and high pressure fluid loss of weighting drilling fluid was 2.6 and 12.6 mL，respectively，which was much smaller than that of drilling fluid containing conventional linear polymer fluid loss additive. PTAPN was suitable as a fluid loss additive for high temperature and high density drilling fluid systems.

Abstract:The Xixiagou tectonic belt Dyas lake group formation in Santanghu oilfield located in Tuha Basin is fractured reservoir.Serious well leakage frequently took place during the drilling development. In order to solve the problem of serious well leakage in Santanghu oilfield Ma-49 block tight reservoir，the composite gel drilling fluid（CGDF）technique was developed based on the analysis of the reasons of well leakage regulation in Ma-49 block. The compatibility，pumpability，high-temperature resistance and bearing capacity of the CGDF was analyzed，and the effect of the field application was mentioned. The research showed that the compatibility between the CGDF and the reservior was of high performance. The gelling time of the CGDF was 30 min，which indicated that the CGDF had good pumpability. There was not obvious change of CGDF mud invading depth in the casting bed after aged at the temperature of 100℃ for different aging time，so the CGDF system was of high temperature resistance. Moreover，The CGDF was of good pressure resisting and plugging capability，which could form the effective plugging formation in the gap of 1—3 mm in static/dynamic state condition. The CGDF technique solved the serious well leakage in Ma-49 block tight reservoir and optimized the effects of the drilling process. By applying the CGDF technique，94.57% of the average leakage in the same block was reduced，89.51% of the plugging time was shorted，and 37.26% of the drilling cycle was saved.

Abstract:In order to reveal the structural characteristics of acrylamide-based cross-linked polymer microspheres prepared by water dispersion polymerization method and their influence on the performance of drilling fluid，the acrylamide-based cross-linked polymer microspheres were prepared in an ammonium sulfate aqueous solution medium，using acrylamide（AM），acrylic acid （AA）and methyl propionyloxyethyltrimethylammonium chloride（DMC）as monomers，2，2-azobis（2-methylpropylimidazolium）dihydrochloride as initiator，and N，N'-methylenebisacrylamide complex as crosslinker. The structure of polymer microspheres was characterized by infrared spectroscopy and particle size analysis. The effect of cross-linked polymer microspheres on the performance of drilling fluid was investigated. The results showed that the synthesis conditions of cross-linked polymer microspheres had little effect on the filtration reduction of product，but had a significant effect on the viscosity-enhancing effect of polymer microspheres in drilling fluid. With the increase dosage of AM and crosslinker，the viscosity-enhancing effect of polymer microspheres on drilling fluid was enhanced. There was an additive amount of initiator and a molar ratio of AA to DMC that had the least effect on the viscosity increase of drilling fluid. The acrylamide-based cross-linked polymer microspheres having an average particle diameter of 8.04 μm（particle size range of 2.43—53.72 μm）were prepared by water dispersion polymerization method.The cross-linked polymer microspheres with excellent temperature-resistant performance significantly reduced the filtration of drilling fluid and slightly enhanced viscosity. After being aged at 150℃ ，the filtration reduction of polymer microspheres was influenced a little，but the viscosity-enhancing effect of polymer microspheres to drilling fluid was weakened and their influence on the rheology of drilling fluid was reduced.

Abstract:Aimed at the problem that the formation fluid can not be plugged effectively to prevent the fluid from flowing upward during the process of the precise pressure control drilling due to the lower compressive and cementation strength，much aperture and fracture of the solid packing formed by hydraulici gel，a kind of waterborne epoxy resin CQ-WERE and matched curing agent CU-900 as the properties modification agent（PMA）was added into the hydraulic gel working fluid（HGWF）and the influence of the PMA on the rheology of HGWF and mechanical property of solid packing formed by HGWF was investigated，and the mechanism that the PMA improved the mechanical property of the solid packing was analyzed. The results showed that the PMA had good compatibility with the HGWF，the PMA had less influence on fluidity and rehology property of the HGWF；the thickening time of the HGWF decreased with the PMA dosage increased；the PMA could significantly improve the compressive strength of the solid packing and cementation strength between the solid packing and the pipe surface，with PMA dosage of 3%，after curing at the temperature of 120℃for 5 h，the compressive strength and cementation strength could increased up to 4.61 MPa and 1.39 MPa/m，respectively；meanwhile，the self-cementing ability of the gel packing was good，the air sealing pressure being not less than 1.02 MPa/m；the drillability grade of the solid packing was 2，meaning that the solid packing could be easily drilled out. When the PMA was added to the HGWF，the water-reducing and solidification crosslinking effect was achieved，which could modify the organization structure of the solid packing，decrease the micro-defect，strengthen the compactness，prevent fracture from propagating and improve the mechanical property of solid packing.

