Abstract
Carbon dioxide (CO2) injection is one of the most applied enhanced oil recovery methods in the hydrocarbon industry, since it has the potential to increase oil recovery significantly and can help reduce greenhouse gases through carbon storage in hydrocarbon reservoirs. Carbon dioxide injection has a severe drawback, however, since it induces asphaltene precipitation by disrupting the asphaltene stability in crude oil that bears even the slightest asphaltene concentration. This can result in severe operational problems, such as reservoir pore plugging and wellbore plugging. This research investigates some of the main factors that impact asphaltene stability in crude oil during CO2 injection. Initially, asphaltene precipitation, flocculation, and deposition were tested using visual tests without CO2 in order to evaluate the effect of oil viscosity and temperature on asphaltene stability and content in the crude oil. The results obtained from the visualization experiments were correlated to the Yen–Mullins asphaltene model and were used to select the proper chemical to alter the oil’s viscosity without strongly affecting asphaltene stability. After performing the visual asphaltene tests, a specially designed filtration vessel was used to perform the oil filtration experiments using filter membranes with a micron and nanometer pore size. The effect of varying CO2 injection pressure, oil viscosity, filter membrane pore size, and filter membrane thickness on asphaltene stability in crude oil was investigated. The results were then correlated with the Yen–Mullins asphaltene model to characterize the asphaltene size within the oil as well. Results showed that as the oil viscosity increased, the asphaltene concentration in the oil also increased. Also, the asphaltene concentration and filter cake thickness increased with the decrease in filter membrane pore size, since the asphaltene particles either plugged up the smaller pores, or the asphaltene nanoaggregates were larger than the pore sizes, and thus the majority of them could not pass. This research studies asphaltene instability in crude oil during CO2 injection in different pore sizes, and correlates the results to the principle of the Yen–Mullins model for asphaltenes. The results from this research can help emphasize the factors that will impact asphaltene stability during CO2 injection in different pore sizes in order to help reduce asphaltene-related problems that arise during CO2 injection in hydrocarbon reservoirs.
Highlights
CO2 has had significant success in increasing oil recovery from conventional oil reservoirs (Fakher et al 2017, 2018b, 2019)
Asphaltenes are present in the crude oil as micelles, which are stabilized by resins, and maltenes, which surround the asphaltene molecules, while their aliphatic tails are comingled in the oil phase (Thomas et al 1995; Groenzin and Mullins 2000; Hernandez 1983; Leontaritis and Mansoori 1987; Punase et al 2016; Mannistu et al 1997)
It is comprised of a high-purity C O2 cylinder for C O2 injection, a pressure regulator attached to the cylinder to control the pressure provided by the cylinder, a filtration vessel, which contains the crude oil, a rubber O-ring to prevent leakages, the filter membrane, and a 60-micron mesh screen used to support the filter membrane and prevent it from being punctured during the experiment due to high pressure without constricting the flow of oil
Summary
CO2 has had significant success in increasing oil recovery from conventional oil reservoirs (Fakher et al 2017, 2018b, 2019). It has been noted that high molecular weight components in the reservoir oil, such as asphaltene and resins, are not mobilized by the C O2 during flooding, and the components precipitate from the oil phase and deposit into the pore spaces, which in turn results in pore plugging and a lower-than-expected oil recovery (Wang et al 2016; AlGhazi and Lawson 2007; Forte and Taylor 2014; Goual and Abudu 2009; Mendoza De La Cruz et al 2009; Escobedo and Mansoori 1997). Journal of Petroleum Exploration and Production Technology (2020) 10:919–931 in the reservoir conditions that alters or disrupts the equilibrium conditions such as a change in temperature, pressure, or introduction of a foreign agent such as CO2 in the reservoir causes the precipitation and eventually the deposition of asphaltene in the pores (Zendehboudi et al 2014; KalantariDahagi et al 2006; Kariznovi et al 2012; Mansoori 1996; Uetani 2014; Rogel et al 1999; Rassamdana et al 1996). Asphaltene instability can result due to reservoir rock properties such as lithology and pore size (Kordestany et al 2019; Shedid and Zekri 2006; Mishra et al 2012; Hannisdal et al 2006; Jha et al 2014)
Sign-in/Register to view highlights & summary Sign-in/Register to access full text options 
Free) 
Talk to us
Join us for a 30 min session where you can share your feedback and ask us any queries you have
Schedule a call
