Abstract:The low-density cement slurry often had the problems of poor compression resistance，bad stability and low compressive strength. It often presented poor performance if the cost was reduced，which could not meet the requirements of reducing cost and increasing efficiency of oilfield. Aiming at the problems，the nanotechnology was introduced into low-density cement slurry. The nanometer material X with size 20—70 nm which composed of silicon，calcium and other elements was modified by polycarboxylic acid surface modifier. Lightening and strengthening material LEM with high water demand was prepared by the combination of material mainly composed of silicon oxide and hollow microsphere. The performance of low-density cement slurry （ 1.30 — 1.50 g/cm³）prepared by modified nanometer material X，LEM，cement，fluid loss additive，retarder and water was studied，and field application was carried out in Shengli oilfield. The results showed that the modified nanometer material X was able to obviously improve the stability of cement slurry and enhance the strength of cement stone. The nanometer low-density cement slurry could resist high pressure，whose density difference could be controlled within 0.05 g/cm³ after exerting pressure to 60 MPa. The nanometer low-density cement slurry with high water cement ratio was able to keep excellent stability and high strength. What is more，it relieved the contradiction between cost and performance of normal low-density cement slurry. The nanometer low-density cement slurry presented low cost and well comprehensive performance and had been successfully applied in Shengli oilfield.

Abstract:During testing process in deepwater HTHP oil and gas well，the main problem was the heat conduction and heat exchange between oil，gas，riser and outer seawater，which decreased the temperature of fluid in wellbore and easily caused salt-out and gas hydrate. Aiming at the problem and basing on the principle of heat transfer between wellbore fluid and seawater decreased by low thermal conductivity fluid，a solid-free and high density insulating testing fluid was developed through indoor selection of base fluid，aggravating agent and corrosion inhibitor. The thermal conductivity，gas hydrate inhibition，high pressure crystallization and high temperature corrosion of the fluid were studied. The results showed that the solid-free high density insulating testing fluid for deepwater HTHP well operation had low thermal conductivity that was less than 0.34 W/ （m·K），good gas hydrate inhibition without crystallization at -30℃ ，and good corrosion resistance with 0.004—0.041 mm/a corrosion rate at 120—180℃ . The solid-free high density insulating testing fluid with 1.05—1.7 g/cm³ density which was composed of 40%—50% low conductivity base fluid LOWCTF，0.5% deoxidizer HBSJ-0，0.2%—0.3% corrosion inhibitor HBSJ-1，2%—4% corrosion inhibitor HBSJ-2，and weight additive calcium salt，was suitable for the operation of deepwater HTHP wells.

Abstract:2-hydroxy-3-n-octadecyloxy propyl guarhum （HOPG） was synthesized with guar gum（GG） as material，using n-octadecyloxy propyl glycidyl ether（OPGE）as the hydrophobic reagent，sodium hydroxide as catalyst and 95% ethanol as solvent through ring opening addition reaction. The crosslinking performance，temperature resistance and shearing performance，breaking performance of the HOPG fracturing fluid were evaluated by simulating the scene formula. The experimental results showed that the HOPG had better solubility and crosslinking performance. When breaking the gelled fracturing fluid，composed of 0.3% HOPG + 0.3% JL-13+0.2% APS，at 90℃ for 1 h，the insoluble content of the broken fluid was only 182 mg/L，and the viscosity of the broken fluid was only 1.02 mPa·s，which was obviously lower than that of the broken fluid prepared with the GG. Moreover，the temperature resistance and shear resistance of the HOPG fracturing fluid was better，the apparent viscosity of the HOPG fracturing fluid was 165 mPa·s when sheared for 70 min at the temperature of 80℃and at the shear rate of 170 s^-1.

Abstract:In order to solve the problems of hard recycling，high cost，inefficiency of guar gum fracturing fluid，an efficient oil-displacement clean fracturing fluid system with near peptide chain structure viscoelastic surfactant as main component was prepared. The performances of temperature and shear resistance，salt tolerance，gel breaking and oil displacement of this fracturing fluid were studied. Finally，it was applied in Longdong oilfield. The results showed that the fracturing fluid had good temperature resistance（90℃）and salt tolerance（100 g/L）. The addition of organic acid regulator in fracturing fluid could reduce the effect of water salinity on the viscosity of fracturing fluid. The fracturing fluid had good sand carrying property and broke gel thoroughly with 2 mg/L residue content. The interfacial tension between broken fluid and kerosene could reach 10^-2—10^-3 mN/m. The fracturing fluid had been successfully applied to 25 wells in oilfield，and the output of single well was 6 times than that of adjacent wells. The fracturing fluid could be prepared again after simple treatment such as separation and sedimentation，and used for oil displacement after end-effluent treatment. The oil recovery rate increased by 10.67% on average on the basis of water flooding. The environmental pollution caused by fracturing fluid could be greatly reduced.

