Can Paraffin Wax Deposit Above Wax Appearance Temperature? A Detailed Experimental Study

Abstract

Abstract Shale producers in North America continue to face challenges with paraffin wax deposition in well bores, production tubing and flowlines as production declines and artificial lift methods such as gas lift are applied. Preventative measures are often based on traditional screening and assessment methods which rely on crude’s wax appearance temperature (WAT). Recent studies have shown that operators are increasingly turning to costly remediation program and stimulation jobs to maintain production rates as oil wells decline at faster rates than anticipated. It appears in many cases that these declines can be exacerbated by downhole organic fouling and wax deposition that surprisingly may have occurred above the original WAT. This paper aims to conduct a root cause analysis to identify the key internal and external factors impacting an oil’s WAT. Four crude oils and field wax deposits from Gulf of Mexico, South Texas and West Texas areas were used for this study. Due to the unique composition of the field deposits and depleted crude sample available for analysis, a novel strategy for lab screening was adopted. Crude oil samples were examined "as received" and after reconditioning via the addition of solvents and/or field deposits. Further measurements were performed to identify and quantify the effects of the addition of production chemicals particularly hydrate inhibitors. A series of dispersion and deposition tests were then conducted in order to demonstrate the potential impacts of incompatible chemistries. Fractionation based on solubility revealed a dynamic behavior for the WAT of crudes that corelated to their paraffin content and distribution. Samples containing C45+ paraffin chains demonstrated significant WAT changes upon reconditioning. The addition of methanol and MEG typically used as hydrate inhibitors, impacted the WATs of the crudes as measured by DSC showing increases in the WATs compared to unconditioned samples. An additional suite of dispersion and deposition testing conducted on the same samples supported the findings of the DSC studies. A nonlinear correlation was found between increasing WAT and paraffin deposition rate. The approach outlined in this paper provides a more accurate field condition simulation leading to more effective inhibitor selection and ultimately improved flow assurance management in more complex production systems. The methodology of mimicking hydrocarbon fluid behavior was the key factor identified by the root cause analysis and correlated to the series of past failures attributed to organic fouling. WAT was found to be a parameter that can vary for a crude oil over the life of a production system. With the current evolution of shale oil production in North America and around the world, we expect these findings will also be relevant to unconventional production and will aid the oil industry to anticipate and manage previously unforeseen problematic paraffins in production systems.