Fangfu Zhang

Measurement and Prediction of Thermal Degradation of Scale Inhibitors

As the oil and gas industry is making firm strides in deepwater and shale exploration and development, possible thermal degradation of scale-inhibitor molecules poses a great challenge for scaling control and flow assurance for high-temperature reservoirs. Although extensive research has been conducted to test thermal stability of scale inhibitors, little work has been devoted to study the thermodynamics/kinetics of thermal degradation of scale inhibitors. In this work, a novel and efficient testing approach based on inhibition kinetics has been developed and successfully applied to determine the fraction of the active inhibitor molecules in preheated samples of scale inhibitors with various generic chemistries. Moreover, for the first time, we have modeled the kinetics of inhibitor thermal degradation on the basis of the integrated firstorder rate equation and Arrhenius equation, with good agreements between the model predictions and experimental data. The preheated scale inhibitors have been analyzed by nuclear-magneticresonance (NMR) spectroscopy for organic-compound characterization. Our results and predictions based on inhibition testing assay are consistent with the P/H NMR analyses. This work has enabled an in-depth understanding of the time and temperature dependence of thermal degradation of scale inhibitors, and facilitates the rational selection and deployment of scale inhibitors for high-temperature oil and gas production.

Scale Prediction and Control at Ultra HTHP

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 H 2 O, CO 2 , and H 2 S 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 H 2 O, CO 2 , and H 2 S 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 CO 2 ,H 2 S, and H 2 O partition in and out of the gas phase during production. The partitioning of CO 2 ,H 2 S, and H 2 O 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 CO 2 flooding.