Scale Prediction and Control at Ultra HTHP

Abstract

Abstract Production from deepwater environment often encounter ultra high temperature, pressure (ultra HTHP) and with more exotic fluid compositions. Most scale prediction programs were developed by semiempirically modeling the thermodynamic parameters using experimentally measured mineral solubilities and other chemical properties. However, the experimental data were limited at temperature, pressure, and ionic strength that were clearly below that typically encountered in deepwater production. Therefore, extending the existing thermodynamic models to HTHP applications is of questionable accuracy. Furthermore, the partitioning of H2O, CO2, and H2S in and out of the gas/oil phases during production can have a significant impact on scaling tendency. The authors have published papers on experimental solubility measurements and thermodynamic modeling to extend the solubility data to HTHP condition. The new thermodynamic parameters and a flash calculator that integrate the latest development of Equation of State (EOS) to model the partition of H2O, CO2, and H2S in hydrocarbon/aqueous phases at temperature and pressure have been incorporated into a scale prediction software that is specifically tailored for oil and gas production application. The objective of this paper is to validate the software's application range with a set of critically evaluated peer-reviewed mineral solubility data for general oilfield produced water and deepwater HTHP application. A total of 73 selected papers and more than 2,500 individual experimental data points were included in this evaluation. Our model has been shown to be applicable to greater than 95% of produced water compositions with SI prediction of better than ±0.03 for halite, ±0.05 for gypsum, ±0.1 for calcite and anhydrite, and ±0.2 for barite at temperature between 32 - 500 °F, and and pressure between 14.7 to 22,000 psia. The newly incorporated flash calculator is capable of predicting how CO2, H2S, and H2O partition in and out of the gas phase during production. The partitioning of CO2, H2S, and H2O between the hydrocarbon and aqueous phases has significantly changed the ion composition and pH and therefore, impacted the scaling tendency of the fluids at the production temperature and pressure. This is a particularly important issue for newer wells with high volumes of gas and low water cuts and for CO2 flooding.