Wettability and interfacial phenomena

Quick refresher

Interfacial tension $\sigma$ is the work needed to create a unit area of the boundary between two fluids. It is also the force per unit length of a line drawn on that boundary. It is measured in N/m; 1 mN/m = 1 dyn/cm. Typical values: water–air about 72 mN/m, oil–water 10–35 mN/m, gas–oil in the reservoir a few mN/m.
The contact angle $\theta$ is the angle where the oil–water boundary meets the rock surface. It is measured through the denser fluid, water. Below 90° the surface is water-wet (hydrophilic: wetted by water). Above 90° it is oil-wet (hydrophobic: wetted by oil). Around 90° the wettability is intermediate, or neutral.
Young's equation: $\sigma_{so} - \sigma_{sw} = \sigma_{ow}\cos\theta$ . The product $\sigma\cos\theta$ is the adhesion tension, and it appears in all capillary calculations.
Wettability belongs to the whole rock–oil–water system, not to the rock alone. It depends on the polar components of the oil (molecules that stick to mineral surfaces: resins, asphaltenes, naphthenic acids), on the minerals, on the composition of the water, and on pressure and temperature. Many reservoirs, especially carbonate ones, are not water-wet but mixed-wet or oil-wet.
The Amott–Harvey index $I_{AH}$ and the USBM index $W$ lie roughly between −1 and +1. Positive values mean water-wet, negative values mean oil-wet, and values near zero mean neutral or non-uniform wettability.
Special core analysis (advanced laboratory tests on core) needs the wettability the rock had in the reservoir. Use core in its native state (sealed after coring, never cleaned) or core with restored wettability (cleaned, then aged in reservoir oil). Cleaned core is suitable only for formations known to be water-wet.

Key relationships

\sigma_{so} - \sigma_{sw} = \sigma_{ow}\cos\theta

Young's equation; $\theta$ is measured through the water

I_{AH} = I_w - I_o

Amott–Harvey index: from −1 (oil-wet rock) to +1 (water-wet)

W = \lg\dfrac{A_1}{A_2}

USBM index from the areas under the capillary pressure curves

Common pitfalls

Treating wettability as a property of the rock alone: the same quartz sandstone can be water-wet with one oil and oil-wet with another.
Mixing up the angle measured through mercury (about 140°) with the angle measured through the wetting phase (about 40°), and so putting a negative cosine into the capillary formulas.
Judging wettability by the Amott–Harvey index alone. A value near zero can mean neutral wettability or mixed wettability, so look at both partial indices.
Running special core analysis on cleaned and dried core without checking the wettability of the formation.

After this lesson you can

explain what surface and interfacial tension are, and know their typical values
find the wettability from the contact angle, and write the balance of forces at the contact line (Young's equation)
tell water-wet, oil-wet, intermediate-wet and mixed-wet rocks apart, and describe how oil and water are distributed in them
calculate the Amott–Harvey and USBM wettability indices from laboratory test results, and know the limits of each method
explain how wettability affects capillary pressure, relative permeability, saturation calculated from logs and oil recovery, and why a core can lose the wettability it had in the reservoir

Surface and interfacial tension

Molecules of a liquid attract one another. A molecule deep inside the liquid has neighbours on all sides, so the pulls cancel out. A molecule at the boundary with another fluid has no neighbours of its own kind on one side, so the net force pulls it inward. So the liquid tends to make its boundary smaller, and the boundary behaves like a stretched elastic skin.

The work needed to make the boundary larger by one unit of area is called the surface tension if the boundary separates a liquid from a gas. It is called the interfacial tension (IFT) if the boundary lies between two liquids that do not mix, for example oil and water. We write it as $\sigma$ and measure it in N/m, which is the same as J/m². It is both the energy of one unit of area of the boundary and the force with which the boundary pulls on each unit of length of a line drawn along it. In practice we use millinewtons per metre. Older and American literature uses dynes per centimetre; 1 dyn/cm = 1 mN/m.

