Abstract:In this paper，API filtration experiments were carried out to study the influence of silica nanoparticles with amino （SiO₂-A），double bond（SiO₂-D）and epoxy groups（SiO₂-E）on the filtration of water-based drilling fluid and their compatibility with commercial filtrate reducer，including phenolic resin，sulfonated asphalt，low viscosity CMC and potassium humate. And the molecular structure of surface modifiers，morphology and hydrophilic/hydrophobic properties of nanoparticles were studied by means of infrared spectrometer，transmission electron microscope and contact angle measuring instrument，respectively. The results showed that the filtrate loss of drilling fluid was reduced by 41% and 29%，respectively，compared with adding commercial filtrate reducer alone，when SiO₂-D was combined with low viscosity CMC and potassium humate at mass ratio of 2∶1 and 1∶1， respectively. After aged at 180 ℃，SiO₂-D still had good compatibility with humic acid potassium，and the filtrate loss of the drilling fluid adding SiO₂-D and humic acid potassium was 28% lower than that adding humic acid alone. The reason for the good compatibility between SiO₂-D and potassium humate was that the polar groups in potassium humate，such as —OH，—OCH₃， =CO，could implement the hydrogen bond adsorption with hydroxyl groups on the surface of SiO₂-D，which could stabilize the viscosity of drilling fluid and maintain the particle size distribution of solid phase in drilling fluid. Ultimately，thin and dense mud cake in the filtration process was formed， so as to effectively control the API filtrate loss of drilling fluid.

Abstract:Aiming at the problem of poor temperature resistance of drilling fluid due to the high temperature degradation of conventional modified starch filtration reducers，a filtration reducer STAR-AM with temperature resistance and viscosity increase was prepared by using natural starch as raw material，2-acrylamido-2-methylpropanesulfonic acid（AMPS）and acrylamide（AM） as grafting monomer through graft copolymerization method. The structure of the product was characterized by infrared spectroscopy. STAR-AM was compounded with flow modifier，plugging agent，shielding temporary plugging agent，lubricating defoamer and HCOONa to form a clay-free drilling fluid system with high temperature resistance. The temperature resistance， viscosity increase and fluid loss reduction performances of STAR-AM in base mud or drilling fluid system were evaluated respectively，and the reservoir protection effect of the drilling fluid was investigated. The results showed that STAR-AM prepared under the condition of starch（corn starch and tapioca starch in mass ratio 60∶40）and monomers（AMPS and AM in molar ratio 1∶ 2）in mass ratio 65∶35 had good performance of temperature resistance，viscosity increase and filtration reduction. When the dosage of STAR-AM was 10—25 g/L，the viscosity and shearing force of base mud significantly increased after aging at 150 ℃，and the API filtration greatly reduced. After adding formate，the temperature resistance of base mud increased from 150 ℃ to 170 ℃. When the dosage of STAR-AM was 25 g/L，the API filtration of the clay-free drilling fluid after aging at 170 ℃ was only 1.3 mL，and the HTHP filtration was only 10.2 mL，which was significantly better than that of conventional modified starch filtration reducers. It had excellent protection effect on reservoir，and the permeability recovery of core exceeded 95% ，which could be popularized and applied in the open-hole drilling and completion of ultra-deep horizontal well.

Abstract:During the process of oil-base drilling fluid in shale gas horizontal well，it is difficult to remove mud cake and oil film， leading to poor cementing quality and even sustained casing pressure. Based on the principle of micro-emulsion solubilization，a modified polyoxyethylene-polyoxylpropylene （PEO-PPO） block copolymer surfactant was prepared by using fatty alcohol， ethylene oxide and propylene oxide as raw materials. Then the oil displacement agent QX-1 was developed by the block copolymer surfactant and sodium dodecyl benzene sulfonate. The high efficiency oil displacement preflush fluid was prepared by mixing QX-1 with isolating agent GL-1，weighting agent barite powder with 23 μm（600 mesh）and water. The sedimentation stability，cleaning efficiency，interface bonding strength and compatibility of this prefluish fluid were evaluated，and it was applied on shale gas production layer cementing in Fuling area. The experiment results showed that the high efficiency oil displacement prefluish fluid had good sedimentation stability at 60—90 ℃ and excellent performance of cleaning efficiency. When the dosage of QX-1 was 20%，the cleaning efficiency at the simulated casing-cement interface was up to 93.94% and the mud cake removal efficiency at the cement-formation interface was 91.16%. And these two interfaces had reverse wetting properties after modified by high efficiency oil displacement preflush fluid，which effectively increased the interface bonding strength. Field application results showed that the compatibility of high efficiency oil displacement preflush fluid with oil-based drilling fluid and leading cement slurry in Fuling shale gas field was good. The cementing pass rate and the cementing quality rate was 100% and 92.73% respectively，which could improve the sustained casing pressure caused by poor interface cementing quality.

