Abstract:The temperature resistance of the current polymer drilling fluid treatment agents is poor and cannot meet the requirements of deep and ultra-deep high temperature drilling. In addition，the sulfonated materials is limited because of environment protection. Using N，N-dimethylamine，oxalic acid，and CA catalyst as the main raw materials，the temperature-resistant synergist HAS was prepared by optimizing the monomer ratio，reaction temperature and time. The temperature resistance and synergistic performance of HAS in more than 10 kinds of polymer solutions such as the coating agent polyacrylamide potassium salt KPAM，high temperature resistant polymer viscosity increasing fluid loss agent driscal-D，temperature resistant salt resistant viscosity increasing agent BDV-200S，and in low viscosity carboxymethyl cellulose sodium salt LV-CMC bentonite drilling fluid，polymer potassium chloride drilling fluid，was evaluated. Furtherly，the biological toxicity of HAS was detected by the bioluminescence bacteria method. The results showed that when the molar ratio of N，N-dimethylamine to oxalic acid to CA catalyst was 1∶3∶2，the reaction temperature was 70℃ and the reaction time was 8 hours，the yield of HAS prepared was the highest，reaching up to 98%. The temperature-resistant synergist HAS had an obvious temperature-resistant synergistic effect on most polymer solutions，which could increase the temperature resistance of BDV-200S polymer from 180℃ to more than 220℃ ，and the temperature resistance of LV-CMC bentonite drilling fluid from 80℃ to 150℃，the temperature resistance of the polymer potassium chloride drilling fluid system reached up to 150℃. After adding HAS，the drilling fluid had stable rheological properties and high viscosity retention， which was equivalent to that before aging. The API fluid loss was reduced by more than 50%，and inhibition performance was improved greatly. The EC50 of HAS，measured by the bioluminescent bacteria method，was 2.76 × 105 mg/L，indicated that HAS had no biological toxicity.

Abstract:In view of the current problems of unfriendly environment of conventional acid solution and the need for timely backflow after acidification，based on the investigation of corrosion performance of lactate and gluconic acid，chelation capacity of glutamic acid N，N-diacetate GLDA，and the optimization of of additives，the formulation of green acid dissolving solution system was determined as follows，20% lactate + gluconic acid（molar ratio 1∶1）+ 1.5% GLDA + 2% inhibitor HLS-1 + 1% iron ion stabilizer CA-1 + 2% clay stabilizer COP-2. The corrosion performance，corrosion inhibition，degradability and damage to reservoir of the system were investigated. The results showed that the system had good corrosion inhibition，inhibition rate and chelation performance，and the system had low damage rate to core，no secondary precipitation，no acid residue，stable residual acid. The corrosion reaction rate constant of the system was 3.37×10-7（mol/L）-m/（cm2·s），which was 0.1 times of that of the conventional thickened hydrochloric acid. The reaction product was calcium lactate gluconate with high solubility in the process of acidification. Infrared spectrum analysis further proved the degradability of the acid solution. The acid solution had the characteristics of nonflowback acidification，which is helpful to reduce the cost of acidification construction and realize green environmental operation

Abstract:The dosage of guar gum in conventional guar gum fracturing fluid is large，and the residual content is high after gel breaking，which affects the percolation capacity of low permeability reservoir. In order to improve the problem，the organic boron crosslinking agent JS-8 was synthesized by boric acid，sodium gluconate and triethanolamine，etc. The properties of low concentration guanidine gum fracturing fluid composed of JS-8，modified guanidine gum HPG-1 and non-ionic additive ZA-07 were studied. The results showed that the crosslinking time of the fracturing fluid system was adjustable，and the temperature tolerance and shearing resistance were excellent. The viscosity remained 218 mPa·s after shearing 90 min at 170 s-1 and 80℃. The gel breaking time of fracturing fluid was short，which could be completely broken within 2 h. The viscosity of gel breaking liquid and residue content were low，and the interfacial tension was only 1.07 mN/m，which greatly reduced water lock damage of the reservoir. The average permeability damage rate of the fracturing fluid was only 19.25%. The low concentration guanidine gum fracturing fluid could be used for the fracturing reformation of low permeability reservoir.

Abstract:The delayed fracturing of fracturing fluid is of great significance in fracturing construction. Based on the sustained release mechanism of core-shell microspheres for drugs，poly （styrene-acrylamide） core-shell microsphere with internal coating ammonium persulfate breaker was prepared by inverse microemulsion polymerization. The polyacrylamide solution adding microsphere or ammonium persulfate was placed in a drying cabinet at 80℃. The sustained release effect of the microsphere was evaluated by measuring the viscosity and pH value of the solution under different standing time. The results showed that the diameter of the microsphere was 50—100 nm. The ammonium persulfate breaker slowly released into the polymer solution after water swelling of microsphere，which delayed the influence of breaker on the viscosity and pH value of polymer solution，and effectively inhibited the free radical degradation and oxidative degradation of polyacrylamide.