Abstract:In order to solve the problem of poor cementing quality caused by residual drilling fluid on wellbore and casing，the formulation of flushing fluid was studied. Through evaluated the flushing efficiency and suitable temperature of the flushing fluid，the non-ionic surfactant，anionic surfactant and inorganic salt additive as raw materials were optimized by different experiments ，and the recipe of the flushing fluid was obtained as follows，6.4% of nonylphenol polyethylene glycol ether （15） TX-15， 6.4% of coconutt diethanol amide（6501），6.4% of sodium dodecyl benzene sulfonate（SDBS），0.64% of sodium tripolyphosphate（STPP），0.16% of kathon and 80% of deionized water，named as BH-Q812L. The temperature resistance，flushing efficiency and the compatibility of the BH-Q812L with drilling fluid and cementing slurry were investigated. The results exhibited that the resistance temperature of BH-Q812L was reached up to 150℃. The flushing efficiency for polymer and salt water drilling fluid was higher than 95% within 4 min using the flushing fluid containing 5% of BH-Q812L；and the flushing efficiency for silicon-based drilling fluid was higher than 95% within 5 min using the flushing fluid containing 10% of BH-Q812L. Moreover，the compatibility of BH-Q812L with drilling fluid and cementing slurry was excellent. The BH-Q812L had been used in eight wells of different drilling fluid，gaining good operation achievement.

Abstract:In view of the leakage control problem of cement sheath in Tahe oilfield，the liquid channeling sealing agent was prepared by mixing 2-acrylamide-2-methylpropane sulfonic acid and acrylamide coploymer （AM-AMPS） with phenolic prepolymer which was synthesized from formaldehyde and phenol. The structure of phenolic prepolymer was characterized by infrared spectrometer and mass spectrometry. The effects of the concentrations of polymer AM-AMPS and phenolic prepolymer，and temperature on the curing of channeling sealing agent were studied，and the stability of channeling sealing agent was evaluated. The results showed that the when the molar ratio of formaldehyde to phenol was 2.8∶1 and the pH value of the system was 8—10，the synthesized phenolic prepolymer was a resole phenolic with 2—3 degree of polymerization. The mass fraction of hydroxymethyl formaldehyde and free formaldehyde was 36.1% and 0.03% respectively. Appropriate amount of AM-AMPS could increase the cementation ability between phenolic prepolymer and pipe wall，and improve the breakthrough pressure gradient of channeling sealing agent. The main reaction of channeling sealing agent（0.5% AM-AMPS+40% phenolic prepolymer）was curing reaction at 140℃ . The breakthough pressure gradient after curing was 150.6 MPa/m and the cruing time was 37 min. The strength of channeling sealing agent after curing increased with increasing amount of phenolic prepolymer，and was less impacted by temperature. Temperature was the main factor affecting the curing time of channeling sealing agent. The channeling sealing agent had good stability under high temperature（90—140℃）and high salinity（100—240 g/L），which could be used to seal channel and plug leakage in Tahe oilfield.

Abstract:when workover operations were performed in Bohai S oilfield，a high permeability and porosity heavy reservoir，using source water as workover fluid，there was the problem of large amounts of fluid leak into formation and poor productivity recovery effect. In order to decrease the formation damage of extraneous operating fluid，a workover fluid which could protect formation was developed. Boundery film washing agent，viscosity reducer，anticrustator and clean up additive used to prepare prepad fluid was optimized by laboratory experiment，and the viscosity increasing property of temporary plugging fluid（TPF）and the plugging performance of the TPF for core and permeability recovery of the core after gel breaking were evaluated. The experiment results showed that the displacement efficiency and viscosity reduction rate of prepad fluid，composed of 15% boundery film washing agent GXXJ + 1.5% viscosity reducer JN-01，0.5% anticrustator ZG-02 and 1% clean up additive ZP-01，was greater than 90% ，respectively，Besides，it could inhibit calcium and magnesium scaling and reduce flowback pressure by 50% . Under the circumstances of 3.5—4 MPa and 60℃，the temporary plugging fluid，composed of 3% oil soluble temporary plugging agent BH-ZD+0.7% viscosity Increaser BH-VIS +3% gel breaker JPC，showed well plugging capacity，moreover，after gel breaking，the permeability recovery rate of core was more than 80% . The workover fluid，composed of prepad fluid and temporary plugging fluid，could prevent organic precipitation and other formation damage. The workover fluid had been applied in S oilfield，after workover，the leakage of operating fluid was low and productivity recover was well.

