Abstract:In order to simplify the preparation process of slick water and reduce the cost of field fracturing construction，using acrylamide （AM） and methacryloxyethyl dimethyl octadecyl ammonium bromide （DH-1） as raw materials， 2， 2'-azodiisobutamidine hydrochloride（V50）as initiator，an anti-salt associative thickener（GAF-KYTP）was synthesized，which could be used not only as a drag-reducing agent for slick water，but also as a gel thickener. When the fracturing fluid was prepared by flow-back fluid，a set of multi-functional complex fracturing fluid（sliding water+glue）system with the same type and different dosage of additives was prepared by optimizing the dosage of GAFKYTP，zirconium organic crosslinker GAF-5 and fluorocarbon additive GAF-6. The resistance reduction，temperature and shear resistance and core damage of fracturing fluid were evaluated. Finally the fracturing fluid was applied in Weiyuan block. The results showed that GAF-KYTP had good salt resistance and viscosity increasing performance in flow-back fluid. The slick water with formula of 0.06% GAF-KYTP+0.1% GAF-6 had fast dissolution speed，79% indoor resistance reduction rate and 78.3% field resistance reduction rate，indicating good resistance reduction effect. The glue with formula of 0.4% GAF-KYTP + 0.2% GAF-6 + 0.3% GAF-5 had good temperature and shear resistance，whose viscosity was 82.6 mPa s after shearing for 1 h at 90℃ and 170 s^-1. The damage rate of slick water and glue prepared by GAF-KYTP to core matrix permeability was less than 10%. The development of this system improved the problem of complex technology of on-site slippage and simultaneous preparation of glue due to different additives in shale gas production in China，and the problem of poor salt resistance of gel thickener，which made it impossible to use flow-back fluid.

Abstract:In order to solve the problem of high concentration of fracturing fluid thickener in China，organic boron crosslinker JS2-6 was synthesized by using sodium tetraborate decahydrate as main material and complexing with ethylene glycol，triethanolamine and polyhydroxy alcohol under the catalysis of NaOH. The synthesized crosslinking agent JS2-6 was used in low concentration fracturing fluid system. The structure of crosslinking agent JS2-6 and HPG/JS2-6 was characterized by infrared spectroscopy. The delayed crosslinking，temperature and shear resistance filtration，demulsification and friction properties of the fracturing fluid formed by the crosslinking agent and low concentration hydroxypropyl guanidine gum were studied. The formula of low concentration fracturing fluid system obtained by experiment was as follows：0.3%—0.35% HPG+0.2% fungicide FHS-18+ 0.2% assistant F220+0.3% clay stabilizer DS-208+0.1% cross-linking accelerator+0.02%—0.04% pH regulator，the cross-linking ratio was 100（0.2—0.3），and the suitable temperature of the system was 60—150℃. The crosslinking time could be prolonged up to 90 s by adjusting the pH value of the system. After sheared for 90 minutes at the temperature of 140℃ and shearing rate of 170s^-1，the viscosity of the fracturing fluid remained about 150 mPa·s，which indicated that the fracturing system had excellent temperature and shear resistance. The system had the lowest filtration coefficient of 7.12×10^-4m/min^1/2 and a filtration capacity of 28mL at 120℃，indicating that the system could effectively reduce formation damage. The interfacial tension between gel breaking fluid after gel breaking and kerosene at 120℃ was less than 1 mN/m，in addition，the gel breaking fluid had low viscosity，low formation damage rate and low frictional resistance，which could meet the requirements of easily draining.

Abstract:Aiming at the problem of gel nonuniform breaking using ammonium persulfate（APS）at fracturing fluid in Gaoshangpu oilfield，a gene fragment of β-mannan enzyme was extracted from marine thermophilous bacteria. The gel breaking principle of APS and biological enzyme was analyzed by means of GPC and electrospray ionization mass spectrometry. The proper temperature and the range of pH vale of β-mannan enzyme was researched. The fracturing fluid prepared with guar gum，biological enzyme，capsule breaker and other additives was applied in some deep wells of Gaoshangpu oilfield. The results showed that mannan enzyme was endonuclease. The viscosity and molecular weight of guar gum were greatly reduced by intersecting action which directly affected on the glycosidic bond and mainly produced 2—6 oligosaccharides with few monosaccharide. While APS preferred to break the C—C bond on the sugar ring. β-mannan enzyme tolerated 120℃ and 4—10.5 pH value. The optimum temperature was 70℃ and the pH value was 6—7. The enzyme activity at 120℃ was 40% of the highest enzyme activity，and the activity could maintain 55 min. While when the temperature was 90℃，the activity maintaining time increased to 180 min. Adding APS and biological enzyme into the fracturing fluid could reduce 22%—45% residue content. When the fracture was completely closed，the technology of injecting high concentration biological enzyme acquired effective stimulation in 9 fractured wells. The average injection pressure initially decreased about 13 MPa，the average cumulative injection quantity was 1.2×10⁴ m³，and the validity was 290 days.