Approximate values of surface and interfacial tension

Pair of phases: Water–air, 20 °C
$\sigma$ , mN/m: 72–73
Remark: about 59 at 100 °C

Pair of phases: Mercury–air
$\sigma$ , mN/m: 480–485
Remark: the working pair of mercury injection capillary pressure (MICP) tests

Pair of phases: Oil–formation water
$\sigma$ , mN/m: 10–35
Remark: surfactants (soap-like chemicals) lower it by orders of magnitude

Pair of phases: Gas–oil in the reservoir
$\sigma$ , mN/m: from below 1 to 20
Remark: falls as pressure rises

Pair of phases: Gas–water in the reservoir
$\sigma$ , mN/m: 30–60
Remark: decreases as pressure and temperature rise

Pair of phases	$\sigma$ , mN/m	Remark
Water–air, 20 °C	72–73	about 59 at 100 °C
Mercury–air	480–485	the working pair of mercury injection capillary pressure (MICP) tests
Oil–formation water	10–35	surfactants (soap-like chemicals) lower it by orders of magnitude
Gas–oil in the reservoir	from below 1 to 20	falls as pressure rises
Gas–water in the reservoir	30–60	decreases as pressure and temperature rise

These are rough values for guidance. For calculations, the interfacial tension is measured on samples of reservoir fluids at reservoir temperature, or estimated from correlations (Oil viscosity and interfacial tension).

A curved boundary between two fluids creates a pressure difference across it. This is the capillary pressure, and it is proportional to $\sigma$ and to the curvature of the boundary. The topic Capillary pressure and the transition zone explains how it arises in pores and what controls it. Here another point matters: interfacial tension sets the size of the capillary forces, and wettability sets their direction.

Contact angle and Young's equation

Place a drop of water on the surface of a mineral that is sitting in oil. Three boundaries meet: mineral–water, mineral–oil and oil–water. They meet along the contact line, and the tension of each boundary pulls this line in its own direction. At equilibrium the drop takes the shape in which the forces along the mineral surface balance. The angle between the mineral surface and the oil–water boundary, measured through the water, is the contact angle ( $\theta$ ).

SchematicA drop of water on a mineral surface in oil, for different wettabilities. The contact angle

\theta

is measured through the water: the smaller it is, the more the water spreads over the surface.

Young's equation (equilibrium at the contact line)

\sigma_{so} - \sigma_{sw} = \sigma_{ow}\cos\theta

where:

$\sigma_{so}$ tension of the mineral–oil interface, N/m
$\sigma_{sw}$ tension of the mineral–water interface, N/m
$\sigma_{ow}$ oil–water interfacial tension, N/m
$\theta$ contact angle, measured through the water, degrees

Units: any units of tension, the same for all three (N/m, mN/m)

Holds when

The surface is smooth, chemically uniform and non-deformable.
The system has come to equilibrium: for oil with polar components this takes tens or hundreds of hours of contact with the mineral.
The angle is measured through the water; measured through the oil it would be $180^\circ - \theta$ .

We cannot measure the tensions at a boundary with a solid directly, but their difference shows up in the contact angle. The right-hand side, $\sigma_{ow}\cos\theta$ , is called the adhesion tension. If it is positive, the mineral is better off in contact with water, and water pushes oil off the surface by itself. If it is negative, the opposite is true. The same product $\sigma\cos\theta$ appears in the formula for capillary pressure.

To get a feel for the numbers: with $\sigma_{ow} = 25$ mN/m and $\theta = 30^\circ$ , the adhesion tension is $25\cos 30^\circ \approx 21.7$ mN/m. Suppose that after long contact with oil the angle grows to 120°. Then it becomes $25\cos 120^\circ = -12.5$ mN/m. The sign has changed: water is no longer drawn into the rock by itself, and has to be forced in.

Wettability by contact angle

Wettability: water-wet (hydrophilic)
Contact angle through water: 0 to 60–75°

Wettability: intermediate (neutral)
Contact angle through water: 60–75° to 105–120°

Wettability: oil-wet (hydrophobic)
Contact angle through water: 105–120° to 180°

Wettability	Contact angle through water
water-wet (hydrophilic)	0 to 60–75°
intermediate (neutral)	60–75° to 105–120°
oil-wet (hydrophobic)	105–120° to 180°

The class boundaries differ between studies, so they are given as ranges.