Abstract:Due to long horizontal displacement，large deviation angle，high formation pressure coefficient and high friction torque during completion，the running of string is affected. In order to solve this problem，a kind of completion fluid lubricant CR301 was developed in laboratory，and the friction reducing and drag reducing performance，anti-friction ability，compatibility，reservoir protection effect and water locking effect of KCl brine completion fluid system with the lubricant were studied. The results showed that when the dosage of CR301 was 2%，the friction coefficient of KCl brine completion fluid decreased from 0.078 to 0.046，the friction coefficient decreased by more than 40%，and the anti-friction ability increased from 4 weights to 10 weights. At the same time，CR301 had good compatibility with KCl brine completion fluid，which could improve the permeability recovery value of core，reduce the surface tension of completion fluid system and reduce reservoir damage. CR301 could obviously improve the drag reduction performance of KCl brine completion fluid system，and had protective effect on reservoir，so it could be used in extended reach well completion fluid.

Abstract:In order to develop the latex cement slurry system with stable and excellent performance，the key materials of the latex powder cement slurry system were studied，the latex powder cement slurry（LPCS）system was constructed，the performance and micromorphology of the LPCS system were studied，and its field application was carried out. The results showed that latex powder could significantly improve the elastic toughness of cement paste，and the dispersant DIP-S，filtrate reducer FLO-S，retarder REM and defoamer CX66L could effectively adjust the performances of cement slurry. Under the conditions of 60 ℃ and 90 ℃，the fluidity index of the LPCS system constructed with these key materials was greater than 0.5，the consistency coefficient was less than 0.7，the thickening time was 3—5 h，no free liquid was formed，the water loss of cement slurry was less than 50 mL，and the compressive strength was more than 24 MPa. The conventional performances of the latex powder cement slurry were excellent. In addition，at these two temperatures，the minimum elastic modulus of latex powder cement slurry was 5.7 GPa，the maximum impact strength and channeling resistance strength were 2.09 kJ/m² and 7.7 MPa/m²，respectively，which indicating that The LPCS had strong sealing capacity. The micro morphology showed that the polymer membrane structure was formed in the latex powder cement paste，which was helpful to improve the performance of cement slurry. The application effect of the LPCS system in shale gas well cementation was good，indicating that the LPCS system was worth popularizing.

Abstract:Nano-SiO₂ can improve the mechanical properties of cement paste，but it cannot be fully dispersed in cement slurry. Aiming at this problem，a nano sol MCRO-T1 which could be effectively dispersed in cement slurry was prepared using alko-S alkoxysilane as raw material. The effects of MCRO-T1 on the conventional property of cement slurry，mechanical property， permeability and micro morphology of cement paste were studied. Finally，nano sol MCRO-T1 was applied in Bohai Bay. The results showed that the content of solid SiO₂ in MCRO-T1 was 45% and the average particle size was 25 nm. When 1% MCRO-T1 was added，the early strength development time of cement slurry was shortened by 1/3，the compressive strength of cement paste was increased by 62.3%，the flexural strength was increased by 21.4%，and the permeability was reduced by 52.1%. Nano particles filled in the voids inside the cement stone，which increased the compactness of cement stone structure and improved the toughness of cement stone. After MCRO-T1 was applied to the cementing slurry system in Bozhong liner，the early strength of cement stone was effectively improved，the cementing quality was significantly improved，and the problem of formation sealing failure of oil and gas reservoir in Bohai Bay was solved，which was of great significance to the exploration of buried hill gas reservoir in Bohai Bay.

Abstract:Gel valve technology has been widely used in underbalanced drilling and completion operations. At present，the combination of mechanical drilling and chemical breaking is the main way of breaking gel，but the process of breaking gel still has the problems of long cycle and high operating cost，which cannot meet the requirements of on-site production. The auxiliary gel breaking microcapsule was prepared by double emulsion method using polyvinyl alcohol（PVA）as the stabilizer solution and ether analogue（EA-1）as the shell layer to cover hydrochloric acid（HCl）. The microstructure and particle size distribution of the product were analyzed by scanning electron microscope. The properties of gel breaking aid and slow release of microcapsules and their influencing factors were studied. The results showed that when the microcapsule was prepared with 6.5% EA-1 solution and 2% PVA stabilizer solution，the morphology of microcapsule was desired，the particle size ranged from 40 to 60 μm，and the drug loading rate was approximately 44.4% . At 60 ℃ ，the auxiliary gel breaking microcapsule acted as a filler in the gel，which increased the gel strength by 64.3% and the gel breaking efficiency of gel breaker by 36.7%. Compared with the system without microcapsule，the gel breaking time was reduced by 1/3，which greatly shortened the field construction period and improved economic benefit.