Abstract:Zwitterion guar 2-hydroxyl-3-（N，N-dimethylglycine）propyl guar gum（HDPG）as high temperature thickener，used for seawater based fracturing fluid，was synthesized from guar and（2-hydroxy-3-chloride）-propyl dimethylamino acetic acid. The effect of dosage of etherifying agent，sodium hydroxide and etherification temperature，etherification time on the substitution degree was studied，and the swelling property，shear resistance property，and break character of HDPG were researched. The optimum reaction condition of thickener was obtained as follows，molar ratio of etherifying agent to guar was 0.18∶1，molar ratio NaOH to guar was 0.125∶1，the etherification temperature was 70℃，the etherification time was 6 hours，the substitution degree of HDPG was 0.43. On the condition of stirring rate of 500 r/min and the swelling time of 10 min，the viscosity of 0.5% HDPG solution reached 85% of final viscosity，which met the requirement of continuous mixing. The viscosity of seawater base fracturing fluid prepared by synthesized thickener and self-made crosslinking agent was above 50 mPa·s at the temperate of 170℃ after sheared for 120 min at the shearing rate of 170 s^-1，which indicated that the seawater based fracturing fluid had good shear resistance. In addition，HDPG seawater base fracturing fluid had good gel-breaking performance，the viscosity of gel breaking liquid being of 1.36 mPa·s，and the residue content being of 326 mg/L.

Abstract:Foam acid has the advantages of high viscosity，low filtration and easy backflow，but the poor performance of high temperature tolerance and high salt tolerance are seriously restricting the application of the foam acid system in Tahe oilfield. In order to improve the acidification effect of foam acid in horizontal well，a new type of deep penetration foam acid system with high temperature and salt resistance，composed of 20% HCl+1% iron stabilizer XC-16 +2% corrosion inhibitor XC-13 +1% demulsifier XC-08 +0.9% blowing agent FRC-1+0.3% stable foam agent CNC+1.5% inorganic SiO2 nanoparticles，was developed，then the stability，salt resistance and acid rock reaction of the foam system was investigated. Experiment results showed that the viscosity of the foam acid was more than 40 mPa·s after sheared for 30 min at the temperature of 150℃ and at the shear rate of 170 s ^-1，which indicated that the temperature resistant performance of the foam acid was better than that of the gelled acid，the viscosity under the same experimental conditions being of 20 mPa·s. The foam acid system developed in the study was able to maintain good foaming and foam stabilization performance in 10×10⁴ mg/L high salinity conditions，the foaming volume was 400 mL and the foam half-life was 2435 s. The systems were arranged in order of the acid rock reaction rate at the temperature of 150℃，the sequencing was foam acid

Abstract:The widespread use of hydraulic fracturing has resulted in a dramatic increase in the demand of fresh water and the treatment of flowback water. In order to relieve the shortage of water and decrease the cost of the waste water treatment of Xinjiang oilfield，the recycling technology of hydroxypropyl guar gum（HPG）fracturing flowback fluid was studied. The results showed that the rapid gel breaking and sterilization of the flowback fluid could be realized by electrolysis. The suspended matters were effectively removed by air flotation and settlement treatment. After adjusting the pH of the treated flowback fluid to about 6.5，the hydroxypropyl guar gum could disperse well in flowback fluid，and the base fluid could be quickly prepared with the flowback. The flash crosslinking caused by residual crosslinker could be eliminated by introducing a crosslinking delayer sodium gluconate and the crosslinking time could be controlled between 10—120 s. The high temperature stability of the fluid was improved by adding sodium sulfite to eliminate the residual breaking agent. In this method，about 2.2×104 m3 flowback fluid was treated to prepare HPG fracturing fluid，and was applied in the fracturing of 75 wells in Xinjiang oilfield with the bottom hole temperature of 22—97℃ with 100% operation success rate.

Abstract:After several years of exploitation of Jurassic reservoirs in HJ oilfield，the development stage of some well areas came to middle and high water content stages. In order to ensure the stable production and enhance the oil recovery，the effect of polymer microspheres type and concentration and injection on the plugging rate was probed by the laboratory sand pack experiment，and the polymer microspheres deep flooding test was carried out in Jurassic reservoirs of HJ oilfield. The experimental results indicated that the permeability of sand pack with the similar core property to Jurassic reservoirs in HJ oilfield decreased by more than 85% when injected with 0.5 PV polyacrylamide nanoscale polymer microspheres solution with 5000 mg/L WQ100，whose initial particle size was 0.1 μm and swelling times was 5—20. The polymer microspheres deep profile field practice results in Yan 7 L242 well area and Yan 9 L141 well area showed that the WQ100 polyacrylamide polymer microspheres had good effect in the well groups whose reservoirs permeability was in 6×10^-3—9×10^-3 μm². When the reservoir permeability was above 9×10^-3 μm²，the effective plugging was not happened. In addition，polymer microspheres deep flooding didn't adapt to well groups which had poor physical property and high pressure water well.

