Abstract:In order to resolve the poor plugging performance of conventional bridge plug sealing material and the problem of repetitive leakage in drilling process of fractured reservoir，a kind of swellable particle plugging agent TP-2 was synthesized by aqueous solution polymerization，using acrylamide and acroleic acid as comonomers，potassium persulfate and sodium bisulfite as initiators，methylene-bis-acrylamide as chemical crosslinker and hectorite as physical crosslinker. The morphological structure，swelling property，water retention property，plugging performance and the effect of TP-2 on the property of drilling fluid were studied. The results showed that TP-2 was a kind of irregular particle and the initial average particle size was 190.5 μm. The plugging agent had good compatibility with drilling fluid. The swellable particle plugging agent sealed the permeable sands effectively with the maximum bearing pressure 11 MPa. TP-2 had good swelling property and water retention property. The expansion ratio was 75 g/g at 80℃ and the water retention rate was 38.4%. Temperature had a great influence on TP-2. The higher temperature，the better swelling property and the lower water retention of TP-2 was. The swellable particle plugging agent was suitable for the plugging of fractured reservoir under 80℃.

Abstract:In order to reveal the interaction mechanism between polyamine inhibitor PF-UHIB and bentonite，the interaction between polyamine PF-UHIB and sodium bentonite（Na-MMT）was investigated by FTIR，XRD，SEM and Zeta potential analysis. Molecular dynamics simulation of this interaction was developed by Material Studio software. The results showed that PF-UHIB could dissociated ammonium ions，which adsorbed on the interlays and surface of clay through electrostatic interaction and pushed out hydrone from clay interlays. The hydrophobic group of PF-UHIB prevented the contaction between hydrone and clay. Meanwhile，hydrogen bonds formed between polyamine molecules and siloxane groups in tetrahedral layers of the clay，which prevent PF-UHIB from entering into clay sheet. In this way，the hydration and swelling of the clay were inhibited effectively.The adsorption of PF-UHIB on the clay had an adsorption equilibrium state with Zeta potential of the clay was about -20 mV，and the dispersion of clay was inhibited availably. The SEM photos displayed that the bond of clay particles was tighter，and the dispersion degree of clay reduced obviously.

Abstract:In order to obtain lubricant for drilling fluid with low fluorescence level and good lubricating performance，a lubricant BDLU-100L was prepared by white oil，high efficiency emulsifier，extreme pressure agent chlorinated paraffin and penetrant succinate sodium alkyl sulfonate. The properties of BDLU-100L，such as fluorescence level，emulsifying stability，lubrication，temperature tolerance and salt resistance，and the effect on the rheological and wall building properties of drilling fluid were studied. The results showed that the fluorescence level of BDLU-100L was lower than three level. BDLU-100L had good emulsifying stability，and could be used at 200℃ and saturated brine. The lubrication coefficient of fresh water drilling fluid was reduced more than 90% by 0.5% BDLU-100L，and that of seawater，compound salt water and saturated brine water drilling fluid was reduced by 82%，73% and 71% respectively with 3% BDLU-100L addition，showing good lubricity. BDLU-100L had little effect on the rheological properties of fresh water drilling fluid and high temperature and high density drilling fluid. It applied to the high brine and high density drilling fluid below 200℃.

Abstract:To improve stability and filtration of water-based drilling fluid at high temperature and pressure in deep and ultra deep well drilling process， salt-resistant fluid loss additive HRF was synthesized by aqueous solution polymerization in an oxidation-reduction initiator system，using 2-acrylamido-2-methyl propionate sulfonic acid（AMPS），acrylamide（AM），acrylic acid（AA），N-vinyl pyrrolidone（NVP）and diallyl dimethyl ammonium chloride（DMDAAC）as comonomers. Optimal synthesis parameters of HRF were chosen as follows: mole ratio of AMPS to AM to AA to NVP to DMDAAC was 35:35:10:10:10，initiator dosage was 0.15%，reaction temperature was 50℃ and the mass fraction of the comonomers was 30%. The anti-temperature ability of the HRF was up to 230℃，and the salt resistance of the HRF could be up to be saturated，anti-CaCl₂/MgCl₂ was over 2%，which was better than that of the foreign products Driscal D and Dristemp. Filtration loss reducer HRF achieved a successful field application in yuanba 10-1H drilling fluid，the effect indicated that HRF could control effectively HTHP filtration loss of the drilling fluid，improve temperature resistance and rheology of slurry system，and prevent the viscosity of the slurry from reducing under high-temperature.

Abstract:In order to reveal the degradation behavior of zwitterionic copolymer thickener in acid at high temperature，a zwitterionic copolymer acidic thickener （CXS） was synthesized using methacryloyloxyethyl trimethyl ammonium chloride （DMC） and 2-acrylamido-2-methylpropane sulfonate（AMPS） . The degradation of CXS under 120℃ and different acid concentrations was studied through the change of viscosity，molecular weight，infrared spectrum and nuclear magnetic resonance spectrum before and after degradation. The results showed that the degradation degree of CXS obviously aggravated with increasing acid concentration，and the content of component with low molecular weight in degradation product increased. The viscosity of CXS degraded in 2%HCl solution reduced less than 40%，while that decreased more than 80% in 10% HCl solution. Under an acid environment and high temperature condition，backbone scission of CXS copolymer chiefly occurred during the degradation process，accompanied by ester bond and amide bond cleavage.

