IMPROVED OIL RECOVERY

Unit 2
Learning Outcomes
At the end of this unit the student should be able to:
 Describe and compare the measurement of interfacial tension using the Wihelmy
plate, Du NoÜy ring and pendant drop methods
 Describe the Imbibition Displacement test used to determine the Amott and USBM
wettability indicies
 Describe primary drainage and imbibition in terms of capillary pressure
 Describe the relationship between wettability and capillary pressure
 Calculate Define Capillary, Gravity and Bond numbers

Reference: Chapter 2 – Enhanced Oil Recovery, Green and Willhite

Wettability

Why is this important? For porous media, the distribution of

phases (oil, water, gas) within the pores is controlled by the
rock wettability.

When two immiscible fluids are placed in contact with a solid

surface, one phase is usually attracted to the surface more
strongly than the other phase.
Wettability
 Original assumption: All sandstone and carbonates
are preferentially wet
 Sandstones deposited in an aqueous environment
 Most sedimentary rock minerals are water-wet in their natural state
 In carbonate formations, water played a large part in the development
of porosity
 Fact: Wettability is due to the absence or the
presence of polar compounds existing in minute
quantity in crude oil.
Influence of surface chemical properties

The chemical compositions of the fluids and the rock surfaces determine the
values of the solid-fluid and fluid-fluid specific surface energies. Thus,
the mineralogy of the rock surface has an influence on the relative
adhesive tensions, which contributes to the overall wettability of the
fluid-rock system.
Polar organic compounds in crude oil can react with the surface, forming a
preferentially oil-wet surface. Interfacially active compounds-those that
tend to accumulate at the interface-can lower the fluid-fluid interfacial
tension and affect the wetting characteristics of the fluid-rock system.
Many of the surface properties of the shales, sandstones and
carbonates that affect the relative wettability of the surfaces by water
and crude oils are readily explained by examining the general
chemical structures associated with the principal minerals.

Petrophysics, Tiab and Donaldson

Wettability Determination
• Contact Angle Measurements
• Imbibition-Displacement Tests on rock samples
Amott wettability measurements
USBM method
• Nuclear Magnetic Relaxation

See ‘Wettability Measurement and Capillary Pressure’ handout

in myelearning
Contact angle measurements
measured through the denser phase
strongly oil wet
 = 180°
strongly water wet
 = 0°

Intermediate wetting
 = 90°

Contact angle cell

• Flat polished crystal of the mineral that is predominantly in the rock surface
immersed in a sample of formation water
• A drop of reservoir oil is placed on the solid surface
Tilt base method
Two plate method
Dynmanic contact angle
• Pro: Reliable results
• Con: long testing time (contact angle is a function of contact time) and test
system must be clean and inert
Determining wettability
• Imbibition-Displacement Tests on rock samples
 Amott
 U.S. Bureau of Mines
Imbibition-Displacment Tests

Forced WATER Forced OIL

Imbibition Imbibition

Spontaneous Spontaneous
WATER Oil
Imbibition Imbibition
Amott Wettability Index
The core is initially saturated with oil.
1. The core is immersed in brine for 20 hours, and the volume of oil
displaced, if any, by spontaneous imbibition of water is measured
2. The oil remaining in the core is displaced by water to S or and the total
amount of oil displaced (by imbibition and by forced displacement) is
summed
3. The core is immersed in oil for 20 hours, and the amount of water
displaced by spontaneous imbibition of oil, if any is measured

4. The water is displaced to the residual water saturaion with oil, and the
total amount of water displaced (by imbibition of oil and by forced
displacement) is measured
Amott Wettability Measurment

Forced WATER Forced OIL

Imbibition Imbibition

Forced displacements of oil to Sor and to water to Siw may be conducted

by centrifuge or by mounting the core in fluid-flow equipment and
pumping the displaced fluids into the core
Imbibition: Increasing water saturation
Imbibition: Increase in wetting phase saturation
Drainage: Decrease in wetting phase saturation
Drainage: Decreasing water saturation

Pc>0: Pressure in the non

wetting phase is greater

Pc<0: Pressure in the wetting

phase is greater

The larger pressure exists in the

non-wetting phase
 USBM
Wettability Indices

Imbibition Indices

Io = Volume of oil displaced in step 1 /

Total volume of oil displaced
Iw = Volume of water displaced in step 3/
Amott-Harvey Index Total volume of water displaced
IAH = Iw- Io
Wettability Indicies and Contact angles
Nuclear Magnetic Relaxation
 Strong magnetic field followed by much weaker
magnetic field
 measure magnetic relaxation rate (time to return to
equilibrium state)

Linear relationship between relaxation rate and

fractional oil-wet surface
 Capillary pressure Pc = capillary pressure, Pa
 = interfacial tension (mN/m)
= contact angle
rc = radius of the capillary, m
The capillary pressure is the pressure difference between the wetting and
non-wetting phases.
2 cos 
Pc 
rc
Immiscible Oil
fluids h
rc range 5-20 micrometres
Water
Oil-Water IFT range 10-
32 dynes/cm
Consider porous media to be a complex network
of capillary tubes.
Trapping forces
Given that the capillary pressure across a drop of oil is -0.68 psi,
if the drop is 0.01cm long what would be the pressure gradient
(psi/ft) required to force this oil drop through a pore throat?
A. 2.073 psi/ft
B. 20.73 psi/ft
C. 207.3 si/ft
D. 2073 psi/ft
Trapping forces
Given that the capillary pressure across a drop of oil is -0.68 psi,
if the drop is 0.01cm long what would be the pressure gradient
(psi/ft) required to force an oil drop through a pore throat?
A. 2.073 psi/ft
B. 20.73 psi/ft See Enhanced Oil Recovery by Green
and Willhite, Chapter 2
C. 207.3 si/ft
D. 2073 psi/ft