On real surfaces the angle depends on whether the water is advancing or receding (pulling back). The advancing angle is measured while water moves forward over the surface. It is larger than the receding angle. The difference is called contact angle hysteresis. It comes from the roughness of the surface, its chemical unevenness, and the sticking (adsorption) of oil components to it. In waterflooding the water advances, so the advancing angle is the one that matters. Contact angle hysteresis is one reason why the capillary pressure and relative permeability curves differ when water displaces oil and when oil displaces water.

Types of wettability and the distribution of phases in the pores

The wetting phase tries to cover as much of the mineral surface as it can. So it coats the grains with a film and fills the corners of the pores, the narrow throats between grains and the smallest pores — the places with the most surface per unit volume. The non-wetting phase is pushed into the centres of the large pores.

SchematicOil and water in a water-wet (left) and an oil-wet (right) rock. The wetting phase coats the grains with a film and fills the narrow pore throats between them; the non-wetting phase occupies the centres of the pores.

Water-wet (hydrophilic) rock: Water is the wetting phase. Oil sits in the large pores. During waterflooding, part of it stays there as separate droplets, which break away from the main oil at the pore throats. This is the classic picture for clean quartz sandstones.
Oil-wet (hydrophobic) rock: Oil is the wetting phase: there are films of oil on the grains, and oil fills the small pores. Injected water moves through the large pores and breaks through early to the production wells. Oil keeps arriving along the films for a long time, at a high water cut (a high share of water in the produced liquid).
Intermediate (neutral) wettability: Neither fluid has a clear advantage. Neither water nor oil is drawn into the rock by itself.
Mixed wettability: The large pores are oil-wet and the small ones are water-wet. Oil that entered the trap filled the large pores, and over geological time its polar components settled on the walls of these pores. The small pores and corners, where water stayed, remained water-wet. The oil-wet walls of the large pores form continuous paths for the oil. So with long flushing, the residual oil saturation can become very low.
Spotted (fractional) wettability: Oil-wet patches occur on the surface in pores of any size. This is usually because of differences between minerals: oil components stick (adsorb) to some and not to others.

What wettability depends on

Clean minerals that have been in water for a long time are almost always water-wet. Substances brought in by the oil make them oil-wet. The result depends on the whole rock–oil–water system:

Polar components of the oil. Molecules of resins, asphaltenes and naphthenic acids have a polar “head” (an electrically charged end) and a hydrocarbon “tail”. They attach to the mineral by the head and turn their tails outward, and the surface starts to be wetted by oil. Light paraffinic hydrocarbons (simple, light oil molecules) hardly change wettability.
Mineral composition. In formation water, the surface of quartz is usually negatively charged. It repels the acidic components of the oil, so sandstones more often stay water-wet. At reservoir conditions, the surface of calcite and dolomite is more often positively charged. It attracts those components, which is why carbonates are so often oil-wet. Clay minerals have an enormous surface area per unit volume (specific surface), and they adsorb organic matter strongly.
Water composition. The salinity, the acidity (pH) and the divalent cations $\mathrm{Ca^{2+}}$ and $\mathrm{Mg^{2+}}$ (calcium and magnesium ions with a double charge) affect how stable the water film on the grains is. These ions can “bridge” the negatively charged surface and the oil components. As long as the film is stable, the oil does not touch the mineral.
Pressure and temperature. They change how well asphaltenes dissolve in the oil and how strongly they stick to the rock. When pressure falls, asphaltenes may drop out of the oil onto the pore walls.
Saturation history. Surfaces that have always been covered with water stay water-wet. Pore walls that have been in contact with oil for a long time do not. So wettability can change with height in the accumulation: near the oil–water contact the rock is often more water-wet than in the upper part.