Abstract:In order to obtain the thickener for fracturing fluids with good performance， using acrylamide （AM） ，2-acrylamido-2-methyl-propanesulfon-icacid （AMPS） ， Styrene （St） and acrylicacid （AA） as raw materials， P（AM-AMPS-St-AA），named as TKF，was prepared by aqueous solution polymerization. The reaction condition was optimized by investigating the effects of monomer content，amount of initiator，reaction temperature，and reaction time on the viscosity of TKF solution. The structure of TKF was characterized by infrared spectroscopy，and the performances of the fracturing fluid used TKF as main ingredient，such as gelling ability，Temperature-resistance and Salt-tolerance，shear-resistance and gel breaking property， were evaluated. The results showed that，the TKF had good performance at following polymerization reaction，the content of St was 9% of the AM mass，the quality ratio of AM to AMPS was 3:7，the content of AA was 1.60% of the AM mass，the amount of initiator was 0.24% of the total monomer mass，the reaction temperature was 45℃，the reaction time was 4 hours，and pH was 8. The performances of the fracturing fluids of gelling ability，temperature-resistance and salt-tolerance，shear-resistance and gel breaking property were good. Adding 0.3% hexamethylene tetramine into the TKF solution with mass fraction of 0.3%，the gel was formed and the viscosity could reach up to 211 mPa·s，the temperature resistance of the gel was of about 150℃，the viscosity could remain 100 mPa·s when adding 10 g/L CaCl₂ into the gel solution，and the viscosity of the gel after shearing at 140℃ and 170 s^-1 for 120 min was greater than 90% of initial viscosity. In addition，the viscosity of the gel-breaking fluid could be reduced to below 5 mPa·s， after the gel was breaked by ammonium persulfate，and residue was little，reducing the damage to formation.

Abstract:pH was an important factor affecting the performance of hydraulic fracturing. The effect of pH on the swelling performance of hydroxypropyl guar gum，crosslinking properties，proppant settlement，guar gum degradation was studied. The results showed that，at the pH value of 7—10，the swelling time of hydroxypropyl guar gum was less than 20 min，while at the pH value of 11 —14 ，the swelling time was larger than 50 min ，the swelling rate at the pH value of 7 —10 was relatively higher than that at the pH value of 11 —14. The relationship between gel viscosity and shear rate could be described by the Ostwald-Dewaele equation，and at the pH value of 7—12，the consistency coefficient of hydroxypropyl guar gum solution was larger than 16744 mPa·sn，while the consistency coefficient at the pH value of pH 13—14 was less than 3130 mPa·sn. The proppant settlement experiments showed that，at the pH value of 9—12，the settling rate of proppant was relatively low，being of 1.31—5.94 mm/h；at the pH value of 7，8，13，the settling rate increased and the value was larger than 10.64 mm/h；and at the pH value of 14，the proppant settlement completed in 20 seconds. The hydroxypropyl guar gum degradation experiments showed that，the degradation rate at the pH value of 7—10 was larger than that at the pH value of 11—14. At the pH value of 7—12，the residue was relatively low， which was 400 mg/L. In summary，the best pH range was 9—10 for the entire construction process.

Abstract:In order to prepare the fracturing fluid with good heat resistance， a acrylamide copolymer thickening agent PAS-1 was prepared using acrylamide and acrylic acid as backbone monomers and sulfonic acid group monomer、 cationic monomer and long hydrophilic chain monomer as functional monomers. The best synthesis conditions were optimized by investigating the effect of the monomer proportioning and reactive conditions on its performance. The structure of the copolymer was characterized and the major performance of the formed fracturing fluid was evaluated. The optimization of experimental conditions was concluded as follows: the mole ratio of AM， AA， PSN， AP and DMDAAC was 4.5∶2.5∶0.80∶0.0040∶0.18；the initiator ammonium persulfate（APS） concentration was 0.8%；and the reaction was initiated at the temperature of 40℃ for 30 min and continued at the temperature of 60℃ for 24 h. The thickening agent PAS-1 had xcellent thermal stability at the high temperature within 300℃. The thickening agent PAS-1 had strong ability of increasing viscosity， and the viscosity of the PAS-1 solutions was up to be 43.7 mPa·s at the mass fraction of 0.6%. the sedimentation velocity of the proppants was 0.095 mm/min when the proppants was placed into the fracturing fluid containing 1% PAS-1 and 0.6% cross-linking agent SJ66， indicating that the fracturing fluid prepared by thickening agent PAS-1 had excellent sand-carrying ability. The final viscosity of the formed fracturing fluid system was above 50 mPa·s after continuously shearing for 120 min at the speed of 170 s^-1 and at the temperature of 200℃ ， possessing a good performance of temperature tolerance and shearing resistance. Therefore， the thickening agent PAS-1 could meet the performance requirements of high temperature fracturing fluid.

Abstract:For high temperature offshore reservoir with high content of calcium and magnesium ion，the stability of the conventional gel systems is poor. To improve the gel’ s tolerance to calcium and magnesium，thermophilic and halotolerant organically cross-linked polymer system was prepared with thermophilic nonionic polymer KF，organic aldehyde cross-linking agent REL， organic phenol cross-linking agent MNE and stabilizer WZ. The effect of polymer， cross-linking agents and stabilizer concentrations，temperature，salinity on gelling property was evaluated with the method of gel strength classification and breakthrough vacuum method. The best formula of the system for the reservoir was confirmed. The appropriate recipe at the temperature of 130℃was as follows，the KF dosage was 0.3%—0.6%，the REL dosage was 0.3%—0.9%，the MNE dosage was 0.3%—0.9%，and the WZ dosage was 2%. The gelation time could be controlled in the range of 4—50 h and the gel strength could be controlled in the range of 0.040—0.089 MPa. The lab experiment showed that the gel system containing 0.6% KF，0.6% REL，0.6% MNE and 2%WZ was thermophilic and halotolerant，while the volume retention was more than 90% after placed for 30 days in the environment of high temperature of 130℃ and high salinity of 2.0×105 mg/L monovalent salt or 8.0×103 mg/L divalent salt.The crosslinking system also had good shear resistance property and the volume retention was 100% after 30 days in the environment of high temperature（130℃）after different extent of shearing. Moreover，the system had consistent performance of flushing resistance，while plugging rate was still above 90% after 10 PV water flooding.