Abstract:According to the characteristics of reservoir burial depth （8600 m），high temperature （180℃ ） and lithologic compactness in Shunbei block of Tarim Basin，a fracturing fluid system with low friction，high density and high temperature resistance was prepared by using thickener GX-100，self-made organic zirconium crosslinker WQ-60 and weighting agent KCl. The temperature and shear resistance，drag reduction and gel breaking properties of the system were evaluated. Field application was carried out in Shunbei block of Tarim Basin. The results showed that the fracturing fluid system composed of 0.5% GX-100，0.65% WQ-60，2.5% pH modifier and 20% weighting agent KCl could be aggravated to density of 1.1 g/cm³. The fracturing fluid had good temperature resistance and shear resistance. The viscosity of fracturing fluid was higher than 50 mPa·s after shearing 90 min at 180℃ and 170 s^-1. The drag reduction efficiency of the solution was greater than 60%. In addition，the gel broke completely and the residue quantity was low，which satisfied the requirement of fracturing construction.

Abstract:In order to reduce the effect of high mineral water on the performance of fracturing fluid and improve the mixing problem of seawater and high salinity water，melamine hexa-acetic acid （ELX） was synthesized by cyanuric chloride and disodium iminodiacetate which was used as a stabilizer to chelate calcium and magnesium ions in high salinity water. The chelating ability of ELX for metal ions，the stabilizing effect on high salinity water，and the effect on the performance of hydroxypropyl guar fracturing fluid were studied. The results showed that the synthetic yield of ELX could reach 72% . The chelation value between ELX and metal ions，such as Mg²⁺，Ca²⁺，Cu²⁺ and Fe³⁺ was 150—350 mg/g，showing good removal effect for most metal ions. The addition of 0.9% ELX could keep the high salinity water clarified，and adding 5% ELX could keep the seawater clarified. ELX and hydroxypropyl guar gum had good compatibility，which had a good improvement effect on the viscosity of base fluid and the cross-linking performance of fracturing fluid. The fracturing fluid had a good temperature and shear resistance. The gel was broken within 2 hrs，maintained the lower surface and interfacial tension of broken fluid. The residue amount of broken fluid and damage rate of core matrix permeability were equivalent to that of clean water，which satisfied the construction requirements. Field trials with ELX were successfully conducted and initial production after fracturing operation by high salinity water-based fracturing fluid was 8.9 t/d. Stabilizer ELX was suitable for hydraulic fracturing of seawater，deep water and high salinity surface water in fresh water scarcity area，which saved operating costs.

Abstract:In order to improve rheological properties of xanthan gum solutions，long-chain hydrophobic amphoteric xanthan gum（OD-XG）was synthesized by xanthan gum（XG）and hydrophobic cationic etherification reagent that was synthesized using the main raw materials of oleamidopropyl dimethylamine and epichlorohydrin. The rheological properties of OD-XG and XG solutions were studied and compared，including the steady viscosity，flow curve，thixotropy，and viscoelasticity，as well as the temperature resistance and the gel-breaking performance. The results showed that the viscosity of OD-XG solution was significantly higher than that of XG，and the viscosity of 0.6% OD-XG solution（237.97 mPa·s）was increased by 221% compared to the viscosity of 0.6% XG solution（74.12 mPa·s）. The flow curve of OD-XG and XG solution could be fitted by nonlinear co-rotation Jefferys model.The viscoelasticity and thixotropy of OD-XG solution were significantly higher than those of XG solution，and the temperature resistance of OD-XG solution was improved. The reserved viscosity of 0.4% OD-XG solution（70.102 mPa·s）was twice as much as that of 0.4% XG solution（35.135 mPa·s）. The rheological study of gel breaking process showed that，after adding the breaker the gel breaking was completed well.

Abstract:The low pressure tight gas reservoir is characteristic of low permeability，low porosity and low pressure coefficient. The problem of water sensitivity damage caused by fracturing fluid invasion is widespread in the low pressure tight gas reservoir. In order to reduce the damage of fracturing fluid to reservoir and increase the flowback rate of fracturing fluid，the slick water system with low surface tension was selected，composed of 0.15% drag reducer XY-205，0.1% clean up additive XY-120 and 0.2% antiswelling agent XY-63. The drag reducing rate，anti-swelling rate and core damage performance of the slick water were also investigated，and the slick water had been put into field uses. The result showed that the surface tension of the slick water was 20.12 mN/m and the interfacial tension between the slick water system and kerosene was 1.52 mN/m，The drag reduction rate of the slick water system was up to 70.58%，and the antiswelling ratio of the core of HG-01 well in Wangfu block was 90%. The core damage caused by slick water was as low as 14.46%. The application of slick water in 3 wells of low pressure tight gas reservoir showed that the fracturing operation was successful，the gas breakthrough rate was fast after fracturing，the flowback rate of slick water was 61%，and the gas came out after 4 hours of running slick water. The application of low surface tension slick water in low pressure tight gas reservoir had achieved good results.