Abstract:In order to meet the requirements of high gel strength，controllable gelation time and broken gelation in low temperature oil well with pressure workover，a tough gel which was suitable for low temperature environment with 30—50℃，was made of polymer P3600 and self-made crosslinking agent Smel 30. The bonding mechanism could be studied by the analysis of its microstructure through SEM. Through the strength of the gel tested by universal material machine and the gelation time and relevant contributing factors studied by viscosity method，the stability and breaking properties of gel were investigated. The results showed that the gel composed of 8.75% P3600 and 2% Smel 30 could stabilize into gel when the temperature was 30—50℃ and pH value was 4.5—5.5，and form a three-dimensional network structure，whose strength reached 18 N. The gelation time of gel was influenced by pH value，which could be adjusted by the control of pH value on site. Metal ions could shorten the gelation time， which could be used as another factor to control the gelation time. The gel system had good oil resistance and stability，and could break quickly into fluids after pressure operation，which met the requirements of pressure operation.

Abstract:In order to meet the performance requirement of pressure operation to the gel strength，controllable gelation time， thermal stability，salt resistance and pressure bearing capacity，the polymer microspheres was introduced to the gel. With acrylamide as the main component，2-acrylamide 2-methylpropanesulfonic acid（AMPS），surfactant SDBS and initiator G20 were introduced to make copolymer microspheres. Corn starch was used as the skeleton and copolymer microspheres were grafted and copolymerized. The pH value was adjusted to 8—9. The optimum ratio of copolymer microspheres was obtained，the influence ofcross-linking agent MES and pH value on the gel formation performance was investigated，the microstructure of the gel was analyzed by scanning electron microscopy，and the thermal stability，salt resistance，high temperature thickening and pressure bearing performance of the gel were evaluated. The results showed that under the condition of 90℃high temperature thickening，the gelling time of the gel system，composed of 2.5% starch + 15% polymer microspheres + 6% cross-linking agent MES + 0.005% initiator G20 gel，could be controlled within around 1.5 h，moreover，the thickening transition time was shorter，which effectively reduced the possibility of gel/gas channeling in the gelling process of the gel solution in the wellbore. Within the temperature range of 90—130℃，the gel strength was up to 28 N and could be stable for 10 days. The gel system prepared with high-salinity aqueous solution with a salt concentration of 9—18 g/L had excellent gel forming performance，showing good salinity resistance，and could effectively overcome the influence of salinity underground. The capacity of pressure bearing of the gel in the case with inner diameter of 121 mm was up to 70 kPa /m，which met the requirements of high-pressure operation.

Abstract:In order to reveal the degradation of anionic polyacrylamide microsphere，anionic polyacrylamide P（AM-AMPS）microsphere was prepared by emulsion polymerization using 2-acrylamide-2-methylpropanesulfonic acid（AMPS）and acrylamide （AM）as monomers. The structure and thermal stability of the prepared microsphere were analyzed by transmission electron microscopy，infrared spectrometer and thermogravimetric analyzer. The viscosity，pH value and particle size of the microsphere which degraded different times at 80℃ after swelling in water were measured. The results showed that the synthesized P （AM-AMPS）microsphere had a uniform distribution with a particle size of about 70 nm，whose thermal stability was similar to that of linear polyacrylamide under anhydrous condition. Different from the linear polyacrylamide hydrolysis，whose hydrolysate was alkaline and the pH value slowly increased，the oxidative degradation of free radical caused the viscosity of the microsphere solution to drop sharply during 0—4 h microsphere degradation in solution，while the hydrolysis reaction was relatively slow，and the pH value maintained at about 2.75. After 4 h，the oxidation degradation rate of free radical decreased，and the hydrolysis reaction promoted the pH value of solution to rise rapidly. Within 0—4 h of the degradation reaction，the anionic polymer segment in outer layer of the microsphere degraded first，and then the microsphere core partially broken，and the particle size of the microsphere rapidly decreased.

Abstract:Conventional acrylamide crosslinked polymer had poor temperature and salt resistance，and would harden under high temperature and high salinity formation conditions，resulting in poor deformation and failure of profile control in deep formation. In order to solve these problems，the temperature and salt tolerant copolymer particle was prepared by introducing the functional monomers N-vinyl pyrrolidone（NVP）and N，N-dimethyl acrylamide（DMAA）into the system，using diethylene benzene as crosslinking agent，formaldehyde sodium bisulfate and ammonium persulfate as initiator and sodium soil as stabilizer. By introducing clay into the system to enhance the toughness and stiffness of polymer，the effects of monomer ratio，addition of various substances on water absorption expansion multiple and energy storage modulus of crosslinked polymer were studied. The results showed that the suitable synthesis condition of the crosslinked polymer was obtained as follows：30% monomer mass fraction，6∶4 NVP and DMAA molar ratio，0.25% diethylene benzene dosage，0.15% formaldehyde sodium bisulfate，0.15% ammonium persulfate dosage，3% sodium soil mass fraction. Through special crushing equipment and two-stage granulation，the particle size could be adjusted from 1 to 10 mm. Under the condition of 130℃ and salinity of 22×10⁴ mg/L，the crosslinked polymer particle was still in the state of water absorption and expansion，and the energy storage modulus was about 5000 Pa after standing for 90 days. The temperature and salt tolerance of the crosslinked polymer was improved.