Abstract:In order to obtain the chromium gel with adjustable gelling time，good heat resistance and salt tolerance，and high intensity，chromium gel profile control agent which could be used for the reservoir with 50—90℃ was developed by adding additive to significantly improve the gel performance. GSC method based on the strength code and breakthrough vacuum method was used in this paper. The effects of HPAM mass fraction，Na₂Cr₂O₇ mass fraction，the mass ratio of Na₂SO₃ to HN，temperature and salinity on gelation time and gel strength were investigated. And core displacement experiment was studied to simulate the stratum plugging effect. The results showed that with the increase of HPAM concentration，the gelling time shortened and gel strength increased，with the increase of Na₂Cr₂O₇ concentration，the gelling time shortened and gel strength increased first and then reduced at high concentration，with the decrease of Na₂SO₃ and sulfide HN mass ratio，the gelling time delayed and gel strength reduced. The optimum formula of chromium gel was obtained as follows: 0.5% HPAM，0.24% Na₂Cr₂O₇，0.16% Na₂SO₃and 0.30% HN. The gelling time extended from 5 h to 17 h after HN was added，and the gel strength（breakthrough vacuum BV value） decreased from 0.076 to 0.070 MPa. The gelling time shortened and BV value increased when the temperature increased.While the gelling time prolonged and BV value reduced with increasing salinity. For high permeability tube，the plugging rate was more than 96%，and the oil recovery was improved by 21.6%—22.8%. The gel had good heat resistance，salt tolerance and thermal stability. It was suitable for the profile control water plugging of reservoir with salinity lower than 50 g/L and temperature in the range of 50—90℃.

Abstract:In order to prepare polymer weak gel profile control agent with high performance using oilfield sewage，the influence of sewage component on the gelling property of partially hydrolyzed polyacrylamide/lactic acid chromium gel was studied. The optimum formula of partially hydrolyzed polyacrylamide/lactic acid chromium gel system that was suitable for sewage was selected，and the plugging effect was investigated. The results showed that the gelling time of partially hydrolyzed polyacrylamide/lactic acid chromium gel system decreased and gel viscosity increased with the increase of Na⁺，Mg²⁺ and Ca²⁺ concentration and salinity. The gelling time increased and gel viscosity decreased with increasing concentration of S^2-. When the concentration of S²⁺ was more than 30 mg/L，it was hard to gel. The oil content had no effect on gel. The optimum formula of gel was obtained as follows: 1∶8 the molar ratio of chromium trichloride to lactic acid，2 g/L partially hydrolyzed polyacrylamide，200 mg/L crosslinking agent，800 mg/L thiourea. The gelling time was 25 hrs and the viscosity of gel was 20 Pa·s. The core plugging rate could reach more than 85% in three different permeability cores，indicating good compatibility between the gel and sewage.

Abstract:In order to reveal the influence of cations with same valence on gelling properties of weak gel，the influence of four common cations including Mg²⁺、 Ca²⁺、 Na⁺and K⁺ on gelling viscosity and stability of partially hydrolyzed polyacrylamide （HPAM） /Cr³⁺ weak gel was studied. The results showed that both the very low and high concentration of cations suppressed the gelation of HPAM/Cr3+ weak gel. When the mass concentration of HPAM was 3 g/L，the proper mass concentration range of Mg²⁺，Ca²⁺，Na⁺ and K⁺ that was conducive to form gel was 0.4—9 g/L，1.2—18 g/L，9—30 g/L and 16—55 g/L，respectively. The smaller cation radius，the more serious influence on gelling viscosity and stability of gel was. The four cations were arranged according to their influence on gelling viscosity of weak gel in following order: Mg²⁺>Ca²⁺>Na⁺>K⁺，and according to the stability of weak gel in following order: Mg²⁺>Ca²⁺,Na⁺>K⁺.

Abstract:The ultrafine Powder plugging agent is a highly effective new plugging agent， composed of 20%—30% superfine oil well cement，10% —15% nano-CaCO3，3% —5% ultrafine CaO，15% —20% nano-oxide containing silicon，iron and aluminum elements，3%—5% Na-bentonite，2%—3% NaCO3，1%—2% Phosphate，1%—2% Fe-Cr-lignosuifonate（FCLS），0.5%—1% HECMC，1%—2% AMPS and 1%—3%NaOH. According to different water-cement ratio，a series of ultra-fine plugging agents with different density was prepared，and its performance，such as the rheological property，the solidification time，the plugging rate to the cores，the compressive strength of the solidified body，and so on，was comprehensively evaluated by laboratory experiment，and the field application was carried out. The research results showed that the viscosity of the plugging agent with density of 1.4—1.8 g/cm³ was less than 35 mPa·s，the injectivity of the plugging agent was good，which could be injected into deep formation pore easily. Suspension of the plugging agents was good，when the density was greater than 1.6 g/cm³，Plugging agent slurry was hardly separated. The curing time of the plugging agent slurry could be adjusted，and the construction was safe，its initial setting time was 2.7—18.5 h，final setting time was 3.1—28.1 h. after the plugging agent slurry was cured，the solidified body（SB）did not contracted，the compressive strength of the SB was over 25 MPa，the SB was resistant to high temperature of 130℃ and salt of 20×104 mg/L. The plugging rate of plugging agent to the cores with different permeability of 20.5×10^-3—127×10^-3μm² was up to 99.9%，moreover，the outwash resistance and high temperature tolerance was good. The plugging agent had certain solubility，and the permeability recovery rate of the plugged cores was over 50% after the acid rock reaction. The field squeezing and plugging technology was applied in Wei 360 block of the low permeability reservoirs for 27 well times，the technological success rate reached 100%，and the effective rate of increase in oil production reached 100%.

