Abstract:In order to satisfy the increasingly stringent requirements for environmental protection，the biological toxicity and degradability of several emulsifiers， internal phase salts and base fluids were tested， and then an environment-friendly non-water-based drilling fluid system was constructed on the basis of plant oleic acid and its ester derivative BIO-EMUL and BIO-COAT，combining with base fluid BIO-OIL and sodium acetate solution by measuring the electrical stability，emulsifying efficiency of water-in oil emulsion and oil/water interfacial tension，interfacial rheology between BIO-EMUL+BIO-COAT solutions and BIO-OIL. The fundamental performance and anti-contamination ability of the drilling fluid was evaluation. The results showed that BIO-EMUL and BIO-COAT could effectively reduce the interfacial tension of oil/water and form water-in-oil emulsions with demulsification voltage up to 350 V and emulsifying efficiency up to 95%. The LC₅₀ of the water-in-oil emulsion system was about 28 200 mg/L，and the BOD₅/COD_Cr was greater than 0.25，indicating that it was an environment-friendly system with low biological toxicity and good degradability. The prepared drilling fluid system had a wide range of applicable density and strong anti-contamiation ability，which provided a foundation for the future study of environmental protection non-water-based drilling fluid system and materials.

Abstract:In order to improve the wellbore instability caused by poor plugging performance of drilling fluid during the drilling of shale oil and gas horizontal wells，firstly，the composition and the wellbore instability of Longmaxi shale in South Sichuan were analyzed. Then n-cetyl-triethoxy-silane，aminopropyl-triethoxy-silane and activated carbon nanotube were used as raw materials to synthesize the nano-micron plugging agent（NP-1）for oil-based drilling fluid. Its structural and physicochemical properties were analyzed by Fourier transform infrared，thermogravimetric，transmission electron microscope and surface wettability，and then its compatibility with oil-based drilling fluid was investigated. Finally，the plugging performance was evaluated by breakthrough pressure，pressure transmission and triaxial compressive strength. The mechanism was analyzed and then the field application was carried out. The results showed that there were lots of developed pore throats in size of nanometer and micron-meter and serious capillary spontaneous imbibition of shale in South Sichuan. As a result，the liquid would permeate into the wellbore continuously， which would lead to wellbore instability. The diameter of NP-1 was in the range of 30—50 nm，the length was in the micron-meter， the surface wettability was hydrophobic and lipophilic，and then the thermal stability was good below 385.2 ℃. NP-1 had good compatibility and stability with oil-based drilling fluid. The high temperature and high pressure filtration loss after aging 16 h at 180 ℃ was reduced from 2.8 mL to 1.8 mL after adding 3% NP-1 to ordinary oil-based drilling fluid. The oil-based drilling fluid with NP-1 could effectively plug the end face of shale，which could improve the breaking pressure，prevent the pressure transmission，stabilize the core internal structure and compressive strength，and then maintain the wellbore stability. Field application results showed that NP-1 could effectively alleviate the lost circulation and wellbore instability of adjoining well caused by the weak plugging ability of drilling fluid. The enlargement rate of well diameter in average was only 5.61% after treating. NP-1 had excellent plugging performance for shale in oil-based drilling fluid. It provided a reference for efficient drilling of similar complex shale gas wells in South Sichuan.

Abstract:Taking polyhedral oligomeric silsesquioxane （POSS） as the organic/inorganic hybrid components and acrylamide （AM），2-acrylamide-2 methyl propyl sulfonic acid（AMPS），octadecyl dimethyl allyl ammonium chloride as monomers，a kind of organic/inorganic composite fluid loss additive PADD was prepared by emulsion polymerization method. The temperature tolerance and calcium resistance properties of PADD in bentonite slurry were analyzed. The results showed that the POSS compound in PAAD had good compatibility with the polymer matrix，and could form a cross-network structure in aqueous solution. The thermal decomposition temperature of PAAD exceeded 300 ℃，and the viscosity of the PAAD aqueous solution still was higher at the temperature of 200 ℃. PAAD had the effect of increasing viscosity and reducing fluid loss in bentonite slurry. After hot-rolling at the temperature of 150 ℃ for 16 h，2.0% PAAD could reduce the fluid loss of bentonite slurry contaminated by 10% CaCl₂ from 150 mL to 15.4 mL，thereby forming a dense filter cake. Microstructure analysis showed that PAAD could effectively shield the adverse effect of high temperature and high calcium on bentonite particles，which could maintain the dispersion stability of bentonite. The research prospect of POSS particles is broad，and the effect of modified POSS particles on the high temperature resistance of polymers should be further explored in the future.

Abstract:Step-by-step scale-up synthesis of comb-copolymer PMAS was carried out using acrylamide （AM）， allyl polyoxyethylene ether （APEG），docosyl acrylate （DA） and 2-acrylamido-2-methylpropanesulfonic acid （AMPS） as reaction monomers，azodiisobutyronitrile（AIBN）as initiator and sodium dodecyl sulfate（SDS）as surfactant via a free radical micellar polymerization，and the properties of viscosity increment，temperature resistance，salt resistance and shear resistance were evaluated，the viscosity increasing of PMAS in the drilling fluid before and after hot-rolling was evaluated. The results showed that the scale-up experimentation of PMAS exhibited slightly varying properties when prepared by three different polymerization scale， however，always maintained excellent viscosity increments，temperature，salt resistance and shear-tolerance. After aging at the temperature of 190 ℃ for 16 h，the apparent viscosity retention rates of low-salt and saturated brine drilling fluids with 1% PMAS were 61.4% and 60.0%，respectively. The temperature and salt resistance of PMAS at big polymerization scale was superior to that of the commercial viscosifier 80A-51，exhibiting a good application prospect.