The pressure calculated for a single capillary does not exist throughout the entire
reservoir because there are numerous alternative paths for fluid flow in a
permeable rock
Channel Flow-Experimental Observation

 In flow through porous media, immiscible fluids each

move through its own network of interconnecting
channels.
 The channels vary in diameter and are bounded by
liquid-liquid interfaces as well as by liquid-solid
interfaces
 With a change in saturation the geometries of the
flow channels were altered
 Flow is streamline and devoid of eddy currents
Channel Flow in porous media

Figure 2.4 shows two drawings

depicting channel flow at different
stages in flooding.

Each fluid, wett and non-wetting

moves in its own network of pores, but
with some wetting fluid in each pore.

As the nonwetting phase saturation

increases, more of the pores are
nearly filled with nonwetting fluid.

The Reservoir Engineering Aspects of

Waterflooding by Forrest Craig
Waterflood of water wet rock

The Reservoir Engineering Aspects of Waterflooding by Forrest Craig

In the unaffected portion of the reservoir, the water saturation (connate water) is
low and exists as a film around the sand grains and in the re-entrant angles.
interior angle
The remaining pore space is full of oil. >180°

In the zone in which water and oil are both flowing, part of the oil exists in
continuous channels, some of which have dead-end branches. Other oil has been
isolated and trapped as globules by the invasion of water.

At flood out, only trapped, isolate oil exists in the rock.

The Reservoir Engineering Aspects of Waterflooding by Forrest Craig

Waterflood of Oil-wet rock

The Reservoir Engineering Aspects of Waterflooding by Forrest Craig

 At the non-wetting phase (water in this case) enters the rock it first
forms tortuous but continuous flow channels through the largest pores.

As water injection continues, successively smaller pores are invaded

and join to form other continuous channels.

When sufficient flow channels form to permit almost unrestricted water

flow, oil flow reduces considerably. The residual oil saturation exists in
the smaller flow channels and as a film in the larger, water filled
channels.

The Reservoir Engineering Aspects of Waterflooding by Forrest Craig

 2 cos 
Pc 
rc

Measuring , 
Describe and compare the measurements of interfacial tension using the
Wihelmy plate, Du NoÜy ring and pendant drop methods

This was not covered in class please read the ‘Measuring IFT’handout
myelearning
Capillary Pressure
 SEM
photomicrographs

In these photographs, the

Wood’s metal surfaces are
rounded at 22% saturation,
but become increasingly
angular at high saturations

Waterflooding by G. Paul Willhite

As the saturation of the non wetting phase
increases, it penetrates progressively smaller pore
spaces .

This confirms that initially the wetting phase

occupies the smallest pores and crevices.

The pressure of the mercury (non-wetting

phase) increases with percentage PV
occupied by the mercury.

Points 1 through 4 correspond to the

saturations in Fig. 2.16a through 2.17d

Waterflooding by G. Paul Willhite

 Saturations for a specific capillary
pressure depend on the direction of
saturation change

Curve 1, the drainage curve, was

obtained as water was displaced
from the core by successive
increases in pressure of the non-
wetting phase

Curve 2 represents the capillary

pressure data when water
imbibed into the core thereby
expelling oil

Waterflooding by G. Paul Willhite

 a. Initial saturation
b. SEM photomicrographs of
residual Wood’s metal ganglia

Ragged edges of the ganglia

indicate small mean radii of
curvature.

These ganglia no longer have a

hydraulic connection with the bulk oil
phase.

Waterflooding by G. Paul Willhite

 Saturations for a specific capillary
pressure depend on the direction of
saturation change

This shows how the nonwetting phase

can be trapped in pores of various
sizes at the end of paths 2, 4 and 6

Waterflooding by G. Paul Willhite

See also Section 2.4.4 page 25 Enhanced Oil Recovery by Willhite

Capillary Number- ratio of viscous to capillary forces
F  w

Fc  ow cos 
Dimensionless group
w- displacing phase
 w ow - IFT between displaced
N ca  and displacing phase
=interstitial velocity
 ow µ = viscosity N ca
*

 w
 ow
For
=Darcy velocity
Correlation of Nca/cos
Waterflood zone

Waterfloods typically operate at

conditions where Nca <10-6

Enhanced Oil Recovery, Green and Willhite

Bond Number- ratio of gravitational forces to surface tension forces

  grc
2
Bo= bond number
Bo  ρ = density difference between fluids

 a = acceleration due to gravity

rc = radius of pore throat
 = surface tension of the interface
Quick Questions
1. Define mobility ratio
2. List two methods of Secondary recovery
3. What are the units of interfacial tension?
4. What is imbibition?
5. In which phase is pressure greater, wetting or non-wetting?
6. Define capillary number
7. Define capillary pressure