Abstract:In order to obtain polymer microsphere for profile control and water shutoff with good suspension，high temperature resistance and high salinity tolerance，nanometer or micrometer polymer microsphere DCA which had a three-layer structure was synthesized by the monomer of acrylamide，initiator of azobisisobutyronitrile，crosslinking agent of divinylbenzene and emulsifier of ethoxylated lauryl alcohol sulfate. The basic performance of DCA microsphere was evaluated，including temperature resistance， suspension，expansion and plugging effect. The results showed that the particle size of DCA microsphere ranged from 0.1—30 μm and the shell had a nanoporous structure. The temperature resistance of DCA microsphere was up to 300℃，and DCA microsphere could be placed 90 days at 115℃. The sedimentation rate of DCA microsphere in simulated formation water with 28 hrs standin time was 0.005 mL/min，showing good suspension. The expansion ratio of DCA microsphere increased with increasing temperature. The maximum expansion ratio of DCA microsphere soaked 24 hrs at 115℃ in simulated formation water was 13.83%. After the experiment of profile control and water plugging with three layer heterogeneous cores，the amplitude of enhanced oil recovery was up to 7% and water-cut rate reduced by 5%. Domestic oilfield test showed that the liquid-producing capacity and water-cut rate reduced and oil increment each day was obvious after microsphere slug profile control. DCA microsphere was suitable for the deep profile control and water shutoff of high temperature and high salinity reservoir.

Abstract:Scale formed seriously when formation water and injection water mixed together for water flooding in Fanxue area of Yanchang oilfield. Water treatment technology was determined after ion content detection，compatibility and scaling tendency prediction of mixed injection water were studied. Then core damage experiment was done. The results showed that the salinity of formation water was as high as 104 mg/L and the concentration of barium and strontium ions was about 1000 mg/L. The concentration of sulfate was about 1000 mg/L in injection water. The critical step was how to control sulfate concentration during the same formation layer reinjection process. Strontium sulfate precipitate did not form if sulfate concentration was less than 100 mg/L， while barium sulfate precipitate appeared when sulfate concentration was greater than 1 mg/L. Use of the precipitant，scale inhibitor and a pre-mixing combined treatment process could improve the compatibility significantly，and the concentration of sulfate was less than 50 mg/L. The mixed water met the requirement of injecting water standard if 40 mg/L inhibitor was added. The core damage rate of the mixed water was 15% correspondingly.

Abstract:In order to understand the change of gas saturation during foam flooding under different injection parameters，and analyze the mechanism of foam flow in porous media，the effects of injection rate，gas-liquid ratio，permeability and oil saturation on foam resistance factor and sand pack gas saturation during foam flooding were studied through sand pack displacement experiment. The relationship of gas saturation and the plugging capability of foam was analyzed. The results showed that foam resistance factor increased with increasing injection rate and permeability，and increased firstly and then decreased with increasing gas-liquid ratio. When the gas-liquid ratio ranged from 1∶1 to 2∶1，the resistance factor increased from 172 to 194，and the plugging capability of foam was the best. When the oil saturation increased from 0 to 65.21%，the resistance factor decreased from 172 to 71. Foam had good selectivity to the permeability and oil-water layer. Injection rate and gas-liquid ratio had weak effect on the highest gas saturation and gas saturation after post water flooding. The highest gas saturation could reach more than 80%，and gas saturation after post water flooding could reach 60%—75%. The highest gas saturation and gas saturation after post water flooding increased first and then decreased with increasing permeability. The gas saturation decreased with increasing oil saturation. The relationship between gas saturation and the plugging capability of foam was good. When the gas saturation was higher than 60% in the sand pack，foam could form effective plugging，and resistance factor increased obviously.

Abstract:In order to understand the effect of the elasticity of polymer flooding system on the displacement efficiency of heavy oil with high viscosity，a flat sand inclusion visual flooding experimental device，which was used to simulate reservoir homogeneity， was established. Grey value method，a new quantitative evaluation method of oil displacement efficiency，was proposed. The elasticity of two typical polyacrylamide polymer，partially hydrolyzed polyacrylamide（HPAM）and hydrophobically associating polyacrylamide（HAWSP-2），and its impact on the displacement efficiency of heavy oil were studied. The experimental results showed that the shear resistance effect of HAWSP-2 was better than that of HPAM at low shearing rate，which was due to the existence of hydrophobic association. The flow index，the first normal stress difference，yield stress and deformation recovery rate of HPAM and HAWSP-2 with 100 mPa·s was 0.384，20.60 Pa，0.29 Pa，35.67% and 0.204，67.50 Pa，1.25 Pa，183.15%， respectively，indicating the elasticity of HAWSP-2 was greater than that of HPAM. In flooding experiment，with increasing viscosity of heavy oil，the oil displacement efficiency of HPAM and HAWSP-2 both decreased. But the oil displacement efficiency of HAWSP-2 was higher than that of HPAM. When heavy oil with same viscosity was flooded，four elastic parameters were arranged according to their changes corresponding the increase of per oil displacement efficiency in following order: deformation recovery rate>yield stress>the first normal stress difference>flow index， that was to say， the contribution of deformation-resilience，yield stress，the first normal stress difference and flow index to oil displacement efficiency increased. The effect of polymer elasticity on heavy oil displacement efficiency was positive correlation，and the flow index was the dominant factor of the effect of polymer elasticity on oil displacement efficiency.