Abstract:To solve the problems that cement slurry can not stay，is easy to be diluted by water，and is poor in cementing strength and plugging effect for blocking the malignant leakage in large cracks，vug and aquifer，a quadripolymer gel was prepared by copolymerization of acrylamide（AM），2-acrylamide-2-methylpropanesulfonic acid（AMPS），N-vinylpyrrolidone（NVP）and hydrophobic monomer（MJ-16），and the gel was further added to cement slurry to form a gel-cement slurry composite leakage plugging system. The water dilution resistance，rheology，retention capacity and compressive strength of the composite system were studied. The results showed that the gel had good rheological property and temperature resistance. The system formed by gel， cement，retarder and defoamer had a fluidity of 21 cm and adjustable thickening time，and can be pumped safely. The system was still integrated under water and had good resistance to water invasion，resulting in it was not diluted by water at the stirring speed of 150 r/min. Moreover，the system had good retention capacity，as a result，the time of the system to pass the 1 mm crack was more than 10 times that of the ordinary cement slurry，and the system could stay and stack at the entrance of the leak layer，as wells as the compressive strength reached more than 7 MPa. The gel-cement system was especially suitable for the leakage plugging of large channels，large fracture holes，underground rivers and aquifers.

Abstract:Taking into account of the current challenges of poor injectability and a short gelation period of conventional gel plugging materials，a high-temperature delayed cross-linked polymer plugging agent（PM-1）was developed through a synergistic approach combining free radical polymerization and cross-linking reaction using acrylamide （AA） and 2-acrylamide- 2-methylpropane sulfonic acid （AMPS） as reaction monomers， azobisisobutyronitrile hydrochloride as initiator， and polyethyleneimine and N，N^'-methylenebisacrylamide（MBA）as cross-linking agents. Optimal synthetic conditions for PM-1 were determined via orthogonal and single-factor experiments. The injectability，gelation performance，and plugging efficiency of PM-1 was evaluated，and the delayed cross-linking mechanism of PM-1 at high-temperature was probed. The optimal synthetic conditions for PM-1 was as follows，mass fraction of monomers was 10% and mole ratio of AM to AMPS was 4∶1，polyethyleneimine and N， N^'-methylenebisacrylamide （MBA） dosage was 0.4% and 0.2% ，azobisisobutyronitrile hydrochloride dosage was 0.1% and polymer BRZ dosage was 1.2%. the injectability of the PM-1 was good. After aging for 96 h at the temperature of 130 ℃，PM-1 could still effectively plug sand layers with meth size of 1.7—4 mm and exhibit a pressure-bearing capacity of 6 MPa for 5 mm fractured layers when combined with inert materials to form a composite gel. Intriguingly，the addition of 0.4% polyethyleneimine extended the cross-linking plugging time of PM-1 to about 3—5 h，which was essential to ensure the smooth construction of underground crosslinking gel plugging.

Abstract:In order to enhance the strength of polyacrylamide（PAM）gel，nanocrystalline cellulose（NCC）was used to prepare AM/NCC composite hydrogel. The effects of NCC on the tensile property，compressive property，adhesion property and viscoelastic property of composite hydrogel were investigated by using texture analyzer and rheometer，and then the microstructure of composite hydrogel was observed by scanning electron microscope （SEM）. The results showed that the tensile strength， compressive stress，adhesive force，elasticity modulus and viscosity modulus of composite hydrogel were significantly higher than those without NCC. When the mass ratio of AM to NCC was 5∶3，the tensile strength，compressive stress and elasticity modulus of composite hydrogel reached the maximum. The toughness of composite hydrogel was significantly enhanced. Meanwhile，the tensile stress and adhesion force were nearly 3 times higher than those of PAM gel. Compared with PAM gel，the network structure of PAM/NCC composite hydrogel became denser. Furthermore，the mechanical strength and adhesion to wellbore wall became better. PAM/NCC composite hydrogel could be used for underbalanced drilling in oil and gas fields.