Abstract:In order to further study the synergistic oil displacement effect of polymer microspheres and origin microorganism flooding technology in low-permeability fractured reservoirs，the plugging ability of polymer microspheres to the core，the compatibility of microorganisms with reservoir temperature and formation water，and the influence of polymer microspheres on the propagation ability of microorganisms were studied，and microbiological displacement and polymer microsphere/compound microbe flooding experiments were also carried out. The test results showed that polymer microspheres had a good injectability in low-permeability cores. With the further migration of polymer microspheres in low permeability cores，the stepwise plugging effect would be produced. The optimized microorganisms could grow and propagate well in the reservoir of the target block，with the addition of polymer microspheres. The interfacial tension between oil and water could be reduced by 47% in microorganism flood test and the oil displacement efficiency could be increased by 6.91% compared with that of water flooding. Oil displacement efficiency was higher than that of water flooding with the increasing of 10.05% in microspheres/origin microorganism flooding test， which met the field profile control and flooding adjustment needs of low-permeability fractured reservoirs in Wangyao block of Ansai oilfield.

Abstract:In order to reduce the interfacial tension between oil and water in alkali-free binary flooding and maintain the viscosity of polymer solution at the same time，aiming at the formation conditions of Shengli ST oilfield，the effects of surfactants such as oleic acid amide carboxybetaine（OAB）and alkanolamide（WCXA）on the viscosity of hydrophobic associating polymer（AP）solution and its interfacial tension with crude oil of Shengli ST oilfield were studied. And the oil displacement performance of binary oil displacement system composed of compound surfactant and AP was evaluated. The results showed that the interfacial tension between the binary system composed of single WCXA or OAB and polymer AP and crude oil could not reach ultra-low value. The combination of WCXA and OAB could produce synergistic effect. Increasing the proportion of WCXA could improve the retention rate of viscosity，while increasing the proportion of OAB was beneficial to decrease the interfacial tension between oil and water. When WCXA and OAB were compounded in a mass ratio of 3∶1，the dosage of compound surfactant was 0.1%-0.4%，and the dosage of AP was 0.15%—0.25%，the interfacial tension between oil and water could be reduced to 10^-3 mN/m order of magnitude in 2 hrs，and the viscosity retention rate of polymer ranged from 102% to 111%. The composite system of 0.25% AP and 0.4% composite surfactant could improve oil recovery by 36% on the basis of water flooding，showing good oil displacement effect.

Abstract:In order to improve formation heterogeneity of stratum，increase sweep volume of displacement agent，reduce water injection pressure and increase water injection capacity，a kind of particle plugging agent SDJ with good salt and acid resistancewas selected from the aspects of expansion ratio，acid resistance and plugging performance. The results showed that the swelling ratio of SDJ was 8.5 times in simulated brine with salinity of 50000 mg/L at the temperature of 60℃. The swelling retention rate was up to 20.83% after acidification treatment. The plugging rate in sand filling pipe with permeability of 997×10^-3 μm² was over 99.5%. The plugging rate in core with permeability of 1.824×10^-3 μm² was 94.7%. Field test results showed that the pressure was raised by 2.0 MPa after injection of the acid-resistant granules，and the water injection displacement was increased by 40.6% after acid injection，and the water injection pressure was reduced by 6.0 MPa. The effect of depressurization and injection-increasing of SDJ was excellent，and the injection profile was modified obviously

Abstract:Aiming at the blocking problem caused by the long-term injection of amphiphilic polymer in the S-block of Bohai Oilfield，an efficient and safe plugging removal system based on beta-cyclodextrin（β-CD）was proposed，the viscosity method and weight loss method were used to study the viscosity reduction effect of β-CD on amphiphilic polymers and plugging，and the plugging model of sand-filled tubes was used to further evaluate its removal effect. The results showed that with the increase of concentration，the viscosity reduction rate of β-CD on oilfield polymers was gradually increased. When the concentration of β-CD was 1.0 g/L，the viscosity reduction rate was 70%. After adding the oil-washing agent，the blocking removal effect of β-CD on X-2and X-18 well field blockage was greatly improved，and the blocking removal rate could reach up to 75.92% and 66.29%，respectively，and the removal rate of sand filled pipe reached up to 64.37% . β-CD had a competitive inclusion effect on the hydrophobic group of amphiphilic polymer，which could destroy the spatial network structure of polymer molecules，as a result，it could be used as a safety degrading agent.

Abstract:In order to improve the contradiction between low viscosity and high strength of epoxy water plugging agent in oil and gas fields，a low viscosity and high strength material used in gas field plugging agent was prepared with bisphenol F epoxy resin（B）as matrix，n-butylated phenolic resin（BPF）as crosslinker and diluent，and 2-ethyl-4-methidazole（EMI）as accelerant. The structure of BPF and its effect on the viscosity，curing time and mechanical strength of the system were studied. The results showed that the viscosity of the curing system could be significantly reduced by the addition of BPF. When the mass fraction of BPF reached 80%，the viscosity of B/BPF system was 50 mPa·s，which completely met the need of its transportation to the depth of gas field. EMI could obviously promote the curing of the system and shorten the gelation time. By adjusting the content of EMI，the curing time of the system could be adjusted within 1—7 h. B/BPF system had high crosslinking density，which endowed the system with excellent mechanical property，and its compression strength was up to 129 MPa. In addition，B/BPF system had decent water/acid resistance and thermal stability，and could stably exist for a long time under the harsh conditions of high temperature and high salinity. B/BPF plugging agent had low viscosity before solidification and high strength after solidification，which met the application requirement of water plugging agent for gas well.

