Low Salinity EOR in Carbonates

Abstract

Modifying the chemistry of injection water yields improved wettability behavior on carbonate rock surfaces. Previous work has focused on demonstrating the effect of modified brine formulation on particular carbonate samples. Here the results of a more general screening study consisting of Amott spontaneous imbibition experiments on the samples from oil-bearing zones and from outcrops of different carbonate formations are reported. Tertiary incremental oil production due to increased water-wetness was observed upon transition to brine of lower ionic strength. Additional oil recovery from the spontaneous imbibition tests ranged from 4 to 20% of OIIP (Oil Initially In Place), reflecting a large variability in the response and indicating a high complexity of the mechanism(s). Consistent with numerous published reports, Stevns Klint outcrop chalk samples were a clear exception and exhibited increased oil recovery with increasing sulfate ion concentration. These did not respond to lowering the salinity of the imbibing brine. Tertiary oil recovery from samples containing evaporites occurred simultaneously with dissolution of salt minerals, as evident from brine analysis. However, incremental oil recovery in the same range was measured for samples without evaporites but from the same geological formation. Hence, mineral dissolution as a mechanism for enhanced oil recovery could not be confirmed. The results show that injection of low salinity brine into carbonate reservoirs has potential as an EOR technology. However, additional research is needed to improve the understanding of the underlying chemical and physical mechanisms and improve a priori predictability.

Modified seawater as a smart EOR fluid in chalk

“…Significant EOR effects by using 10 times diluted SW, larger than those using ordinary SW, were observed in both outcrop dolomite without anhydrite present and in reservoir cores with anhydrite present (Romanuka et al, 2012). This could be explained by weaker bonds between the carboxylic material and the dolomite surface.…”

Zeta potential in oil-water-carbonate systems and its impact on oil recovery during controlled salinity water-flooding

“…The brines were synthetic solutions of reagent-grade NaCl, CaCl 2 , Na 2 SO 4 and MgCl 2 salts in deionized water. Three of the brine compositions tested were designed to represent the natural formation brine typical of hydrocarbon reservoirs6 (denoted FMB), natural seawater (denoted SW) and seawater diluted 20 times (denoted 20dSW) (Table 1). Similar brines have been used previously in studies of CSW in carbonates404345.…”

“…The water injected may be formation brine produced from the oil reservoir or an underlying aquifer, seawater, or water from some other convenient source. Formation brine (FMB) is typically highly saline (total ionic strength >2 mol·dm −3 ) and rich in monovalent and divalent ions such as Na + , Cl − , Ca 2+ and Mg 2+ 67 (Table 1). Seawater (SW) is less saline than typical FMB (total ionic strength 0.55–0.69 mol·dm −3 ) but is still rich in a range of monovalent and divalent ions891011 (Table 1).…”

Zeta potential of intact natural limestone: Impact of potential-determining ions Ca, Mg and SO4

“…Table 2 lists the compositions of the electrolytes used, including the natural seawater and synthetic formation brine (FMB) typical of oil reservoirs and deep saline aquifers (e.g. Romanuka et al, 2012).…”