Abstract:In order to solve the problem of increasing sludge volume in the process of oilfield sewage treatment，oily sludge filled gel particle flooding agent was prepared by oily sludge，acrylamide，silica sol，initiator potassium persulfate and methylene bisacrylamide. The temperature resistance，salt tolerance，viscoelasticity and plugging ability of the profile control agent were studied. Finally，the profile control agent was used in Zhongyuan oilfield. The results showed that the oily sludge filled gel particle could be produced locally，and the reaction could be carried out at normal temperature of 20—30℃ without reaction kettle. The reaction time was 1.5—2 h. The mixing effect of upper and lower sawtooth dispersing disc agitators was better than that of manual and blade agitators. The amount of sludge filled was up to 50%. Compared with ordinary gel particle，the oily sludge filled gel particle had higher temperature resistance，salt tolerance，viscoelasticity and plugging ability. The deep profile control effect on site of oily sludge filled gel particle was good，which made waste profitable，and provided technical support for improving oil recovery and reducing environmental pressure.

Abstract:The problem of producing both oil and water is caused by long-term waterflooding in the fractured-cavity carbonate reservoirs. To solve the problem，low molecular weight polymer was used in this paper to replace high molecular weight polyacrylamide which was commonly used as blocking agent，and novolac resin used as crosslinker. The effects of dosage of polymer and crosslinker on the viscosity，gelation time and gel strength were investigated，as well as high temperature and salt resistance. The results showed that with the increase of polymer dosage and crosslinker dosage，the viscosity of the system increased，the gelation time shortened and the gel strength enhanced. The results of TG and DSC indicated that the system had good thermal stability. The system had good temperature-resistance and salt-resistance. The gel product，prepared with 4.8% of P（AM-co-AMPS）and 10% of phenolic resin，did not degrade when soaked in the simulated formation water with the mineralization of 22×10⁴ mg/L for 48 h at the temperature of 120℃.

Abstract:The effect of surfactant on micro-cracks and fine tunnels could increase the yield of single well. The anionic-nonionic surfactant AN211 was synthesized by alkyl alcohol polyoxyethylene ether and maleic anhydride. The structure of the product was characterized by NMR. The critical micelle concentration，oil-water interfacial tension，wettability，imbibition efficiency and other properties of AN211 were studied. The results showed that the critical micelle concentration of AN211 was 0.052 g/L. The interfacial tension of AN211 solution decreased with the increase of concentration. The interfacial tension of 0.3% AN211 solution was 3.37 mN/m. AN211 had strong ability to change core wettability and short wettability time. By reducing Zeta potential on core surface，AN211 could change core wettability and achieve wettability reversal. AN211 effectively stripped oily adsorbate on core surface，and the imbibition efficiency improved with 48%. Its permeability was less affected by the degree of mineralization，and its application of water scope was wide. The performance of AN211 was better than that of amphoteric surfactant coconut oil amides acrylamide hydroxy sulfonyl betaine，cationic surfactant cetyltrimethyl ammonium chloride and oil displacement agent QY-1，which could be used for oil displacement of unconventional oil and gas reservoir.

Abstract:As a result of supercritical CO₂ dissolution，the physical properties of heavy oil can be significantly improved，and thus leading to a mobilization efficiency. Herein，in order to gain the underlying interactions between heavy oil and supercritical CO₂ deeply，the effect of supercritical CO₂ on physical properties and asphaltene precipitation of two heavy oils was thoroughly examined，and the texture change of the asphaltene from conventional heavy oil and extra-heavy oil before and after CO₂ injection was observed. The results showed that the viscosities of the heavy oils were noticeably reduced due to the dissolution of supercritical CO₂. The dissolved gas-oil ratio of the conventional heavy oil increased with the increasing pressure，while for the extra-heavy oil，the gas-oil ratio was 30 m³/m³ at the saturation pressure. In addition，supercritical CO₂ in the heavy oils caused the asphaltenes to agglomerate and subsequently to precipitate，especially for the conventional heavy oil，which produced approximately 30% more precipitatant than the extra-heavy oil did. Furthermore，the texture of the asphaltenes in the conventional heavy oil was notably altered to be smooth，as revealed by SEM observations. In contrast，a weak alteration of the asphaltene textures for the extra-heavy oil was observed due to the compacted architecture of asphaltenes and resin，which obstructed the entrance of CO₂ molecules.