Abstract:The existing hydrogel based plugging agents can’t meet the complex pore structure，ununiform fracture scale，ultra-high temperature and ultra-high salinity environment of Tahe reservoir. In this case，self-stickness rubber with different density and hardness were prepared using sulfur and cottonseed oil，and the thermal stability，self-stickness，oil-solubiliy，strength and water plugging performance of the prepared rubber were studied. The results showed that the density could be varied from 1.10 to 1.30 g/ cm3，and the hardness could be varied from 17 to 40 degree，respectively. The rubber was soluble in crude oil and toluene，but not soluble in formation water，indicating the breakable property when oil layer was blocked by mistake. The physical model test of fractured reservoir at 110℃ showed that the best effect could be achieved when the ratio of rubber particle size to crack width was 1∶ 2.5，and the water plugging rate was 94.9%. This work provides new ideas for the utilization of sulfur by-products and the design and preparation of water-blocking agents with adjustable density and flexible particles.

Abstract:Due to sedimentary rhythm，reservoir property and heterogeneity，uneven profile well of Changqing oil field is over 35% in recent years，which has severely disrupted well production. To solve these problems，Jiyuan oilfield of ultra-low permeability reservoir as the research object，an oil soluble diverting agent WS-2 for profile correction near wellbore area was developed，and its solubility，temperature tolerance，dispersion，particle size distribution and plugging performance was tested in lab，the field test was carried out. the results showed that the diverting agent WS-2 was insoluble in water and acid solution，and was soluble in kerosene，the softening point of WS-2 was at about 120℃，the particle size was 30—150 μm. The WS-2 had good dispersion performance and could suspend in the carrier fluid，which was conducive to be injected into the formation. The plugging efficiency of SW-2 to the core was over 90%，meeting the demand of the field application. Aiming at the peak and the finger shape of uneven water wells，the diverting agent WS-2 was applied and achieved good results. The average water absorption thickness increased by 2.5 m，the average degree of water drive increased by 8%，and production well group maintained stability after three months， realizing the injection profile adjustment. The diverting agent WS-2 has a bright prospect in the same kind of reservoir.

Abstract:For these problems of poor acidizing effect and difficult acidizing diversion in high permeability heterogeneous sandstone reservoirs，the ionic Bola surfactant（BS）（sodium polypropylene glycol dicarboxylate）was prepared by etherification reaction of polypropylene glycol，and a cationic guar（hydroxypropyl trimethylammonium chloride guar）and BS were assembled into a supramolecular gel BSP system. The optimal conditions for gel formation of BSP system were obtained by analyzing the viscosity change characteristics. Theological characteristics and shear repairability of the BSP system were tested by rheometer. Acidification diversion effect of the system was tested by parallel core flow experiment，and the mechanism was probed by SEM. The results showed that the viscosity of the BSP system exhibited“hump phenomenon”with temperature rose，and had excellent self-assembly recovery performance of viscosity after shearing. It is difficult to stimulation the low permeability area when acidizing the reservoir with serious heterogeneity. BSP system had excellent temporary plugging and diverting effect，during acidification，the injection of BSP system could effectively reduce the filtration loss of acid solution in high permeability area and effectively start the low permeability area. The BSP showed network structure and supramolecular microspheres at different pH values，which was helpful to realize the temporary plugging and cleaning.

Abstract:In order to reveal the properties of chorionic vesicle fluids prepared by different surfactants，a series of chorionic vesicle fluids were prepared by using sodium dodecyl sulfate （SDS），sodium dodecylbenzene sulfonate （SDBS），alkylphenol polyoxyethylene ether （OP-10），cetyltrimethylammonium bromide （CTAB） and modified polysaccharides. The effects of temperature，NaCl and hydrochloric acid on the rheological properties of chorionic vesicle fluids were investigated. The results showed that the properties of chorionic vesicle fluids prepared by different surfactants were significantly different. The apparent viscosity of chorionic vesicle fluid prepared by SDS was the highest，followed by CTAB，SDBS and OP-10. The viscosity of chorionic vesicle fluids showed unique change relationships with temperature. When the temperature was low，the viscosity decreased with increasing temperature. When the temperature reached about 80℃，the decrease of viscosity slowed down with increasing temperature. When the temperature rose to 100℃，the viscosity no longer changed. When the temperature was higher than 120℃，the viscosity of chorionic vesicle fluids prepared by SDS，OP-10 and CTAB was comparable，while that by SDBS was the lowest. Four surfactants were arranged according to the viscosity stability of chorionic vesicle fluid at 140℃ in following order： OP-10>CTAB>SDS>SDBS. The change rates of the apparent viscosity were less than 10% after adding 2% NaCl into the chorionic vesicle fluids prepared by SDS，SDBS，OP-10 and CTAB，which had good salt resistance. Four surfactants were arranged according to the acid resistance of chorionic vesicle fluid in following order：CTAB>OP-10>SDS≈SDBS. In general，cationic surfactant should be used to prepare acid resistant fluids and anionic surfactant such as SDS or SDBS could not be used.