Abstract:In order to improve the performance of the clean fracturing fluid systems，the rheological properties of the micelle systems formed by cationic Gemini G3-18，anionic surfactant sodium（AOS）and sodium salicylate（NaSal）were investigated. The fluidity，viscoelasticity，thixotropy and temperature resistance of the systems was measured. The results showed that the 3% G3-18+ 1.5% NaSal system possessed good fluidity，viscoelasticity and thixotropy. After being sheared for 90 min at the temperature of 100℃ and at the shear rate of 170 s^-1，the viscosity of the system was 30.83 mPa·s. The viscous dominant frequency interval of 3% G3-18+1.5% NaSal+ AOS complex system increased while the elasticity dominant frequency interval reduced with increasing mass fraction of AOS in the range of 0.01—10 Hz. At the same time，the positive thixotropic ring gradually became smaller and the reverse thixotropic loop increased gradually with the AOS increased. After being sheared for 90 min at the temperature of 100℃ and at the shear rate of 170 s^-1，the viscosity of the 3% G3-18+1.5% NaSal+0.20%AOS mixture system remained 40.57 mPa·s，which was enhanced by 31.6% compared to that of the system without AOS.

Abstract:Cationic surfactants can change the surface properties of rocks and could be used to reduce the rate of acid-rock reaction to ensure that the acid was pushed deeply into the reservoir. In order to reveal the effect of the carbon chain length of the cationic surfactant on the retarding performance，in this paper，the critical micelle concentrations of tetradecyltrimethyl ammonium chloride，hexadecyltrimethyl ammonium chloride，octadecyltrimethyl ammonium chloride and dodecyltrimethyl ammonium chloride（C_nTAC，n=14，16，18，22）were determined by surface tensiometer and conductivity meter. Atomic force microscope was used to observe the adsorption patterns of C_nTAC on the rock surface. The solid/gas/liquid three-phase contact angle method was used to study the ability of C_nTAC changing the surface wettability of calcite. Finally，the static acid-rock reaction rate was tested. The experimental results showed that with the increase of the carbon chain length，the c_cmc of the C_nTAC decreased obviously，the adsorption of C_nTAC on calcite surface was mainly monolayer adsorption；C_nTAC could reversed wettability of hydrophilic solid surface to lipophilicity，with the increase of carbon chain length，the thickness of adsorbed layer of calcite treated by C_nTAC decreased and the hydrophobicity of calcite increased. C_nTAC could effectively reduce the acid rock reaction rate and the C₁₄TAC had the best retarding properties，the retardance rate was 69.70%，with the increase of carbon chain length，the retardation performance of C_nTAC became worse，and the surface morphology of calcite etching tended to be inhomogeneous.

Abstract:In order to obtain temporary plugging agent with small formation damage and low cost，water-soluble sodium chloride temporary plugging agent was synthesized by dispersant sodium dodecyl sulfate（SDS），corrosion inhibitor sodium molybdate，stabilizer xanthan gum，sodium chloride，precipitator calcium chloride and deoxidizer sodium sulfite. The dosages of additives were optimized and the performances of the new temporary plugging agent，including steering，plugging and plugging removal properties were studied. The results showed that the temporary plugging particle synthesized by 0.1 g SDS，1.0 g sodium molybdate，0.35 g xanthan gum，18.0 g sodium chloride，25.0 g calcium chloride and sodium sulfite had good stability without stratification within 12 days. The corrosion rate of N80 steel by temporary plugging agent was 0.067 mm/a at 90℃，which was lower than that of industry standard（0.075 mm/a）. The average particle size of temporary plugging agent was about 5 μm and the solid content of that was 6.96% . Sodium chloride temporary plugging agent had good steering ability，plugging and plugging removal performance. When the injection volume was 1 PV，the plugging rate of sand filling pipe with permeability of 231×10^-3 μm² was 95.6% ，and the plugging removal rate was 96.2% . NaCl temporary plugging agent could reduce operating costs and environmental pollution，and could be used for the oil displacement in low permeability fractured reservoirs.

