Density Measurement and Prediction Model of the CO₂–Water-Bearing Crude Oil System

Accurately predicting the density variation trend of water-bearing crude oil in high-CO₂-concentration production wells is of great significance for forecasting wellbore fluid flow dynamics and designing lifting processes at different stages of development. Indoor experiments were conducted on the CO₂-water-bearing crude oil system, measuring the crude oil density under various conditions of temperature, pressure, CO₂ concentration, and water cut. The study explored the behavior of crude oil density under different working conditions, and a predictive model for high-CO₂-concentration water-bearing crude oil density was developed using multiple regression analysis. The results indicate that under a certain water-cut condition, when the CO₂ content is below 50%, the density of the mixed fluid increases with rising pressure. However, when the CO₂ content exceeds 50%, the density first decreases and then increases as the pressure continues to rise. Under the same CO₂ injection volume, the density of the mixed fluid decreases with increasing temperature, and compared to the pressure, the density is more sensitive to temperature changes. Under the same temperature and pressure conditions, the density of the mixed fluid decreases with increasing the CO₂ injection volume but increases with higher water content. The new predictive model for the density of the CO₂-water-bearing crude oil system, accounting for the combined influence of multiple factors, has an average error of just 3.16%, meeting the precision requirements for engineering calculations. This model offers valuable theoretical guidance for CO₂ flooding development in similar high-water-cut reservoirs.