Abstract:In order to improve the heat resistance and salt tolerance of chemical wellbore plug based on biopolymer，plug that was prepared from phenolic resin crosslinker SG-3 and scleroglucan in saturated NaCl solution was studied. The effects of crosslinking temperature，time，concentration of both crosslinker and scleroglucan on the mechanical properties of plug and influence mechanism were investigated，and its ageing resistance in saturated NaCl solution at 120℃ was then examined. The results showed that the crosslinking temperature and scleroglucan concentration exerted great influence on plug’s performance. The mechanical performance of plug increased with the rising of scleroglucan concentration. Plug prepared from 3.0% scleroglucan and 1.0% crosslinker at 80°C showed both good toughness and mechanical property. And，its shape could keep stable for 40 h in saturated NaCl solution at 120°C. However，it nearly completely degraded after 72 h. Chemical wellbore plug prepared from scleroglucan and phenolic resin crosslinker displayed good heat resistance and salt tolerance. Moreover，it could gradually degrade in simulated formation water. Therefore，the plug might find applications in well cementation，completion and workover in oilfield.

Abstract:In the process of oilfield development，due to the influence of routine well workover，oil recovery and stratum structure，outputting oil and injecting water well tubers often have problems such as water channeling of outside tubes or drilling fluid loss，which seriously affects the oil production rate and the service life of oil or water wells. Therefore，in this paper，the epoxy resin was selected as the main agent for sealing channeling，and the effects of active diluent（glycidyl butyl ether）dosage， curing agent TEA dosage and silane coupling agent KH-560 dosage on curing time，curing strength and sealing channeling of epoxy resin adhesive plugging agent were studied. The research results showed that the optimal dilution ratio of epoxy resin plugging agent was 15%，accounting for epoxy resin dosage，and by adjusting the dosage of curing agent in range of 10%—20%，the curing time of epoxy resin plug sealing agent could be controlled within 2—5 h，and the compressive strength of colloid plug could reach above 20 MPa，and the sealing strength was 5.57 MPa. By adding 3%—4% silane coupling agent，the sealing strength could be increased two times. The plugging agent had good sealing and channeling performance，and could completely meet the requirements of casing sealing and channeling. According to the simplified chemical reaction kinetic model of epoxy resin curing，the relationship between gel time and temperature of the resin rubber plugging agent was simulated，which had guiding significance for field construction.

Abstract:The fracture-vuggy reservoirs in Tahe oilfield are characterized by high temperature，high salt and complicated water production rules，so it is difficult to achieve higher recovery. Aiming at these problems，using sand filling pipe model and two-dimensional visual fractured-vuggy model，the selective blocking and flow channel adjustment mechanisms of hyperbranched slow-expanding particles were studied under Tahe fractured-vuggy reservoir conditions. The experimental results showed that the slow-expanding particles had excellent temperature and salt resistance，oil-water selectivity and fluid steering performance. The maximum expansion ratio of slow-expanding particle was 14 times in simulated water，the water blocking rate was 66.7% and the oil blocking rate was 7.0%. The high permeability pipe could be effectively blocked，and the split ratio of high permeability pipe to low permeability pipe reduced from 98∶2 to 23∶77 after profile control. The result of microscopic visualization model experiment showed that the expanded elastic particles could form a seal in the large-size fractures by extrusion deformation and accumulation compaction. It could narrow the flow channel to promote deep fluid steering，and expand the sweeping efficiency of subsequent water flooding through stepwise blocking and migration，which would benefit to improve the recovery of fracture-vuggy reservoir

Abstract:In order to improve the poor stability and breakage of pre-crosslinking gel particles and the effect of gradual deterioration after multi-round profile control，a granular fracture plugging agent with high strength and soft elasticity was prepared by using aromatic monomer and special comonomer as main agent and benzoyl peroxide as initiator. The mechanical property of the plugging agent was studied and it was applied in Changqing fractured reservoir. The results showed that the hardness of plugging agent was small and the flexibility was good，which was good for pump injection. The change of shore hardness of plugging agent at low temperature was small. The value of shore hardness was 18.6—18.9 HA at 18—28℃ . The strain increment of plugging agent increased and the storage modulus decreased with the increase of temperature. Temperature had little effect on the loss modulus of plugging agent. The elongation at break of plugging agent was 1352%—1358%，and the corresponding tensile stress was 1.20— 1.56 MPa. The compressive deformation ability of plugging agent was good. When the compressive stress increased，the strain increased gradually. The salinity of formation water had little effect on the flexibility of plugging agent. The plugging agent had good effect in the field application of Ansai oilfield with the input-output ratio of 1∶2.92 and cumulative oil increment of 3768 t. It had effectively improved the problem of using pre-crosslinking gel particle profile control agent.

Abstract:In order to improve the recovery factor of Changqing high-salinity oil reservoir，the seepage characteristics and influencing factors of polymer weak gel were studied，and the action mechanism was analyzed basing on the geological characteristics and fluid properties of Changqing oilfield. The results showed that there were many factors influencing the seepage characteristics of polymer weak gel. With the increase of polymer concentration，relative molecular mass，injection water salinity and Cr3 + concentration，the drag coefficient（Fr）and residual resistance coefficient（Frr）of polymer weak gel increased，and the injection pressure increased. As the core permeability decreased，the Fr and Frr increased，and the injection pressure increased. Weak gels formed by different types of polymers had different blocking effects on the core. Although the apparent viscosity of polymer weak gel was lower than that of polymer solution at the same concentration，the Fr and Frr of polymer weak gel were larger. Moreover，the Frr was greater than Fr，which indicated excellent flow steering ability. The main reason for the increase in the size of weak gel molecular aggregate was molecular chain stretching and water swelling of weak gel as a result of water dilution，which led to enhanced retention and plugging in the core.