That is why special core analysis (tests of relative permeability, capillary pressure and displacement efficiency) uses one of three kinds of core:

Core in its native state. It is sealed straight after coring and tested without cleaning. This is the best option if coring has not changed the wettability.
Cleaned core. It has been washed out with solvents. It is suitable only for formations known to be water-wet.
Core with restored wettability (restored state). After cleaning, the core is saturated with formation water. The water is then displaced with reservoir oil down to the irreducible water saturation. The core is aged (kept) at reservoir temperature for several weeks, often about 40 days, so that the oil components settle on the pore walls again. A match with the reservoir wettability is not guaranteed; it is checked by comparing with native-state core where there is any.

How wettability is measured

Three methods give a number for wettability: the contact angle, the Amott method and the USBM method (developed at the U.S. Bureau of Mines). Other signs are qualitative, which means they give a hint but no number. They are the rate of spontaneous imbibition (how fast the rock soaks up a fluid by itself), nuclear magnetic resonance measurements, and the shape of the relative permeability curves.

The contact angle is measured on a polished plate of mineral — quartz for sandstones, calcite for carbonates — in formation water and oil, at reservoir temperature. A drop of oil is placed between two parallel plates. One plate is shifted so that water advances in place of oil, and this gives the advancing angle. The angle keeps changing with the time of contact, sometimes for hundreds of hours, until it settles. The method describes the surface chemistry well. But it ignores the roughness, the mixture of minerals and the pore structure of the real rock, so it is used mainly in research.

The Amott method compares how much of a fluid the rock takes in by itself with how much has to be forced in. A sample at residual oil saturation is immersed in oil. After a set time (20 hours in the classic procedure; often one waits longer, until the soaking stops), we measure the volume of water pushed out by the spontaneous imbibition (soaking up by itself) of oil. Then oil is forced in, by centrifuging or by pumping, down to the irreducible water saturation. After that the cycle is repeated for water. The sample soaks up water by itself in a bath of water, and then water forces the oil out until only the residual oil saturation is left.

Amott and Amott–Harvey wettability indices

I_w = \frac{V_{o1}}{V_{o1} + V_{o2}},\qquad I_o = \frac{V_{w1}}{V_{w1} + V_{w2}},\qquad I_{AH} = I_w - I_o

where:

$I_w$ water displacement index: the fraction of the oil displaced by water that was displaced spontaneously, —
$I_o$ oil displacement index: the fraction of the water displaced by oil that was displaced spontaneously, —
$V_{o1},\ V_{o2}$ volumes of oil displaced by water in spontaneous imbibition and then in forced displacement, cm³
$V_{w1},\ V_{w2}$ volumes of water displaced by oil in spontaneous imbibition and then in forced displacement, cm³
$I_{AH}$ Amott–Harvey index, from −1 to +1

Units: volumes in the same units; the indices have no units

Holds when

Spontaneous imbibition lasts the same agreed time in every test. Slow imbibition may not have time to finish, and then the index comes out too low.
The volumes are measured accurately. When the moveable saturation is small, small errors change the ratios a lot.
The sample keeps the reservoir wettability.

A water-wet rock soaks up water by itself ( $I_w$ close to 1) and does not soak up oil ( $I_o = 0$ ). An oil-wet rock does the opposite. If the rock soaks up both fluids by itself ( $I_w > 0$ and $I_o > 0$ ), the wettability is non-uniform — mixed or spotted. If it soaks up neither, the wettability is neutral. The single number $I_{AH}$ cannot tell these two cases apart.

Worked exampleAmott indices for a core sample

Given (assumed data)

Sample: pore volume 20.0 cm³; the test starts at a residual oil saturation of 0.30
Spontaneous imbibition of oil, 20 h: water displaced, $V_{w1} = 1.8$ cm³
Forced displacement of water by oil: a further $V_{w2} = 7.2$ cm³
Spontaneous imbibition of water, 20 h: oil displaced, $V_{o1} = 3.1$ cm³
Forced displacement of oil by water: a further $V_{o2} = 5.9$ cm³

Solution

Check the balance. Oil displaced $1.8 + 7.2 = 9.0$ cm³ of water, and water displaced $3.1 + 5.9 = 9.0$ cm³ of oil. The two volumes agree, so the cycle is closed. The moveable part of the pore volume is $9.0/20.0 = 0.45$ . So the irreducible water saturation is $1 - 0.30 - 0.45 = 0.25$ .
Oil displacement index: $I_o = 1.8/9.0 = 0.20$ .
Water displacement index: $I_w = 3.1/9.0 = 0.34$ .
Amott–Harvey index: $I_{AH} = 0.34 - 0.20 = 0.14$ .