Abstract:The resource potential of in-situ conversion of shale oil is enormous，and it is a strategic replacement resource for China’s oil and gas industry. However，extreme high temperatures under low maturity shale oil in-situ conversion conditions can lead to a decline in the strength of hardened cement. The influence of modified material sodium hexametaphosphate on the hydration behavior of aluminate cement and the application performance of cement slurry at the high temperature environment of 650 ℃ was systematically studied，and its macro performance and microstructure were deeply explored. low field nuclear magnetic resonance analysis and testing technology showed that the sodium hexametaphosphate had a significant retarding effect on the initial hydration behavior of aluminate cement and could effectively improve its rheological properties. In addition，at the temperature of 50 ℃， addition of sodium hexametaphosphate could significantly reduce the permeability of hardened aluminate cement，at the same time， which had no significant impact on the strength. After treatment at the temperature of 650 ℃，the maximum compressive strength of was 47.19 MPa by adding 5% sodium hexametaphosphate to modify hardened aluminate cement. Simultaneously，before and after treatment at 650 ℃，the hydration products of aluminate cement slurry underwent significant transformation，the C₃AH₆ and AH₃ converted into C₁₂A₇ and CA mainly. C₃AH₆ and AH₃ underwent thermal decomposition mainly during the period of 180—400 ℃. the pore size distribution of mercury intrusion showed that the pore size range of clean hardened aluminate cement and 5% sodium hexametaphosphate modified hardened aluminate cement was mainly between 100 and 1000 nm，and the pore size of both types of cement stones increased due to the transformation of crystal form after high-temperature treatment at the temperature of 650 ℃.

Abstract:In order to meet the strength，gelling time and gel breaking performance requirements of the gel plugging system for high pressure water injection wells under pressure operation，a temperature-resistant and salt-resistant gel plugging system was developed. This system utilized acrylamide（AM）/2-acrylamido-2-methylpropanesulfonic acid（AMPS）as a binary polymer system and trimethylol compound（Smel30）as crosslinking agent. The effects of temperature，inorganic salt，simulated oil content，and shear time on gelling time and gel strength of the system were investigated. Additionally，the influence of sodium persulfate on gel breaking effect of the system was studied. The results showed that when the temperature increased from 40 ℃ to 100 ℃，the gelling time of the system decreased from 23.5 hours to 2.0 hours，while the gel strength increased from 39.4 Pa to 88.6 Pa. Inorganic salts could reduce the distance between polymer chains，which led to shorter gelation time and a slight increase in gel strength. Three inorganic salts were arranged according to the effects on gelling time and gel strength of the system in following order：NaCl < MgCl₂ < CaCl₂. The gel system exhibited strong resistance to oil stains and shear forces. The addition of 1%—10% simulated oil increased the gelation time from 8 hours to 15 hours，with minimal change in gel strength. After shearing at 60 ℃ and 500 r/min for 60 minutes，the gelling time increased from 7 hours to 17 hours，while the gel strength remained 81%. The gel system displayed good thermal stability. There was no significant dehydration after aging at 60 ℃ for 15 days，and then the gel strength remained at 67 Pa. Sodium persulfate was an effective and cost-efficient gel breaker. After adding 30%（mass fraction）sodium persulfate with dosage of 30% volume fraction to the gel system，the gel breaking time at 60 ℃ was 20 hours，and then the apparent viscosity of the residual liquid was 64.4 mPa·s. The gel breaking residual liquid could be easily displaced to the ground using gas or water， meeting on-site construction requirement.

Abstract:The factors affecting the asphaltene stability in crude oil are complex，and the mechanism of the change of crude oil composition on the stability of asphaltene is still unclear. On the basis of measuring the density，viscosity，element composition and four components（saturated hydrocarbon，aromatic hydrocarbon，resin and asphaltene）content of 10 different crude oil samples， the composition of 10 crude oil samples and their interaction characteristics with asphaltene were studied by means of field emission scanning electron microscopy，Fourier transform infrared spectroscopy，X-ray fluorescence spectroscopy and Zeta potential evaluation. The influence of wax，water and inorganic salt on the stability of asphaltene. The results showed that the density and viscosity of crude oil were in direct proportion to the content ratio of heavy and light hydrocarbons. When the asphaltene content increased，the H content and molar ratio of H to C in crude oil decreased，while the non hydrocarbon content increased，and the stability of asphaltene decreased. Wax and water would change the composition of crude oil and affect the stability of asphaltene. The contents of inorganic and organic metals in crude oil were 0.0021%—0.0814% and 0.0007%—0.0655%，respectively. Organic metals such as vanadium and nickel would destroy the stability of asphaltene，while inorganic metals in the reservoir would enhance the stability of asphaltene. There were a large number of negatively charged inorganic particles on the surface of asphaltene sediment，resulting in negative Zeta potential of its aqueous solution. When the absolute value of Zeta potential was greater，the stability of asphaltene was better，indicating that the charge generated by inorganic particles could stabilize asphaltene in crude oil and reduce the aggregation tendency of asphaltene. The research results provided a reference for effective prevention of asphaltene deposition and mitigation of deposition damage.

