The corrosive environment of oilfield condensate water was simulated at different temperatures with CO2/H2S. Weight-loss corrosion tests were conducted on S135 and G105 steels at different temperatures. The corrosion rates of the S135 and G105 were measured at room temperature, 100 °C and 180 °C. The phase structure of the corrosion products and the corrosion morphologies of the samples were characterized. The results show that the corrosion rates of the S135 and G105 increased at first and then decreased with the increase in temperature. The corrosion rates peaked at 100 °C, reaching 0.8463 mm/y and 0.8500 mm/y, respectively. CO2 was the main controlling factor in the corrosion. The corrosion products were FeS and FeCO3. The corrosion rate at room temperature was lower than that at 100 °C. The corrosion rate at the temperature of 180 °C was the lowest. The corrosion rates of the S135 and G105 were 0.2291 mm/y and 0.2309 mm/y, respectively. CO2 was not the main controlling factor in the corrosion. The corrosion product was FeS. High temperatures aggravated the carbon-steel corrosion further in the environment with the high concentration of CO2 and a loose corrosion-product film formed. The dense and uniform FeS corrosives formed and attached to the surface of the substrate, and inhibited corrosion. Dense and uniform FeS products formed on the surface of the steel with the increase in temperature. A small amount of H2S inhibited the progress of the corrosion.

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Guantao oil reservoir of the Bohai Bay, is characterized by low formation water salinity, high pore structure heterogeneity and flooding, which complicates the logging response, especially the low contrast of resistivity response. Traditional methods by resistivity fail to estimate reservoir parameters accurately and cannot determine producible fluid type. In this study, the reservoir heterogeneity was investigated with advanced nuclear magnetic resonance data, and oil saturation was calculated using array dielectric data. Combining the two aspects, a special reservoir evaluation and fluid identification method was established.

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Fluid loss is inevitable in the well drilling and completion, which may cause series of formation damage such as clay swelling, solid plugging and water blocking. In tight sand gas reservoir, water blocking has become the major damage factor for economical developing. In deliverability test, water blocking will bring an inaccurate productivity test result to affect the following development strategy. With the development of East China Sea gas field, well drilling is focusing on the deeper tight sand formation. The tiny pore throat and high capillary pressure can bring out serious water blocking damage during well drilling and completion. The damaged zone can mislead the resource assessment and productivity evaluation. In this paper, an exploration well X in East China Sea gas field is selected as the research target to investigate the water blocking mechanism and physical process during well drilling and completion process. This study compares the productivity performance of X well with fluid loss and no fluid loss models through numerical modeling approach based on the actual data. Sensitive studies are also performed in the simulation. Results show that the excessive fluid invasion pressure and lower matrix permeability will result in serious water blocking damage to mislead the resource assessment and productivity evaluation even in underbalanced well drilling. Interestingly, extending shut-in time can make the gas production rate quickly reach the peak value in the early production stage, while it can decrease the cumulative gas production in whole production process. This study can provide an avenue to initiate quantitative analysis on resource assessment, and gas productivity evaluation strategy after water invasion during the well drilling and completion in tight sand gas reservoir of East China Sea.