Oil Recovery From Fractured Carbonates by Surfactant-Aided Gravity Drainage: Laboratory Experiments and Mechanistic Simulations
- Bhargaw Adibhatla (ExxonMobil Corp.) | Kishore K. Mohanty (U. of Houston)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- February 2008
- Document Type
- Journal Paper
- 119 - 130
- 2008. Society of Petroleum Engineers
- 5.4.1 Waterflooding, 5.8.7 Carbonate Reservoir, 5.1.1 Exploration, Development, Structural Geology, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 5.8.6 Naturally Fractured Reservoir, 2.5.2 Fracturing Materials (Fluids, Proppant), 5.7.2 Recovery Factors, 4.1.2 Separation and Treating, 1.6.9 Coring, Fishing, 5.2.1 Phase Behavior and PVT Measurements, 4.1.5 Processing Equipment, 4.3.4 Scale, 1.8.5 Phase Trapping
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Waterflooding recovers little oil from naturally fractured carbonate reservoirs if the matrix is oil-wet and fracture intensity is high. Laboratory experiments and mechanistic simulations have been conducted to understand the injection of dilute anionic surfactant solutions into oil-wet, fractured reservoirs. In this process, surfactant diffuses into the matrix, lowering the interfacial tension (IFT) and contact angle, which decreases the capillary pressure and increases oil relative permeability, enabling gravity to drain up the oil. The rate of oil recovery increases with an increase in matrix permeability, a decrease in initial gas saturation, a decrease of fracture height or spacing, and an increase in the wettability-altering capabilities of the surfactant. Increasing the surfactant concentration does not necessarily enhance the oil recovery rate, because IFT and wettability alterations are not linearly related to surfactant concentration. Adsorption of anionic surfactants on calcite can be suppressed with an increase in pH and a decrease in salinity.
Approximately 60% of the world's oil is found in carbonate reservoirs (Akbar et al. 2000). Recovery from reservoirs depends on reservoir heterogeneity, oil quality, drive mechanisms, and reservoir management. Many carbonate reservoirs are naturally fractured and oil-wet/mixed-wet (Roehl and Choquette 1985, Chillenger and Yen 1983). Such reservoirs are difficult to produce after the primary production if the fractures form a connected network (Allan and Sun 2003). Waterflooding is effective only if the formation is water-wet. Flooding processes do not work in general, because large, viscous gradients cannot be imposed. Gravity drainage (surfactant, gas, and thermal) techniques can be applied, but the recovery is slow. Surfactant-enhanced gravity drainage and imbibition processes are being developed (Yang and Wadleigh 2000; Austad and Milter 1997; Standnes and Austad 2000a, 2000b, 2003a, 2003b, 2003c; Xie et al. 2005; Seethepalli et al. 2004; Hirasaki and Zhang 2004) to improve oil recovery from oil-wet/mixed-wet, fractured carbonate formations and are the subject of this study.
Cationic surfactants of the type alkyl trimethyl ammonium bromide, CnTAB, are effective [recovery approximately 70% original oil in place (OOIP)] in imbibing water into originally oil-wet chalks at concentrations greater than their critical micellar concentration (approximately 1 wt%) (Austad and Milter 1997; Standnes and Austad 2000a, 2000b, 2003b). Cationic surfactants form ion pairs with adsorbed organic carboxylates of the crude oil, and solubilize them into the oil thereby changing the rock surface to be water-wet. This wettability alteration can lead to countercurrent imbibition of brine and, thus, to oil recovery. The IFT between the surfactant solution and oil are not low (> 0.1 dynes/cm). Several cheaper cationic surfactants of the form C10NH2 and bioderivatives from the coconut palm, termed Arquad and Dodigen (priced at 3 USD/kg), have been identified (Standnes and Austad 2003c, 2003a; Strand et al. 2003). The two key problems with this method are still the high concentration and the high surfactant cost.
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