Abstract:In order to construct the thickener acid system that can be applied in deep penetration acid fracturing process for a long time，anionic thickener PAP-1 and hydrophobically associating thickener PAP-2 was prepared using acrylamide（AM），acrylic acid （AA），2-acrylamido-2-methylpropanesulfonic acid（AMPS）as main raw materials and AT100 as hydrophobic monomer. The effect of reaction conditions on the properties of thickeners was investigated，and the performances of thickeners obtained under optimal conditions was researched by measurement of the viscometer and rheometer. The optimal reaction conditions of thickener PAP-1 were obtained as follows，the molar ratio of AM，AA and AMPS was 90∶9∶1，the initiator dosage was 0.03% of monomer mass，monomer mass concentration was 25%，the temperature of the reaction system was 55 ℃. Except for the hydrophobic monomer AT100 dosage of 0.2 mol%，the reaction conditions of thickener PAP-2 were the same as that of the thickener PAP-1. The results indicated that the acid dissolving time of thickeners PAP-1 and PAP-2 with mass fraction of 0.8% in hydrochloric acid with mass fraction of 20% at room temperature was 20 min and 50 min，respectively，and the viscosity was 39 mPa·s and 54 mPa·s， respectively. Meanwhile，they had good compatibility with another additive. The viscosity of PAP-1 and PAP-2 acid fluid was 10 mPa·s and 31 mPa·s at the temperature of 160 ℃ and at the shear rate of 170 s^-1

Abstract:In view of the problem that the performance of conventional slip-water drag reducer is seriously decreased at high temperature and high salinity，a no-miscible salt-resistant polymer emulsion was developed as a drag reducer. It is necessary to carry out research on the optimization of polymer emulsion formula. Rheology，viscoelasticity，resistance reduction，gel breaking properties，core damage of fracturing fluid prepared with clean water and Ma 18 water were tested in laboratory and field application was carried out. The results showed that，when the concentration of salt-resistant polymer emulsion was 0.05%—1.2%， the viscosity retention rate was between 32.5%—62.5% at high salinity of 21 159.88 mg/L，and the performance of the fracture liquid system at the concentration of 0.2%—0.5% could be similar to that at the concentration of 0.1%—0.2% at low salinity，and the elastic modulus of the system was dominant. The resistance reduction rate of the system was more than 4% higher than that of conventional polymer emulsion. The surface tension of the gel-breaking fluid was less than 28 mN/m，and the interfacial tension with kerosene was less than 2 mN/m，and the residue content was less than 50 mg/L. The damage of gel-breaking fluid to core was less. In field application，the idea of stepping polymer concentration increase was adopted，and it was obtained that when the sand concentration was 30—270 kg/m³，the mass fraction of polymer fracturing fluid should be 0.15% —0.2% ；when the sand concentration was 300—360 kg/m³，the mass fraction of polymer fracturing fluid should be 0.2%—0.35%. The mass fraction of polymer fracturing fluid was further optimized to be 0.15%—0.35%，and the resistance reduction rate could reach up to about 85% during construction. After the test well was put into operation，the effect was good，which provided a reasonable technical scheme for the effective use of polymer fracturing liquid system in horizontal wells of Mahu oilfield.

Abstract:Preformed particle gels（PPG）are widely used to control the dominant channeling channel of reservoir to stabilize oil production and control water production. In order to solve the problems of inadequate strength，poor shear recovery performance and salt intolerance of conventional PPG with covalent structure，a host-guest inclusion supramolecular particle gels（S-PPG） profile control agent containing covalent and non-covalent crosslinked structure was developed，which had shear recovery performance. S-PPG was prepared using allyl-β-cyclodextrin （allyl-β-CD，host functional monomer），cetyldimethylallyl ammonium chloride（C16DMAAC，guest functional monomer）and N，N-methylene diacrylamide（MBA，crosslinking agent）and acrylamide（AM）as main raw materials. The rheological properties，swelling properties and salt tolerance of S-PPG was systematically investigated by measurements of rheometer，laser particle size analyzer and optical microscope. The results showed that the elastic modulus of S-PPG（2.5+2.5）system with mass fraction of 0.6% prepared with the formation water was 73 Pa after swelling for 24 h，which was 3.04 times of conventional PPG. The yield stress was 120 Pa，the shear viscosity loss rate was only 39%，the shear resistance and yield stress were about 4 times of the conventional PPG，and the swelling ratio in formation water was 23. In addition，the swelling property of S-PPG was gradually increased with the increase of salt content，and the swelling ratio could reach 27.9 at 1×10⁵ mg/L NaCl concentration，showing excellent salt tolerance. It provides a potential new shear resistant S-PPG material for reservoir in-depth conformance control.

Abstract:In order to control excessive water production in oil wells in offshore oilfield，the properties including injectivity， plugging capability，selectivity and water flushing resistance of an in-situ gelation water shutoff system in offshore oilfield， composed of 1% functional microsphere +3% functional monomer +0.8% gel promoter，were evaluated，and a field pilot test was carried out. The property evaluation results showed that the gelation time of the in-situ gelation water shutoff system from strength A to strength I was as long as 134 h，which could meet the requirements of on-site implementation for gelation time. The injection pressure was only 0.28 MPa in the sandpack with a permeability of 1020×10^-3μm²，and decreased with the increase of permeability， indicating the good injectivity of the system. The system had good properties of selectivity，plugging and water erosion resistance. It could preferentially enter the high permeability channeling area. After gelation，the plugging rate of the high permeability channeling area was more than 90%，and the plugging rate was only reduced by about 5.0% after 100 PV continuously water injection. After 60 days of immersing in water at the temperature of 65 ℃，the strength loss rate was only 4.1%，indicating that the system had good property of water immersion resistance after gelation. The field pilot test results showed that the water plugging effect of the in-situ gelation water shutoff system was obvious，the complex water channeling of the target well could be effectively controlled，and achieved the purpose of decreasing water production and increasing oil production of the target well.