Abstract:In order to optimize the profile control technology suitable for horizontal injection well in Bohai oilfield，using the self-made horizontal well profile control flow model，the injectability，temperature and salt tolerance and long-term stability of the system，including the powder polyacrylamide gel and emulsion polyacrylamide gel system，the pressure reduction injection system and the particles system were investigated，the adaptability of several profile control system injections was studied，and the emulsion polymer gel and adaptive particle multi-segment combination（EPMSC）system，was determined and the field test was carried out. The results showed that the injection pressure of the high molecular weight powder gel system rised rapidly，the partial flow rate of the high-permeability layer was very high，while the partial flow rate of the medium-low permeability layer was very low，indicating that the injection effect of the high molecular weight powder gel system was extremely poor. The viscosity of emulsion polymer gels，depressurized injections and granules systems was in range of 3—50 mPa·s，and the injectionability was good. These three types of systems had a salt tolerance of 5×10⁴—10×10⁴ mg/L，a temperature resistance of 50—100℃，and a thermal stability of 10—12 months. The recovery rate of different combination systems after the regulation and control was 36.7%— 43.6%，and enhanced oil recovery rate was 13.6%—20.5%. The pressure reduction and injection system had certain advantages for reducing the injection pressure，but the effect of enhanced oil recovery was limited. It is considered that The EPMSC system had a good pressure-reducing and injection-increasing capacity，and the enhanced oil recovery rate was 20.3% based on the water flooding. EPMSC profile control technology was carried out in an H horizontal well in Bohai oilfield，the water injection pressure increased steadily after the measure，and the apparent water absorption index decreased by 36.5% . The apparent resistance coefficient and residual resistance coefficient calculated by the Hall curve were 4.30 and 3.42，respectively，indicating the dominant flow channel was effectively blocked，and the cumulative oil increase of the corresponding well group was 8414.5 m³，which was remarkable. The successful application of EPMSC profile control technology was of great significance in increasing the production and stable production of horizontal well water injection reservoirs throughout the Bohai oilfield.

Abstract:In the field of microbial enhanced oil recovery（MEOR）research，bacterial liquid product quality testing，field test monitoring and environmental protection，the amount of denitrifying bacteria（DNB）was determined by the time-consuming most probable number method（MPN method）. In order to measure the amount of DNB bacteria more easily and accurately，it was recommended to use a DNB-specific test bottle containing carbon source，nitrogen source，phosphorus source and chemical deoxidizer. The results showed that the water sample was infused into the test bottle and was diluted step by step，the culture solution became cloudy and bubbles appeared after culturing for 5 days at 30℃，indicating the growth of DNB bacteria. The DNB count was performed according to the conventional bacterial bottle method. The amounts of DNB bacteria in an oilfield production fluid，biological bacteriostatic agent and microbial anti-wax agent were determined by the bacterial bottle method，and the results were basically the same as those of the MPN method. Compared with the traditional MPN method，the bacterial bottle method had the advantages of obvious growth indication，simple operation and high work efficiency.

Abstract:At present，the existing one-step acid system optimization method was based on room temperature condition，and oftencould not reflect the actual condition under the dynamic reservoir condition in real，which resulted in many preferred systems still producing fluoride precipitation in the residual acid environment，etc. Based on the complexometric titration method，a new method for chelating acid system based on the chelation value and the clamping criterion was proposed. The chelating abilities of five kinds of acid systems，including mud acid and chelating acid 1—4#，to four metal ions Ca₂₊、Al₃₊、Fe₃₊、Si₄₊ were studied. The effects of mud acid and preferred chelating acid on the permeability and damage of core were compared. The results showed that chelating acid 4# had the best capability of chelating four kinds of metal ions at 25，60，80 and 90℃. The permeability of the core after treatment with chelating acid 4# at 25，60 and 90℃ was 1.68，3.14 and 9.21 times than that of the core before treatment，respectively. The results of core morphology after acid treatment showed that the mud acid had a secondary precipitation after treatment，and there was no obvious secondary precipitation after chelating acid 4# treatment，which further proved the reliability of the preferred acidification system method. This method could simulate the real-time reaction dynamics of metal ions in acid system under different formation temperature conditions，and truly reproduce the secondary precipitation problem of sandstone acidizing liquid system.