Abstract:To improve the development effect of routine steam stimulation in the middle and late period，the swelling and viscosity reduction effect of air and CO₂ on common heavy oil was probed using PVT. Air assisted steam stimulation and CO₂ assisted steam stimulation was developed by laboratory experiments，and the development effects of two kinds of stimulation was evaluated through index analysis of return water rate，injection production ratio，average temperature of reservoir and recovery degree. Results showed that，after air and CO₂ dissolved in crude oil，the viscosity decreased and the volume factor increased，however，the effect of injecting CO₂ was better. The sweep efficiency of steam and average temperature of reservoir increased with the increase of stimulation cycle. The sweep efficiency and average temperature of the gas assisted steam stimulation was higher than that of the routine steam stimulation in the same cycle. The development effect of adding air and CO₂ was obvious in the middle and late period of routine steam stimulation，which increased the return water rate，oil steam ratio and injection production ratio. Compared with the routine steam stimulation，the air assisted steam stimulation and CO₂ assisted steam stimulation could greatly improve the recovery degree，and the development effect of CO₂ assisted steam stimulation was the best.

Abstract:For the complex fault block reservoir with edge water，it is impossible for foam displacement to prevent edge-water coning because of such a long distance，while the foam huff-n-puff just can solve this problem. In order to confine the mechanism of foam suppression for edge water in huff-n-puff wells，the effect of nitrogen，surfactant and polymer should be known clearly. The foam system’s stability，adsorption properties and sealing performance was evaluated，then a related experimental model was developed to evaluate the effectiveness of nitrogen foam preventing edge water coning in huff-n-puff wells by comparing with that of single nitrogen system and surfactant-polymer system. The experimental results showed that the selected nitrogen foam system had good adaptability with the formation. The interfacial tension between the system and the simulated oil was 1.097 mN/m and the foam index was 14750 mL·min at the temperature of 85℃ and salinity 4176 of mg/L. The resistance factor was 26—103 correspond to the formation permeability of 500×10^-3—1500×10^-3 μm². The main mechanism of nitrogen foam in puff and huff wells was as follows，the injection of nitrogen could keep the reservoir’s pressure in a high level；the injection of surfactant and polymer could control the gas flow of nitrogen and reduce oil and water interfacial tension to a certain extent. When the foam is shaped by mixture of gas and liquid，the before-mentioned shortages of gas，surfactant and polymer would be canceled because of their co-reaction，which made nitrogen foam have its own superiority in preventing edge water coning in puff and huff wells.

Abstract:Heavy oil reserves in Xinjiang oilfields are abundant，and the main development methods at the present stage are still steam stimulation and steam flooding. However，the oil-steam ratio and oil production are lower at the middle and late development stages. In order to improve the recovery rate，it is urgent to change development method. In this paper，the M-zone crude was taken as the research object，the oil-displacement efficiency of immiscible steam-CO₂ flooding relative to the pure steam flooding in the high-permeability and low-pressure oil reservoirs and the steam-CO₂ in different residual oil saturations were studied systematically through laboratory experiments. The results showed that when the development method changed to steam-CO₂ flooding from steam stimulation after a certain time，the oil displacement efficiency increases by 34.1%. The steam-CO₂ flooding had the gas and water alternating flooding characteristics. If CO₂ was injected too early，the percolation channel would be opened in advance. The steam would contact most of the crude oil in the tunnel prematurely，which resulted in that the crude oil was emulsified and some emulsified crude oil was difficult to be swept out. When the residual oil saturation was 45%，the final oil displacement efficiency could reach up to 87% ，which was the best CO₂ injection opportunity in the experiment. However，in the actual development process，the CO₂ injection opportunity should be determined through judging whether the steam channel was open by the water production rate.

Abstract:In order to plug the gas channeling passage in the fractured reservoir，a modified cellulose gel used as plugging channeling agent at the high-pressure CO₂ environment，composed of 2% modified cellulose + 2% acrylamide + 0.1% crosslinking agent（N，N'-methylenediacrylamide）+ 0.03% ～ 0.1% initiator，was developed，and the viscoelasticity，thermal stability and plugging performance of the gel was investigated by bottle test，SEM，and rheological test，respectively. The results showed that under the high-pressure CO₂ environment of 10 MPa，the gelling time was controlled from 6 to 24 h，the viscosity of the gel could achieve 18×10⁴ mPa·s，and the elastic modulus and loss modulus of the gel was 3500 Pa and 500 Pa at 1 Hz，respectively. The gel could be stable under the high pressure gas environment for a long time. After placed for 120 d，the performance of the gel was relatively weakened due to the effect of acidification and gas penetration，the microstructure became relatively sparse，however，it still had the nature of the semisolid and the elastic modulus and the loss modulus was 2100 Pa and 280 Pa at 1 Hz，respectively.After plugging，the gas flow rate decreased from 23000 mL/min to 830 mL/min，which was close to the homogeneous core gas velocity（640 mL/min）. The cellulose gel could be used to plug the gas channeling under high pressure CO2 environment in the fractured reservoirs.