Abstract:In view of the characteristics of high temperature and high salinity heavy oil in Yudong Block of Lukeqin and the unsatisfactory oil displacement effect of XHY-4 foam system applied in the field，the viscosity reduction effect，foam stability，oil resistance，plugging ability and oil displacement effect of DY-2 foam system with heavy oil viscosity reduction were studied and compared with XHY-4 foam system. The experimental results showed that the viscosity of heavy oil could be reduced by 82.5% when the DY-2 solution with an effective content of 0.1% was mixed with heavy oil at a volume ratio of 1∶1. The foam performance of DY-2 foam system was better than that of XHY-4 foam system. The DY-2 foam system could also achieve excellent foam performance while significantly reducing viscosity of heavy oil. The foaming volume of DY-2 foam system with effective content of 0.1% was 445 mL，the foam half-life was 2186 s，the half-life of liquid separation was 96 s，and the foam comprehensive index was 72.96×10⁴ mL·s. The DY-2 foam system had good oil resistance and plugging performance. When the oil content increased from 0% to 20%，the stability of the foam system did not decrease significantly. When the core permeability was 750×10^-3～1250×10^-3μm²，the resistance factor of DY-2 foam system could be stabilized at about 60. In the double-tube displacement experiment， DY-2 was superior to XHY-4 in improving the diversion rate，comprehensive water content and comprehensive recovery degree of high and low permeability pipes. The recovery degree increased by 16.2%，being 4.6 percentage points higher than XHY-4. The DY-2 foam system could better meet the technical requirements of foam flooding to enhance oil recovery in Yudong block.

Abstract:Biosurfactant is a specific natural surfactant produced by the microorganism. Its adsorption on rock surface has a great impact on the change of reservoir wettability. The mechanism of wettability alteration is crucial to the oil recovery. In this paper，the interaction between rhamnolipid biosurfactant and hydrophobic glass surface was studied by contact angle experiment，oil displacement experiment，free energy of liquid-solid interface measurement and molecular dynamics simulation，explaining the adsorption effect of rhamnolipid biosurfactant on the hydrophobic glass surface’s wettability. The results showed that the wettability of hydrophobic slide could be rapidly altered by rhamnolipid biosurfactant. Once the rhamnolipid biosurfactant adsorbed on the hydrophobic glass surface lasting for 12 h，the contact angle could be dramatically decreased from 111.6° to 32.7°. The optimum dosage of rhamnolipid biosurfactant to extract oil from oilsands was 30%，resulting in the better oil displacement efficiency（i.e.， 84.83%）and the lower adhesion force（0.2 mN/m）. Furthermore，the free energy between deionized water and hydrophobic glass slide treated by rhamnolipid solution using the liquid-solid interface free energy formula was-140.2 mJ/m²，which was much lower than that between deionized water and original hydrophobic glass slide（-52.1 mJ/m²）. On the other hand，based on the molecular simulation，the rhamnolipid molecules could quickly adsorb on the hydrophilic surface via hydrogen bonds（strong interaction force），while both the electrostatic force and van der Waals force（weak interaction force）were the main interaction forces between rhamnolipid molecules and hydrophobic surface. Therefore，the adsorption binding energy between rhamnolipid molecules and hydrophilic surface（29.7 eV）was much higher than that between molecule and hydrophobic surface（12.2 eV），leading to the stronger interfacial competitive adsorption capacity of rhamnolipid molecules compared to asphaltenes. In other words，according to the free energy calculation and molecular simulation results，rhamnolipid molecules would easily anchor to the hydrophilic surface and“sweep off”the oil molecule，resulting in higher oil displacement efficiency. This paper provided an insight to construct an effective wetting control flooding system based on rhamnolipid biosurfactants.

Abstract:In order to achieve green and efficient development of oil fields，a green，environmentally friendly and efficient biological nano-oil displacement system was prepared through combining the metabolites of Bacillus sp. 3096-3 with the reduction products of Shewanella sp. CD-8. The metabolites，reduction products and dispersion stability of the compound system were characterized by liquid chromatography-mass spectrometry（HPLC-MS/MS），infrared absorption spectroscopy（FT-IR），X-ray powder diffraction（XRD），scanning electron microscopy（SEM），particle size and Zeta potential analysis，and the emulsification performance and enhanced oil recovery ability were explored. The results showed that the bio-nano oil displacement agent system composed of lipopeptide biosurfactants and nano-iron particles had good dispersion stability，and the emulsification performance was positively correlated with the concentration of nano-iron particles. In the range of experimental conditions，the recovery rate increased with the increase of concentration of nano-iron particles and temperature，and the maximum recovery rate could reach up to 56.80% at the temperature 70 ℃ when the concentration of nano-iron particles was 100 mg/L. The recovery effect of bio-nano oil displacement agent system was better than that of single biosurfactant and nano-iron fluid. The prepared bio-nano oil displacement agent system provides a feasible method for the green development of oil fields.