Abstract:In order to remove the plugging of oil well caused by the precipitation of paraffins，asphalts，and other organic substances in the middle and late development of Bohai oilfield，high efficient plug removal agent XL-1 was prepared by using compound oil soluble organic solvent，alcohol ether surfactant and penetrating agent. Three sets of orthogonal control experiments were carried out to investigate the effect of various reagents dosages on the oil washing rate，which could determine the best formula of XL-1 and study the dissolution effect of XL-1 on paraffin and asphaltene. Finally，field application was carried out in 58-5 well of Shahejie formation in Bohai oilfield. The results showed that when the mass ratio of alcohol ether surfactant， compound oil soluble organic solvent and 2-methyl-2，4-pentanediol was 3∶7∶0.5，the oil washing effect of XL-1 on oil pollution was the best with 98% oil washing rate. It had good dissolution effect on paraffin and asphalt，and the dissolution rate was 90% and 40% ，respectively. After injection of XL-1 in 58-5 well，the drop of the formation pressure was up to 23% ，indicating good plugging removal effect. Alcohol ether type plug removal agent XL-1 could be used to remove organic plugging caused by the deposition of paraffins and asphalts in low permeability oilfield.

Abstract:In order to resolve the problem of gas channeling in offshore horizontal wells during multi-component thermal fluid （MCTF）huff and puff，a thermo-sensitive gel（TSG）was prepared using the refined cotton，propylene oxide and methyl chloride as main raw materials，and the viscosity，salt resistance，plugging properties and effective period of the TSG was evaluated and an experiment simulating the plugging effect of the TSG was conducted using a large two-dimensional physical modeling system. The results showed that with the increase of temperature，the viscosity of the TSG solution decreased gradually，but increased when the temperature exceeded 70℃. TSG solution formed a non-flowable and strong gel when the temperature reached up to 80℃. The TSG had good salt resistance，as 1.5% TSG solution prepared with 1000 mg/L Ca2+ aqueous solution，1000 mg/L Mg2+ aqueous solution or 50，000 mg/L sodium chloride solution could become gel at the temperature of 80℃. The plugging rate of TSG was tested to be 99.74% using a sand packed tube，as the permeability of the sand packed tube was 1.59 μm2 before TSG injection and turned out to be 0.004 μm2 after TSG injection at 80℃ followed by 1.0 PV water drive. The permeability retention rate of the sand packed was 95.28% after 30 PV water drive at a rate of 40 mL/min，indicating that the TSG had a strong plugging strength and a long effective-period. The result of simulation experiment showed that TSG solution tended to enter and plug the high permeability channel，then it gelled under the heating effect of MCTF injected later，which inhibited the occurrence of gas channeling. MCTF was forced to bypass the high permeability channel plugged by the TSG，which expanded sweep area and improved oil recovery from 36.1% to 45.3%. Field application in NB35-2 showed that the injected TSG had plugged the high permeability channel formed in the first two rounds of huff and puff，and the connected well was not affected during the whole injection stage of 25 days，and injecting pressure increased by 2 MPa.

Abstract:Due to the complex formation conditions，serious heterogeneity，the development of natural or artificial fractures，and adverse mobility ratio of CO2，thus CO2 gas channeling is serious and the recovery factor is low. In order to reduce the gas mobility and improve the effect of CO2 flooding，YC oilfield provided a linear block copolymer thickener based on the property of CO2. The shear rheological property，high temperature and high pressure rheological property of the thickener/CO2 system were evaluated by simulating YC oilfield block. Combined with two-dimensional core and three-dimensional triaxial model experiments，the oil displacement effect of thickener/CO2 system was evaluated dynamically. The results showed that the system formed by thickener and CO2 had good stability at 40—80℃，which could increase the viscosity of CO2（0.014 mPa·s）by about 20 times. Temperature had little effect on the viscosity of thickener/CO2 system. As the shear rate increased，the viscosity of thickener/CO2 system decreased. While as the pressure increased，the viscosity of thickener/CO2 system gradually increased. Under simulated formation conditions，the thickener/CO2 system had a good effect on reducing CO2 mobility and improving gas flooding. For heterogeneous cores，the enhanced recovery factor（13.75%）for cores with small permeability differences was greater than that（11.98%）for cores with large permeability differences. For homogeneous cores，the thickener/CO2 system could effectively improve the problem of serious CO2 channeling，further develop CO2 displacement effect and greatly increase the recovery factor of crude oil.

