wettability, Oil & Gas Glossary

What Is Wettability in Oil and Gas Reservoirs?

Wettability is the tendency of one fluid to spread on or adhere to a solid surface in the presence of another immiscible fluid. In petroleum reservoirs, it describes which fluid — oil or water — preferentially coats the rock grain surfaces and occupies the smallest pore throats. Wettability is one of the most influential rock properties governing oil recovery: a water-wet reservoir allows injected water to displace oil efficiently from pore surfaces; an oil-wet reservoir traps oil on grain surfaces and produces it poorly. Most natural reservoir rocks are water-wet to intermediate-wet in their virgin state, but wettability can be altered by asphaltene adsorption, crude oil aging, and exposure to oil-based drilling fluids.

Key Takeaways

Water-wet rocks hold water on grain surfaces and displace oil efficiently during waterflood; oil-wet rocks hold oil on grain surfaces and water floods through preferentially.
Wettability is measured by contact angle: <90° = water-wet; >90° = oil-wet; near 90° = neutral/intermediate wet.
The Amott-Harvey index and USBM method are the standard wettability measurement techniques used in core analysis laboratories.
Oil-wet conditions increase residual oil saturation and reduce waterflood recovery — EOR surfactant treatments target wettability alteration as a primary recovery mechanism.
Wettability alteration by asphaltene deposition is a major source of formation damage in heavy crude and high-asphaltene oil systems.

Water-Wet vs. Oil-Wet Reservoirs

In a water-wet system, water occupies the small pores and coats grain surfaces; oil resides in the larger pores as a continuous non-wetting phase. During waterflood, injected water advances through the smaller pores and displaces oil from the larger ones — this piston-like displacement is relatively efficient and produces good oil recovery (40–60% of OOIP in favourable cases). The North Sea Brent Group sandstones and many Middle East carbonate reservoirs are predominantly water-wet.

In an oil-wet system, oil coats grain surfaces and occupies small pores; water is the non-wetting phase in the larger pores. Injected water channels through the larger pores without contacting the oil on grain surfaces — sweep efficiency is poor, residual oil saturation (Sor) is high, and recovery factor suffers. The Permian Basin San Andres dolomite and many naturally fractured carbonates with high asphaltene content exhibit mixed or oil-wet behaviour. Surfactant EOR treatments specifically target these systems, altering wettability from oil-wet back toward water-wet to mobilise trapped residual oil.

Fast Facts: Wettability

Contact angle (water-wet): 0–75°
Contact angle (neutral/intermediate): 75–105°
Contact angle (oil-wet): 105–180°
Measurement methods: Amott-Harvey index, USBM wettability index, contact angle goniometry
Primary cause of wettability alteration: asphaltene adsorption onto mineral surfaces
Effect on Sor: oil-wet systems have 10–20% higher residual oil saturation than water-wet
EOR relevance: wettability alteration is the primary mechanism of surfactant and low-salinity waterflooding
OBM drilling impact: OBM filtrate can alter near-wellbore wettability from water-wet to oil-wet

Core Analysis Tip:

Core wettability measurements are highly sensitive to handling and cleaning procedures. Cores cut with oil-based mud (OBM) have their near-wellbore wettability altered by OBM filtrate before the core ever reaches the surface. Solvent cleaning (Dean-Stark extraction) used to remove oil before analysis can itself alter wettability by removing the asphaltene layer that was controlling the in-situ wetting state. For reliable wettability data, request "preserved" or "native-state" cores — cut with water-based mud and shipped in sealed containers at reservoir temperature without cleaning — and measure wettability within days of cutting. Restored-state cores are an acceptable alternative where native cores are unavailable.

Wettability is also referred to in these contexts:

Water-wet / oil-wet — the two end-member wetting states
Mixed-wet — a system where large pores are oil-wet and small pores remain water-wet; common in many carbonate reservoirs
Intermediate-wet — contact angle near 90°; neither phase strongly preferential
Amott-Harvey index — the standard wettability index ranging from −1 (strongly oil-wet) to +1 (strongly water-wet)

Frequently Asked Questions About Wettability

How does low-salinity waterflooding improve oil recovery through wettability?

Low-salinity waterflooding injects fresh or reduced-salinity water (typically below 5,000 ppm TDS) into a reservoir containing formation brine at 50,000–200,000 ppm TDS. The ionic strength change destabilises the adsorbed layer of polar oil compounds (asphaltenes, naphthenic acids) on clay and mineral grain surfaces, promoting desorption and shifting wettability from oil-wet or mixed-wet toward water-wet. This wettability alteration reduces residual oil saturation, improves relative permeability to oil, and increases waterflood sweep efficiency. BP's pioneering work on Alaskan North Slope fields and Equinor's Snorre and Heidrun field trials demonstrated incremental recoveries of 5–15% of OOIP from low-salinity flooding.

Why does wettability affect relative permeability curves?

Relative permeability (kr) curves — which describe oil and water mobility as functions of water saturation — are directly controlled by wettability. In a water-wet system, water occupies small pores first during imbibition, leaving oil mobile in large pores — the result is high kro at low water saturation and efficient oil displacement. In an oil-wet system, oil occupies small pores and is the last phase to be mobilised — kro remains significant even at high water saturations, but sweep efficiency is poor because water bypasses oil-coated grain surfaces. The difference in kr curves between water-wet and oil-wet systems is why wettability measurement is mandatory for any credible waterflood simulation model.

Can wettability be restored once altered by oil-based mud?

Yes, to a degree. Matrix acid treatments (HCl or HF depending on lithology) can dissolve asphaltene-coated mineral surfaces and partially restore water-wet conditions near the wellbore. Surfactant treatments (wettability-altering surfactants injected as a pre-flush before waterflood) can alter surface chemistry in the near-wellbore region. However, restoring reservoir-scale wettability to its pristine state after years of oil production and OBM exposure is not practically achievable — EOR designs must account for the actual in-situ wetting state rather than assuming an idealised water-wet condition.

Why Wettability Matters in Oil and Gas

Wettability controls how oil, water, and gas distribute themselves in reservoir pore space, how efficiently water or gas can displace oil, and how much oil remains trapped after primary and secondary recovery. A single percentage point change in residual oil saturation across a major field can represent tens of millions of barrels of additional reserve. That's why wettability is central to every EOR design and why surfactant, low-salinity waterflood, and CO2 miscible flooding programmes specifically target wettability alteration as the primary recovery mechanism.

Wettability: Definition, Reservoir Rock Properties, and Oil Recovery