Abstract:CO₂ flooding is greatly affected by areal heterogeneity in low permeability reservoirs，causing uneven pressure distribution，early gas breakthrough and low recovery factor. This study explored the applicability of diffluence management to improve CO₂ flooding under laboratory condition using physical experiment simulation. Based on the permeability ratio of the actual reservoir block，a radius model with areal heterogeneity was made to simulate CO₂ flooding as five spots pattern and relative experimental methods were designed. Three production patterns，including constant pressure，preproduction in low permeability well and high producing pressure differential in low permeability well，were introduced to evaluate the gas flooding effects. Results showed that under constant pressure production pattern，there was a significant gas breakthrough in only one production well located in high permeability area，and a huge production difference over the other four production wells，and only 23.11% oil was recovered. The latter two methods produced more oil and delayed gas breakthrough time，achieving oil recovery 42.50% and 46.42% ，respectively. By high producing pressure differential in low permeability well，the injected gas was evenly distributed across the radius model，leading to a lager gas sweeping volume，a higher gas utility and more oil production. Because of low operational cost，diffluence management method is expected to be an effective way to improve CO₂ flooding efficiency in low permeability reservoirs with areal heterogeneity

Abstract:Aimed at the problems of strong channeling and high water cut in the mature development stage for horizontal well in low permeability oilfield due to severe heterogeneity of the reservoirs，the composite CO₂ foam huff and puff stimulation technology was studied，a. suitable foam YQY-1 system in CO₂ circumstance was screened，the optimal gas-liquid ratio CO₂ was determined and the water flooding-CO₂ huff and puff-composite CO₂ foam huff and puff was simulated in the laboratory. In addition，the composite CO₂ foam huff and puff technology was used in field. The results showed that the YQY-1 system had good foamability in the CO₂ circumstance. When the CO₂ and YQY-1 system was injected alternately at gas-liquid ratio of 1∶1，the injection pressure of the composite CO₂ foam huff and puff was increased by 1.9 MPa，and oil recovery was enhanced by 11.6%，compared to that of the CO₂ foam huff and puff. In the reservoir conditions，CO₂ foam system could temporarily plug high permeability reservoirs and fractures，and the subsequent gas injection could expand swept volume effectively and initiate the remaining oil in low permeability reservoirs. The results of the composite CO₂ foam huff and puff technology in the field indicated the oil production was increased and the water cut was decreased obviously.

Abstract:Whether CO₂ flooding could mix with crude oil under reservoir conditions directly affected the oil displacement efficiency. Therefore the miscible conditions between CO₂with crude oil and the minimum miscible pressure in miscible region were studied systematically in low permeability reservoirs. Selecting the low permeability target block in YC oilfield and under the simulated reservoir conditions，CO₂ flooding effects were acquired through the various series of experiments considering permeability，recovery，displacement velocity，gas-oil ratio，permeability differential as well as flooding pressure by flooding experiment in both homogeneous and heterogeneous rectangular cores. The method to determine the minimum miscible pressure by core experiment was established. The results showed that the method had good repeatability and could simulate low permeability or ultra-low permeability porous media and reservoir heterogeneity. The minimum miscible pressure was 18.5 MPa under the simulated reservoir conditions，which was the same as the calculation result of numerical simulation software and was 0.7 MPa higher than that of the traditional slim tube experiment. It reflected the consistency with two methods for the minimum miscible pressure. The effect of different factors，such as permeability，heterogeneity and displacement velocity on the minimum miscible pressure by core displacement experiment were studied. The core displacement experiment method could be used to determine the minimum miscible pressure in near-miscible region，which could deepen the mechanism realization of CO₂ near-miscible flooding and offer technological base and theoretical guidance for field application

Abstract:In order to obtain the influence of different alkalis on the emulsification and dynamic interfacial tension of heavy oil，the effects of inorganic alkalis including Na₂CO₃，NaOH，NH₃·H₂O and（NH₄）₂CO₃and organic alkalis including CH₃ONa，C₂H₅ONa and C₄H₉ONa on the viscosity of heavy oil and the dynamic interfacial tension between heavy oil and alkali were studied. The results showed that organic alkali had much better emulsifying ability than inorganic alkali. At the same time，organic alkali could avoid the scaling and corrosion caused by inorganic alkali to the pipeline. The influences of organic alkali or inorganic alkali on the dynamic interfacial tension between heavy oil and alkalis were different. The regular patterns of dynamic interfacial tension between heavy oil and inorganic alkalis were different with increasing dosage of inorganic alkalis. The mass fraction of NH₃·H₂O，（NH₄）₂CO₃，Na₂CO₃ and NaOH was 0.8%，1.0%，1.0% and 0.6% respectively，when the minimum interfacial tension reached. The interfacial tension between CH₃ONa or C₄H₉ONa and heavy oil decreased first and then increased with increasing dosage of organic alkali，and the mass fraction of organic alkali was 0.15% when the minimum interfacial tension reached. The interfacial tension between C₂H₅ONa and heavy oil showed a trend of increasing first and then decreasing gradually with increasing dosage of alkali. The organic alkali had an advantage over the inorganic alkali in the emulsification and viscosity reduction of heavy oil and enhancing oil recovery.