Abstract:In view of the characteristics of poor CO2 flooding effect and serious gas channeling phenomenon in low permeability and ultra-low permeability reservoirs，water alternate gas（WAG）improving CO2 flooding effect was investigated. Taking reservoir physical simulation as the main research method，the impacts of low permeability and ultra-low permeability core and heterogeneity on the WAG flooding effect was studied. Selecting natural outcrops and artificial heterogeneous cores，and the injection method， injection speed，injection parameters and injection timing were researched and optimized for WAG flooding. The results showed that WAG flooding could achieve good mobility control and prolong CO2 channeling time for low permeability and ultra-low permeability homogeneous cores of 0.5×10-3 μm2，1×10-3 μm2 and 5×10-3 μm2，and the lower the permeability，the later the gas channeling time. As for the heterogeneous cores with the permeability differential of 5（1×10-3/5×10-3 μm2 ），10（1×10-3/10×10-3 μm2） and 50（1×10-3/50×10-3 μm2 ），the smaller the permeability differential ，the higher the gas-water ratio，the higher the enhanced oil recovery. When The permeability differential was 10，the gas channeling time was obviously advanced，especially when the permeability differential was greater than 50，the WAG slug could not start the remaining oil in the low-permeability matrix，and only a small part of the crude oil could be displaced in gas injection stage. WAG in use within limit adaptation could significantly reduce the CO2 mobility and prolong CO2 channeling time，start the residual oil in matrix and enhanced the residual oil recovery.

Abstract:In order to improve the recovery factor of conglomerate reservoir，polymer flooding was carried out in Qidong-1 area in view of the strong heterogeneity of low permeability reservoir，low recovery degree of water driving and high residual oil saturation. Through theoretical calculation，polymer injectivity and fluidity analysis，and oil displacement experiment in natural core，the relative molecular weight and injection concentration of polymer were screened. Finally，the polymer flooding was applied in Qidong-1 area. The results showed that the recovery factor of Qidong-1 conglomerate reservoir with low permeability increased by 4%—9% when the polymer concentration was less than 1000 mg/L and the relative molecular weight was less than 400 × 104 . According to the characteristics of low permeability reservoir，the fluidity control technology of equal viscosity displacement such as oil displacement system and reservoir fluid was formed. In the test area，polymer injection was carried out in January 2016，with a relative molecular weight of 350×104 and polymer injection concentration of 800 mg/L. Up to February 2019， the oil production in polymer flooding stage was 8.01 × 104 t，and the recovery factor was 14.5% . The effect of increasing oil production and decreasing water cut was obvious.

Abstract:In order to microscopic study mechanism and oil recovery efficiency of oil displacement of polymeric surfactant，the micro-etching simulation model was used to carry out the oil displacement experiment，and the result was compared with that of core flooding experiment. The results showed that in the microscopic oil displacement experiment，six types of residual oil were produced in the model after water flooding. Flooding effect was not obvious that polymeric surfactant displaced residual oil at blind end. The mechanism of oil displacement of polymeric surfactant was viscosity-increasing effect，viscoelastic effect and emulsification，which could expand swept volume，reduce percolating resistance，and pull and squeeze residual oil to emulsify large oil droplets into small oil droplets，respectively. Therefore，the residual oil was effectively displaced. Comparing the microscopic model with the core flooding experiment，the oil recovery efficiency was basically consistent. When the concentration of polymeric surfactant was higher，the ability of displacing residual oil was stronger and the oil recovery was better. When the concentration of polymeric surfactant was 2000 mg/L，the oil recovery efficiency was the best and the enhanced oil recovery was 19.69%.

Abstract:In order to reveal the influence of two-dimensional nanosheet material（2-D smart black nano-card）on the stability of crude oil emulsion，taking the crude oil of Changchunling and Third Block of Fuyu oilfield as an example，the effect of 2-D smart black nano-card fluid with a mass fraction of 0.005% on the stability of crude oil emulsion was studied under the condition of 7∶3 water-oil volume ratio. The stability and interfacial film strength of crude oil emulsion were analyzed using stability analyzer and interfacial rheological instrument. The mechanism of smart black nano-card on enhancing the stability of emulsion was analyzed by observing the microscopic shape and particle size distribution of emulsion. The results showed that the size of smart black nano-card was about 70 nm × 100 nm and the thickness was 0.65—1.2 nm. The Pickering emulsion was formed by adding smart black nano-card to the emulsion composed of crude oil and 0.01% stabilizer cetyl trimethylammonium bromide（CTAB）. The ultimate dewatering rates of the emulsions slowed down，which decreased from 75.71%—78.57% to 65.71%—72.86% . The stability of emulsion increased and the turbiscan stability index（TSI）value decreased from 4.73—5.64 to 2.71—3.84. The strength of the emulsion film increased and the rheological characteristic of the system changed from viscosity to apparent elasticity. The backscattering spectra of the Pickering emulsions with smart black nano-card could be divided into three regions，such as emulsion demulsification zone， transition zone and emulsion coalescence zone. Smart black nano-card could change the hydrophilic-lipophilic balance of stabilizer，transform W/O emulsion into O/W emulsion and form emulsion with droplet size of 0.1—5 μm，resulting in greatly viscosity reduction of crude oil. Smart black nano-card had hydrophilic-lipophilic amphiphilic property，which could arrange on the liquid film through self-adsorption，increase the strength of liquid film and improve the stability of emulsion.