Abstract:In order to improve the phenomenon that the producing degree of Pu Ⅰ 1—3 layers was uneven and the polymer circulated along high permeability layers inefficiently in Xingshugang oilfield，three tubes parallel core injection experiment was designed. The impact of olymer relative molecular mass，concentration and injection mode（single injection and alternative injection）on the recovery was researched，and the alternative injection cycle was optimized using numerical simulation method. The results showed that with increasing relative molecular mass and concentration of polymer，the core recovery increased. Single polymer could effectively flood the high permeability layer，but had poor effect in low permeability layer. The average recovery ratio of alternative injection polymer flooding was 3.3%—5.47% higher than that of single injection polymer flooding. The oil displacement effect of polymer flooding with first injection of high molecular weight polymer slug and then small molecular weight of polymer slug was better than that of reverse injection order polymer slug. The numerical simulation results showed that it was not conducive to control fluidity if the alternate injection interval was too long，while it was easy to cause viscosity loss if the time interval was too short，which resulted in the loss of a large amount of energy and was not conducive to oil displacement. So the best alternative injection period was 3 months，which could increase the recovery ratio by 11.68%.

Abstract:In order to study the influence of start-up pressure gradient on the percolation law of polymer flooding in low permeability reservoir，laboratory experiments were conducted with the combined method of differential pressure-flow and capillary equilibrium. Under the condition of residual oil saturation with water driving，the effects of core permeability and polymer viscosity on polymer flow curves were studied. Quantitative relations between minimum or quasi start-up pressure gradient and viscosity，core permeability or mobility were established. The results showed that displacement pressure gradient increased with increasing polymer viscosity and decreasing core permeability under the same seepage velocity. And with the increase of viscosity or the decrease of permeability and mobility，the minimum or quasi start-up pressure gradients of polymer flooding increased，which were greater than the start-up ressure gradient values of water flooding under same conditions. The inflection point was 17.89×10^-3μm²/mPa·s in the relation curve of quasi start-up pressure gradient and mobility，and the lower limit of permeability was 10×10^-3μm² with polymer flooding in low permeable reservoir. The method used for water flooding quasi start-up pressure gradient could be used to characterize the quasi start-up pressure gradient of polymer flooding flow curve.

Abstract:In order to discover the oil displacing action and the enlarged swept volume mechanism of emulsion in porous medium， the mixed system of betaine surfactant and nonionic surfactant was used to conduct experiments based on the geological features and fluid characteristics of major blocks in Daqing oilfied. The oil displacing action of the emulsion and the produced fluid proportion in layers with different permeability was studied on triple parallel heterogeneous cores with different permeability variation oefficient using core emulsification way to simulate the underground emulsification process，and the emulsion flooding mechanism was probed from the aspects of relative permeability curve and Jamin effect of the emulsion flooding by comparing with that of the surfactant flooding with the same interfacial ability. The result showed that the greater permeability variation coefficient，the reater the oil recovery degree of the emulsion flooding，the greater the reduction of the produced fluid capacity in high permeability layers.As for the heterogeneous cores of three layers with even permeability of 400×10^-3μm² and permeability variation coefficient of 0.72，the oil recovery of emulsion flooding was more than that of water flooding by 16.98% and fluid production in middle-low permeability layers was more by 16%. The emulsion could play a better plugging role in the displacing process due to the jamin effect，and the relative permeability curve of the water phasev was changed，as a result，the emulsion had good controlling fluid action，which could avoid the channeling phenomenon which happened in surfactant flooding.The emulsion was able to enlarge the swept volume in late high water cut stage，which was mainly due to the change of water phase relative permeability raised by the viscoelasticity of emulsion and Jamin effect of emulsion of large particle size. The oil displacing effect of the emulsion flooding was better than that of the surfactant flooding.

Abstract:In order to study the influence of the component in Changqing crude oil on the interfacial tension of surfactant solution， the crude oil fractions were obtained by four-fraction separation method and NaOH/ethanol mixture extraction. The interfacial tension between crude oil fraction and betaine surfactant solution was measured. The results showed that single fraction，such as saturate，aromatic and asphaltene had low contribution to the formation of ultra-low interfacial tension. On the other hand，the interfacial tension between non hydrocarbon component and betaine surfactant could reach 4.82 × 10^-3 mN/m. The equilibrium interfacial tension between petroleum acid in non hydrocarbon component and surfactant was 0.347 mN/m，while the interfacial tension between petroleum alkali and surfactant decreased rapidly and then increased to about 0.1 mN/m. Single petroleum acid or petroleum alkali could not effectively decrease the interfacial tension to low value，furthermore they had the opposite interface characteristic. The interfacial tension between the compound system of petroleum acid and petroleum alkali and the surfactant was 4.70×10^-3 mN/m. The synergistic effect of petroleum acid and petroleum alkali caused the interfacial tension between crude oil and betaine surfactant to reach ultra-low value.

Abstract:In order to investigate the effect of shear action on enhanced oil recovery of spontaneous emulsification system，the oil displacement efficiency of spontaneous emulsification system under different sandpack permeability，displacement rate of chemical flooding and shear strength was investigated through introducing two parameters including dimensionless shear rate and effective mobility ratio of water to oil. The results showed that when sandpack permeability was high and the displacement rate of chemical flooding was low，the dimensionless shear rate was low，the particle size of emulsion droplet formed was large. Droplets could coalesce in pore throat and generate strong Jamin effect，and the effective mobility ratio of water to oil reduced so as to increase the sweep efficiency and oil recovery. The dimensionless shear rate increased with decreasing sandpack permeability or increasing chemical flooding displacement rate，which led to a reduce in particle size of emulsion. Emulsion droplets were insufficient to plug water channel effectively and entrained out of formation with displacing fluid，due to limited capability of reducing the effective mobility ratio of water to oil result in lower oil displacement efficiency. Therefore，the effect of enhanced oil recovery of emulsification and entrapment effect of spontaneous emulsification flooding was better than that of emulsification and entrainment effect，and the oil recovery could be improved by reducing the dimensionless shear rate during flooding.