Abstract:The viscosity of supercritical carbon dioxide（CO₂）is less than 0.1 mPa·s. It is difficult to carry sand in fracturing， which needs thickener to increase its viscosity. Considering that the solubility of thickener in CO₂ was closely related to its viscosity enhancement effect，the solubility of polymer ZCJ-01，surfactant microemulsion APRF-2 and surfactant emulsion SC-T-18 in liquid CO₂，supercritical CO₂ and water was comparatively studied. The experimental data of solubility was linearly correlated by using Chrastil semi-empirical model，and compared with the theoretical value. Finally，the influence law of temperature and pressure on the solubility of thickener in supercritical CO₂ was analyzed. The results showed that the thickener with the best solubility was SC-T-18，and it formed a single，stable，homogeneous emulsion micelle with supercritical CO₂ after full stirring. The relative deviation of solubility between experimental value and theoretical value of the three thickeners in CO₂ was less than 5%，and the experimental value was relatively accurate. The solubility of three thickeners in CO₂ increased with the increase of temperature and pressure，which met the requirement of fracturing operation.

Abstract:The physical properties of the reservoir in the Bohai LD5-2 oilfield are characteristic of high permeability and strong heterogeneity. Long-term water flood development has further exacerbated heterogeneity between reservoirs. It is urgent to take flood control measures to realize deep fluid flow diversion. In this article，profile control and displacement were tested for injection pressure. The characteristics of LD5-2 reservoir were taken as the research object. The indoor three-tube parallel experiment was used to study the effect of injection pressure on the liquid absorption profile of the reservoir. The test results showed that microsphere particles are susceptible to stagnate on the end face of the core injection end，which caused the injection pressure to be "virtually high"，as a result，the liquid flow diverting effect was eventually weakened. Compared with microsphere-based flooding agents，polymer gel-based profile-controlling agents had a stronger injection capacity，and were more likely to enter deep cores and cause retention. The added seepage resistance and injection pressure increased significantly. With the increase of injection pressure， the liquid absorption of the middle and low permeability layers increased，the additional seepage resistance increased due to the retention effect，and the liquid flow diverting effect became worse. Therefore，adopting a reasonable injection pressure could help improve profile and flood control flow diverting effect. It was recommended to carry out the liquid absorption profile test of the injection well before implementing the profile adjustment measures at the mine to determine the maximum injection pressure or injection speed of the agent.

Abstract:In order to meet the high strength requirement，acrylamide/tert-butyl acrylate Copolymer（PAtBA）and crosslinking agent polyethyleneimine（PEI）was used to prepare the gellant，the influence of the content of polymer，the content and molecular weight of crosslinking agent，temperature，salt content and pH on the gelation was emphatically studied. Experimental results showed that gel strength was positively correlated with the content of polymer and crosslinking agent. When the pH value was in range of 6—9，as the pH value increased，the gelation time was prolonged；when the pH value was in the range of 9—12，as the pH value increased，the gelation time was shortened. With the salt content increased，the gel strength would first increase and then decrease. The relationship between gelation time and temperature conformed to the Arrhenius formula，the activation energy required for the reaction was 48.36 kJ/mol. Storage modulus of the gel formed at the temperature of 110℃，which was composed of 5% PAtBA and 1.5% PEI，could reach up to 2689.2 Pa. The gel strength could maintain I level for more than 30 days at the temperature of 170 ℃，indicating that PEI gel had excellent temperature resistance. In addition，compared with chrome gel and phenolic gel，PEI gel had low toxicity and was more suitable for offshore oilfields.

Abstract:In order to meet the technical requirement of deep liquid flow steering in Bohai oilfield，the expansibility of two kinds of polymer microspheres in injected water and porous media was studied，as well as the injection capacity and plugging performance in long rock core by means of laser particle sizer，biomicroscope and core displacement experiment. The results showed that after 8 days of slow expansion in simulated injected water，the average particle size of microsphere A increased from 0.59 μm to 2.21 μm and that of microsphere B increased from 9.18 μm to 31.40 μm. After 7 days of slow expansion in porous media，the injection pressure increased significantly，showing the same good slow expansion effect. The microsphere could enter into the deep part of reservoir during injection process. The two microspheres had good transport and migration performance on the core with long of 300 cm and permeability of 1000 × 10^-3 μm² . After different time of hydration and expansion，the plugging rate of core increased significantly. After 7 days，the average plugging rate of microsphere B and microsphere A was 55.65% and 41.68% respectively. The closer to injection end，the higher plugging rate was. However，some microspheres with large particle size would stay at the end face of the core，resulting in the end face clogging and injection pressure loss of more than 40%.