Answer:

I_w = 0.34

I_o = 0.20

I_{AH} = 0.14

What it means. By the single number $I_{AH} = 0.14$ , the sample falls in the neutral wettability class. But both partial indices are clearly above zero: the rock soaks up both water and oil by itself. This is a sign of non-uniform wettability, most likely mixed (water-wet small pores and oil-wet large ones). It does not mean the rock has no preference. The capillary pressure curves of such a rock have both a positive and a negative branch. This matters when we choose relative permeability curves and forecast a waterflood. The data in this example are assumed for illustration.

The USBM method compares the work needed to displace each fluid. First, a sample in a centrifuge is brought to the irreducible water saturation with oil. Then it is spun in water, with the speed raised in steps, up to a chosen negative capillary pressure (water is forced into the rock). Then it is spun again in oil, up to the same pressure with a positive sign. We plot two curves of capillary pressure against the average water saturation of the sample, and find the area between each curve and the axis $p_c = 0$ .

USBM wettability index

W = \lg\frac{A_1}{A_2}

where:

$A_1$ area under the curve of displacement of water by oil (the capillary pressure is positive), kPa × fractions of pore volume
$A_2$ area above the curve of displacement of oil by water (the capillary pressure is negative), in absolute value, the same
$W$ USBM index, —

Units: both areas in the same units; $\lg$ is the base-10 logarithm

Holds when

Both curves are obtained on the same sample over the same range of capillary pressure, for example from −70 to +70 kPa (about ±10 psi).
Only forced displacement counts: spontaneous imbibition happens at $p_c \approx 0$ , so it adds almost nothing to the area.

The area under the capillary pressure–saturation curve equals the work of displacement per unit of pore volume. In a water-wet rock it is hard to force oil in and easy to force water in, so $A_1 > A_2$ and $W > 0$ . In an oil-wet rock, $W < 0$ . In theory the index has no limits, but it usually lies between −1 and +1. Unlike the Amott index, it can tell apart shades of wettability near neutral.

USBM test data for the example below

$S_w$: 0.28
$p_c$ : oil displacing water, kPa: 70
$p_c$ : water displacing oil, kPa: 0

$S_w$: 0.35
$p_c$ : oil displacing water, kPa: 40
$p_c$ : water displacing oil, kPa: −0.5

$S_w$: 0.45
$p_c$ : oil displacing water, kPa: 25
$p_c$ : water displacing oil, kPa: −1.0

$S_w$: 0.55
$p_c$ : oil displacing water, kPa: 18
$p_c$ : water displacing oil, kPa: −1.5

$S_w$: 0.65
$p_c$ : oil displacing water, kPa: 12
$p_c$ : water displacing oil, kPa: −12

$S_w$: 0.70
$p_c$ : oil displacing water, kPa: 0
$p_c$ : water displacing oil, kPa: −70

$S_w$	$p_c$ : oil displacing water, kPa	$p_c$ : water displacing oil, kPa
0.28	70	0
0.35	40	−0.5
0.45	25	−1.0
0.55	18	−1.5
0.65	12	−12
0.70	0	−70

Average water saturation of the sample and capillary pressure at the centrifuge steps; the data are assumed.

CalculatedCurves of the USBM test, drawn from the table data. The area

A_1

under the curve of water displaced by oil is clearly larger than the area

A_2

for oil displaced by water, so the rock is water-wet.