Abstract:In order to optimize the foaming activity of cationic surfactant，the branched quaternary ammonium cationic surfactants（XSYP-1—XSYP-4）were synthesized by cetyltrimethylammonium chlorine（XSYP-0）and modifier. The foaming ability and stabilization of synthetic products were evaluated by Ross-Miles and Waring Blender methods. The microstructures of five surfactants were compared. And the effects of temperature，inorganic salts，methanol and condensate on the foaming activity of cationic surfactants were studied. The results showed that the surface tension of surfactant solution decreased with increasing molar ratio of reactant modifier to XSYP-0. The surface tension of 2.0 g/L XSYP-4 solution was 31.88 mN/m. The foaming ability and stability of modified XSYP-0 were improved，as a result of smaller foam size and thicker foam wall. Compared with XSYP-0，the temperature resistance，methanol resistance，salt resistance and anticoagulant ability of surfactants XSYP-1—XSYP-4 were improved. Among them，XSYP-4 had excellent resistance of high temperature，XSYP-3 had outstanding resistance of methanol and condensate oil，and XSYP-2 had good salinity tolerance. The branched modification could improve the overall performance of cetyltrimethylammonium chloride as a foaming agent.

Abstract:In order to obtain foaming agent for heavy oil thermal recovery with good foaming ability and temperature resistance，12 kinds of heat-resisting surfactants including petroleum sulfonate， alkylbenzene sulfonate， α-olefin sulfonate， alkyl ether carboxylate and alkyl phenol ether sulfonate were studied. The foaming ability and thermal stability of these surfactants were systematically evaluated. The results showed that some surfactants had better foaming ability and stability，including alkylbenzene sulfonate，α-olefin sulfonate，Gemini alkylbenzene sulfonate，short chain alcohol ether sulfonate and short chain alcohol ether carboxylate. The long chain α-olefin sulfonate and long chain alkylbenzene sulfonate had the biggest resistance factor among 12 kinds of surfactants，while heavy alkylbenzene sulfonate and petroleum sulfonate had the lowest value. The surfactants were arranged according to the thermal tolerance under experiment condition in following order: alkylbenzene sulfonate > α-olefin sulfonate > Gemini alkylbenzene sulfonate > alcohol ether sulfonates ≈ alcohol ether carboxylate > heavy alkylbenzene sulfonate > petroleum sulfonate. It was recommended that long chain alkylbenzene sulfonate or long chain α-olefin sulfonate should be used as high temperature resistant foaming agent

Abstract:In order to improve the surface activity of fatty alcohol polyoxyethylene ether（AEO）nonionic surfactants， fatty alcohol polyoxyethylene polydiglycerol ethers were synthesized by two-step processing using AEO and glycerine as main raw material， and its surface activity， emulsification property and foam property were measured and analyzed. The results of performance test showed that the turbidity point of AEO₇ -polydiglycerol ethers and AEO₉ -polydiglycerol ethers both increased by 3℃ compared with the corresponding AEO. The surface tension of fatty alcohol polyoxyethylene polydiglycerol ethers solution was all slightly higher than that of the corresponding AEO under the same condition. The critical micelle concentration of AEO₃ -polydiglycerol ethers，AEO₅ -polydiglycerol ethers， AEO₇ -polydiglycerol ethers and AEO₉ -polydiglycerol ethers were 3.16×10^-4 ， 1.00×10^-3 ， 3.14×10^-3 and 5.01 × 10^-3 mol/L，respectively，which were all larger than that of the corresponding AEO. The analysis of foam property and emulsifiability indicated that the fatty alcohol polyoxyethylene polydiglycerol ethers had excellent foaming stability and emulsification property， among which the foaming stability of AEO₉-polydiglycerol ethers was 82.14%.

Abstract:In order to meet the oil displacement requirements of high temperature and high salinity reservoirs of Zhou16 well area in Jianghan oilfield，a kind of polyoxyethylene polyoxypropylene block polyether anionic-nonionic surfactant（PPS）was synthesized from phenol and styrene by etherification and esterification reaction. The interfacial tension，temperature and salt resistance， dynamic adsorption and oil displacement performance of PPS/alcohol ether sulphates（AES）compound system were studied. The results showed that the interface activity of compound system was good. The oil-water interfacial tension of PPS/AES compound system with 0.1% mass fraction and 1∶1 molar ratio could reach 1.39×10^-2 mN/m，and that remained at the order of 10^-2 mN/m after being treated at 140℃. The compound system had good salt tolerance. Under the condition of mineralization degree of 30×10⁴ mg/L or Ca²⁺ mass concentration of 3000 mg/L，the oil-water interfacial tension of the system maintained at the order of 10^-2 mN/m. The saturated adsorption capacity of compound system on the core surface was 0.097 mg/g sand，and the dynamic adsorption loss was less than that of a single surfactant. The compound system had better oil displacement effect. When the water content of water flooding in homogeneous core was 65% ，the maximum increment of oil displacement efficiency could reach 22.53% after transferring 0.4 PV PPS/AES at the injection speed of 0.05 mL/min. In heterogeneous core，the maximum increase of oil recovery rate of compound system was 19.8%. The PPS/AES compound system could be used for the oil displacement of Zhou16 well area in Jianghan oilfield.

