In oil and gas production, the coexistence of water and condensate in subsea pipelines often leads to emulsion formation, complicating separation processes and increasing operational challenges in flow assurance. Emulsions can be stabilized or destabilized depending on temperature, salinity, inhibitor chemistry, and water cut, yet their combined effects remain poorly understood. This study investigates the emulsification tendency and phase behavior of South Pars condensates (SPD10 and SPD15) under pipeline-representative mixing. Experiments were conducted at condensate-to-water ratios of 4:1 and 2:2, across four temperatures (12, 30, 45, and 70 °C). Samples were agitated with controlled high-shear pulses, and separated water and emulsion volumes were monitored at different settling times. Results show that at low temperature (12 °C), corrosion inhibitor (CI) with brine produced large but short-lived emulsions (~ 165 mL at 5 min decreasing to ~ 71 mL at 1 h), while kinetic hydrate inhibitor alone did not generate stable emulsions. At higher water cuts (2:2), CI with brine generated much larger emulsions, up to ~ 195 mL initially and ~ 20 mL remaining after 24 h, compared with rapid collapse when deionized water was used. At 70 °C, emulsions diminished and sludge-like interfacial layers dominated. Thermal path also influenced stability, as heating produced larger emulsions than cooling at the same set point. MEG/MDEA blends acted as non-emulsifiers but consistently produced sludge. Overall, the findings highlight CI–brine interactions as the main driver of emulsion and sludge formation. Water cut and thermal history strongly affect stability, offering insights for inhibitor screening and flow-assurance design.
Motlagh et al. (2026) studied this question.