Abstract:According to the characteristics of low permeability reservoir，such as poor permeability，narrow pore throat and tight rock formation，a flaky two-dimensional（2-D）smart black nano-card oil displacement system was developed. The microstructure， wettability，interfacial property，stability，emulsification and viscosity reduction of 2-D smart black nano-card were studied. The effects of core permeability，nano-black card concentration and crude oil viscosity on the oil displacement effect of 2-D smart black nano-card solution were investigated through one-dimensional core displacement experiments. The results showed that the size of 2-D smart black nano-card was about 60 nm × 80 nm × 1.2 nm. It formed a“surface-surface”contact with oil-water interface，and the interface interaction was very strong. 2-D smart black nano-card had a large specific surface area. It could be uniformly dispersed in the aqueous phase，and exert multiple functions such as wetting reversal，emulsifying and reducing viscosity，reducing interfacial tension，reducing pressure and increasing injection and so on. The experiment results of core displacement showed that core permeability，nano-card concentration and crude oil viscosity had influence on oil displacement effect. When the core permeability was 25 × 10-3 μm2，the amount of nano-card was 0.005% ，and the viscosity of crude oil was 25 mPa·s，the oil displacement effect of 2-D smart black nano-card solution was better，and the enhanced oil recovery rate was 18.10%. The flaky 2-D smart black nano-card could give full play to the function of“intelligent oil exploration”and was suitable for improving oil displacement efficiency in low permeability reservoir.

Abstract:In order to efficiently repair the crude oil-contaminated soil near the Dingbian oil field in northern Shaanxi，five strains of crude oil-degrading bacteria were selected from the local oil-contaminated soil，the isolated degrading-bacteria were analyzed through physiological and biochemical experiments and 16S rDNA sequence method. The orthogonal experiment method was used to explore and establish an efficient mixed bacteria repair system and analyze the degradation products of the strains. The surfactant Tween80 was used to stimulate the microorganisms to further improve the degradation efficiency of petroleum. The research showed that the strains were D-1 Cellulomonas，D-3 Serratia marcescens，C-2 Achromobacter，D-5 Acinetobacter，and A-3 Pseudomonas aeruginosa. By measuring the growth status of strains in LB medium and petroleum medium，analyzing the residual components of strains degrading petroleum，D-5，C-2，A-3 were screened out for compounding，and it was found that the effect of each strain on oil degradation was D-5> A-3> C-2 and the optimal dosage ratio of strain compounding of D-5 to C-2 to A-3 was 5∶1∶5. It was found that under the degradation conditions of temperature 35℃，pH 7.5，shaker speed 180 r/min，bacterial solution dosage 6%， and Tween80 content 5 cmc，the degradation effect of the mixed bacteria on crude oil could reach up to 87.12% ，effectively promoting the efficient repair of the crude oil-contaminated soil.

Abstract:In view of the high viscosity and poor fluidity of super heavy oil and high salinity of formation water，emulsified viscosity reducer was prepared by surfactant，alkali and organic phosphoric acid and its formula was optimized. The effects of salinity and temperature on the viscosity-reducing properties of viscosity reducer were studied and the mechanism of viscosity reduction was analyzed. The results showed that the optimal formula of emulsifying viscosity reducer for super heavy oil was obtained as follows：1.1∶0.45∶1.15 the mass ratio of compound surfactant consisting of sulfonate anionic surfactant YBH and alcohol ether carboxylate anionic-nonionic surfactant YFBH with a mass ratio of 1∶1，alkali and salt resistant additive NYZJ-1. When the dosage of compound agent and additives was 0.81% in the emulsion，emulsification temperature was 80℃，the mass ratio of oil to water was 7∶3 and the salinity was 95 g/L，the viscosity of super heavy oil reduced from 316.5 Pa·s to 0.0831 Pa·s at 50℃，the viscosity reduction rate was up to 99.97% and the water separating proportion was only 5.93% after standing in 4 hours at 50℃. Temperature had little effect on the viscosity-reducing property of viscosity reducer and the viscosity reduction rate of super heavy oil emulsion remained unchanged after 2 hours treatment at 200℃ . The synergetic effect among the components of the compound emulsifier enhanced the viscosity-reducing property of the system and the stability of emulsion. The emulsified viscosity reducer had good viscosity-reducing effect and could withstand temperature and salt，which was suitable for the oil reservoir with high temperature and high salt.

Abstract:Aiming at the oil and gas well environment with high content of CO2，H2S and Cl-，1-（2-naphthyl- thioureaethyl）- 2-pentadecyl-imidazoline corrosion inhibitor was prepared from hexadecanoic acid，diethylenetriamine and 1-naphthyl-2-thiourea. In the salt solution with saturated concentration of CO2，H2S mass concentration of 30 mg/L and Cl- mass fraction of 0—30%，the effect of corrosion inhibitor on the corrosion morphology and corrosion inhibition effect of the steel sheet was studied. The corrosion inhibition mechanism was analyzed through electrochemical polarization curves and AC impedance spectroscopy. The results showed that Cl- accelerated the corrosion of carbon steel in CO2/H2S medium. In the salt solution containing saturated CO2，30 mg/L H2S and 10% Cl-，the corrosion inhibitor could slow down the corrosion of carbon steel by Cl- . The inhibition effect of corrosion inhibitor decreased with increasing Cl- concentration. When the Cl- content was less than 20%，the inhibition effect was better. As the concentration of corrosion inhibitor increased，the corrosion inhibition rate increased and gradually stabilized. When the amount of corrosion inhibitor was 100 mg/L，the corrosion inhibition rate was 94.36% . The corrosion inhibitor was a mixed corrosion inhibitor that could inhibit the action of cathode and anode. It could form a dense protective film on the surface of carbon steel， hinder the contact between corrosion medium and metal matrix，and inhibit the corrosion of metal. The corrosion inhibitor could be used for the corrosion inhibition of pipelines with high content of CO2，H2S and Cl-.

