Asphaltene Deposition During CO2 Flooding: A Laboratory Assessment

Abstract

Abstract In a CO2 miscible displacement process, the injected CO2 solvent can induce flocculation and deposition of asphaltenes and other heavy organic particles. This can cause numerous production problems with a detrimental effect on oil recovery. Therefore, it is important to understand the behavior of this organic matter under reservoir operating conditions. This paper presents results of dynamic and static precipitation tests conducted at reservoir temperature and pressure conditions to investigate the likelihood of asphaltene deposition problems in the Weyburn reservoir (in southeast Saskatchewan). A laboratory study using a high-pressure PVT cell was undertaken to determine the effect on asphaltene flocculation/precipitation of operating pressure, CO2 concentration, gas contaminants in CO2, and presence of formation brine for three different oil samples collected from the reservoir. The extent of asphaltene deposition was also assessed through coreflood experiments using preserved and restored reservoir core material collected from different reservoir zones of increasing permeability (Marly, Vuggy and high-grain-size Vuggy) and through a suitably designed X-ray CAT-scanning visualization experiment. Static tests indicated the most important factor on which the asphaltene precipitation depended was the CO2 concentration. For oils belonging to the same pool, the increase in asphaltene precipitation with solvent concentration was proportional to the initial asphaltene contents of the oil. Coreflood experiments showed a considerable increase in asphaltene deposition in the core matrix following CO2 injection. Pore topography of the core matrix played an important role in the extent of CO2-induced asphaltene deposition. The deposition appeared to be higher in a high-grain-size Vuggy matrix than in the normal Vuggy matrix, and lowest in the Marly matrix. X-ray CAT-scanning tests depicted localized areas of asphaltene deposition along the length of the core, with significant deposition suspected to be occurring near the inlet of the core. The CAT-scan tests also identified sites of suspected formation damage to the core matrix associated with CO2 injection. Introduction After initial waterflooding, many light and medium oil reservoirs are subjected to miscible or near-miscible CO2 or hydrocarbon flooding for enhanced oil recovery. In the U.S.A., 60 active miscible CO2 projects were in operation in 1996, whereas in Canada, hydrocarbon miscible floods are more common and number around forty active projects. In Saskatchewan, Canada, most of the light oil reservoirs have reached their economic limit of production by waterflooding and are suitable candidates for miscible/near-miscible CO2 flooding. The injected CO2, when it contacts the reservoir oil, can cause changes in the fluid behavior and equilibrium conditions which favor precipitation of organic solids, mainly asphaltenes. Asphaltene precipitation can change the wettability of the reservoir matrix and consequently affect the flood performance. It can also cause formation damage and wellbore plugging, requiring expensive treatment and cleanup procedures. Asphaltene deposition problems are not limited to miscible floods but are also encountered during natural depletion, gas-lift operations, caustic flooding, and matrix acidizing. Asphaltenes are the polar, polyaromatic and high molecular weight hydrocarbon fraction of crude oil that are generally characterized as insoluble in n-hexane or in n-pentane. They are believed to exist either dissolved in oil or as a finely dispersed colloidal suspension in oil stabilized by resins adsorbed on their surface. The asphaltene/resin ratio and high/low molecular weight component ratio determines which crude oil can precipitate asphaltenes. Application of chemical, mechanical, or electrical forces can alter these ratios and destabilize resins and asphaltenes. The fine particles of destabilized asphaltenes coalesce and cause flocculation. Flocculated asphaltenes may contain sizable amounts of entrapped oil which inhibits deposition. Asphaltene precipitation is considered to occur when the flocculated asphaltenes separate from the oil phase. However, precipitated asphaltenes (which are hard to observe visually because of their similar dark colour) can return to solution if the asphaltene/resin ratio of the precipitated phase is the same as that of the original oil. P. 617^