An associative seawater⁃based fracturing fluids with temperature resistance of 180 ℃ was formed by thermostable and salt⁃resistant thickening agent containing hydrophobic groups, physical crosslinking agent with ionic surfactant, high temperature stabilizer and high efficiency chelating agent. The fracturing fluid forms a high⁃strength network structure through the physical association between the hydrophobic groups on the molecular chain of thickener and cross⁃linker, which enhances its viscoelasticity and takes elasticity as the dominant factor. The viscosity of the fracturing fluid can be maintained above 30 mPa•s for 90 minutes at 180 ℃ and 170 s-1, which has good static sand⁃carrying and wall⁃building properties. The viscosity of gel breaking fluid is 3.3 mPa•s, the residual content is 45 mg/L, and the damage rate of core permeability is less than 10%. The seawater⁃based fracturing fluid meets the requirements of fracturing for offshore ultra⁃high temperature deep reservoirs.

New clean fracturing fluid VES⁃YF was prepared by mixing the betain type amphoteric surfactant YF⁃1 and cosurfactant YF⁃2 with KCl. By measuring the influence of different concentration of YF⁃1, YF⁃2 and KCl on the viscosity of fracturing fluid, the optimized formulation was obtained, which is 2.0%YF⁃1+1.0%YF⁃2+2.0%KCl. The research and evaluation of the system's construction mechanism and its applicable performance were conducted. The results show that VES⁃YF clean fracturing fluid has shear thinning property and good viscoelasticity. The rheological measurement shows that the network structure of worm⁃like micelle exists in the system and can be recovered after shear failure. The apparent viscosity of VES⁃YF clean fracturing fluid is still higher than 80 mPa·s after shearing for 2 h at the temperature of 45 ℃ and the shearing rate of 170 s-1. The system has the advantages of strong sand carrying capacity, good gel breaking property and low core damage rate. VES⁃YF clean fracturing fluid has a broad application prospects in the fracturing operation of low permeability reservoir.

Iron removal in the oil field produced water and effect of iron mass concentration in the outlet water on turbidity were explored by addition alkali process. Iron contents were determined by 1,10-phenanthroline spectrophotometry and portable turbidimeter was adopted at the determination of turbidity. Results show that pH of inlet water has significant effects on iron removal, turbidity reduce and anti-corrosion of treatment devices. Iron removal is bad and corrosion of treatment device could not be restrained when pH is below 7, which resulted in negative iron removal rate. Better pH is about 8.3 where iron removal and anti-corrosion of treatment devices are attained. And the quality of outlet water can meet the A1 quality standards of recommended indexes in SY/T5329-94 about the injection water quality for clastic rock oil fields, and its turbidity keep invariablenes at a dwell time of 2.5 h. However, outlet water turidity at 6.6 and 7.3 of pH rose gradually because of Fe(OH) ₂ oxidation. Coagulant can promote Fe(OH) ₂ settlement and major removal mechanisms of Fe(OH) ₂ include settlement, interception based on filtration and adsorption from theoretical analysis. At a low pH, electrochemical corrosion made treatment devices release iron which induces outlet iron contents above inlet iron contents. On the contrary, at a high pH, it is blockaded owing to protective layer formation and cathode reaction suppressed.