Adhesion Tension

Key Takeaways

• Young's equation relates the adhesion tension to the three solid-fluid interfacial tensions at the contact line: gamma_SO = gamma_SW + gamma_OW × cos(theta), where gamma_SO is the solid-oil interfacial energy, gamma_SW is the solid-water interfacial energy, and gamma_OW is the oil-water interfacial tension. Rearranging gives AT = gamma_OW × cos(theta) = gamma_SW - gamma_SO: adhesion tension equals the difference between the solid-water and solid-oil interfacial energies. When the solid-water energy is lower than the solid-oil energy (the solid would rather be in contact with water than oil), the contact angle through water is less than 90 degrees and AT is positive: the surface is water-wet. When the solid-oil energy is lower (the solid prefers oil), the contact angle through water exceeds 90 degrees and AT is negative: the surface is oil-wet. Most reservoir rocks have mineralogies (quartz, calcite, dolomite) that are inherently water-wet in their clean state, but exposure to polar components of crude oil (asphaltenes, resins) can cause adsorption of these components onto the rock surface, shifting the wettability toward intermediate-wet or oil-wet conditions.
• The magnitude of the capillary pressure in a reservoir pore system depends directly on the adhesion tension. For a water-wet pore of radius 1 micrometre with IFT of 25 mN/m and contact angle of 30 degrees (AT = 25 × cos(30°) = 21.7 mN/m), the capillary pressure across a curved oil-water interface is Pc = 2AT/r = 2×21.7×10⁻³/10⁻⁶ = 43,400 Pa = 0.43 bar. This capillary entry pressure means that oil cannot enter the 1-micrometre pore unless the oil column is tall enough to generate a pressure exceeding 0.43 bar at the water-oil contact. In a reservoir with pores of 0.1 micrometre radius (tight carbonate or tight sandstone), the capillary entry pressure at the same wettability would be 10 times higher (4.3 bar), explaining why very tight formations require long hydrocarbon columns or high displacement pressures for oil to enter. Reducing IFT (as in surfactant flooding) or altering the contact angle (as in chemical wettability alteration treatments) changes the adhesion tension and therefore the capillary entry pressure, affecting fluid mobility and recovery.
• Wettability measurement methods include the Amott-Harvey index (the ratio of spontaneous imbibition to forced displacement for both oil and water, ranging from -1 for strongly oil-wet to +1 for strongly water-wet), the USBM wettability number (based on the ratio of areas under the two branches of the capillary pressure curve on a log scale), and direct contact angle measurement using a sessile drop of oil on a polished mineral surface in brine. The Amott-Harvey index is the most widely used routine wettability measurement in WCSB core analysis laboratories; values from 0.3 to 0.7 are considered water-wet, -0.3 to +0.3 are intermediate-wet, and -0.3 to -1.0 are oil-wet. Intermediate to oil-wet wettability is common in carbonate reservoirs that have been in contact with crude oil for geological time periods (millions of years of hydrocarbon column exposure), particularly in formations with high asphaltene content such as the Devonian carbonates of the WCSB. Wettability has been shown to affect waterflood recovery efficiency by 20 to 40 percentage points in reservoir simulations calibrated to laboratory corefloods, making wettability measurement and incorporation into reservoir simulation one of the highest-value rock physics measurements for waterflood design.
• Capillary number (N_ca = viscous forces / capillary forces = viscosity × velocity / IFT) characterises the relative dominance of viscous versus capillary forces during fluid displacement. At the low flow velocities in reservoir-scale waterfloods (typically 10⁻⁶ to 10⁻⁵ m/s), N_ca is on the order of 10⁻⁷ to 10⁻⁵, meaning capillary forces controlled by adhesion tension dominate over viscous forces. Residual oil saturation (the fraction of oil that cannot be displaced by waterflooding) is controlled entirely by capillary trapping of oil ganglia in pore throats at these low capillary numbers. At N_ca above approximately 10⁻³ (achievable only with very low IFT or very high velocity), the capillary forces are overwhelmed by viscous forces and residual oil can be mobilised. Low IFT flooding (surfactant or miscible gas) aims to raise N_ca above the critical value by reducing IFT (and thus AT) to near zero, mobilising trapped oil and improving recovery above the conventional waterflood residual saturation.
• Wettability alteration by injection of water with low ionic strength or controlled composition (low salinity waterflooding) is an emerging EOR mechanism in WCSB carbonates and sandstones. At low salinity (below approximately 5,000 ppm total dissolved solids), the double-layer expansion between brine-mineral surfaces and the oil-brine interface increases (the zeta potential becomes more negative on both surfaces), reducing the adhesion of polar oil components to the rock surface. This shifts the contact angle toward more water-wet conditions, increasing AT and improving water imbibition and capillary-driven oil recovery. Field pilots in Viking, Cardium, and Lloydminster sandstones have shown 5 to 12 percent additional oil recovery above conventional waterflood by switching injection water to lower salinity formation water or desalinated produced water, with the mechanism linked to wettability alteration as quantified by contact angle measurements on representative core samples.