Abstract:The harmless treatment of oily sludge in oilfield production is difficult and costly. Reinjection of oily sludge is a low-cost harmless treatment technology. The conventional reinjection profile control method can only reinject the oily sludge particles with smaller particle size，which can not fully recycle the oily sludge. Therefore，the oily sludge particles were ball milled to the micro-nano scale，and then petroleum sulfonate surfactant was added to form a stable oil displacement system by stirring， ultrasonication and centrifugation. The particle size distribution，emulsification ability and oil displacement performance of oily sludge flooding system with micro-nano particle were studied. The results showed that the median particle size of oily sludge micro-nano particle in oil displacement system was 158 nm. The system could maintain good suspension after standing at room temperature（25 ℃）for 4 days. The time of complete separation of oil and water was equal or greater than 5 min. The interfacial tension between the system with kerosene at 60 ℃ was 7.4×10^-3 mN/m，indicating strong emulsification ability. Due to the dual effects of emulsification and plugging，the oily sludge micro-nano particle flooding system had better injection capacity and oil displacement effect than surfactant flooding，which was suitable for medium and low permeability reservoirs. Under the condition of 60 ℃，injection volume of 0.5 PV and injection rate of 1 mL/min，the oil displacement efficiency was about 20 percentage points higher than that of water flooding and about 8 percentage points higher than that of surfactant flooding. The preparation method of oily sludge micro-nano particle flooding system could completely treat oily sludge，and then realize the efficient reuse of oily sludge.

Abstract:Aiming at the problems of poor injection，low oil washing efficiency and inability of water flooding to improve oil recovery in low permeability reservoirs，a new technology of low interfacial tension small molecule oil displacement agent（LST solution） to improve oil recovery in low permeability reservoirs was proposed. The interfacial activity，viscosity increase， emulsification，wettability，reservoir environment adaptability and oil displacement effect of LST solution were evaluated. The results showed that the displacement agent had good interfacial activity and viscidity. In the mineralized water with salinity of 6788.23 mg/L，the interfacial tension of 0.4% LST solution was 0.012 mN/m，meanwhile the viscosity was similar to that of reservoir crude oil（3.4 mPa·s）. LST solution had good oil-water emulsification ability and could improve reservoir water wettability. The stabilization time of LST emulsion was 120 min at 47.2 ℃ and 1∶1 ratio of oil to water. After the core was treated with LST solution，the water-phase antenna decreased from 57.0° to 12.5°，while the oil-phase antenna increased from 24.3° to 38.6°. LST solution had good static anti-adsorption properties. After three times of core adsorption，the interfacial tension between LST residue and crude oil could still reach the order of 10^-2 mN/m，and then the viscosity could reach 2.895 mPa·s. The water eluting rate of the emulsion after standing for 10 min and 120 min was 38.6% and 73.4%，respectively. The salt resistance of LST solution was good. When the salinity was 16 570 mg/L，the oil-water interfacial tension was lower than 7×10^-2 mN/m and the viscosity was 3.06 mPa·s. LST solution had a good displacement effect，which could effectively plug the high permeability pore and start the residual oil in low permeability pore. Injecting 0.4 PV 0.4% LST solution could increase the water flooding efficiency of homogeneous core（0.05 μm²）by 11.21 percentage points，while the integrated recovery efficiency of heterogeneous core（3— 10 difference）by 6.55—19.41 percentage points. LST solution could effectively improve water drive recovery at low dosage or low cost，which had a good application prospect in enhancing oil recovery by chemical drive in low permeability heterogeneous reservoirs.

Abstract:Gas condensate exists generally in the upper Paleozoic Sulige gas reservoir. During production，it was found that the produced liquid of condensate in some gas gathering stations was seriously emulsified，which had a great impact on the normal production. Taking the produced liquid emulsion of condensate in Sulige gas field as the research object，the emulsification characteristics and influencing factors of produced liquid in typical blocks were analyzed. The composition of the five produced condensate emulsions was quite different，and the stability of the emulsions was in good correspondence with zeta potential and salinity. The greater the absolute value of Zeta potential，the more stable the emulsion. The higher the salinity of the aqueous phase， the lower the stability of the emulsion. The mass fraction of alcohols and esters in five produced condensate emulsions was 1.48%— 4.80% and 2.08%—6.34%，respectively. the polar organic substances of alcohols and esters would form a composite interface facial film with hydrophilic surfactant at the interface，which was conducive to the formation of condensate emulsion. In the condensate emulsion in Sulige gas field，the water phase was continuous phase and oil was dispersed phase. For some single oil droplet，oil was a continuous phase and water was a dispersed phase，which finally formed a complex water-in-oil-in-water（W/O/W）type emulsion. With the increase of foaming agent and suspended matter content，the volume fraction of the simulated condensate emulsion increased first and then decreased. When the mass fraction of foaming agent was 0.6% and the mass fraction of suspended solids was 0.4%，the volume fraction of the simulated condensate emulsion was the largest，while the concentration of corrosion inhibitor had no obvious effect on the volume fraction of condensate emulsion.

