Water-Wet

Key Takeaways

• Wettability alteration during core recovery and laboratory preparation is one of the most persistent sources of error in reservoir characterization — when a core plug is recovered from the wellbore, exposed to air or oxygen, washed with solvents, and dried in an oven before testing, the original wettability state of the grain surfaces is typically destroyed; evaporation and oxidation of adsorbed organics from grain surfaces can shift the wettability toward more water-wet than the original reservoir condition, and solvent washing removes the natural wettability modifiers (asphaltic and resinous compounds in the crude oil) that are responsible for the mixed or oil-wet character of many carbonate reservoirs; preserved core — core that is sealed immediately at the wellsite before any air exposure, maintained at reservoir temperature and pressure, and shipped in sealed containers with preservation fluid — provides a more representative sample of original reservoir wettability, but the cost and complexity of preserved core handling means that many laboratory measurements are performed on routine core that has been altered from its in-situ state; interpreting routine core capillary pressure and relative permeability data without accounting for potential wettability alteration leads to waterflood performance predictions that are systematically wrong.
• The relative permeability to oil at residual water saturation (Kro at Swi) and to water at residual oil saturation (Krw at Sor) are the parameters most sensitively controlled by wettability — in a strongly water-wet rock, Kro at Swi is high (typically 0.8-1.0) because the thin water films on grain surfaces do not significantly impede oil flow through the pore centers, while Krw at Sor is low (typically 0.1-0.3) because the oil residual is trapped in the large pore centers and forces water to flow through the smaller, more tortuous pore throats; in an oil-wet rock, these relationships are reversed — Kro at Swi is lower (oil-coated grains create more tortuous oil flow paths) and Krw at Sor is higher (water is confined to the pore centers in a more interconnected network); the difference in waterflood recovery between a water-wet and oil-wet reservoir of identical porosity, permeability, and geometry can be 15-30 percentage points of OOIP — a difference with enormous economic consequence that comes entirely from the wettability state of the grain surfaces.
• Wettability alteration by crude oil components — particularly asphaltenes and resins — creates the mixed and oil-wet character of many carbonate reservoirs that were initially water-wet at deposition; as oil migrated into the reservoir millions of years ago, polar organic compounds in the crude oil adsorbed onto the grain surfaces and changed the wettability from water-wet to oil-wet or mixed-wet; the degree of wettability alteration depends on the crude oil composition (higher asphaltene and resin content = more wettability alteration), the mineralogy (carbonates, which have positively charged calcite surfaces, are more susceptible to wettability alteration by anionic organic compounds than quartz sandstones), and the contact time between the oil and the rock surface; this history means that carbonate reservoirs that have held oil for millions of years are often significantly more oil-wet than their equivalent sandstone counterparts, and their waterflooding performance is correspondingly poorer — a finding with profound implications for EOR (enhanced oil recovery) design in Middle Eastern and other large carbonate fields.
• Enhanced oil recovery methods including low-salinity waterflooding, surfactant flooding, and alkaline-surfactant-polymer (ASP) flooding work in part by altering reservoir wettability toward more water-wet conditions to improve waterflood sweep efficiency and reduce residual oil saturation; low-salinity waterflooding (injecting water with lower ionic strength than formation water) triggers wettability modification mechanisms that release adsorbed organics from grain surfaces, shifting the wettability toward water-wet and improving oil mobility; laboratory experiments and field pilots have demonstrated incremental oil recovery of 5-15% OOIP from low-salinity waterflooding in some sandstone reservoirs; surfactant systems specifically designed for wettability alteration (cationic surfactants for carbonate reservoirs, anionic surfactants for sandstones) can shift even strongly oil-wet carbonates toward water-wet, potentially unlocking residual oil saturations that conventional waterflooding cannot access; the scale-up from positive laboratory wettability alteration to incremental field recovery is uncertain and field-dependent, which explains why many EOR methods show impressive laboratory performance but modest and variable field-scale results.
• Wettability control in drilling and completion fluids is critical for preserving original reservoir wettability and avoiding formation damage that reduces well productivity — oil-based mud (OBM) filtrate invasion into a water-wet sandstone reservoir can alter the near-wellbore wettability from water-wet to oil-wet by depositing OBM components on previously water-wet grain surfaces, reducing the relative permeability to oil in the invaded zone and causing a "wettability damage" skin that reduces well productivity in proportion to the invasion depth; water-based muds (WBM) cause a different kind of wettability concern in oil-wet or mixed-wet reservoirs by introducing water into the oil-wet pore network, potentially causing water blockage (Jamin effect) where water trapped in smaller pore throats reduces the effective permeability to oil; designing the mud system with wettability preservation in mind — using surfactant additives to maintain the formation's original wettability state, controlling filtrate volume and composition, and cleaning up the invasion zone with appropriate acid or surfactant treatments before producing the well — can preserve near-wellbore productivity that careless fluid selection might damage irreversibly.