Worked exampleUSBM index from centrifuge curves

Given (assumed data)

Capillary pressure curves: six points of each curve are in the table above
Pore volume of the sample: 20 cm³

Solution

We find the area under the curve of water displaced by oil with trapezoids. On each interval, multiply the mean pressure by the change in saturation. The mean pressures on the five intervals are 55, 32.5, 21.5, 15 and 6 kPa, and the lengths of the intervals are 0.07, 0.10, 0.10, 0.10 and 0.05. The sum is $A_1 = 11.05$ kPa.
Do the same for the curve of oil displaced by water, using the absolute value of the pressure. The means are 0.25, 0.75, 1.25, 6.75 and 41 kPa, and $A_2 = 2.94$ kPa.
The index: $W = \lg(11.05/2.94) = \lg 3.76 = 0.57$ .

Answer:

W \approx 0.57

: the rock is water-wet, but not strongly.

What it means. The area $A_1$ is the work of displacing water by oil per unit of pore volume. 11.05 kPa is 11.05 kJ per cubic metre of pores, which for a sample with a pore volume of 20 cm³ is about 0.22 J. Water entered the rock almost without effort. Most of the rise in water saturation, from 0.28 to 0.55, took place at pressures of no more than 1.5 kPa, that is, almost entirely by spontaneous imbibition. A value of about 0.6 means moderate water-wetness. In strongly water-wet rocks the index approaches 1. The data in this example are assumed for illustration.

How to read the measurement results

Indicator: Contact angle through water
Water-wet: up to 60–75°
Neutral: 60–75° … 105–120°
Oil-wet: from 105–120°

Indicator: $I_{AH}$
Water-wet: +0.3 … +1
Neutral: −0.3 … +0.3
Oil-wet: −1 … −0.3

Indicator: $W$ (USBM)
Water-wet: about +1
Neutral: about 0
Oil-wet: about −1

Indicator: Soaks up by itself
Water-wet: water
Neutral: neither fluid
Oil-wet: oil

Indicator	Water-wet	Neutral	Oil-wet
Contact angle through water	up to 60–75°	60–75° … 105–120°	from 105–120°
$I_{AH}$	+0.3 … +1	−0.3 … +0.3	−1 … −0.3
$W$ (USBM)	about +1	about 0	about −1
Soaks up by itself	water	neither fluid	oil

The boundaries are approximate, and they differ between procedures. With mixed wettability, both fluids soak into the rock by themselves, and $I_{AH}$ may turn out close to zero.

What wettability changes in the reservoir

Wettability decides where the fluids sit, so almost all the properties that are measured in special core analysis depend on it.

Capillary pressure. In a water-wet rock, oil enters the pores only after it overcomes the entry pressure, while water soaks in by itself. In an oil-wet rock, water can get in only if the capillary pressure $p_c = p_o - p_w$ becomes negative. That means water has to be forced in. A negative branch of the curve is a sign of an oil-wet part of the pore space. In oil-wet formations the transition zone is shorter and the irreducible water saturation is lower (Capillary pressure and the transition zone).
Relative permeability. In a water-wet rock, water moves through the small pores and in films, and oil moves through the large pores. The permeability to oil falls slowly as the water saturation increases, and the permeability to water stays low. In an oil-wet rock it is the other way round (Relative permeability).
Saturation from resistivity logs. In an oil-wet rock, water does not form continuous films, so the electrical connection is worse. The saturation exponent $n$ in Archie's equation then rises from 2 to 3–8 or higher. If $n = 2$ is used, the water saturation comes out too low and the hydrocarbons in place too high (Archie's equation and saturation of clean reservoirs).
Waterflooding. In a strongly water-wet formation, water pushes the oil ahead of it with a broad front. Most of the oil is produced before the water breaks through (arrives at the producing wells), but part of it is trapped in the large pores. In an oil-wet formation, water breaks through early along the large pores, and oil is then produced for a long time at a high water cut. Many experiments show the highest recovery at weak water-wetness, close to neutral, or at mixed wettability. But there is no single rule: you need tests on core from your own formation.