Abstract:In order to obtain gemini imidazoline quaternary ammonium salt corrosion inhibitor with good inhibition performance，three gemini imidazoline inhibitors of quaternary ammonium salts，including metronidazole G1，asymmetric imidazoline G2 and bis-imidazoline G3，were synthesized by using epichlorohydrin，thiourea and three different amines. Chemical soaking for weight loss，electrochemical polarization curves and electrochemical impedance spectroscopy （EIS） were applied to compare the inhibition behaviors of three inhibitors on X52 steel in produced water of a certain natural gas well with 34330 mg/L salinity. The effect of inhibitor concentration on the inhibition efficiency was studied，and the mechanism of gemini quaternary ammonium salt corrosion inhibitor was analyzed. The results showed that inhibitor G1 and G2 were asymmetrical，while inhibitor G3 were symmetrical. Three inhibitors exhibited excellent inhibition performance. The corrosion rate of X52 steel decreased significantly and the corrosion inhibition efficiency increased with increasing concentration of three inhibitors at 76℃ . Three inhibitors were arranged according to the corrosion ability in following order：G3>G2>G1. All the adsorption and inhibition of three inhibitors on the surface of sheet steel accorded the Langmuir adsorption isotherm. The adsorption mode obeyed mixed-type of synergized chemisorption and physisorption. The three gemini quaternary ammonium salt corrosion inhibitors were all mixed corrosion inhibitors with anodic inhibition as the main factor. The film forming effect on the surface of X52 steel had a great influence on the electric double layers. Due to the difference of molecular structure and symmetry of three corrosion inhibitors，the coverage of X52 steel surface during adsorption process was affected，resulting in the difference of film forming behavior and corrosion inhibition performance of three inhibitors.

Abstract:Supercritical carbon dioxide corrosion and scaling often happened during carbon dioxide flooding in high salinity and low permeability reservoirs. A corrosion and scale inhibitor CQ-HS mainly consisted of thiourea imidazoline benzoate，organic phosphate imidazoline，quinoline quaternary ammonium salt and poly-epoxy-succinate，was synthesized. The anti-carbon dioxide corrosion and anti-scale performance were researched through high temperature and high pressure trial，electrochemical evaluation and scale inhibition rate evaluation method. The results showed that when adding 200 mg/L CQ-HS，the corrosion rate of carbon steel was controlled below 0.076 mm/a at the temperature of 80℃ and CO₂ partial pressure of 9.0 MPa. The anti-scale rate was 80% when 200 mg/L CQ-HS was adding into the field water. Under the supercritical CO₂ condition，the CQ-HS could possess theadvantages of corrosion and scale inhibition，and be used as a multi-function treatment agent.

Abstract:In order to reduce the occurrence of different degrees of CO₂ channeling during the CO₂ flooding in low permeability reservoirs，the low-permeability and heterogeneous plane-section cores were selected，and large cracks and micro-cracks were created in the cores. The anti-five-point method was used to carry out the water flooding and CO₂ immiscible flooding experiments.The development after water flooding were simulated. Two-stage sealing experiment were carried，which was CO₂ flooding after water flooding with modified starch gel plugging cracks andC₂H₈N₂ blocking gas channel. The experiment results showed that modified starch gel could block cracks in the formation，and the recovery rate of water flooding was 23.4%. Gas channeling occurred during the first CO₂ flooding，but gas channeling was still an important stage to enhance recovery. The recovery rate of first CO₂ flooding was 21.3% . C2H8N2 could block gas channeling effectively and increase the volume of the sweep. The recovery rate of second CO₂ flooding after C₂H₈N₂sealing was 15.0%. In the anti-five-point core physics simulation experiment，modified starch gel’s first-stage sealing after water flooding and C₂H₈N₂ second sealing after CO₂ flooding had 59.6% recovery rate，indicating obvious oil increment.

Abstract:The permeability of the tight reservoir was low，and there were many natural and artificial cracks，resulting in serious CO2 Channeling. the injection performance and blocking ability of the modified starch gel（MSG）system was evaluated by measurements of the viscosity and the gel strength under different concentration. the sealing effect of MSG system on the fractured tight sandstone core with 3 different fracture opening degrees was studied，and the effect of improving the recovery rate after plugging was studied. Furtherly，the MSG plugging limits of CO2 flooding in fractured tight sandstone reservoirs was probed. The experimental results showed that the viscosity of MSG system was low before gelling，which was beneficial to the smooth injection of the system，and the strength was high after the gel formation，indicating that MSG system could be used for the sealing of crack in experimental condition. Under the condition of 0.42 mm crack opening，the blocking rate of MSG system was more than 99%，the breakthrough pressure was up to 24.9 MPa and the enhanced oil recovery was 28% after plugging. Under the condition of 0.65 mm crack opening，the blocking rate was 92%，the breakthrough pressure was reduced to 15.9 MPa，and the enhanced oil recovery rate after plugging was 18%. Under the condition of 0.08 mm crack opening，the injection performance of MSG system was poor，the blocking rate was 90%，the breakthrough pressure was 3.6 MPa，and the enhanced oil recovery rate was 9.8% after plugging.The MSG system was adaptable to the fractured tight sandstone reservoirs with about 0.42 mm crack opening

Abstract:The tight oil layer had poor physical property，small pore throat radius，serious heterogeneity of reservoir，low water flooding efficiency，and poor effect of waterflood development. In order to further improve the oil displacement efficiency of Gaotaizi tight oil layer in Daqing oilfield，the experiment of air foam liquid system flooding was carried out by simulating the conditions of oil layer. The experiment results showed that the average oil displacement efficiency of water flooding in Gaotaizi tight oil layer was 48.95%，and the displacement efficiency of air-foam alternating flooding after water flooding was 79.63%，which increased the oil displacement efficiency by 26.92%. The displacement effect of a short alternating displacement was better than that of big slug. When the gas-liquid ratio was too high，the breakthrough time became shorter and flooding effect reduced. Instead of water flooding，direct air-foam liquid slug could achieve good flooding effect. The air-foam flooding could substantially improve the oil displacement efficiency of tight oil after water flooding. The displacement effect of tight oil layer could be improved through the injection parameter optimization of air-foam liquid slug，cycle and gas-liquid ratio.