Abstract:The process of catalytic synthesis of corrosion inhibitor by mixing ketone，aldehyde and amine in proportion at one time was optimized to improve the effect of corrosion inhibitor in deep well with high temperature. Under the conditions of 16 MPa， 160°C，4.0% addition and 180°C，4.5% addition in hydrochloric acid（20% HCl）and earth acid（12% HCl + 3% HF）respectively， the effect of ketoaldehyde amine condensate corrosion inhibitor produced in pilot test on the corrosion rate of N80 test piece was evaluated. The results showed that the modified preparation process was divided into four steps. First，ketoaldehyde condensate was obtained by the reaction between acetophenone and formaldehyde with hydrochloric acid as catalyst. Second，water removal was achieved by separating the produced water. Third，ketoaldehyde amine condensate was obtained by reacting ketoaldehyde condensate with aniline. Finally，ketoaldehyde amine condensate corrosion inhibitor product was prepared by mixing ketoaldehyde amine condensate，corrosion inhibitor synergist（octanol），high temperature synergist（cuprous chloride）and organic solvent （anhydrous ethanol）. Compared with the original one，the improved process had a higher production rate and better product performance. The pilot test product prepared by modified technology reached the first class product corresponding to the oil and gas industry standard SY/T 5405—1996 and met the acidification requirement of oil-gas reservoir in deep well and ultra-deep well.

Abstract:In the process of crude oil production，the H2S maybe release from the crude oil with the change of system temperature and pressure，resulting in potential safety hazards. At present，steam injection thermal production mode will aggravates the harm of H2S. The H2S release in an extraction liquid or the corresponding crude oil of Shengli oilfield after treatment at different temperatures was investigated and H2S production mechanism was mentioned. The crude oil or extraction solution was placed in an autoclave for high temperature treatment，then cooled to 50℃ to extract gas samples，and the gas samples was analyzed by gas chromatography. It was found that after 330℃ high temperature treatment，the H2S release from extraction liquid was less than that from the corresponding crude oil. Furthermore，the H2S release values of the crude oil treated at 200℃ or 85℃ were similar to each other，and the H2S release values were relatively large. The sulfur in released H2S reached up to 32.3% or 34.5% of the sulfur in the treated crude oil. Moreover，the study indicated that the main source of H2S released in the experiment was the H2S dissolved in crude oil. As crude oil coexisted with the formation water，some H2S dissolved in the formation water and reduced the H2S release.

Abstract:The injection of polymer in Bohai oilfield has caused the blockage in injection well，which has seriously affected oil exploitation. In order to clarify the composition of fouling and the interaction mechanism of each component in X injection well in Bohai oilfield，the component，content and microtopography of fouling，water compatibility，interactions between inorganic scale or crude oil and polymer were analyzed by means of synchronous thermal analyzer，SEM，Malvern laser particle size analyzer， inductively coupled plasma mass spectrometer，etc. The results showed that the fouling had a complex structure which was mainly composed of polymer，inorganic scale，crude oil and clay particle. The polymer was the main composition of the fouling. The injected water and formation water of Bohai oilfield was not compatible，which was easy to produce inorganic scale. The inorganic scale crystal would wrap polymer chain and grow，resulting in the increase of hydraulic diameter for the polymer micelle. The polymer scale was wrapped by crude oil to form a flexible material that was difficult to be swollen by formation water，which seriously blocked the formation.

Abstract:In order to reduce the transportation cost of high wax type JENM crude oil，the octadecyl acrylate-docosyl acrylate-maleic anhydride comb copolymer freezing point depressant（FPD）was synthesized，the influence of the molecular weight of the FPD on the freezing point depressing effect was studied，and the regulation of the molecular weight of the copolymer was achieved by optimizing the reaction conditions. The characteristic of paraffin precipitation and morphology of paraffin crystal of JENM crude oil with/without the synthetic FPD was investigated. It was found that the average molecular weight of the synthetic FPD decreased with the increase of the reaction temperature and the amount of the solvent，and increased first and then decreased with the increase of the dosage of the initiator. The octadecyl acrylate-docosyl acrylate-maleic anhydride copolymer freezing point depressant had a better freezing point depressing effect on JENM crude oil when the average molecular weight was about 14000. Typical optimum synthetic conditions were the reaction temperature of 100℃，the solvent concentration of 77% and the initiator dosage of 1%. By adding 0.3% FPD synthesized under these conditions，the freezing point of JENM crude oil reduced from 30℃ to 17℃ with the decreasing amplitude of 13℃；the viscosity at 30℃ decreased from 9.12 Pa·s to 2.24 Pa·s with the viscosity reduction rate of 75%，as a result，the low temperature fluidity of JENM crude oil was significantly improved. Differential scanning calorimetry and microscopic analysis showed that the addition of the FPD reduced the paraffin precipitation point and the paraffin peak temperature of JENM crude oil，and increased the paraffin precipitation amount at the freezing point. The polar group of FPD inhibited the growth of paraffin crystals，promoted the dispersion of paraffin molecules in crude oil，and made the paraffin seed crystals start to precipitate at lower temperatures. Besides，since the paraffin crystal was finer，the crude oil lost fluidity when the amount of paraffin is larger，thereby effectively reduced the freezing point of the crude oil.

