A gas condensate field was tie-backed to an existing subsea pipeline transporting paraffinic crude oil from an Indonesian offshore production system where wax deposition was a primary flow assurance challenge. As expected, condensate addition did alleviate the challenge of both wax deposition and waxy oil gel restart of the commingled pipeline. Pipeline operating data including pigging frequency, transient flow rate and pressure drop were analyzed to estimate average wax deposit growth rates for the condensate line and the commingled line for various blends of oil and condensate liquids.
Flow rate, pressure drop, inlet and arrival temperatures, and seabed temperature data were used to validate thermo-hydraulics of the system. A numerical scheme was developed to eliminate noise in the data and calculate deposition rates between two consecutive pig runs for condensate and commingled pipelines for various blends of the condensate and oil. Detailed laboratory analysis of fluids was performed for their wax deposition potentials (including high temperature gas chromatographic, wax appearance temperature, wax content, density and viscosity). Wax characteristics have been used in an in-house Wax Deposition simulator to predict the wax deposition rate under various operating conditions.
For the condensate liquid, wax deposit surface roughness was found to significantly contribute to the pressure drop increases, and therefore, increase in the measured pressure drop cannot be solely attributed to deposit thickness increase. For the commingled fluid system, the simulator predictions using the Film Mass Transfer Model (FMTM) with aging reasonably matched the deposit thickness obtained from the field data. For the condensate liquid system, both FMTM and Equilibrium Model (EM) were assessed and it was confirmed that the predictions from the two models bound the wax deposition rate calculated from the field data.