Abstract:In order to enhance the recovery of heavy oil reservoir with middle and low permeability，emulsifying and viscosity reducing technology was developed. The effect of emulsifier concentration，oil-water ratio and shear rate on the state and performance of emulsion was evaluated. Oil displacement efficiency of polymer slug and emulsifier-polymer slug which had the same viscosity was studied，and the mechanism of enhancing oil recovery by combination flooding was analyzed. The experiment results showed that the viscosity of emulsion decreased first and then increased with the increase of emulsifier concentration，while the droplet size of emulsion became smaller gradually. For Fuyu heavy oil，the optimum mass fraction of emulsifier was 0.3%. O/W emulsion could be triggered when oil-water ratio was lower than 55∶45. With increasing shear rate，the emulsion viscosity decreased first and then increased. When the shear rate reached 45 cm/min，the emulsion completely became O/W，however，when the shear rate reached 450 cm/min，the emulsion completely became W/O. When polymer slug or emulsifier-polymer slug was injected after water flooding，the recovery was improved by 10.5% or 25.4% respectively. Emulsifier-polymer flooding could not only enlarge sweep efficiency，but also reduce interfacial tension，emulsify crude oil and enhance oil recovery.

Abstract:Aimed at the characteristics of hypercoagulable，high viscosity and high salinity in Kongnan block of Dagang oilfield and the poor development effect of water flooding，the feasibility of the application of hydrophobic associating polymer/surfactant displacement system was probed. The dimension of polymer molecular coil Dh，interfacial tension between the crude oil and the hydrophobic associating polymer AP-P7 solution or“polymer/surfactant”displacement system，compounded of AP-P7 and nonionic surfactant Guan 109PS985，and their influential factors were studied under the experimental conditions，and β-cyclodextrin（β-cd） was used as the regulator to improve the suitability of polymer with oil reservoir，also the EOR mechanism of polymer flooding and “polymer/surfactant”displacement system in high viscosity and high condensate reservoirs was analyzed. The results showed that， β-cd could change the molecular morphological structure of the hydrophobic associating polymer，and make the matching of the polymer structure and core pore throat stronger，resulting in the reduction of the blockage. The viscosity hydrophobic associating polymer solution and“polymer/surfactant”system prepared with soft water，increased by 35.2% and 20.2% compared to that of the inject water，the viscosity of the polymer solution at the concentration of 2000 mg/L prepared with injected water and soft water， respectively，were 223.4 mPa.s and 302.5 mPa·s，When adding 700 mg/L of β-cd，the viscosity decreased to be of 26.5 mPa·s and 35.3 mPa·s，respectively，which indicated that the addition of the β-cd made the viscosity of AP-P7 solutions decrease obviously. When the concentration of β-cd increased from 10 mg/L to 700 mg/L，the D_h of AP-P7 decreased from 235 nm to 155 nm. In addition，when the concentration of β-cd increased from 10 mg/L to 700 mg/L or the concentration of Ca²⁺ and Mg²⁺ decreased from 508 mg/L to 0，the interfacial tension between the polymer system and the simulated reduced to some degree. The 2000 mg/L polymer solution containing β-cd was injected into the core with permeability of 3500×10^-3 μm²，and the residual factor and residual resistance factor of polymer solution reduced from 35.6 and 15.9 to 25.7 and 11.0，respectively，when the β-cd dosage increased from 0.001% to 0.07%. After adding 0.02% β-cd，The viscosity of the“polymer/surfactant”system（C_p=2000 mg/L，C_s=2000 mg/L）prepared with soft water was of 81.5 mPa·s，which was higher that prepared with the soft water containing stains，while，the residual factor and residual resistance factor of the latter was higher than that of the former，and the injection pressure of the latter was higher than that of the former.

Abstract:In order to get the accurate polymer/surfactant combination flooding relative permeability curves of Bohai Suizhong 36-1 oilfield，a new viscosity treatment method，taking the average value of combination system viscosity in the core entrance and that in the core exit as the average viscosity in whole core under some water saturation，was suggested. On the experimental condition of Suizhong 36-1 oilfield，the relative permeability curves of water flooding and polymer/surfactant combination flooding were measured through the constant speed unsteady method. And the effects of surfactant and polymer concentration on the relative permeability curves of polymer/surfactant flooding were studied. The results showed that the relative permeability of oil phase in combination flooding was higher than that in water flooding，while the relative permeability of water phase in combination flooding was lower than that in water flooding，and the residual oil saturation of combination flooding was lower than that of water flooding. The higher mass fraction of surfactant，the higher relative permeability of water and oil phase was，and the lower residual oil saturation was. While the higher concentration of polymer，the higher relative permeability of oil phase was，and the lower relative permeability of water phase and residual oil saturation was.

Abstract:The binary system of cocamidopropyl betaine（CPB）and polyacrylamide（PAM）as foaming agent was prepared to develop foam drainage technology suitable for high sulfur gas well in Northeast Sichuan area. The effect of mass ratio of CPB and PAM on the foaming ability of binary system was studied，and its resistance performance of temperature，hydrogen sulfide and salt， etc was investigated. The results showed that CPB/PAM binary system achieved the best frothing ability with mass ratio of 6∶1. This system had good thermal stability at temperature as high as 175°C. The initial foam height only declined 16.6% after aging. The foaming ability of CPB/PAM binary system was not affected by H2S partial pressure. The foaming agent exhibited good salt-resistance and liquid carrying capability，which applied to the foam drainage of high sulfur gas well.