Abstract:In order to improve the performance of the polymer solution prepared with the tertiary oil recovery wastewater，compare to the KYPAM，the viscosification property，viscoelasticity，salt resistance，long-term stability performance and oil displacement properties was investigated，and the structure of HBPAM and KYPAM solution was observed. The research results showed that when the HBPAM concentration reached up to its critical association concentration of 1250 mg/L，HBPAM had stronger viscosity and viscoelastic properties. Compared with KYPAM，HBPAM had better salt resistance and long-term stability. The viscosity of the KYPAM solution，prepared from sewage with the concentration of 1500 mg/L，was only around 13 mPa·s after being aged for 180 days under the reservoir condition，and the viscosity retention rate was only 20%；while under the same treatment conditions，the viscosity of HBPAM solution was greater than 50 mPa·s，and the viscosity retention rate was about 80%. HBPAM solution had better shear resistance The viscosity retention rate of HBPAM solution with concentration of 1500 mg/L was 85%～89% after mechanical shear action of 1500 s^-1 and then stand for 24 h . SEM results showed that HBPAM has more regular three-dimensional network structure. Experimental results of core displacement showed that on the basis of water flooding，the injection of the 0.3 PV HBPAM solution with the concentration of 1500 mg/L could make the oil recovery be enhanced by 16.5%，which was 5.0% higher than that of KYPAM solution with similar viscosity and concentration of 1800 mg/L. Compared with KYPAM solution，the HBPAM solution with the same viscosity could effectively improve the heterogeneity of oil reservoir.

Abstract:Aiming at the problem of large viscosity and mining difficulty in Chenjiazhuang heavy oil production in Shengli oilfield， the ability of emulsified viscosity reducer to reduce the interfacial tension between oil and water and the ability to emulsify heavy oil were investigated，including emulsified viscosity reducer SS（anionic olefin sulfonates），SD（Anionic alkane sulfonates），nonionic emulsification viscosity reducer SF，SS+SF（mass ratio 1∶1）and SD+SF（mass ratio 1∶1）compound system. The microscopic experiments were conducted using SS，SD，SF and SS+SF systems. the experimental results showed that under the condition of mass concentration of 0.4% and temperature of 25℃，the interfacial tension between the simulated heavy oil and the emulsification viscosity reducer SD or SS system was 1.87×10^-2mN/m and 1.21×10^-2 mN/m，respectively，the viscosity of the emulsion formed with heavy oil，whose viscosity was 187 mPa·s，in mass ratio of 3∶7 was 42 mPa·s and 46 mPa·s，respectively. In the microscopic oil displacement process，the enhanced oil recovery rates of SD and SS anionic emulsification viscosity reducers system were 56.75% and 61.93%，respectively. Under the same conditions，the interfacial activity and ability to enhance oil recovery of SS+SF system was superior to that of the single component，the interfacial tension was reduced to 1×10^-4 mN/m or less，the viscosity of the emulsion with heavy oil was 30 mPa·s，and compared with the SF emulsifying viscosity reducing agent system，the recovery rate was enhanced by 14.9% . The emulsion viscosity reducing agent SS + SF was expected to be used as oil displacement agent in ordinary heavy oil field.

Abstract:In order to qualitatively study the displacement effect of polymer/surfactant composite system on heavy oil，the oil displacement process of the composite system in homogeneous microscopic glass model was observed by microscope，and the residual oil distribution in the image was analyzed by image processing technology. The recovery rate was calculated and the microscopic oil displacement mechanism of the composite system was analyzed and compared with that of surfactant，polymer and water flooding. The results showed that the recovery rate of water flooding could reach 56.94%，and the residual oil mainly existed in the form of column，oil droplet，membrane，blind end oil and cluster，etc. The residual oil of surfactant flooding was existed in the form of blind end and cluster，and the enhanced oil recovery rate of 1% anionic surfactant（BCJ-11）flooding was 29.46%. The residual oil of polymer flooding was mainly existed in the form of filament and oil film. The enhanced oil recovery rate of 100 PV 1500 mg/L partially hydrolyzed polyacrylamide（C6725）was 22.12%. The residual oil of composite flooding existed in the form of oil film. The enhanced oil recovery rate of composite system consisting of 1500 mg/L C6725 and 0.8% BCJ-11 was 34.59%. For several types of residual oils bound in the pores，the viscoelasticity and low interfacial tension of polymer/surfactant flooding system could cause the oil phase interface to form filaments for continuous migration. The composite flooding system displaced the residual oil in a wide range，and the washing efficiency of the affected area was high.