Terms and symbols

Interfacial tension $\sigma$: The work needed to create a unit area of the boundary between two phases that do not mix. It is measured in N/m, or in practice in mN/m (1 mN/m = 1 dyn/cm).
Contact angle $\theta$: The angle between the mineral surface and the boundary between the fluids, measured through the water. Below 90° the surface is water-wet; above 90° it is oil-wet.
Adhesion tension: The product $\sigma\cos\theta$ , equal to the difference between the mineral–oil and mineral–water tensions. It is positive for a water-wet surface.
Wetting phase: The fluid that coats the grains with a film, fills the pore throats and small pores, and soaks into the rock by itself.
Spontaneous imbibition: The uptake of the wetting phase into the rock with no applied pressure difference, by capillary forces alone.
Mixed wettability: The large pores are oil-wet and the small ones are water-wet. It arises when oil stays in contact with the walls of the large pores for a long time.
Amott–Harvey and USBM indices: Laboratory measures of wettability, from roughly −1 (oil-wet rock) to +1 (water-wet). They are based on spontaneous imbibition and on the work of forced displacement, respectively.

Common mistakes and misconceptions

Wrong

“The rock is a quartz sandstone, so it is water-wet.”

In fact

Wettability is a property of the rock–oil–water system. The polar components of the oil can make even quartz oil-wet. Wettability is found by tests on core with reservoir fluids.

Wrong

“An Amott–Harvey index near zero means that the wettability is neutral.”

In fact

Mixed wettability, where the rock soaks up both fluids by itself, gives the same value. Look at both partial indices, $I_w$ and $I_o$ .

Wrong

“Before special core analysis the core must be thoroughly cleaned of oil.”

In fact

Cleaning removes the oil components stuck to the surface and makes the rock water-wet. Cleaned core is suitable only for formations known to be water-wet. Otherwise you need core in its native state, or core with restored wettability.

Wrong

“Mercury makes an angle of 140° with the rock, so in the capillary pressure formula for mercury the cosine is negative.”

In fact

The angle of 140° is measured through mercury, the non-wetting fluid. Measured through the wetting fluid (air or vacuum), it is 40°, and $\cos 40^\circ \approx 0.77$ goes into the capillary calculations.

Wrong

“An oil-wet formation is certainly a poor target for waterflooding.”

In fact

Water breaks through earlier in it, and the water cut grows faster. But the ultimate recovery after long flushing may be no worse. Experiments often show the highest recovery at weak water-wetness or mixed wettability.

In depth: advanced detail

How wettability determines residual oil

Residual oil is oil that the water has bypassed or cut off. The mechanism depends on wettability.

In a water-wet rock, water moves not only as a front but also along the films and corners of the pores. In a pore throat the film thickens and closes up. It breaks a thread of oil away from the main body of oil and leaves an isolated droplet in a large pore. Also, water is the wetting phase, so capillary forces draw it into the narrow channels, and it passes through them faster. It bypasses the oil in the neighbouring wide channel. Only a pressure difference that beats the capillary pressure at the two ends of the droplet (its menisci, the curved surfaces) can move such a droplet. At ordinary waterflood speeds this pressure difference is too small. So a noticeable residual oil saturation is left, and it hardly depends on how much water is pumped through.

In an oil-wet rock, oil stays in the small pores and as films on the walls. These films are connected to one another, so oil keeps flowing out slowly after water breakthrough. The residual saturation falls as the injected volume grows, but at the price of a very high water cut. With mixed wettability, the oil-wet walls of the large pores form continuous paths for the oil. After many pore volumes of water have been pumped through (one pore volume is a volume of water equal to the pore space of the rock), the residual oil saturation can be lower than in a water-wet rock.

So there are two routes to the residual oil. One is to lower the interfacial tension, so that the capillary forces holding the droplets become smaller than the viscous forces (the drag of the flowing fluid). The other is to change the wettability. Enhanced oil recovery methods use both routes.

Why the Amott and USBM methods give different answers

The Amott index is based on spontaneous imbibition. A rock with a contact angle from roughly 60–75° to 105–120° soaks up neither water nor oil by itself. So over this whole wide range $I_w \approx I_o \approx 0$ , and the method cannot tell apart shades of wettability near neutral. On the other hand, it recognises mixed wettability well, because with mixed wettability both fluids soak in.

