Classification of reservoirs

S T U D E N T / M O H A M E D S a l a h A B O U
E L _ H A M E D
D E P A R T M E N T / P e t r o l e u m R e f i n i n g
Y E A R / T H I R D
Classification of Reservoirs

Classification of Reservoirs and Reservoir Fluids
Petroleum reservoirs are broadly classified as oil or gas
reservoirs. These broad classifications are further
subdivided depending on
 1. The composition of the reservoir hydrocarbon mixture.
 2. Initial reservoir pressure and temperature.
 3. Pressure and temperature of the surface production.
 4. Location of the reservoir temperature with respect to
the critical temperature and the
cricondentherm.

ClassificationFrist
• Oil reservoirs If the reservoir temperature, T, is
less than the critical temperature, Tc,of the
reservoir fluid, the reservoir is classified as an oil
reservoir.
• Gas reservoirs If the reservoir temperature is
greater than the critical temperature of the
hydrocarbon fluid, the reservoir is considered a gas
reservoir.

reservoirsCrude oils
Crude oils cover a wide range in physical properties
and chemical compositions, and it
is often important to be able to group them into
broad categories of related oils. In general,
crude oils are commonly classified into the
following types:
 • Ordinary black oil.
 • Low-shrinkage crude oil.
 • High-shrinkage (volatile) crude oil.
 • Near-critical crude oil.

This classification essentially is based on the
properties exhibited by the crude oil, including:
 • Physical properties, such as API gravity of the
stock-tank liquid.
 • Composition.
 • Initial producing gas/oil ratio (GOR).
 • Appearance, such as color of the stock-tank
liquid.
 • Pressure-temperature phase diagram.

Ordinary black oil
 The liquid shrinkage curve approximates a straight
line except at very low pressures.
 ordinary black oils usually yield gas/oil ratios
between 200 and 700 scf/STB.
 oil gravities of 15 to 40 API.
 The stock-tank oil usually is brown to dark green in
color.

Gas Reservoirs
In general, if the reservoir temperature is above the
critical temperature of the hydrocarbon
system, the reservoir is classified as a natural gas
reservoir. Natural gases can be categorized
on the basis of their phase diagram and the prevailing
reservoir condition into
 four categories:
 1. Retrograde gas reservoirs.
 2. Near-critical gas-condensate reservoirs.
 3. Wet gas reservoirs.
 4. Dry gas reservoirs.

Retrograde Gas Reservoirs
 If the reservoir temperature, T, lies between the critical
temperature, Tc, and cricondentherm,Tct, of the reservoir
fluid, the reservoir is classified as a retrograde gas-
condensate reservoir.

 This category of gas reservoir has a unique type of
hydrocarbon accumulation, in that the special thermodynamic
behavior of the reservoir fluid is the controlling factor in the
development and the depletion process of the reservoir.
 When the pressure is decreased on these mixtures, instead of
expanding (if a gas) or vaporizing (if a liquid) as might be
expected, they vaporize instead of condensing.

Descripition
Consider that the initial condition of a retrograde gas reservoir is represented by
point 1 on the pressure-temperature phase diagram.
Because the reservoir pressure is above the upper dew-point pressure, the
hydrocarbon system exists as a single phase (i.e., vapor phase) in the reservoir.
As the reservoir pressure declines isothermally during production from the initial
pressure (point 1) to the upper dew-point pressure (point 2), the attraction
between the molecules of the light and heavy components move further apart.
As this occurs, attraction between the heavy component molecules becomes
more effective, therefore, liquid begins to condense. This retrograde
condensation process continues with decreasing pressure until the liquid
dropout reaches its maximum at point 3. Further reduction in pressure permits
the heavy molecules to commence the normal vaporization process.

This is the process whereby fewer gas molecules strike the liquid surface and
more molecules leave than enter the liquid phase.
The vaporization process continues until the reservoir pressure reaches the
lower dew-point pressure. This means that all the liquid that formed must
vaporize because the system essentially is all vapor at the lower dew point.

Descripition
a typical liquid shrinkage volume curve for a relatively rich condensate
system. The curve is commonly called the liquid dropout curve. The
maximum liquid dropout (LDO) is 26.5%, which occurs when the
reservoir pressure drops from a
dew-point pressure of 5900 psi to 2800 psi.
In most gas-condensate reservoirs, the condensed liquid volume
seldom exceeds more than 15–19% of the pore volume.
This liquid saturation is not large enough to allow any liquid flow. It
should be recognized, however, 40 equations of state and PVT
analysis that around the well bore, where the pressure drop is high,
enough liquid dropout migh accumulate to give two-phase flow of
gas and retrograde liquid.

The associated physical characteristics of this category
are
• Gas-oil ratios between 8000 and 70,000 scf/STB.
Generally, the gas-oil ratio for condensate system
increases with time due to the liquid dropout and the
loss of heavy components in the liquid.
• Condensate gravity above 50° API.
• Stock-tank liquid is usually water-white or slightly
colored.

It should be pointed out that the gas that comes out of the solution
from a volatile oil and remains in the reservoir typically is
classified a retrograde gas and exhibits the retrograde condensate
with pressure declines.
There is a fairly sharp dividing line between oils and condensates
from a compositional standpoint. Reservoir fluids that contain
heptanes and are in concentration of more than 12.5 mol% almost
always are in the liquid phase in the reservoir.
Oils have beenobserved with heptanes and heavier concentrations
as low as 10% and condensates as high as 15.5%. These cases are
rare, however, and usually have very high tank liquid gravities.

Near-Critical Gas-Condensate
Reservoirs
If the reservoir temperature is near the critical temperature, the hydrocarbon
mixture is classified as a near-critical gas condensate. The volumetric behavior
of this category of natural gas is described through the isothermal pressure
declines, as shown by the vertical line 1–3 in Figure 1–28 and the
corresponding liquid dropout curve of Figure.
Because all the quality lines converge at the critical point, a rapid liquid
buildup immediately occurs below the dew point (Figure 1–29) as the pressure is
reduced to point 2.
This behavior can be justified by the fact that several quality lines are crossed very
rapidly by the isothermal reduction in pressure. At the point where the liquid
ceases to build up and begins to shrink again, the reservoir goes from the
retrograde region to a normal vaporization region.

Wet gas reservoirs
Wet gas reservoirs are characterized by the following
properties:
• Gas oil ratios between 60,000 and 100,000 scf/STB.
• Stock-tank oil gravity above 60° API.
• Liquid is water-white in color.
• Separator conditions (i.e., separator pressure and
temperature) lie within the twophase
region.

Dry Gas Reservoirs
The hydrocarbon mixture exists as a gas both in the
reservoir and the surface facilities.
The only liquid associated with the gas from a dry gas
reservoir is water. Figure 1–31 is a
phase diagram of a dry gas reservoir. Usually, a system that
has a gas/oil ratio greater than
100,000 scf/STB is considered to be a dry gas. The kinetic
energy of the mixture is so high
and attraction between molecules so small that none of
them coalesce to a liquid at stocktank
conditions of temperature and pressure.

Phase envelops for 3 reservoir types

Classification of reservoirs

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