Abstract:In order to effectively prevent scale formation in the polymer-contained sewage reinjection formation，it took the polymer flooding demonstration oilfield SZ36-1 oilfield as an example. The indoor compatibility experiment and core dynamic damage assessment，nuclear magnetic resonance spectrometer，environmental scanning electron microscopy and other analytical methods were used to compare the differences in scaling mechanism between polymer-contained sewage and conventional water flooding oilfield production sewage. The results showed that calcium carbonate scale occurred in reinjection water of SZ36-1 oilfield. The calcium carbonate scale in common sewage had a high degree of self-formation and was cubic with a particle size above 20 μm. The produced polymer in the polymer-contained sewage increased the degree of incompatibility，and matched and bonded with Ca²⁺ by —COO^-，which caused the deformation from multilateral crystal of calcium carbonate to spherical nanocrystalline calcite（<5 μm）. The scaling crystal adhered each other，and cross-linked with the incompatible product，such as suspended solids，formation particles，residual polymers，and so on，by which generating composite blockages. The reservoir damage degree of polymer-contained sewage scaling was greater than that of ordinary sewage. The composite blockages attached to the surface of mineral skeleton，filled in the intergranular hole or membranoid substance plugged the pore throat. The blocking was mainly occurred in large and medium hole throat，which increased the depth and complexity degree of formation damage. The research results had important reference value for the optimization of water quality index system in polymer flooding field，and provided theoretical basis for on-site regulation and controlling of polluted water quality.

Abstract:Aiming at the problems of high quantity liquid production rate，high oil content sewage and short processing time on Zhaodong platform，the 3rd generation polyamide-amine hyperbranched polymer was prepared with diethylenetriamine and methyl acrylate as raw materials，and then reacted with dimethylamine and epichlorohydrin to obtain dendritic polyamide-amine polycation product KYOR. The branching degree effect of KYOR on oil removal rate and the compatibility of KYOR and demulsifier DGF-18B were studied. Finally，KYOR was applied in the field on Zhaodong platform by continuous injection. The results showed that in the spherical structure of hyperbranched polyamines，the termination and modification with quaternary ammonium salts could improve their hydrophilicity and molecular weight. Among the KYOR series products，KYOR-3 prepared by 3.0-generation polyamide-amine with the highest branching degree had the best oil removal effect. The new oil removing agent could reduce the oil content from 202.8 to 17.8 mg/L and the oil removal rate was high up to 91.22% in 20 minutes when the dosage of KYOR-3 was 30mg/L. Good compatibility was found between KYOR-3 and DGF-18B used on Zhaodong platform，which indicated that there was no effect on crude oil dehydration. The oil content，suspended matter and median particle diameter of injection water were all decreased after KYOR-3 was used in Zhaodong platform，which achieved the index requirements of reinjection water in Zhaodong platform

Abstract:Studying reservoir damage caused by the quality of polymer-contained sewage provided the evidence for the feasibility of reinjecting polymer-contained sewage. Taking the SZ36-1 oilfield of the Bohai Sea as an example，with the help of polarizing microscopy，environmental scanning electron microscope，nuclear magnetic resonance and other means of microscopic analysis， the four significant indexes of water quality including the concentration of emulsified oil，suspended solids and produced polymer， and particle median size，were quantitatively evaluated by the core dynamic damage experiment，and the damage mechanism of reinjecting polymer-contained sewage to reservoir was also discussed. The results showed that the synergy effect between oil， suspended solids and polymer was the main damage source，and the damage degree of reservoir increased with increasing magnitude of single index of water quality. The deformable mass with high strength due to the adsorption and aggregation of polymer molecules，was the key factor to cause the blockage of pore throat. When the polymer-contained sewage invaded into the reservoir，the polymer preferred to block the large and medium-sized throat，and the blocked behavior gradually transformed from the interior to the exterior of filter cake. Optimizing the treatment process of sewage water and the current dosing method was the key to solve the treatment problem of polymer-contained sewage.

Abstract:In order to reveal the wettability and wetting kinetics of quaternary ammonium Gemini surfactants，the wetting angle changes of six quaternary ammonium Gemini surfactants solutions such as 817，A37，A42，G50，G51 and G53 on hydrophilic/ lipophilic mica surface were determined by hanging drop method. The wetting properties of different kinds of surfactants were compared and the better ones were selected. Through the analysis of wetting mechanism，the wetting model of surfactant solution on mica surface was established and verified by experimental data. The results showed that the wetting reversal ability of G51 and 817 on the surface of natural mica was better than that of other ones，i.e.，the hydrophilic mica surface could be changed into strong lipophilic and weak lipophilic surface respectively because of the physical adsorption on mica surface by electrostatic attraction.While for oil treated mica，G50 and G53 were better，i.e.，the lipophilic mica surface could be changed into weak hydrophilic surface because of physical adsorption on mica surface by Van der Waals’force and electrostatic attraction. The correlation coefficient between wetting model and experimental data was 0.8803—0.9988，which indicated that the model was suitable for the characterization of wetting process of surfactant solution on mica surface.