Abstract:In order to reveal the adsorption and lost amount of each component in surfactant/polymer（SP）flooding system for conglomerate reservoir with strong heterogeneity and complex model pore structure， the static adsorption and dynamic retention laws of petroleum sulfonate（KPS）and polyacrylamide（HPAM）on the surface of conglomerate core in Karamay reservoir were studied. The results showed that the static adsorption amount of HPAM and KPS on the surface of single mineral and conglomerate core increased with increasing initial concentration and then kept unchanged. The adsorption amount of KPS on each single mineral was more than that of HPAM. Because of the difference of material composition and surface structure， the adsorption amount of clay mineral was more than that of rock skeleton mineral. The static adsorption amount of each component in SP flooding system（0.3% KPS+0.18% HPAM）was proportional to the strength of mineral active center. Because of the competitive adsorption effect， the static adsorption amount of HPAM and KPS in SP flooding system on conglomerate core surface was less than that of single chemical component. The static adsorption amount of HPAM and KPS on conglomerate core surface was less than that of clay mineral but more than that of skeleton mineral. The main absorption effect occurred on the surface of clay mineral. The dynamic retention amount of HPAM and KPS in SP flooding system was negative correlation with the permeability of conglomerate core. Because of the influence of core specific surface area and the dilution of water to chemical agent， the dynamic retention amount of KPS in SP flooding system was lower than its static absorption amount. The dynamic retention amount of HPAM was less than static absorption amount due to the effect of pore structure and specific surface area.

Abstract:Aiming at the problem of low liquid and low yield in Zhuang 139 block wells in deep heavy oil reservoir，which did not get good results of the second cycle of DC as a result of high pressure of steam injection，the technology for microbial huff and puff in deep heavy oil reservoir was studied. According to the reservoir characteristics and crude oil properties of test well，the main components of microbial complex huff and puff system were optimized，which was applied to Zhuangxi oilfield and Taiping oilfield by designed injection slug. The results showed that by using microbial compound system that consisted of activator II（0.4% molasses+0.2% corn pulp dry powder+0.2% dextrin+0.2% NaNO₃ +0.02%（NH₄ ） 2HPO₄ ），inoculating microbes containing bacillus polymyxa. and 0.1% surface active agent of Sophora japonica lipid biologic surfactant，the effect of emulsified crude oil was good and gas production was great under the pH value of 6. The viscosity of crude oil reduced by 50.1%，the oil increase period was 166d，the cumulative oil increased 915 t，the input-output ratio was 1∶9.07，and the economic benefit was obviously improved after microbial compound system was injected in field with 6 m3/h injection speed and 200 m3 main slug

Abstract:The viscous heavy oil near the emulsification reverse phase point had a large viscosity，which was extremely unfavorable for the exploitation and transportation of heavy oil. By examining the effect of temperature and stirring speed on the reverse phase point of heavy oil emulsification，suitable preparation condition for heavy oil emulsion was obtained. The effects of water soluble viscosity reducer and oil soluble viscosity reducer on the reverse phase point of heavy oil emulsification were investigated. The mechanism of emulsification inversion of heavy oil emulsion was analyzed from the viewpoint of interfacial membrane and agent action on asphaltene. The results showed that the emulsification reverse phase point of heavy oil emulsion reached the maximum on the preparation condition of 50℃ and 800 r/min stirring speed. Both the water soluble viscosity reducer and oil soluble viscosity reducer advanced the emulsification reverse phase point of heavy oil，but there was difference in advancing degree. With the increasing concentration of viscosity reducer，water soluble viscosity reducer decreased the emulsification reverse phase point of heavy oil from 48% to 35.6% ，while oil soluble viscosity reducer made the emulsification reverse phase point of heavy oil decreased first and then increased. Water soluble viscosity reducer achieved early phase reversal by decreasing the interfacial dilatational modulus and interfacial tension，while oil soluble viscosity reducer achieved phase reversal by decreasing the interfacial dilational modulus. The analysis of microcosmic morphology of asphaltene before and after adding viscosity reducer showed that water soluble viscosity reducer had higher extent of damage to asphaltene aggregates than oil soluble viscosity reducer. The viscosity reducer mainly realized phase reversal by reducing the strength of interfacial film formed by asphaltene.