Abstract:In order to improve the curing strength of the sealing and channeling agent system in ASP flooding environment and improve the plugging effect of external channeling well after ASP flooding，through investigating the influence of the concentrations of main agent（a mixture of irradiated acrylamide and bentonite grafted semi-copolymerized polymer derivatives）， crosslinking agent（ammonium persulfate），reinforcing agent（N，N-methyl-diacrylamide），micro-expansion agent（OP-10 and sodium dodecyl benzene sulfonate）and hardening agent（G grade cement）on curing effect，a slightly expanded sealing and channeling（SESC）system suitable for ASP flooding was obtained. The long-term stability of solidified body of SESC system in ASP flooding system and the compatibility between the SESC system and ASP flooding system were studied，and the plugging performance test of the SESC system on the core in ASP flooding system and the field plugging and channeling test were carried out. The optimal recipe of the SESC system was as follows：13%—17% main agent+0.12%—0.18% crosslinking agent +0.06%— 0.09% reinforcing agent +0.3%—0.5% OP-10 or 0.8%—1.0% sodium dodecyl benzene sulfonate+5%—7% hardening agent. The curing time of the SESC system was 1—5 h. The minimum strength of the system could still exceed 20 N，and the volume expansion multiple was less than 1.5 times after 12 months immersion in ASP environment. After soaking，the volume inflation of the system was controllable and the high strength stability was maintained. The core sealing experiment showed that the breakthrough pressure reached above 10.0 MPa and the core plugging rate exceeded up to 97%，which proved that the SESC system possessed excellent plugging ability. The field sealing test showed that the total well fluid production decreased by 30.3%，the maximum oil production increased by 1.58 t，and the water cut decreased by 4.1% after the SESC system was used to seal the cross-flow horizon of a well. The SESC system had good sealing effect on cross-flow wells after ASP flooding.

Abstract:The deep heavy oil reservoir in Ji 7 area is developed by water flooding，and the emulsion phenomenon is common during development process. In order to understand the effect of emulsification on the development，the emulsification characteristics of the produced fluid were analyzed，the wetting types of produced fluid was determined through by the filter paper method，and emulsifying time was judged by analysis of the change of chloride ion content in water，the emulsion droplet size distribution was observed under a microscope lens and its stability was evaluated. Experimental results showed that the crude oil in JI 7 had special emulsification property. That is，the oil and water could be emulsified spontaneously and quickly even if without the addition of emulsifiers. The emulsifying time was early，the water content of emulsion was high，and the droplet dispersion was uniform and the size was close to that of microemulsion，exhibiting good stability. The viscosity of the emulsion was 2.23 times higher than crude oil before emulsification，which was favorable for forming stable water drive front，and greatly improving water drive recovery. The recovery rate was predicted to be 15% ，however，the current recovery degree was nearly 20% and the comprehensive water cut was kept at 40%. It was obvious that self-emulsification made the actual development effect far better than predicted.

Abstract:As a new nano material oil displacement system，molecular deposition filming flooding agent（MDFFA）can effectively improve oil displacement efficiency. In this paper，trihydroxymethyl aminomethane，epichlorohydrin and triethylamine were selected as raw materials to synthesize a single molecular biquaternium salt system for molecular deposition film oil displacement. The viscosity，cation degree，surface tension and contact angle of MDFFA were measured，and the oil displacement effect was evaluated by dynamic flooding test. The results showed that MDFFA had stable performance，and the viscosity of the system was about 1.11 mPa·s. When the concentration was 800 mg/L，the cation degree reached up to 71.73%，and the adsorption performance on the surface of sandstone was the best. MDFFA could change the wettability of the oil-wet surface slide，the connect angle being of 98.70°，to the weak oil-wet，the connect angle being of 85.31°，and made the water-wet surface slide，the connect angle being of 58.1°，more hydrophilic，the connect angle being 45.58°. MDFFA could displace the crude oil that could not be produced by water flooding. After water flooding was converted to molecular deposition flooding，the displacement efficiency increased from 42.55% to 48.29%，while after molecular deposition flooding directly，the displacement efficiency reached up to 54.81%. Compared with molecular film flooding after water flooding，direct molecular film flooding could enhance higher oil recovery.

Abstract:In order to improve the efficiency of CO₂ flooding in low permeability reservoir，the interaction between CO₂ and crude oil and the influence on CO₂ flooding were studied. Firstly，the principle of CO₂-crude oil interaction under different pressures was analyzed from two aspects such as dissolution and extraction. Then，CO₂ huff and puff experiments were carried out using the de signed core model. At the same time，nuclear magnetic resonance scan was performed on the core before and after displacement and the distribution of remaining oil was analyzed. Finally，combining with the field application in Jiangsu oilfield，the further applica tion direction of CO₂ flooding was proposed. Experiment results showed that when the pressure exceeded the threshold value（10.0 MPa），the extraction rate increased significantly with increasing pressure. The extraction rate reached 85.2% at 40.0 MPa. When the pressure was less than the oil-shrinkage value（13.0 MPa），the crude oil exhibited volume expansion with a maximum expansion co efficient of 1.25. When the pressure was greater than 13.0 MPa，the crude oil exhibited a significant volume shrinkage under the strong extraction of CO₂. The flooding experiment results showed that for a low permeability matrix core with a length of 6.0 cm， the recovery factor of CO₂ huff and puff was 48.0%. During the earlier stage of displacement，the main mechanism of increasing production was oil expansion due to the dissolution of CO₂ in crude oil. And during the second stage of displacement，light weight component extracted by CO₂ was the main factor. In practical application，the effect of oil reservoir conditions on the interaction be tween CO₂ and crude oil should be fully considered. Reservoir with pressure under 15 MPa gave priority to CO₂ huff and puff，and that above 15 MPa gave priority to CO₂ flooding.

