<![CDATA[Corrosion in oil and gas pipelines can reduce asset integrity, disrupt operations, and increase safety and environmental risks. This study evaluates corrosion conditions in an oil and gas pipeline network by examining the effects of operational parameters and fluid composition on corrosion rate. A quantitative approach was applied using Ultrasonic Thickness Measurement (UTM) inspection data, operational records, and fluid composition analyses. Corrosion rate was determined from the reduction in pipe wall thickness over the inspection interval. The analyzed variables included temperature, pressure, flow rate, water cut, CO2 content, H2S concentration, chloride concentration, and pH. Correlation analysis and multiple linear regression were used to identify significant factors affecting corrosion behavior. The dataset consisted of 23 pipeline segments, with corrosion rates ranging from 0.039 to 0.064 mm/year. Regression results showed that temperature, CO2 content, and water cut significantly influenced corrosion rate (p < 0.05), while the model achieved an R^2 value above 0.85. Higher temperatures, elevated CO2 levels, and high water cut increased corrosion susceptibility, whereas H2S and chloride ions contributed to localised corrosion mechanisms. The findings indicate that integrated corrosion management, including operational control, corrosion inhibitor application, and risk-based inspection (RBI), is essential for maintaining pipeline integrity and reliability.Keywords: corrosion, oil and gas pipelines, corrosion rate, operational parameters, fluid composition, UTM, multiple linear regression]]>
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