Abstract:The fracturing fluid plays a vital role in hydraulic fracturing and its properties will directly influence on the fracturing operations and stimulation effect. The advantages，disadvantages and application of different fracturing fluids were analyzed. The rheological properties of water-based fracturing fluid at high pressure were described and the method of improving the rheological properties of water-based fracturing fluid by using nanomaterials as well as non-oxide gel-breaking were pointed out，providing a novel approach to improve the work efficiency and recycling of water-based fracturing fluid.

Abstract:With the development of deep/super-deep reservoir stimulation technology，urgent demand was proposed for ultra-high temperature fracturing fluid. In the last decade three different ultrahigh-temperature fracturing fluids were developed in China， including hydroxypropyl guar or carboxymethyl hydroxypropyl guar，modified guar gum and polyacrylamide，and synthetic polyacrylamide. The domestic applications and the latest development of three ultra-high temperature fracturing fluid technologies were introduced in this paper. The disadvantages and limitations of these fracturing fluids were summarized. Finally the research direction and keys to develop ultrahigh-temperature fracturing fluid were suggested.

Abstract:Due to the complex pore structure of sandstone reservoirs of continental sedimentary type and severe reservoir heterogeneity，the channeling-path formed after long-term water flooding aggravated the plane contradiction，and the recovery efficiency and development effect of oilfields were seriously affected. According to the origin，present situation，technical and economic requirements of channeling-path of sandstone reservoirs，six kinds of plugging agents which accorded with the characteristics of channeling-path of sandstone reservoirs were reviewed from the type of plugging agent，plugging mechanism and performance. The types of six plugging agents mainly included polymer gel，resin，particle，precipitation，microorganism and foam. The plugging agents had their own advantages and disadvantages. So it was necessary to study systematically and comprehensively the sealing method of channeling-path to select suitable plugging agents on the basis of the characteristics of sandstone reservoir.

Abstract:For chemical flooding，emulsification was one of the important mechanisms of enhanced oil recovery（EOR）. In the process of compound flooding，the emulsification could improve oil recovery significantly. The structure，properties and solubilization of surfactant-forming micelles in chemical flooding were introduced in this paper. The structure and properties of microemulsions and their applications in EOR were summarized. And the stability of emulsions and their effects in EOR were introduced. Finally，the development direction of compound flooding emulsification was summarized

Abstract:Biosurfactants have great advantages in the development of low permeability oil fields and heavy oil fields compared with other synthetic surfactants. The classification of biosurfactants was described. The mechanism of biosurfactant flooding was concluded. The field application methods of biosurfactants in oil fields，including extra situm and underground method were introduced，and the advantages and disadvantages of the two methods were analyzed. The results of the field application of biosurfactants in heavy oil fields and low permeability oil fields was put forward to prove that that biosurfactants have greater advantages in improving the oil displacement effect of oil fields with poor development conditions. At last，the advantages and disavantages of biosurfactants in EOR were summarized and some corresponding suggestions was put forward.

Abstract:Carbonate reservoirs widely distributed around the world，with a relatively high proportion of the total oil production. Due to the complex structure，the development of fractures，strong heterogeneity and preferential oil-wet characteristic，the oil recovery of carbonate reservoirs was always low with water injection. Chemical assistance was an effective method to further improve the oil recovery of such reservoirs. In order to further study the chemical EOR technology of fractured carbonate reservoirs，the mechanism，common used surfactants，and numerical simulation methods of chemical EOR for improving the recovery of fractured carbonate reservoirs were systematically summarized. Several examples of field projects that successfully applied surfactant-assisted method for oil recovery were introduced. Finally，the focus of future work and research direction were proposed.

Abstract:In view of the broad application prospects of the electro-demulsification method in oil field production，in order to improve the mechanism of micro-droplet coalescence of electro-demulsification，from the dynamics progress of disperse phase droplets deformation，proximity，rupture and coalescence，the research progress of coalescence mechanisms at home and abroad was systematically reviewed. Firstly，The effects of physical factors were first described in terms of moisture content，viscosity， conductivity，and surface tension of the droplets；secondly，the effect of electric field parameters，including electric field form， intensity，and frequency，on the coalescence velocity was reviewed significantly.

Abstract:Paraffin deposits in pipelines will reduce the flow area of pipelines，increase frictional resistance，reduce pipeline transportation capacity，and even cause significant economic losses and safety problems. Asphaltene has an important influence on the form of the wax. The structure of asphaltene is complex and diverse，leading to great differences in its polarity and surface activity. Interaction between asphaltenes and paraffin molecules has dual effects on paraffin precipitation. The structure of asphaltene，the promotion effects and inhibitory effects of asphaltenes on the paraffin precipitation was reviewed.