Reservoir Rock Properties

 Introduction
 Porosity
 Permeability
 Saturation
 Wettability
 Surface and Interfacial tension
 Capillary pressure
 Rock Compressibility
Reservoir rock properties

 Oil created by the source rock won’t be useful unless it
winds up being stored in an easily accessible container, a
rock that has room to “suck it up”
 A reservoir rock is a place that oil migrates to and is held
underground.
 Reservoir rocks are dominantly sedimentary (sandstones,
carbonates); however, highly fractured igneous and
metamorphic rocks have been known to produce
hydrocarbons, but on a much smaller scale.

A good reservoir rock must have porosity
in which petroleum can exist.
Another characteristics of reservoir
rock is that it must be permeable.
Other properties include:
Fluid Saturation, Saturation, Wettability, Surface and Interfacial tension, Capillary pressure
Rock Compressibility, Overburden pressure etc.

 Even though a reservoir rock looks solid to the naked
eye, a microscopic examination reveals the existence
of tiny openings in the rock, called pores. These spaces
or voids are the one in which reservoir fluids are present.
 Porosity(φ) : Porosity is the capability of a rock to hold
fluids in pore. It is the ratio of the pore volume in a rock
to the bulk volume of that rock. Expressed in per cent.
Mathematical form is:
φ = Vp/Vb

 Porosity is a measure of the void space in
rock, hence, measures how much HC in rock
 Porosity φ = Vp/Vb = (Vb-Vm)/Vb; Vb = Vp + Vm
◦ theoretically, φ varies from 0% - 47.6%
◦ In practice, φ varies between 3% and 37%
 Porosity is a function of particle size distribution:
◦ Framework materials (sandstone) – high φ
◦ Interstitial materials (shaly-sand) – low φ
Rock matrix
Water
Oil and/or gas

 Porosity can be classified into;
1. Original porosity
2. Induced porosity
 Original porosity (primary) is formed during the deposition
of rock materials, e.g. porosity between granular in sandstone,
porosity among crystal and oolitic in limestone
 Induced porosity (secondary) is developed by some geological
process on the deposited rock material.
E.g; Fractures, or vugs cavity usual occur in limestone
(chemical reaction b/w CaCO3 and MgCl2)

Sand grain
Cement
material
Effective / connected
porosity (25%)
Ineffective
Porosity (5%)
Total Porosity (30%)

PRIMARY
• Particle sphericity and angularity
• Packing
• Sorting (variable grain sizes)
• Cementing materials
• Overburden stress (compaction)
• Vugs, dissolution, and fractures
SECONDARY (DIAGENETIC)

cubic packing of
spheres resulting
in a least-compact
arrangement with
a porosity of
47.64%
Rhombohedral
packing of
spheres resulting
in a most-
compact
arrangement with
a porosity of 26%
Spherical size variation
influences type & volume
of solid porosity
Effect of cement material
Porosity
36%
Porosity
20%

 Permeability is a property of the porous medium that
measures the ability of the formation to transmit fluids. It’s
the a measure of the ease with which the rock will permit
the passage of fluids.
 Unlike porosity, permeability cannot be defined apart from
fluid flow. For a rock to be Permeable, it must contain
inter-connected pores
 Reservoir permeability is usually quoted in millidarcies,
(md).

 Absolute permeability - the permeability of a porous
medium with only one fluid present (single-phase flow).
 When two or more fluids are present permeability of the
rock to a flowing fluid is called effective permeability
(ko, kg, kw).
 Relative permeability is the ratio of absolute and effective
permeabilities kro=ko/k, krg=kg/k, krw=kw/k.

Darcy’s law helps us to measure the degree of permeability.
 Darcy’s “K” was determined to be a combination of
◦ k, permeability of the sand pack (porous medium,
e.g. reservoir rock)
◦ K is a constant of proportionality
◦ , viscosity of the liquid
◦ dp, Pressure gradient
 K constant may be written as;
dL
dp
KAQ 
μ
k
K

The unit of permeability in the empirical equation is the Darcy
and the dimension is (L2). It is usually too large to be convenient
in hydrocarbon reservoirs. The millidarcy (10-3 Darcy) is
therefore used.
Generally the permeability is termed as :
 Poor if; k<1,
 Fair if; 1<k<10,
 Moderate if; 10<k<50,
 Good if; 50<k<250,
 Very good if; k>250.