Abstract:The chemical structure characterization of petroleum coke is of great significance to the study of fuel generation mechanism of heavy oil fire flooding. The petroleum coke was prepared by using Xinjiang naphthenic heavy oil as raw material under the condition of gas composition of 5% O₂，79% N₂ and 16% CO₂，50—100 mL/min gas flow rate，40 min reaction time and 500 ℃. The solid particles of petroleum coke washed by solvent extraction were subjected to the structure characterization by various detection methods. The results showed that the yield of petroleum coke was 23.4% . After petroleum coke burned under aerobic condition（21% oxygen content）at 440—600 ℃，the total weight of 87.98% was lost，and 8662 J of heat per gram of carbon material was produced. The ignition temperature was 490 ℃. Petroleum coke was characterized and analyzed by infrared spectroscopy，X-ray photoelectron spectroscopy，Raman spectroscopy and X-powder diffraction. It inferred that the structure of petroleum coke was graphite-like molecular lamellar structure with aromatic ring as core body，which surrounded by the ring of naphthene and heterocycles containing nitrogen and oxygen，and linked a small amount of alkane branch chains，ether and ester hydrocarbon branch chains. The oxygen on carbon skeleton was non-reactive oxygen in the form of ketone carbonyl group and aliphatic hydrocarbon aromatic ether. The molecular sheets were combined into 5 layers of stacked associations by intermolecular interaction，such as Vander Waals force，charge transfer，π-π interaction，hydrogen bonding and dipole，and superimposed crystal-like carbon particles.

Abstract:Wood powder is cheap and has a wide range of sources. It contains a large amount of lignocellulose，which is biodegradable and environmentally friendly. The oil-displacement agent compositing wood powder and hydrogel can effectively reduce the cost of production. This work used acrylamide（AM）as monomer，poplar wood fiber mechanochemically modified by ball milling（PWF-BA）as filler，potassium persulfate（KPS）as initiator，N，N'-methylenebisacrylamide（MBA）as crosslinking agent，to synthesize wood powder composite hydrogel. The elasticity，viscosity，shear resistance and anti-aging property of the composite hydrogel under high temperature and high salt conditions were studied. The results showed that after chemical treatment， the lignin and hemicellulose in the wood powder were basically removed. As the milling time increased，the particle size and crystallinity decreased significantly，and the specific surface area increased. When the ball milling time was 4 h，the wood powder obtained had good dispersibility and interfacial interaction in the polyacrylamide matrix. The tensile property of the composite hydrogel and the anti-aging performance in salt water at 85 ℃ were good. The hydrogel was expected to be used as an oil displacing agent in tertiary recovery.

Abstract:The production of styrene tar is high and the price is cheap. However，the utilization ratio of styrene tar is not high and the burning of styrene tar has pollution to environment. In order to enhance the economic value added of styrene tar and provide a kind of low-cost raw material for oilfield development，styrene tar was made into O/W emulsion used in oil displacement process. The emulsification instability coefficient was used as an emulsifier index to select surfactant. The stability，rheology behavior and oil displacement effect of O/W emulsion，that prepared by styrene tar and aqueous surfactant solution，were evaluated. The results showed that O/W emulsion prepared by styrene tar had a good oil displacement effect. The stability of the emulsion was the best when the emulsifier content was 0.3% and the mass ratio of polyoxyethylene ether to alcohol ether sodium sulfate was 1∶1. For the conventional heavy oil with viscosity of 185 mPa·s，O/W emulsion prepared by styrene tar could increase the degree of reserve recovery by 16.7 percentage points on the basis of water flooding. The emulsion prepared by styrene tar could enhance recovery at the later stage of oilfield development with high water cut.

Abstract:In order to clarify the law of petroleum acid on the interfacial tension and emulsifying performance of binary oil displacement system（SP），two kinds of petroleum acids and oil with acid removed were separated from crude oil in compound flooding test area. The carbon number distribution and structure of two petroleum acids were tested，and the influence on dynamic interfacial tension and emulsion stability of SP were studied. The results showed that the relative molecular mass 1# and 2# petroleum acid was 242 and 312，while the carbon number distribution was distributed between 10—15 and 10—25，respectively. The 2# petroleum acid with mass concentration of 700 mg/L could reduce the equilibrium interfacial tension（IFT_eq）between oil and water to 0.021 mN/m，while 1# petroleum acid with the same concentration could only reduce IFT_eq to 0.095 mN/m. The mixed acid had a positive synergistic effect on reducing interfacial tension. The combination of two petroleum acids could achieve ultra-low oil-water interfacial tension in SP. The stability of acid-containing emulsion system was related to the dynamic interfacial tension. The final stability of the oil-water emulsion system containing 2# petroleum acid was higher due to the low IFT_eq. Through the reverse analysis from the performance to raw materials of SP，it was pointed out that the sulfonate should be prepared by adding petroleum acid to raw oil，which increased the emulsification performance of SP and obtained a better effect of reducing interfacial tension.