Abstract:Because of the poor stability of ordinary foaming agents in high temperature reservoir environment，hydrophobic SiO2 nanoparticle was selected to enhance high temperature stability of benzene sulfonate foaming agent HY-4. Foam properties of HY-4 before and after compounding with nanoparticles were contrasted，while the foam stabilization mechanism of nanoparticles was discussed. Then，the temperature resistance of different foam systems were evaluated，as well as their high temperature plugging capabilities were compared. The results showed that the composite foam system with 0.5% HY-4 and 1.0% hydrophobic SiO2 nanoparticles had the best foam performance. The foam performance of composite system after aging 12 hrs was obviously better than that of HY-4 foam system below 150℃. The foam size of composite foam system was also smaller than that of HY-4 foam system，and it was little changed after 1 h standing. Besides，the core plugging capability of composite foam system was superior to that of HY-4 foam system at 150℃. And the foam of the composite system produced by the core had small particle size，high sphericity and strong compression resistance. Hydrophobic SiO2 nanoparticle could greatly enhance foam stability and improve foam plugging capability at high temperature

Abstract:The salinity affected the foaming ability of foaming agent and the stability of foam. The compounding of different types of foaming agent could play a synergistic effect on foam and enhance the salt tolerance of foam. Four kinds of water with salinity of 0，50，100 and 150 g/L，three surfactants including sodium alpha olefin sulfonate（AOS），sodium dodecyl sulfate（SDS）and anionic-nonionic surfactant（SS-163）were selected to prepare foaming agent solution. In order to simulate the contacting process between foam and formation water with high salinity after foam injection，the brine with salinity of 220 g/L was injected into the foam. The foaming performance of surfactant system was evaluated by Waring Blender method. And the concept of salt sensitivity index was put forward to define the evaluation standard of salt sensitivity，which was suitable for the compound system of foaming agent and single foaming agent. The results showed that when foaming with brine，the salt tolerance of surfactant complex system was better than that of single surfactant system. The salinity of brine had a great effect on the foaming properties of anionic surfactant AOS and SDS，but had little effect on anionic-nonionic surfactant SS-163. There was a critical point C of salt tolerance in the range of salinity 100 to 150 g/L. When the salinity was less than C，the compound effect of AOS and SDS was the best with the mass ratio of 1∶1，while the salinity was greater than C，the compound effect of SDS and SS-163 was the best with the mass ratio of 1∶1. According to the average salt sensitivity index and standard deviation of foaming agent，the salt sensitivity of single foaming agent could be divided into three grades，such as weak salt sensitivity，medium salt sensitivity and strong salt sensitivity. And according to whether the compound system contained weak salt sensitive surfactant and the average value and standard deviation of salt sensitivity index，the strength of salt sensitivity of the compound system could be judged.

Abstract:Longfengshan gas field water well is characteristic of deep well depth，high gas temperature（104—149℃）and super high content of condensate oil for some blocks. A kind of organic ammonium salt type cationic fluorocarbon surfactant was synthesized，and it was mixed with the existing foaming agent as a ratio of 1∶15，which was composed of zwitterionic surfactant cocoamidopropylbetaine and sodium alpha-olefin sulfonate at ratio of 10∶1，thus the foam unloading agent PQ-Y was developed. Its foaming ability，foam stabilizing ability and liquid carrying ability were tested and field test was also carried. Laboratory tests showed that the initial foaming height Ho and foam height after 5 min H5 of the foam unloading agent were 194 mm and 186 mm，respectively，after aging at 160℃ for 14 h，and Ho and H5 were 189 mm and 180 mm when the salinity was as high as 250000 mg/L，and Ho and H5 were 171 mm and 168 mm，respectively，when the volume fracion of petroleum ether was 50%，its liquid carrying rate was as high as 8 mL/min，which indicated that the foam unloading agent PQ-Y was resistant to the condensate oil. The field test of the foam unloading agent in Longfengshan north 201-XY well showed that，the average gas production increased from 7256 m3/day to 11329 m3/day，increasing by 56%，the average differential pressure between tubing and casing dropped from 2.66 MPa to 2.38 MPa，felling by 10.5%，both liquid yield and gas production were obvious，which proved that the foam unloading agent PQ-Y could meet the demand of drainage gas recovery for high content condensate oil gas field

Abstract:In order to obtain betaine amphoteric surfactant with good salt tolerance，N-dodecyl benzyl-N，N-dimethyl hydroxypropyl sulfonate betaine（DB-17）was synthesized by using dodecyl benzene（linear chain）polyformaldehyde，dimethylamine and sodium 3-chloro-2-hydroxypropyl sulfonate as main materials through chloromethylation reaction，nucleophilic substitution reaction and quaternary ammonium reaction. The structure of the synthetic compound was characterized by mass spectrometry and infrared spectroscopy. The interfacial tension between DB-17 solution and Xinjiang crude oil was measured. Finally，the oil displacement effect of DB-17 was evaluated by the core displacement device. The results showed that the yield of DB-17 could reach 90.3% when the reaction carried out on the condition of 1.3∶1 mole ratio of N，N-dimethylhydroxypropyl sulfonate sodium and dodecyl benzyl chloride，70℃ reaction temperature，and 6 hrs reaction time. DB-17 had strong interface activity. With the increase of DB-17 concentration，the interfacial tension between oil and water decreased. When the mass concentration of DB-17 was 250 mg/L，the interfacial tension between oil and water could be reduced to 1.3×10-3 mN/m. DB-17 had better salt resistance，and 15 g/L NaCl solution had less effect on the interfacial tension between DB-17 and crude oil. DB-17 had a good flooding effect. 250 mg/L DB-17 could increase the oil displacement efficiency of natural rock with high permeability by an average of 14.7% based on water flooding

