Abstract
Abstract
During deep and ultra-deep drilling, CO
2
influx can alter gas–liquid phase partitioning in water-based drilling fluids and thereby affect wellbore multiphase-flow and pit-volume responses. To improve the description of this behavior, CO
2
solubility was measured for three field KCl-based polysulfonate water-based drilling fluids over 30–150 °C and 10–90 MPa using an equilibrium liquid-sampling method. A fugacity–activity framework was then established by combining the Peng–Robinson equation of state, a pressure-corrected Henry term, electrolyte activity corrections, and an empirical polymer contribution. The experimental results show that CO
2
solubility increases nonlinearly with pressure and decreases with temperature. The three formulations exhibit different solubilities; the lower solubility of the formulation containing 15% KCl is consistent with salting-out, although the simultaneous variation in polymers, asphaltic additives, and suspended solids prevents the contribution of salt from being isolated independently. For the three tested fluids, the model gives mean absolute percentage errors of 2.72%, 2.49%, and 5.03%, with R² values of 0.9891, 0.9954, and 0.9777, respectively. An engineering wellbore simulation was further used to illustrate how CO
2
dissolution/exsolution can delay mud-pit volume gain during gas influx. Because the case-study reservoir conditions (175 °C and 172 MPa) exceed the experimental validation envelope, this simulation is interpreted as an extrapolative engineering illustration rather than independent field validation. Accordingly, the proposed model is presently validated only for the three tested KCl-based water-based drilling-fluid systems within 30–150 °C and 10–90 MPa. The results provide experimental data and an engineering-oriented thermodynamic correlation for assessing CO
2
dissolution effects in deep-well well-control calculations.