Abstract:To reduce the damage of the inorganic alkali/ chemical surfactant dual oil displacement system to reservoir formation， improve the biodegradability of the oil displacement system，the interface performance between the biosurfactant rhamnolipid（RL）/ sophorolipid（SL）/monoethanolamine（MEA）or other organic alkali compound oil displacement system and the crude oil was analyzed，and through core displacement model，experimental evaluation of the enhanced oil recovery of RL/ SL/ MEA compound system to Shengli oilfield Zhan 3 block was carried out. The calculation results of Rubingh regular solution theoretical model showed that the RL and SL molecules in the biosurfactant mixed system could spontaneously attract on the surface adsorption layer and synergistically reduce the surface and interfacial tension of the solution. When the ratio of SL to the total surfactants was less than 0.3，the synergistic effect was stronger. The RL/SL/MEA compound system with 0.15% surfactant（SL accounts for 0.2 of both）and 3.5% MEA，could make oil-water interface tension reduce to 9×10^-3 mN/m，reaching the order of magnitude range of ultra-low interinterface tension. Core displacement model experiments showed that RL/SL/MEA oil displacement system could enhance oil recovery by 24.13% based on the water flooding. The RL/SL/MEA oil displacement system has a certain application potential in enhancing oil recovery of oilfield.

Abstract:In Daqing oilfield，physical properties of reservoir become worse and adsorption loss of surfactant increases，research on surfactant concentration optimization was carried out to improve the technical and economic effect of composite flooding. Two static adsorption experimental methods were used to analyze chemical agent loss at different positions of the slug. One method was to change sand without changing liquid，the other was to change liquid without changing sand. Combined with dynamic adsorption and physical simulation experiment，the reasonable variation mode of surfactant concentration was determined. The result showed that，surfactant adsorption at the front of slug displacement was serious，and surfactant concentration should be increased. Adsorption capacity of oil sand flowing through leading edge was weakened，the concentration of subsequent slugs should be reduced appropriately. The adsorbed surfactant could desorb and compensate subsequent slug. According to the law of chemical agent loss，a gradient injection method of surfactant was proposed，which could enlarge action distance of ultra-low interfacial tension with same chemical dosage. Compared with conventional injection method，EOR could be further improved by 0.91% using the gradient injection method.

Abstract:In order to research the adsorption and retention law of chemicals agent in process of compound flooding in conglomerate reservoir，the interfacial property and the adsorption retention of chemical agents of the SP system/ASP system after conglomerate core sand adsorption at different liquid-solid ratios was investigated. The results showed that at different liquid-solid ratios，the interfacial tension between SP system/ASP system and the crude oil changed a little after four times of the conglomerate core sand adsorption，and the equilibrium interfacial tension（IFT_120min）could reach the requirement of ultra-low interfacial tension， being of 10^-3 mN/m. After four times of conglomerate core sand adsorption，the concentration of the chemical agents in SP system/ ASP system decreased with the increase of adsorption times. The reduction degree of the concentration of the chemical agents was arraged as follows，alkali concentration of ASP system＞surfactant concentration of ASP system＞surfactant concentraion of SP system＞polymer concentration of ASP system≈polymer concentration of SP system.

Abstract:Alkali/surfactant/polymer（ASP）flooding produced liquid has high emulsification stability，which affects the stable operation and effective dehydration performance of crude oil electric dehydration process. In order to improve this problem， polyaluminium chloride（PAC）was used as a chemical regulator to control electric-field destabilization by charge neutralization mechanism. The results showed that PAC could reduce the electronegativity of the emulsified system，decrease the peak current of dehydration，shorten the duration of peak current of dehydration，improve the response performance of the electric-field，and increase dehydration rate in ASP flooding dehydration process. The dehydration rate of produced liquid increased from below 95% to above 97.5% after adding PAC. When the mass concentration of PAC was from 180 mg/L to 240 mg/L，both the response and mechanism of electric-field dehydration played a significant role during the operation，low current value with short duration and steady change of current were obtained. The water cut in crude oil and oil content in separated water was controlled within 0.30% and 100 mg/L respectively after experiencing dehydration process. Furthermore，the control effect at 60 ℃ was further improved due to the increased dehydration temperature. PAC could be used to improve the problem of electric-field instability in dehydration process for weak-base ASP flooding produced liquid. The electronegativity could be reduced，the oil-water interfacial film intensity could be weakened，and the electric-field destabilization performance could be improved by means of the potential mechanism of charge neutralization and electrostatic adsorption of PAC.