Abstract:The concentration detection method and results of a viscosity reducer play important roles on its structure design and usage method. To realize the concentration analysis of a novel viscosity reducer used in shengli oilfield， a high-performance liquid chromatography method with a hydrophobic column was established for water and oil phase samples，and the distribution regulations of concentration in different phases were investigated. The results showed the lowest limit of detection for water phase sample was 10 mg/L， the broad linear range was 10—3000 mg/L and relative standard deviation was less than 5%. Combined with gradient solvent extraction technique， the viscosity reducer existing in the oil phase could be efficiently extracted and separated from oil samples， and then could be analyzed adopting above established analytical method. The extraction efficiency was over 95%. As for crude oil/viscosity reducer binary system（the mass ratio of kerosene and crude oil was 1∶2， and the mass ratio of oil sample and 3% mass fraction of viscosity reducer solution was 1∶1）， over 80% viscosity reducer distributed in water phase， and the content in oil phase slighted increased with the increase of temperature. As for crude oil/viscosity reducer ternary system（the mass ratio of kerosene and crude oil was 1∶1， and the mass ratio of oil sample and 3% mass fraction of viscosity reducer solution was 1∶1）， there was nearly no viscosity reducer in oil phase， about 75% of viscosity reducer distributed in emulsion phase and the minority was in water phase. With the increase of temperature， the content in water phase increased. Under the condition of salt solution， the content in water phase was little more than that with pure water solution， however， the content was almost similar to each other under the conditions of various concentration salt solution.

Abstract:In order to solve the problem of high viscosity and poor fluidity of heavy oil in Bohai A27-2 platform during long-distance pipeline transportation，a terpolymer viscosity reducer with octadecyl methacrylate （A），styrene （S） and 2-acrylamido-2-methylpropanesulfonic acid（Xm）as monomers was synthesized. The effect of various factors on polymerization reaction was studied by measuring the oil viscosity reduction rate of viscosity reducer. The optimal reaction condition was determined and the structure of reaction product was characterized by infrared spectrometer. The experimental results showed that the optimum polymerization condition was obtained as follows：9∶5∶1.5 mole ratio of monomer A∶S∶Xm，4 h reaction time，80℃ reaction temperature，2.0% and 320% the addition of initiator and mixed solvent of the total mass of monomer respectively，and 8∶ 3 mass ratio of toluene to Ys in mixed solvent. The oil-soluble viscosity reducer had a good viscosity-reducing effect on heavy oil. The viscosity reduction rate was 59.25% when the dosage of viscosity reducer was 1‰ of heavy oil. The viscosity reduction rate of heavy oil was 82.18% after 10% composite oil-soluble viscosity reducer contained viscosity reducer and surfactant OP-10 was added，which indicated that the heavy oil could be transported through pipe at lower temperature.

Abstract:The effective components of the water-soluble corrosion inhibitor 9H contained cationic imidazoline often separate out after long-term injection， which results in that the sea pipe is blocked in high temperature condition or the following processing. In this paper， oleic acid， divinyl three amine and xylene， as raw materials， were used to synthesize oleic acid imidazoline， which was be used in accordance with the requirements of anti-corrosion of pipelines in offshore exploitation. The imidazoline inhibitor was further modified by adding different ratio of epoxy ethane and epoxy propane. Dynamic weight loss method， SEM， EDS and optical profiler was applied to evaluation the inhibition efficiency of the inhibitor， the surface morphology and the influence of inhibitor on film-forming were also analyzed. The optimum inhibitor HS-006 was composed of 5% thiourea and imidazoline which was synthesized by oleic acid imidazoline， epoxy ethane and epoxy propane （mass ratio was 1∶0.1∶0.05） . The inhibition efficiency of the corrosion inhibitor HS-006 to X65 steel sheet could reach 95.03% in the corrosion environment with H₂ S concentration of 50 mg/L under CO₂ partial pressure of 0.4 MPa and the total pressureof 1.0 MPa at the temperature of 95℃， which was higher than that of the inhibitor 9H. The corrosion inhibitor HS-006 mainly inhibit the corrosion caused by cathode reaction and the HS-006 could form a excellent protect film on the surface of the steel sheet