Abstract:In order to promote the development of viscosity reducing methods and obtain controlling factors of the viscosity of heavy oil，15 super heavy oil samples chosen from Tahe and Lungu oilfield were investigated. Analysis methods including viscositytemperature characteristics，four components（saturate，aromatic，resin and asphaltene）separation，element composition analysis were conducted，and then correlated with the viscosity of crude oil. The effect of aquathermolysis on the viscosity of heavy oil was studied. The results showed that there existed structure viscosity in heavy oil，and the viscosity-temperature curve accorded well with Arrehenius equation. The viscosity was connected with the component of heavy oil，decreasing with increasing content of saturate，aromatic or resin. And with the increase of asphaltene content or decrease of colloidal stability parameter（mass ratio of resin and asphaltene），the viscosity increased in an exponential means. The viscosity had a positive correlation with content of N and Ni，while the correlation between viscosity and content of V and S was not clear. Additionally，the smaller atomic ratio of H to C，the higher aromatic carbon ratio，the greater viscosity of heavy oil was. Aquathermolysis of LG-01 heavy oil was conducted to reduce its viscosity. The results showed that the viscosity（80℃）of oil sample varied from 34965 mPa·s before reaction to 12165—295858 mPa·s，corresponding with the change of component. After aquathermolysis，the corresponding content of asphaltene ranged from 21.50% to 29.22%，colloidal stability parameter ranged from 1.19 to 0.63，atomic ratio of H to C decreased and the content of heteroatom including S and N increased.

Abstract:In order to reveal the relationship between heavy oil property and sandstone wettability，the functional groups and Zeta potential of asphaltenes and resins from different areas were investigated by X-ray photoelectron spectroscopy and Zeta potential analyzer. The relationship between Zeta potential of heavy constituents in viscous crude oil（asphaltene or resin）and sandstone wettability index was studied by the improved core wettability detection method and the effect of cations and anions in brine on core wettability where asphaltene had been adsorbed was analyzed. The results showed that the asphaltene of Liaohe oilfield carried negative charge because of a high mass fraction of carboxylic acid and carboxylic acid calcium，while asphaltene of Tahe，Gudao， Karamay and Kendong oilfield carried positive charge. The more positive charge of asphaltene and resin，the greater change of wettability index was. As a result，wettability index（W_R）and Zeta potential（ζ）of asphaltene and resin constituted logarithmic function relation: ζ=-2.9508 ln（WR）. Once the inorganic cation had a higher valence，there was a lower wettability index，while there was a slight impact of inorganic anion on wettability. The wettability change trend of sandstone rock could be estimated by the quantitative formula between wettability index and Zeta potential of asphaltene or resin，and the change degree of wettability caused by asphaltene deposition could be controlled by adjusting the composition of injection water.

Abstract:In order to reduce the viscosity of heavy oil in Chennan station of Shengli oilfied，seven kinds of surfactants whose HLB value between 8 and 18 were selected. By measuring the dehydration rate and viscosity reduction rate of the emulsion with single and compound emulsifiers，the emulsifiers which had both good static stability and viscosity reduction effect were selected. The effect of the mass ratio of oil to water，emulsifier concentration，emulsifying temperature and strength on the viscosity was investigated. The results showed that when the emulsifying temperature was 50℃ and emulsifying strength was 2000 r/min×10 min，two kinds of optimum compound emulsifiers were selected，including 25.8% Span80 and 74.2% sodium dodecyl benzene sulfonate，10.1% Span80 and 89.9% sodium dodecyl benzene sulfonate，whose dehydration rate was 21.8% and 23.0% and the viscosity reduction rate was 99.92% and 99.89% at 100 s^-1 respectively when they were put into heavy oil and placed for 5 hrs. The dehydration rate of emulsion increased，the viscosity decreased and the stability deteriorated with decreasing mass ratio of oil to water. The viscosity of emulsion decreased first and then increased with increasing emulsifier concentration. The viscosity of emulsion increased with decreasing emulsifying temperature and increasing emulsifying strength. The viscosity of heavy oil in Chennan station could be reduced from 1964 mPa·s to 35 mPa·s under the emulsifying condition of 5∶5 mass ratio of oil to water， 1% dosage of emulsifier，50℃ emulsifying temperature and 1000 r/min×5 min emulsifying strength.

Abstract:Considering the emulsion stabilized by organic base and compound surfactants was too stabile to separate automatically，and in order to obtain an efficient demulsification technique，the effect of pH，demulsifier，flocculant and temperature on the demulisification of this kind of heavy oil-in-water emulsion was investigated. The experiment results showed that pH had a prominent effect on the demulsification of emulsion. The water separation rate reached its highest point 59.6% when the solution was neutral. When the pH value was equal to 7，the demulsification effect of different demulsifiers was various，and three demulsifiers were arranged according to their influence on water separation rate in following order: CTAB（cationic）＞RK（nonionic）＞SDS（anionic）. The separated water and oil/water interface were both clear under the influence of RKP，and the water separation rate reached its maximum value 68.0% with 0.01% RKP dosage. The demulsification effect of system with different kinds of flocculant was different，and the water separation rate of emulsion increased first and then decreased as the flocculant concentration increased. Three inorganic flocculants were arranged according to their influence on water separation rate in following order: PAC＞FeCl₃·6H₂O＞AlCl₃·6H₂O，and three organic flocculants were arranged in following order: CPAM（cationic）＞PAM（nonionic）＞HPAM（anionic）. CPAM could significantly improve the water separation rate. The water separation rate increased with increasing temperature. The effect of temperature on the demulsification under the influence of HCl solution was insignificant， but that on binary system and ternary system which were respectively composed by HCl and RKP，HCl，RKP and CPAM were prominent. The suitable demulsification condition of Tahe heavy oil was obtained as follows: pH=7，0.01% RKP，0.008% CPAM and 70℃，on which the water separation rate could reach 98.4% with 2 hrs breaking time.

