Asphaltene Deposition during CO₂Injection and Pressure Depletion: A Visual Study

Abstract

Carbon dioxide miscible flooding has become a popular method for Enhanced Oil Recovery (EOR) because it not only efficiently enhances oil recovery but also considerably reduces green house gas emissions. However, it can significantly cause asphaltene deposition, which leads to serious production problems such as wettability alteration, plugging of the reservoir formation, blocking the transportation pipelines, etc. It is crucial to investigate the effects of different factors on asphaltene deposition. A novel experimental setup was prepared to employ a high-pressure visual cell for investigation of asphaltene deposition on a model rock under typical reservoir conditions. The evolution of asphaltene deposition was monitored via a highresolution microscope. Image processing software was utilized to check the amount of deposited asphaltene and its size distribution under different conditions. Crudes from two Iranian oil fields were used in the experiments. The amount of asphaltene deposition was measured during pressure depletion under two operating conditions: with/without CO 2 -injection. It was observed that the amount of deposited asphaltene decreases with pressure depletion. For instance, asphaltene deposition at 140 bar and 90 °C is 5.7 times greater compared to 30 bar and 90 °C condition. The results of CO 2 gas injection confirm that the deposited asphaltene increases with the concentration of injected CO 2 . According to the results, a temperature increase from 35 to 90 °C contributes to growth and aggregation of asphaltene particles. A comparison of two different asphaltene sources in terms of aggregation and flocculation behavior revealed that the asphaltene molecular structure could have a noticeable influence on asphaltene deposition. A new parameter was defined as the potential of deposition to describe, quantify, and compare the tendency of different asphaltene samples for flocculation and deposition.

Experimental investigation of miscibility conditions of dead and live asphaltenic crude oil–CO2 systems

“…It is a condition at which two fluids can be mixed together so that no separation can be identified (Green and Willhite 1998;Orr and Jessen 2007). In general, the mechanisms of oil recovery under miscible conditions are mainly reduction of both capillary pressure and reservoir fluid viscosity (Leach and Yellig 1981;Wylie and Mohanty 1999;Zanganeh et al 2012). From operational point of view, the minimum miscibility pressure (MMP) is the minimum operating pressure at which oil recovery is high and displacing gas with reservoir oil can reach miscibility at reservoir conditions (Cao and Gu 2013b;Dong et al 2001;Stalkup 1987).…”

“…During the miscible CO 2 injection process, the asphaltene precipitation phenomenon occurs in asphaltenic oil samples (Escrochi et al 2013;Jafari Behbahani et al 2012;Zanganeh et al 2012). Asphaltene is the heaviest component of the crude oil that is not soluble in n-heptane and n-pentane but is soluble in toluene (Ferworn et al 1993;Nielsen et al 1994).…”

Investigation of asphaltene deposition under dynamic flow conditions

“…Asphaltenes as colloidal with various sizes or as individual molecules can be absorbed on solid surfaces by the virtue of their weak phenolic and carboxylic acid groups (Kokal et al 1995). These materials can also be strongly deposited on mineral surfaces and reservoir rocks, and hence cause formation damage, and hinder oil recovery from the reservoirs (Dubey and Doe 1993;Kord et al 2012;Zanganeh et al 2012). Furthermore, the absorption and deposition of asphaltenes on steel surfaces would restrict oil flow in transportation pipelines (Faus et al 1984;Mochida et al 1988).…”

Microscopic pore structure of Chang 63 reservoir in Huaqing oilfield, Ordos Basin, China and its effect on water flooding characteristics

“…The simulated water phase is used to displace the simulated oil phase until the content of the simulated oil phase in the core is approximately the same as the actual oil saturation. When the formation temperature and original distribution is reached, the core is consolidated (Lappin-Scott et al 1988;Zanganeh et al 2012;Zhang et al 2012aZhang et al , 2015b.…”