Abstract:Tertiary oil recovery sewage in Bohai oilfield contained anionic polymer， which had space steric effect. The traditional polyether block type water-clearing agent had a slow water-cleaning rate， large dosage of reagents， and a large number of sticky flocs adhering to the wall of pipeline and causing blockage of device. With epichlorohydrin and organic amine as the initiator， and ethylenediamine as the crosslinking agent， a new high-efficiency quaternary ammonium cation water clarifier H1 was synthesized by controlling reaction condition. The clear water effect of H1 and detergents（BHQ-04 and BN-5）used in field was compared. The results showed that water clarifier H1 had the best water-cleaning effect which synthesized on the condition of 1.2∶1∶0.3 the molar ratio of three ingredients（epichlorohydrin∶organic amine∶crosslinking agent）， 5—6 hrs reaction time and 75℃. The effective purifying concentration of H1 was only 175 mg/L， which was far lower than that of BHQ-04（400 mg/L）and BN-5（300 mg/L） . Compared with BN-5 and BHQ-04， H1 had higher oil-water separation speed and better flowability， and the upper flocculent was loose and free flowing after oil and water separation. The synthesized water clarifier H1 had the ability to prevent the formation of sticky silt during effluent treatment of polymer flooding in SZ36-1 reservoir of Bohai oilfield

Abstract:In order to improve the wellbore stability of hard-brittle shale，the plugging ability of drilling fluid was usually emphasized，but the effect of drilling fluid hydration on mechanical strength of shale was not considered. Based on traditional drilling fluid plugging performance evaluation method，the rock mechanical strength retention ability of drilling fluid was investigated. The effect of hydration of drilling fluid on rock compressive strength，tensile strength and pressure increment of formation collapse was carried out. And a set of evaluation method for wellbore stability of hard-brittle shale was developed. The results showed that the excellent wellbore stability should have a low penetration plugging filter loss，excellent ability to delay the delivery of pressure，high plugging rate for core cracks，and strong rock mechanical strength retention ability，i. e. ，the decrease of rock mechanical strength was minimum，and the increment of collapse pressure was the lowest after drilling fluid immersion. It was suggested that PPT permeability plugging test，pressure transfer test and core fracture plugging test should be carried out initially， the drilling fluid formula with better performance should be selected，and then the influence experiment of drilling fluid on rock mechanical strength should be carried out，combined with the impact analysis of drilling fluid on collapse pressure and fracture pressure. Finally，the optimum formula of drilling fluid with good wellbore stability could be further determined. From the perspective of rock mechanics，this set of evaluation methods comprehensively estimated the wellbore stability performance，and provided reference for the optimization of drilling fluid.

Abstract:With the decline of conventional oil and gas resource， unconventional oil and gas resource and complex well increased gradually. The drilling technology encountered new challenge. The research and application of graphene materials in oilfield based on the requirement of drilling technology was reviewed， and the prospect of graphene materials in oilfield was discussed.

Abstract:Temporary plugging agent can divert the fracturing fluid into lower permeability layer by plugging higher permeability layer, then the uniform stimulating in reservoir can be achieved. Temporary plugging agent had the properties of high plugging strength, no damage to formation and simple construction. In this paper, according to the different mechanism in plugging reservoir fracture, temporary plugging agents were divided into four types which included particle type, fiber type, gel type and compound type. Furthermore, various temporary plugging agents were reviewed from the aspects of the temporary plugging mechanism, technical characteristics and application.

Abstract:The exploitation of high-temperature and low-permeability oil and gas fields is of great significance to the sustainable developments of china's oil and gas resources. The‘13th Five-year’major national research and development projects require the development of a fracturing fluid system with reliable rheological and sand-carrying properties for application in 240℃ reservoirs. In this paper， the fracturing fluid systems with temperature tolerance above 170℃ were reviewed. The characteristics of vegetable gum fracturing fluid， polymer fracturing fluid， mixed fracturing fluid and temperature tolerant cross linking agents were analyzed， respectively. Suggestions for the development of 240℃ fracturing fluids were put forward.

Abstract:Carbon dioxide（CO₂）geological storage technology had become a research hotspot with the concern of greenhouse gases emission. CO₂ storage in oil and gas fields could help reducing greenhouse gases emission and enhancing oil recovery（EOR） .Therefore，it became one of the most important technologies to reduce large-scale CO₂ or other greenhouse gases emission and enhance oil recovery. The solubility and diffusion coefficient of CO₂during CO₂ injection in oil reservoir，the density and volume change of system caused by CO₂ dissolution were key theoretical basis for CO₂ geological storage technology. In this paper，the research progress on those parameters were reviewed，and the technology of CO₂ for EOR was introduced. In addition，the shortcomings in the current research and the development direction were presented.

Abstract:During chemical flooding process，oil-water dilational viscoelasticity had a great influence on oil displacement mechanism and effects. The influencing law of surfactant，alkali and polymer on the interfacial dilational viscoelasticity was summarized. The distribution characteristics， interactions and interface structures of different types of materials in oil-water interface were analyzed. The special attention was paid to the effects of time， frequency and concentration on oil-water interfacial dilational viscoelasticity. Methods， means， theories and viewpoints summarized in this review could provide reference and basis for studying the percolation characteristics， emulsification mechanism， oil wall formation and emulsion post-processing.