Abstract:In order to obtain a heavy oil viscosity reducer with good temperature resistance，salt resistance and viscosity reduction，sulfobetaine surfactant YJN-1 was prepared by oleic acid，N，N-dimethyl-1，3-propanediamine and 1，3-propanesultone. YJN-1 could be used not only as an oil-soluble viscosity reducer but also as an emulsifying viscosity reducer，showing a dual-effect function. The effects of YJN-1 dosage and temperature on the viscosity reduction of heavy oil were studied. The temperature resistance and salt resistance of YJN-1 as an emulsifying viscosity reducer were investigated. The experiment results showed that as an oil-soluble viscosity reducer，the viscosity reduction rate of YJN-1 to Xinjiang and Shengli heavy oil was about 91% under the condition of 50℃ and 0.5% dosage，whose viscosity reduction effect was better than that of some commercial reducers. As an emulsification viscosity reducer，0.15% YJN-1 had an emulsification viscosity reduction rate of about 99% for two heavy oils at 50℃. The emulsion could be dehydrated automatically，and the dehydration rate was 96.4%—98.2%. YJN-1 had good resistance of temperature（160℃）and salt（85 g/L），and good viscosity reduction

Abstract:The heavy oil resource in Bohai area was huge，but the effect of water flooding development was poor because of the high viscosity of crude oil and the serious heterogeneity of reservoir. In order to make the technology of reducing viscosity by emulsification play an important role in Bohai oilfield development，based on the reservoir and fluid of LD5-2 oilfield，the technology research of profile control and reducing viscosity by emulsification and analysis of field test effect were carried out.Referring to the results of previous physical experiments，the parameters of numerical simulation，including the concentration and slug size of viscosity reducer，slug size of profile control agent were obtained. The influence order of injection parameters on the oil increasing effect of viscosity reducer was obtained by orthogonal experimental scheme simulation，and then the field test scheme was optimized. The results showed that the injection parameters were arranged according to their influence on the oil increasing effect of viscosity reducer in following order：slug size of viscosity reducer>slug size of profile control agent>concentration of viscosity reducer. Combined the results of physical simulation and numerical simulation，B15 well group should adapt the technology of profile control and reducing viscosity by emulsification to improve oil recovery，in which the optimum concentration and slug size of viscosity reducer（nonionic surfactant）were 1600 mg/L and 0.08 PV，the polymer dosage in profile control agent was 4000 mg/L and the ratio between polymer and Cr3+ was 180∶1，and the slug size of profile control agent was 0.03 PV. The cumulative oil production was estimated to 62.89×104 m3，the cumulative oil increment was 5.61×104 m3，and the recovery was increased by 3.06% after construction according to these parameter. The field test had achieved remarkable effect of oil increasing and precipitation. The net increase of oil was 6906.4 m3 as of August 27，2017

Abstract:In order to solve the problems of conventional emulsion，such as easy demulsification at high temperature，weak viscosifying ability and poor steering ability，a high temperature resistance and high salinity tolerance water-in-oil emulsion with 3∶7 oil-water ratio was prepared by using diesel oil as oil phase，oleic diethanolamide（ODEA），polyisobutylene succinimide（T154）and sodium dodecylbenzene sulfonate（SDBS）as emulsifiers. And the properties of emulsion were evaluated. The results showed that the emulsifying rate of the water-in-oil emulsion prepared with 2% ODEA，0.8% T154 and 0.3% SDBS emulsifier was over 85% after aging at 150℃ for 12 hrs. The particle size of the emulsion ranged from 20 to 50 μm. The emulsion had good stability，temperature and salt tolerance，and the viscosity of the emulsion was 295.6 mPa·s at 95℃ and 170 s-1. The viscosity of the emulsion was 7090.2 mPa·s when it mixed with 20×104 mg/L salinity water at volume ratio of 10∶5，and that was lower than 50 mPa·s when it mixed with diesel oil. High concentration acid could reduce the viscosity increasing effect of emulsion. As a result，water phase slug should be injected before acid injection. The emulsion could effectively plug the high permeability area and fracture of matrix，and realize continuous multi-stage turning of acid，which could be used in high temperature and high salinity carbonate reservoir.

