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The effect of formation water composition on the wettability established between carbonate rocks and crude oil

Argyri Smaragda-Maria

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Summary

Initial reservoir rock wetting conditions are of the main factors influencing the overall oil recovery (primary, secondary and tertiary). Depending on the conditions under which an oil field was formed, different rock/oil/brine systems have been established over millions of years. In this study, the effect that the composition of formation water has on the wetting state of Stevns Klint Chalk cores was examined. More specifically, for carbonate rocks it has been experimentally observed that the existence of Sulfate (SO42-), Magnesium (Mg2+) and Calcium (Ca2+) ions in the formation water contributes towards an improved oil recovery. The fact that the active oil compounds (e.g. R-COO-) are responsible for the mixed wet conditions justifies this observation, because these compounds serve as anchor molecules, creating a very strong bonding with the calcite surface. For high oil recovery to occur, the rock needs to be at least partially water-wet. In order to improve water-wetness, part of the oil active polar compounds must be removed by chemical reactions with injected water. Sulfate, Magnesium and Calcium ions operate as substituents of these oil active polar compounds, by creating symbiotic interactions with the rock surface. Sea water enriched in specific ions has been injected in several operators. For instance, in the Ekofisk field (Tres=130oC) in the Norwegian sector injection of sea water enriched in Sulfate and Magnesium ions has been proved as an enhanced oil recovery fluid. Additionally, the high reservoir temperature (130oC), acts complementary for wettability alteration to take place. To examine the effect of each ion separately on the wetting conditions, three Chalk cores, drilled from the same quarry were used. Each core was saturated with a brine enriched in one of the above three ions. Afterwards, a mixture of Heidrun field crude oil (60%) and Heptane (C7) (40%) was flooded through the cores at 50oC. Effluent samples were collected and analyzed for negatively and positively charged polar compounds. For that reason, a potentiometric titrator was used and the properties related to the amount of negative and positive polar compounds are the Acid Number (AN) and the Base Number (BN) respectively. The cores were then aged at 50oC for two weeks to acquire a uniform polar compound distribution throughout each core. Afterwards, oil recovery wettability tests took place. More specifically, spontaneous imbibition and forced displacement processes were performed to the cores with Valhall Brine depleted in Sulphate (VB0S). Finally, Mild Cleaning procedure was conducted to restore the initial wetting state of the cores and compare the wetting state after the oil flooding and after the Mild Cleaning procedure. To measure the wettability of the cores, additional oil recovery wettability test (spontaneous imbibitions and chromatographic wettability test) took place, at ambient conditions. The experimental results show that both Magnesium and Sulfate ions improve oil recovery, with Sulfate to bear the greatest impact. The effect of temperature on oil recovery wettability tests (at 20oC and 50oC) and the resulting wettability alteration is also discussed.

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