Abstract:In order to investigate the feasibility of viscosity reduction of offshore heavy oil by catalytic upgrading，and to resolve the problems in the process of artificial lift and gathering and transportation，targeting a heavy oil in the western Bohai Bay，the relationship between viscosity and SARA of heavy oil was analyzed. Ten catalysts，composed of two anion，PAS and FAS，and five cation，Zn²⁺，Cu²⁺，Mn²⁺、Fe³⁺ and Ni²⁺，were used to carry out catalytic upgrading test，and the catalytic upgrading effect was evaluated by comparing SARA of heavy oil before and after upgrading. The result of experiments indicated that the viscosity of the Bohai heavy oil declined with the increase of saturates content and aromatics content and grew with the increase of resin content and asphaltene content. Saturates content had more influence on viscosity compared to aromatics content，and asphaltene content had a little bit more influence on viscosity than aromatics content. Considering resin took a big proportion，decreasing resin content was the primary target of reducing viscosity of the heavy oil. The catalytic upgrading effect of PAS-Ni was the best，as viscosity was reduced from 2167 mPa·s to 566 mPa·s with reduction rate of 73.88%. Followed by PAS-Fe，as viscosity was reduced to 716 mPa·s with reduction rate of 66.96%. SARA analysis of the upgraded heavy oil showed that the resin content dramatically dropped，and saturates content and aromatics content rose，while asphaltene content slightly increased.

Abstract:Aiming at the problems of long dehydration time，large amount of demulsifier，and low dehydration efficiency of a certain heavy oil field in Xinjiang，a thermochemical sedimentation dehydration technology assisted by mixing super heavy oil with coking diesel oil was proposed. Experiments were carried out in the laboratory to reduce the viscosity of super heavy oil by adding different kinds of diluents at different temperatures，and the effect of the coking diesel oil extracted from super heavy oil on viscosity，cyclone desanding，demulsifier dosing concentration and dewatering was studied. The results showed that when blending coking diesel oil into the super heavy oil，the dehydration time of thermochemical sedimentation of super heavy oil was shortened and the concentration of demulsifier was reduced. When the second stage sedimentation tank was filled with super heavy oil blending with 9% coking diesel oil，the qualified water cut index of purification oil could be achieved as soon as the tank was full， and the average settling time of the second stage sedimentation tank filled with super heavy oil blending with 5% coking diesel oil was only 13.4 h，while the settling time before blending with coking diesel oil was 27.8 h. Moreover，the dosage of demulsifier SB-1 could be reduced to 100 mg/L after blending super heavy oil with coking diesel oil，which was 54.5% lower than that before blending，being of 220 m g/L. In addition，the addition of coking diesel oil could also enhance the swirling sand removal effect， reduce the viscosity of crude oil，end the history of on-site tank truck transport，achieve the long-distance pipeline gathering of super heavy oil，and reduce the cost by more than 40%.

Abstract:Natural gas hydrates were easily generated in the drilling and development of deepwater oil and gas reservoirs，which will have a serious impact on deepwater drilling and oil and gas gathering and transportation. The components of associated gas in a deepwater oilfield were complex，and the existing hydrate formation prediction models had large calculation errors. In order to accurately measure the hydrate formation risk of the associated gas in the oil field，a natural gas hydrate micro-observation experimental device was used to determine the hydrate generation conditions of the multi-component gas in the oil field. The influence of ethylene glycol on the formation conditions of multi-component gas hydrate was explored. The results showed that when the temperature was below 15 ℃，the phase equilibrium condition of the multi-component gas was lower than that of methane and carbon dioxide，and higher than that of ethane and propane. When the temperature was higher than 15 ℃ ，the phase equilibrium condition of the multi-component gas was lower than that of methane，ethane and carbon dioxide，which showed that compared with methane gas，the multi-component gas was easier to form hydrate due to the presence of ethane and propane. In addition，hydrate crystals growed in acicular form，and the acicular structure would rapidly develop into body structure，which would easily cause pipeline clog. When the average pressure of the fluid in the gathering and transportation pipeline was 5 MPa， 40% ethylene glycol solution could reduce the equilibrium temperature of the simulated gas hydrate phase by 5.3 ℃，providing a theoretical basis for hydrate prevention and treatment in the process of underwater oil and gas gathering and transportation in this oilfield.

Abstract:In order to achieve targeted release of corrosion inhibitors，and solve the situation of further corrosion of oil and gas pipeline metals，a rapidly responding container was synthesized by modified Stober method. Organic silicon nanoparticles （S-SNPs）embedded with different imines were synthesized by changing the mole ratio of inorganic and organic silicon sources and loaded with MBT to obtain the intelligent corrosion inhibitor MBT@S-SNPs，and its intelligent anticorrosion performance was studied. The results showed that S-SNPs was stable in a neutral environment，but would degrade in an acidic environment，which could achieve a controlled release of corrosion inhibitor. In addition，the impedance of the corrosion sample containing MBT@S-SNPs could be 5 times than that of the blank sample，which effectively alleviated the occurrence of corrosion. The response degradation of S-SNPs and its interaction with corrosion inhibitors resulted in a high load（16%）and pH response release of corrosion inhibitors. The S-SNPs could respond to pH changes caused by corrosion and had broad application prospects in the targeted repair of corrosion.