Abstract:In order to remove strontium barium sulfate scale generated during the development of oil and gas fields，which is characteristic of dense scaling，low solubility，and insoluble in acids and alkalis，the chemical scaling technology was adopted. Firstly，a chelating agent was selected，and then different additives were added to utilize their synergistic and modifying effects. The optimal formulation of barium sulfate/strontium scale remover was determined through single factor experiments as follows， 10% DTPA+ 6% salicylic acid+0.03% potassium polyacrylate concentration+ 0.2% Tween-80. The effects of pH，temperature，and reaction time on the scale removal effect were also investigated. The results showed that the best scale removal effect was achieved when the pH value was 12，the temperature was 80 ℃ ，and the scale removal time was 8 hours. Under these conditions，the descaling rates of barium sulfate，strontium sulfate，and actual scale samples were 79.41%，80.56% and 59.7%，respectively. The scale remover had the advantages of high scale removal efficiency，short scale removal time and low cost，and had broad application prospects in oil and gas field scale removal.

Abstract:In order to compare the scale penetrability and penetration mechanism of different bactericides，a simulated penetration experiment was conducted under the scale layer from the field，employing polyhexamethylene monoguanidine hydrochloride （PHMH） and glutaraldehyde as prototypes. The pore size distribution of scale samples was characterized by nitrogen adsorption-desorption method. Meanwhile，the charging property of scale layers in 3.5% NaCl solution was determined by dynamic light scattering technique. Standard curves for PHMH and glutaraldehyde in 3.5% NaCl solution were established at 506.7 nm and 232.2 nm，respectively. With the aid of self-made device and standard curves，the penetrations of PHMH and glutaraldehyde with time were monitored by ultraviolet spectrophotometer. The results showed that two scale samples on site were mainly composed of calcium carbonate and barium sulfate with an average pore size of 0.43 and 0.27 μm，respectively. The Zeta potentials showed a trend from positive to negative as the pH value of the solution increased. The corresponding isoelectric points were 4.14 and 4.56， respectively. After immersing two scale samples in NaCl solution，the interface showed negative charge with Zeta potential of -6.56 mV and -5.14 mV，respectively. After 15 days of penetration monitoring，PHMH showed a slow penetration behavior first and then fast with 17.70% the highest permeability，while glutaraldehyde showed a fast penetration behavior first and then slow with 38.75% the highest permeability. The pore size of scale sample directly affected the total diffused amount of bactericide，but did not change its diffusion pattern. Electrostatic interaction with the scale layer resulted in the early slow penetration of PHMH，while physical screening effect determined the final penetration amount of glutaraldehyde. This work provided guidance for the screening of on-site bactericide and the synergistic compatibility with other agents.

Abstract:As important ingredients in corrosion inhibitor at high temperature acidizing，pyridine quaternary ammonium salt and antimony salt have been universally used in application. In this paper，chemical soaking at high temperature and high pressure and electrochemical measurements was carried out to investigate the synergistic corrosion inhibition effects between pyridine quaternary ammonium salt（BDJ）and Sb₂O₃ on N80 steel in 20%HCl solution. The performance of the formed film at different conditions was analyzed using contact angle，scanning electron microscopy（SEM），energy dispersive spectroscopy（EDS），X-ray diffraction （XRD）and attenuated total reflectance（ATR）. The mechanism of film forming process of acidizing corrosion inhibitor relating BDJ and Sb₂O₃was proposed. The results showed that there existed in apparent synergistic corrosion inhibition between BDJ and Sb₂O₃. With the increase of Sb₂O₃concentration，the inhibition efficiency was remarkably enhanced. When adding corrosion inhibitor of 2% BDJ + 0.5% Sb₂O₃，the corrosion rate of N80 steel decreased to 18.0 g/（m²·h），which was far less than the requirement of 45 g/（m²·h），as a result，the inhibition efficiency increased over 95%. The mixture inhibitor shifted the potential positively and decreased the corrosion tendency thermodynamically. The protective film was consisted of compound film with Sb and BDJ inside，which effectively enlarged the contact angle and inhibited the acid corrosion.

Abstract:Self-healing material is a kind of material which can heal itself after being damaged by external action. It is of great significance to prolong the service life of materials，eliminate safety hazards and reduce maintenance costs. In recent years，it has been widely researched and applied in the field of oil and gas drilling and production. Self-healing materials were classified into external and intrinsic types based on different healing methods. The healing mechanisms and characteristics of external （microcapsules，oil and gas activated materials，differential pressure activated sealants） and intrinsic （physical self-healing， chemical self-healing）self-healing materials were systematically summarized in this paper. Physical self-healing mainly included hydrogen bonding，hydrophobic association，ionic bond actions，host-guest recognition. Chemical self-healing mainly included the combination and fracture of imine bond，acylhydrazone bond，disulfide bond，etc. The research status of different types of self-healing materials in the fields of well cementing，downhole pipe fittings repair，leak-proof plugging，wellbore strengthening， fluid loss reduction，and profile control and water shutoff was summarized，and the prospects for their development were prospected.