The USBM index, by contrast, is built on forced displacement. It is sensitive near the neutral point. But it does not see spontaneous imbibition, so it cannot tell mixed wettability from uniform wettability. Also, the USBM test is run in a centrifuge, which limits the size of the sample.

So a combined procedure is also used. In one centrifuge cycle, it measures both the volumes of spontaneous imbibition and the areas under the capillary pressure curves, and gives both indices at once. In any case, the result is for one particular sample. For the formation as a whole, it is compared with the shape of the relative permeability curves and with how the wells behave.

Connections to other topics

Fluid saturation — where irreducible water and residual oil are held in the pores.
Capillary pressure and the transition zone — how interfacial tension and contact angle turn into capillary pressure and the saturation profile above the contact.
Relative permeability — how wettability changes the shape of the relative permeability curves.
Archie's equation and saturation of clean reservoirs — why the saturation exponent $n$ depends on wettability.
Oil viscosity and interfacial tension — how the interfacial tension of reservoir fluids is estimated.
Core analysis — special core analysis and the preparation of samples.

Check yourself

1
A drop of water on a mineral surface in oil makes a contact angle of 140°, measured through the water. How is the surface wetted?
1. A.The contact angle cannot show this
2. B.By water (water-wet)
3. C.Neutrally
4. D.By oil (oil-wet)
Show the answer
Correct answer: D. By oil (oil-wet)
The angle measured through the water is above 90°, and above the 105–120° boundary. The water gathers into a drop, and the surface prefers contact with oil. The adhesion tension $\sigma\cos 140^\circ$ is negative.
2
An Amott test gave $I_w = 0$ and $I_o = 0.55$ . What is the Amott–Harvey index and what is the wettability?
1. A.−0.55, oil-wet
2. B.0.55, mixed
3. C.+0.55, water-wet
4. D.0, neutral
Show the answer
Correct answer: A. −0.55, oil-wet
$I_{AH} = I_w - I_o = 0 - 0.55 = -0.55$ . This is below −0.3, so the rock is oil-wet: it soaks up oil by itself and does not soak up water.
3
Which rock is most likely to soak up both water and oil by itself?
1. A.A strongly oil-wet one
2. B.One with mixed wettability
3. C.One with neutral wettability
4. D.A strongly water-wet one
Show the answer
Correct answer: B. One with mixed wettability
With mixed wettability, the small pores are water-wet and soak up water, while the large ones are oil-wet and soak up oil. So both Amott indices are positive. With neutral wettability, neither fluid soaks in by itself.
4
Why can't you simply use core that has been cleaned with solvents and dried to measure relative permeabilities?
Show the answer
Cleaning removes the oil components stuck to the pore surfaces, and the rock becomes water-wet, even if it was mixed-wet or oil-wet in the formation. Wettability decides how the fluids are distributed in the pores. So it decides the shape of the relative permeability curves, the residual oil and the capillary pressure. You need core in its native state, or core with restored wettability: saturated with reservoir fluids and aged at reservoir temperature for several weeks.
5
A USBM test gives the areas $A_1 = 6.0$ kPa and $A_2 = 15$ kPa. Find the index and assess the wettability.
Show the answer
$W = \lg(6.0/15) = \lg 0.4 \approx -0.40$ . The value is negative: it is harder to force water into the rock than oil, so the rock is moderately oil-wet.
6
The resistivity index from logs is $R_t/R_0 = 25$ . What water saturation do the saturation exponents $n = 2$ and $n = 4$ give, and what does it mean for an oil-wet formation?
Show the answer
$S_w = 25^{-1/n}$ : for $n = 2$ we get 0.20, for $n = 4$ we get $25^{-1/4} \approx 0.45$ . If the rock is oil-wet and the true exponent is about 4, the standard $n = 2$ gives a water saturation more than two times too low, and an oil saturation of 0.80 instead of 0.55.

Updated: 19 October 2026