Abstract:A large amount of oily sludge will be produced in the process of petroleum exploitation. In order to solve the problems of oil waste and environmental pollution in this process，based on the analysis of the basic composition of oily sludge，the hot water/chemical cleaning method was adopted to degrease the oil sludge in Tahe oilfield. The effects of detergent concentration，cleaning temperature，stirring rate，stirring time and liquid-solid ratio on residual oil rate were investigated using surfactant QT9 and alkali as cleaning agentsby single factor and orthogonal experiments. The experimental results showed that when the concentration of QT9 was 0.6%，the concentration of mixed alkali was 3%，the cleaning temperature was 25℃，the stirring time was 30 min，the stirring rate was 210 r/min and the liquid-solid ratio was 3∶1，the oil content of sludge could be reduced from 14.3% to 1.3% by twice cleaning. The orthogonal experiment results showed that the influence factors to the residual oil rate were arranged as follows：temperature > dosage of main agent > dosage of auxiliary agent > liquid-solid ratio. Thermogravimetric analysis showed that the crude oil composition in the sludge decreased significantly after cleaning

Abstract:Using polyacrylic acid，sodium polyacrylate，polyacrylamide（non-ionic），aluminum potassium sulphate，DAMPE （modified demulsifier）as the main raw materials，a compound quenching agent was prepared by compounding，and was applied to oily sludge treatment by tempering and centrifugation. The solid-liquid ratio，stirring time，centrifugal time，and centrifugal speed was investigated to determine the optimal centrifugation conditions. Through the single flocculation and orthogonal experiments，the amount of each flocculant was determined to obtain the best compound flocculant. The compound quenching agent was obtained by combining the best compound flocculant with DAMPE，and the best tempering temperature was determined by investigating the deoiling effect. The results showed that the best treatment conditions for oily sludge were as follows：solid liquid ratio was 1∶2，stirring time was 20 min，centrifugal time was 30 min，centrifugal speed was 3600 r/min. The demulsifier DAMPE and the complex flocculant（5 mg/L polyacrylamide + 2.5 mg/L polyacrylic acid + 5 mg/L sodium polyacrylate + 5 mg/L alum）were mixed at a mass ratio of 2∶3 to obtain a compound quenching agent. Under optimal treatment conditions，when the tempering temperature was 45℃，the deoiling effect was the best and the deoiling rate was up to 95.66%. The composite tempering-centrifugation treatment could realize the three-phase separation of oil cement and was an effective treatment technology for oily sludge

Abstract:Aiming at the problems of water treatment agent commonly used in Gudong oilfield，an efficient water purifier HQG which was suitable for heavy oil thermal recovery sewage in Gudong oilfield was compounded by optimizing demulsifier，degreaser and flocculant in laboratory and utilizing the mechanism of compound synergy，and the optimum application condition of HQG was systematically studied. The results showed that polyamines demulsifier Thg-A2 had relatively good demulsification performance and oil removal performance. Self-made polysilicon zinc sulfate flocculant PSZS showed better flocculation performance than common polyferric aluminum chloride and polyferric aluminum sulfate. When the mass ratio of Thg-A2 and PSZS was 1∶4，the treatment effect of HQG on heavy oil wastewater was the best. Under the best condition such as 300 mg/L dosage，80℃，20 min settling time and 7 pH value，the oil content of heavy oil wastewater after treatment decreased to 19.44 mg/L，the deoiling rate reached 98.3%，the content of suspended matter decreased to 10.2 mg/L. The water quality was clear and the transmittance reached 94.2%，showing good water purification

Abstract:Pipeline played a significant role in production and transportation of oil and gas. The use of film-forming corrosion inhibitor was one of the most economical and reliable methods of controlling internal corrosion of oil and gas pipeline. The mechanism and characteristics of different types of corrosion was introduced. Through the selection of pipeline equipment material and the pipeline internal corrosion control of pH stabilizer and corrosion inhibitors，the research status and development direction of organic film-forming inhibitor using in oil and gas pipeline were analyzed，including imidazoline，fatty amine，ethoxylation amine，quaternary ammonium compound，sulfur compound and polyamine derivative based polymer inhibitor

Abstract:Diffusion coefficient was one of the prime parameters to study the gas EOR mechanism. In order to understand the influencing factors and the corresponding mechanism of gas diffusion coefficient in crude oil，the recent researches about diffusion coefficient of conventional gas such as CO2，N2 and light hydrocarbons in crude oil were summarized. Through different reports on experimental methods for determining the gas diffusion coefficient in crude oil，the influences of gas type，oil composition，and diffusion conditions like temperature，pressure and other factors on gas diffusion coefficient were discussed. Subsequently，primary influence rules of these factors were described，and relevant functioning mechanisms of these factors on gas diffusion in crude oil under high temperature and high pressure conditions were briefly presented. The research directions of gas diffusion coefficient on complicated reservoir conditions were proposed

Abstract:Because of small size，large specific surface area，nanomaterial exhibited good mechanical，magnetic，electrical， thermal，optical and chemical properties，and was widely used in the field of petroleum exploration and development. By combing nanomaterial in the description of formation parameter，fracturing process and oilfield wastewater treatment，etc.，the research progress of nanomaterial in the key areas of petroleum exploration and development was summarized，and the future research trending of low cost was expected. Nanomaterial could be used as new sensor and intelligent robot in oil and gas exploration and development process for data monitoring and analysis，as additive in drilling and fracturing process，and to prepare nanocatalytic membrane for oilfield wastewater treatment. The application of nanomaterial could solve some of the problems of existing oil exploitation and improve the recovery of unconventional oil and gas resource