Abstract:In order to analyse the growth behavior and the influence of scale inhibitor on it，electrochemical quartz crystal microbalance（EQCM）was used to measure the scaling process rapidly. The effect of applied potential，temperature and the concentration of Ca²⁺ on the scaling of CaCO₃ was studied. Additional evaluating of scaling inhibition properties of three scale inhibitors，such as 1-hydroxyethylidene-1，1-diphosphonic acid（HEDP），copolymer of phosphono and carboxylic acid（POCA） and amino trimethylene phosphonic acid（ATMP）was conducted. Partial fitting of scaling curve was also carried out. The results showed that the scaling rate increased with the increase of potential，temperature and the concentration of Ca²⁺ . Particularly， polarization potential had remarkable impact on the scaling process. The total scaling amount decreased with the increase of scale inhibitor concentration at 50℃. The optimum dosage for HEDP was 5—10 mg/L，while 20 mg/L for POCA and ATMP respectively. There were three stages of the scaling curve with 10 mg/L dosage of scale inhibitor，such as scaling，the diffusion of scale inhibitor and stable stage. Two stable depositing process equations were obtained by fitting the experimental data，and the slope value k standed for the kinetic parameter of scaling. The inhibition efficiency of POCA，HEDP and ATMP was calculated as 98.50%， 93.86% and 97.23%，with the diffusion time of 1021，622 and 537 s，respectively，by regarding the deviation of k before and after adding the scale inhibitor. ATMP had the best inhibition performance among three scale inhibitors.

Abstract:In order to reveal the dynamic process of scaling in oil gathering pipeline，CaCO₃ was typically introduced to explore the dynamic mechanism of scaling in circular pipes. Based on the fluid flow process，the flow patterns and reaction rate constant of CaCO₃ scaling were measured by pulse tracing method and electrical conductivity method using homemade scaling dynamic analyzer. With the average residence time distribution，the one-dimensional axial dispersion model of scaling fluid was established. The results showed that the back mixing phenomenon of CaCl₂ and Na₂CO₃ water solution was more obvious than that of deionized water（blank）. The rate constant of CaCO₃ scaling during the process of flow in a circular tube was 0.025 L/（s·mol）. According to the established model，the conversion rate of CaCO₃ scale was 53.600% . The relative error between calculated value and experimental value was 5.438%，indicating an accurate prediction for the developed dynamic model，which should provide basic information for scale prevention design in circular pipe.

Abstract:In order to investigate the effect of non-ionic gas-wetting agent on the wettability of cores，obtain gas-wetting sandstone core and enhance the gas-condensate recovery，gas-wetting and surface free energy of cores before and after treatment were measured using contact-angle measurement and Owens two-liquid method respectively. Meanwhile，the effect of inorganic salt，temperature and pH value on the gas-wetting core and the lasting time of gas-wetting were studied. The results showed that the wettability of core was altered from liquid-wetting into gas-wetting by 0.3% non-ionic fluorocarbon surfactant（FG24）treatment， the contact-angle of water and decane on the surface of core increased from 36.0° and 0° to 141.3° and 108.0°，respectively，and the surface free energy of core sharply decreased from 71.0 mN/m to 3.29 mN/m. The treated core could keep preferential gas-wetting on the condition of pH=1—10，100 g/L inorganic salt and 140℃. The contact angle of water and decane on the surface of core was larger than 90°，and FG24 had a long term validity about 60 days. FG24 could alter the rock surface to strong gas-wetting and show excellent heat resistance and salt tolerance.

Abstract:In order to enhance the accuracy of the detection of particle median diameter in oilfield injected water，the effect of several aspects on the measurement was discussed，such as sampling method，temperature and pressure，bacteria，agglomeration， stirring speed，concentration and oil content. The effect of standard of instrument measurement was also taken into consideration. The results showed that the exposure of oxygen，temperature，pressure and agglomeration would amplify the test result with th extension of storage time，while the influence of bacteria could be ignored，and stirring speed，concentration and oil content would cause the test result to appear deviation. Isolation of oxygen and adding EDTA could improve the stability of water. An appropriate stirring speed and water concentration should be established and the storage time should be decreased to exclude the effect of oil when using laser particle size analyzer. During the measurement，it should consider the effect of particle volume and number，and establish a reasonable evaluation benchmark.

Abstract:When the concentration of polymer in ternary compound system of Daqing oilfield was detected by turbidimetric method，the test result could be influenced by alkali and surfactant. In order to measure more accurately the concentration of polymer in ternary compound system，the research on the improvement of turbidimetric method was carried out，the effect of surfactant was eliminated by salt-out extraction analysis method and the effect of alkali was removed by increasing the dosage of acetic acid. The application of improved turbidimetric method in the determination of polymer concentration in produced fluid of oil well was studied. The results showed that the improved turbidimetric method eliminated the interference of surfactant and alkali in ternary compound system，and improved the accuracy of test results. When improved turbidimetric method was used to detect the polymer concentration of ternary system in laboratory，the relative error decreased from 2.00%—50.25% to -4.40%—2.00%，while used to detect the polymer concentration in produced fluid of oil well in alkali ternary compound pilot area of Lamadian oilfield，the relative error was 1.90%—5.20%.

Abstract:The deposition of asphaltene in near wellbore zone would have seriously negative impact on oil exploration. Therefore， the development of asphaltene deposition control technology had very important significance on the security of oil’s efficient exploitation. The research and application of oil asphaltene deposition control technology of oil well was introduced，such as asphaltene inhibition technology and asphaltene blockage removal technology. The asphaltene inhibition technology included the adjustment of production plans and chemical inhibition method. While the asphaltene blockage removal technology included physical blockage removal method，chemical blockage removal method，biological blockage removal method and the combined blockage removal method. Some suggestions about the development of asphaltene inhibition and blockage removal technology were given.

Abstract:On account of the difficulties confronted with the unconventional hydrocarbon resources during the exploration and development progress，which often depends on the hydraulic fracture stimulation，combining with the channel fracturing technique rising up in the past several years，the latest advances of self-initiated aggregating proppant（SIAP）overseas were introduced. The present research status of SIAP，surface modification mechanism，and on-the-fly coating technology was mainly summarized. The troubles that SIAP faces and the future trends were also pointed out.