Abstract:Lost circulation is the main technical problem that restricts the improvement of quality and efficiency of oil and gas drilling engineering. Improving the success rate of one-time plugging is an urgent need to ensure "safe，efficient，and economical" drilling in global oilfields. This paper summarized the leakage mechanism of drilling fluid，introduced the properties and interaction mechanism of various plugging materials such as bridging，high water loss，curing，polymer gel and smart materials，and then clarified the problems existing in current plugging materials. The bridging and plugging material was inexpensive，easy to operate， widely sourced，and had little impact on the rheological properties of drilling fluid. However，its particle size had poor compatibility with the leakage channel of formation. Furthermore，its formula was complex. High water loss plugging material was easy to use，effective，and had a high success rate in plugging. But it had some deficiencies. For example，the composition was complex，the water loss rate was difficult to control，and the blockage was not easy to remove. Curable plugging material was inexpensive，had high pressure sealing ability，and simple preparation and operation processes. However，its construction safety risks were high. Polymer gel plugging material had strong adaptability to leakage channels，good viscous resistance and anti-shearing dilution ability. However，its high-temperature resistance was low，long-term sealing performance and compatibility with drilling fluid were poor. Furthermore，the gelation time was difficult to control. Intelligent plugging material could intelligently adapt to various complex formations. It had strong pertinence and little damage to the formation. However，its plugging mechanism and adaptability needed to be further improved. The future development direction of plugging materials was proposed，such as the development of intelligent plugging materials and drilling fluid plugging materials for high-temperature well in deep and ultra deep wells.

Abstract:The settlement stability of cementing slurry is one of the important indicators of cement slurry construction performance. With the more complex well conditions such as deep wells and ultra-deep wells，especially in recent years，the well depth is extended to 10 000 meters，therefor the temperature of the bottom of the well will reach more than 240 ℃. Consequently，it poses a challenge to the stability of cementing slurry. Previously the suspending agents can improve the suspension stability，but reduce the rheological property of cementing slurry，which is detrimental to well cementing under complex well conditions. By summarizing the research status of oil well cement suspension，the main types and mechanisms of suspending agents were systematically discussed. Additionally，the optimization of current suspension agents was analyzed，including the optimal compounding of inorganic and organic polymer materials，the optimization of comonomers，as well as the graft copolymerization，which would provide reference for research of oil well cement suspension.

Abstract:In-depth profile control and oil displacement technology is an important tool to improve the recovery rate of the oil reservoir. Through analysis of the key problems of water channeling and efficient displacement of residual oil，two major contradictions of in-depth profile control and oil displacement technology were explained from two aspects：the contradiction between the injectivity of the profile control agent and the blockage of the deep water breakthrough channels，and the contradiction between in-depth profile control and the displacement of remaining oil. In this paper，the principle of deep profile control technology and its application in low permeability reservoir were reviewed，the advantages and problems of each technology were pointed out，and the development trend of in-depth profile control and oil displacement technology in China was analyzed.

Abstract:Because of the difficult problem of water injection and liquid production in unconventional reservoirs such as low-permeability and ultra-low permeability reservoirs，this paper systematically discussed the oil displacement mechanism of micro-emulsion flooding for improving oil recovery in low-permeability reservoirs，such as injection pressure reduction and injection ability increase，profile control and water plugging，and reservoir protection. Compared with water flooding，the viscosity of injected micro-emulsion into the reservoir is higher than that of water. Thus，it can improve the oil-water mobility ratio，reduce the viscous fingering of displacement fluids，and reduce interfacial tension（IFT）between the micro-emulsion system and oil phase，which reduces capillary resistance，changes wettability of reservoir rock，and expands the macroscopic sweep volume in the reservoir. In addition，when the micro-emulsion flows through the pore and throat channel of the reservoir，it will also improve the oil-washing efficiency of the reservoir through the synergistic effect of oil solubilization，viscoelastic drag，etc. At the same time， various types and properties of microemulsions（supercritical CO₂ micro-emulsion，nano micro-emulsion，in-situ micro-emulsion， and micro-emulsion foam）with good applicability of oil displacement for low permeability reservoirs were also discussed. The application effect of different types of micro-emulsion in actual low permeability fields was also discussed in this paper. It was found that micro-emulsion flooding can generally reduce the injection pressure of water injection wells in low permeability reservoirs by more than 35%，and the oil increase effect of oil wells was also good. The purpose of this review is to provide a certain theoretical reference for the application of micro-emulsion flooding to enhance oil recovery in low permeability and other unconventional reservoirs.

Abstract:In order to reduce the word errors，several groups of easily confusing terms commonly used in daily editing were analyzed，including“配制（preparation）”and“配置（configuration）”，“瓜尔胶（guar gum）”and“胍胶（guanidine gum）”，“黏度 （viscosity）”and“粘度（viscosity）”，three structural auxiliary words，and“氨（ammonia）”，“胺（amine）”and“铵（ammonium）”. By analyzing the interpretation of preparation and configuration，“preparation”should be used when involving the preparation of solution in periodical.“Guar gum”was a standard technical term，so“guanidine gum”should not be used in oil and gas industry. “Viscosity”was a physical property of a fluid，so it should be written as“黏度”. Three structural auxiliary words，such as“的”， “地”，“得”，should be distinguished，which made written language accurate. By analyzing the definition，structure and properties of ammonia，amine and ammonium，as well as the common examples of chemical reagent names in the field of oilfield chemistry， this paper provided reference for the correct and standardized use of scientific and technical workers and periodical editors.