Abstract:In order to prevent wax deposition in the gathering and transportation of Shunbei crude oil pipeline，a hyperbranched polymer wax inhibitor was designed and synthesized with octadecyl methacrylate，vinyl acetate and p-phenylethylene as monomers according to the carbon chain distribution of wax separated from Shunbei crude oil. The effect of synthesis conditions on the wax prevention performance of the wax inhibitor was investigated. The wax prevention effect of the wax inhibitor was evaluated and analyzed by cold fingering method，and the wax prevention mechanism was mentioned. The results showed that the wax content of Shunbei crude oil is 6.57%，the wax precipitation point is 23℃，and it is easy to form wax at ambient temperature. The optimum synthesis conditions of the hyperbranched polymer wax inhibitor was as follows，the molar ratio of octadecyl methacrylate and vinyl acetate was 5∶1，the amount of p-phenyleneethylene was 0.02% of the total monomer mass，the amount of initiator was 0.7% of the total monomer mass，the polymerization temperature was 70℃，and the polymerization time was 6 hours. When the dosage of the wax inhibitor was 500 mg/L，the paraffin control rate was over 70%，showing good paraffin control effect. When 600 mg/L paraffin inhibitor was added，the condensation point of the crude oil was reduced by 8℃，and the wax precipitation point was reduced by 13.4℃. The eutectic of paraffin and paraffin was formed by paraffin inhibitor，which could destroy the crystal structure of paraffin and inhibit the continuous growth of paraffin，so as to achieve the effect of paraffin prevention.

Abstract:Degradation of fracturing flowback fluid is significance for saving water resource and environment protection. In this paper，the oxidative degradation of the Changqing oil field sewage with high salinity and viscosity was carried out adopting the ultrasound-assisted Fenton oxidation method and the influence of different factors on the oxidative degradation reaction was investigated. Under appropriate reaction conditions that the molar ratio of H2O2 to FeSO4 was 3.7∶1，the ultrasound power was 120 W，the reaction temperature was 20℃，the reaction time was 18 min and the pH value was 6.17，the COD decreased from 10615.5 mg/L to 2351.3 mg/L ，the removal rate of COD reaching up to 77.85%；the chromaticity decreased from 2113. 8 CU to 20.95 CU， the turbidity decreased from 47.88 NTU to 0.12 NTU，the viscosity decreased from 1.79 mPa·s to 1.02 mPa·s，the salinity decreased from 7130 mg/L to 1045 mg/L. Ultrasonic assisted Fenton oxidation degradation of the flowback fluid could realize the decrease of viscosity and the removal of COD，greatly reduce the chromaticity and turbidity，which was advantageous for the following deep treatment.

Abstract:In order to effectively reduce the damage of fracturing fluid to coal seam，it is necessary to measure the composition of formation water by ion chromatograph，determine the degree of mineralization of stratigraphic water，and use compound formation water as fracturing fluid for hydraulic fracturing construction. In order to save time and cost，based on the basic idea of microelement analysis，a real-time and dynamic model for predicting the concentration of compound in formation water was established. According to the drainage situation of the field production wells，it was assumed that the volume of formation water produced in any time period was the same as that injected into the far well zone，and the concentration of compound in the discharged formation water remained unchanged in the small time period. The results showed that the average error between the concentration of KCl and NaCl in formation water of coal-bed gas well in a block of Xinjiang calculated by the model and that measured by the ion chromatograph was 4.01%—12.10% and 6.06%—10.46% under different production time respectively，which verified the correctness of the model.

Abstract:Most of carbonate reservoirs exists bottom water in China. Due to the coning of bottom water，water cut of oil wells rises rapidly，causing to water flooding in severe cases. Controlling the rapid breakthrough of bottom water in carbonate reservoirs has become one of the hot issues in recent years. Therefore，it is necessary to sort out and summarize the bottom water control technology of carbonate reservoirs. The water production characteristics and mechanism of oil wells in carbonate bottom water reservoirs，water control technology and water control or water blocking materials were explained. The research progress and problems of water control materials and technics such as inorganic materials，polymer solutions or gel systems were summarized. The nanocomposites applied into water control in low-permeability carbonate reservoirs were prospected.

Abstract:Carbon dioxide capture，utilization and storage（CCUS）technology is of great significance for the mitigation of climate change. However，CO2 leakage may occur during gas injection and storage. The failure of wellbore integrity is the main way of CO2 leakage. At present，the research of wellbore cement integrity is mostly about the modification of anticorrosive cement system or cement squeezing. Thus，choosing polymer gel with better inject ability，stronger stability and lower cost can prevent and repair the failure wellbore. Smart polymer gels are currently receiving widespread attention，which can respond intelligently to changes in the formation environment. When the pH of the formation changes，the hydrogel will swell and expand，and the shape will become larger，thereby achieving effective sealing of the failure cement. The research progress of sealants for carbon dioxide geological storage was introduced in detail in this study，and the sealing mechanism and sealing performance of pH-responsive gels were critical reviewed，and then the future development direction and application prospects were discussed as well.