Abstract:Scaling in oilfield usually leads to the blockage of formation and pipeline，cost increase of development and reduction of oil recovery. Aiming at this problem，barium sulfate scale inhibitor was prepared by using three kinds of chelating agents with good anti-scaling performance，such as sodium polyacrylate with low molecular weight，hydrolyzed polymaleic anhydride and polyaspartic acid. The anti-scaling performance，suspension performance and corrosion performance to pipeline of barium sulfate scale inhibitor were studied. The results showed that the best mass ratio of sodium polyacrylate with low molecular weight， hydrolyzed polymaleic anhydride and polyaspartic acid in barium sulfate scale inhibitor was 2∶2∶3. When the mass concentration of barium ion was 300 mg/L and the temperature was 50 ℃，the scale inhibitor had an excellent anti-scaling effect when the dosage was higher than 12.5 mg/L. When the dosage of scale inhibitor was 100 mg/L，the anti-scaling rate could reach more than 95%. The scale inhibitor had good temperature resistance and low corrosion resistance to pipeline. The scale inhibitor could affect the sedimentation of barium sulfate scale and the normal growth of scale nuclei，which made the structure of obtained scale regular and looser. It was conducive to the subsequent mechanical cleaning treatment and met the normal production need of oilfield.

Abstract:Water injection development is one of the commonly used methods to improve oil and gas recovery in oil fields，but the scaling of injected water will cause blockage of the injected water pipeline and increase the number of pump washing operations， especially in high-temperature，ultra-low permeability reservoirs. The scaling problem will make the formation porosity decrease and the injection pressure increase. In order to solve this problem，the injection water samples and reservoir core of the oil field were taken as the research objects，the scale crystals growth rule of injected water samples was analyzed using particle size analysis，scanning electron microscopy and X-ray diffraction. Combined with the analysis of the core pore structure and mineral composition of the main oil layer，the methods of descaling and anti-scaling was explored. The results showed that the injected water existed in a serious scaling tendency，and the type of scaling was mainly carbonate scale. After the softener was added，the scale crystal grew rapidly in a short time，and the D₁₀ of the scale crystal reached 8—10 μm within 1 h. According to the reservoir characteristics of the target block，a 0.45 μm filter membrane was preferred，and in order to prevent residual ions and scale with smaller particle size from entering the reservoir，a high-temperature anti-scale inhibitors，mainly composed of poly（maleic anhydride），was further preferred，and a combined“softening-filtration-scale inhibition”treatment method was determined to achieve complete prevention of scale formation in injected water.

Abstract:In order to inhibit the production of sulfides in oilfield wastewater，the wastewater from hilly station was taken as the research object，the optimal sulfides bioinhibitor was optimized by monitoring the H₂S content，SO₄^2-consumption and SRB quantity in bioinhibition process culture in laboratory. The system was used in the oilfield test of hydrogen sulfide inhibition in the hilly station of Tuha oilfield，and the microbial community changes before and after adding the bioinhibitor were monitored. The results showed that the optimal hydrogen sulfide biological inhibition system was 200 mg/L sodium nitrate and 60 mg/L JHB，and the sulfide content was less than 1 mg/L and the SRB count was less than 10² cfu/mL in the field test. The main microorganism in the oil field before the field test was desulfomicrobium thermophilum，while pseudomonas balearica and pseudomonas stutzeri dominated in the oilfield wastewater in the oilfield test，indicating that the mechanism of biological inhibition of sulfide is to inhibit the activity of SRB by competing for the electron receptor by biological competition and decreasing SRB in oilfield wastewater.

Abstract:Gelled acid is a common retarded acid system，which is widely used in acidizing and fracturing operations to enhance oil and gas production for carbonate reservoir. The key of gelled acid is the polymer thickening agent，which can impart the acid solution high viscosity and good performances，thus the research of thickener has gained intense attention during the past decades. In this article，we reviewed the research history and recent advances of thickener in this area，and particularly focused on the molecular structure design and preparation of thickener，the performances and practical applications of corresponding gelled acids. Moreover，the advantages and disadvantages of different thickening agents were discussed，and a special attention was given to discuss the strategy that how to optimize the molecular structure of thickener and improve the performances of the gelled acid. Furthermore，we also discussed the challenges that concern the future development of gelled acid.

Abstract:As the water flooding reservoir at Shengli oilfield enters ultra-high water-cut extraction period，the water-cut and the intensity of injection and extraction increase quickly which proposes higher requirement to the production and validity period of chemical sand control. It summarized the extraction confliction of Shengli oilfield at ultra-high water-cut extraction period， introduced the improvement about the technology combination of sand controlling and water-cut reducing，chemical screen with high permeability，sand consolidation technique at low temperature and multi-layer injecting technology. It provided experience of the chemical sand control for water flooding reservoir at ultra-high water-cut oilfield.

Abstract:In view of the shortcomings of conventional CO₂ flooding，domestic and foreign scholars have proposed in-situ CO₂ generation technology and done a lot of research. This technology is a new technology that spontaneously produces CO₂ or foam in the reservoir to displacement oil through the interaction of chemical agents，it has the advantages of no natural CO₂ resources required，controllable gas production，simple process，good injection，and strong adaptability，it is a promising enhanced oil recovery technology. Based on in-depth research，this paper reviews the research progress on the CO₂ gas production system in recent years and the mechanism of the self-generated CO₂ flooding technology.