Factors Influencing the CO2 Corrosion Pattern of Oil–Water Mixed Transmission Pipeline during High Water Content Period

After the oil field enters the high water content period, the oil–water mixed fluid in the mixing system will gradually change into the water-in-oil mixed fluid, while the dissolved CO2 causes the pH value of the mixed fluid to decrease. There is also a certain amount of bacteria in the output fluid, with many factors leading to the intensification in the corrosion of the oil–water mixed system pipeline in the high water content period. To clarify its corrosion law, through the mixed transmission pipeline material, 20# carbon steel, in high water conditions under the action of different single factor dynamic corrosion rate experiments, along with the use of the SPSS method, were used to determine the corrosion of the main control factors. The results show that in the high water content period, the corrosion rate of the mixed pipeline 20# steel gradually increases with the increase in temperature pressure, CO2 partial pressure, SRB content, Ca2+ + Mg2+ content, and Cl− content. The corrosion rate with the CO2 partial pressure and SRB content changes show a strong multiplicative power relationship; with Ca2+ + Mg2+ content, Cl− content changes show a logarithmic relationship, the relationship degree R2 is above 0.98. Through SPSS data analysis software combined with experimental data for correlation degree analysis, it is concluded that the correlation magnitude relationship between each factor and corrosion rate is CO2 partial pressure > SRB content > Cl− content > Ca2+ + Mg2+ content > temperature pressure, which provides a theoretical basis for the corrosion protection of an oil gathering pipeline.