 Permeability is a very important rock property because it controls the
directional movement and flowrate of the reservoir fluid in the
formation.
The factors affecting the magnitude of Permeability are:
 Shape and size of grain sizes,
 cementation
 overburden pressure
 fracturing and Dissolution

Saturation is defined as that fraction, or percent, of the pore volume
occupied by a particular fluid (oil, gas, or water). This property is
expressed mathematically by the following relationship:
Applying the above mathematical concept of saturation to each reservoir
fluid gives

Where
 So = Oil saturation
 Sg = Gas saturation
 Sw = Water saturation
The saturation of each individual phase range from 0-100%.
By definition, the sum of saturation is 100% therefore,
Sg+So+Sw=1.0

The major saturation types of interest in a Reservoir
are;
 Critical Oil saturation, Soc
 Movable oil saturation, Som
 Residual Oil Saturation, Sor
 Connate water Saturation, Swc

 This is the tendency of a fluid to spread on or adhere to a solid
surface in the presence of other immiscible fluid. The angles made
by the fluid with the surface with which it is in contact is known as
the “contact angle”.
 Depending on the type of fluid in contact with a solid surface, a
reservoir could be; water-wet or oil-wet. Because of the attractive
force, the wetting phase tends to occupy the smaller pores of the
rock and the nonwetting phase occupies the more channels.

 Knowledge of the wettability of reservoir rocks is essential
in determining the appropriate drive mechanism for a
particular reservoir. It is an important control on the
amount of recovery.
 Hydrocarbon wet system retard hydrocarbon mobility while
water wet systems promotes hydrocarbon mobility.

 Petroleum reservoirs commonly have 2 – 3 fluids (multiphase
systems)
 It is necessary to consider the effect of the forces at the
interface when two immiscible fluids are in contact.
When these two fluids are liquid and gas, the term surface
tension is used to describe the forces acting at the interface.
When the interface is between two liquids, the acting forces are
called interfacial tension.
 When 2 or more fluids are present, there are at least 3 sets of
forces acting on the fluids and affecting HC recovery

 Immiscible fluids: when you bring them into contact they do not mix
 Two fluids are separated by an interface
 The molecules are attracted more to their own kind
Oil
Rock
water

 When two immiscible fluids are in contact, a discontinuity in
pressure exits between the two fluids, which depends upon
the curvature of the interface separating the fluids. We call
this pressure difference the capillary pressure, Pc.
 Similarly, it can be defined as the pressure differential
between two immiscible fluid phases occupying the same
pores caused by interfacial tension between the two phases
that must be overcome to initiate flow.

 Reservoir rocks are subjected to the internal stress exerted by fluids
contained in the pores, and to external stress which is in part exerted
by the overlying rocks.
 The weight of the overburden simply applies a compressive force to
the reservoir rock. Compressibility typically decreases with increasing
porosity and effective overburden pressure.
 Porosity is a function of compaction. It is generally reduced by
increase in compaction. Compaction is a function of depth of burial.

 Rock compressibility is the fractional change in Volume per unit change in
pressure
Expressed as
 Three types of compressibility
Rock- matrix (grain) compressibility, Cs
Rock-bulk compressibility, Cb
Pore-volume compressibility, Cp
 Formation Compressibility is important to Reservoir engineers. It plays a role
in depletion of fluid from pore spaces, internal rock stress changes which
results in change in Vp, Vm, Vb
P
v
V
c
p
p

1
=

 Knowledge of reservoir rock properties is very essential to
evaluating Reservoir Performance and understanding reservoir
behavior.
 The aforementioned rock properties are essential for reservoir
engineering calculations as they directly affect both the
quantity and the distribution of hydrocarbons and, when
combined with fluid properties, control the flow of the existing
phases (i.e., gas, oil and water) within the reservoir.

Reservoir Rock Properties

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