Enhanced oil recovery (abbreviated EOR) is the implementation of various techniques for increasing the amount of crude oil that can be extracted from an oil field. Enhanced oil recovery is also called improved oil recovery or tertiary recovery (as opposed to primary and secondary recovery). According to the US Department of Energy, there are three primary techniques for EOR: thermal recovery, gas injection, and chemical injection.Sometimes the term quaternary recovery is used to refer to more advanced, speculative, EOR techniques. Using EOR, 30 to 60 percent, or more, of the reservoir's original oil can be extracted, compared with 20 to 40 percent using primary and secondary recovery.
Primary recovery techniques: This implies the initial production stage, resulted from the
displacement energy naturally existing in a reservoir.
Secondary recovery techniques: Normally utilized when the primary production declines.
Traditionally these techniques are water flooding, pressure maintenance, and gas injection. The
recovery factor can rise up to 50%.
Tertiary recovery techniques: These techniques are referred to the ones used after the
implementation of the secondary recovery method. Usually these processes use miscible gases,
chemicals, and/or thermal energy to displace additional oil after the secondary recovery
process has become uneconomical. The recovery factor may arise up to 12% additionally to the
RF obtained with the secondary recovery method.
Primary Recovery
In this recovery process oil is forced out of the petroleum reservoir by existing natural pressure
of the trapped fluids in the reservoir. The efficiency of oil displacement is primary oil recovery
process depends mainly on existing natural pressure in the reservoir. This pressure originated
from various forces:
Expanding force of natural gas
Gravitational force
Buoyancy force of encroaching water
An expulsion force due to the compaction of poorly consolidated reservoir rocks
Among these forces, expanding force of high-pressure natural gas contributes mainly to oil
production. These forces in the reservoir either can act simultaneously or sequentially,
depending on the composition and properties of the reservoir.
The gravitational force is more effective in steeply inclined reservoirs, where it facilities the
drainage of oil. This force alone may not be effective in moving large amounts of oil into a
production well. Another, more effective, force for displacement oil is encroachment of water
from the side or bottom of a reservoir. In some fields, edge water encroachment from a side
appears to be stationary. The ability of the edge water to encroach depends upon the pressure
distribution in the reservoir and the permeability. Compaction of the reservoir as fluids are
withdrawn also is a mechanism for movement of oil to production wells. Part of the oil will be
expelled due to the decrease in the reservoir volume.
Secondary Recovery
When the reservoir pressure is reduced to a point where it is no longer effective as a stress
causing movement of hydrocarbons to the producing wells, water or gas is injected to augment or increase the existing pressure in the reservoir. Conversion of some of the wells into injection
wells and subsequent injection of gas or water for pressure maintenance in the reservoir has
been designated as secondary oil recovery.
When oil production declines because of hydrocarbon production from the formation, the
secondary oil recovery process is employed to increase the pressure required to drive the oil to
production wells. The purposes of a secondary recovery technique are:
Pressure restoration
Pressure maintenance
The mechanism of secondary oil recovery is similar to that of primary oil recovery except that
more than one well bore is involved, and the pressure of the reservoir is augmented or
maintained artificially to force oil to the production wells. The process includes the application
of a vacuum to a well, the injection of gas or water .
Water Injection
In water injection operation, the injected water is discharged in the aquifer through several
injection wells surrounding the production well. The injected water creates a bottom water
drive on the oil zone pushing the oil upwards. In earlier practices, water injection was done in
the later phase of the reservoir life but now it is carried out in the earlier phase so that voidage
and gas cap in the reservoir are avoided. Using water injection in earlier phase helps in
improving the production as once secondary gas cap is formed the injected water initially tends
to compress free gas cap and later on pushes the oil thus the amount of injection water
required is much more. The water injection is generally carried out when solution gas drive is
present or water drive is weak. Therefore for better economy the water injection is carried out
when the reservoir pressure is higher than the saturation pressure.
Water is injected for two reasons:
1) For pressure support of the reservoir (also known as voidage replacement).
2) To sweep or displace the oil from the reservoir, and push it towards an oil production
well.
The selection of injection water method depends upon the mobility rate between the displacing
fluid (water) and the displaced fluid (oil).
The water injection however, has some disadvantages, some of these disadvantages are:
• Reaction of injected water with the formation water can cause formation damage.
• Corrosion of surface and sub-surface equipment.
As part of water injection it is also common to find the water flooding technique.
Water
flooding consists of water Water is injected into the reservoir through injection wells. The water
drives oil through the reservoir rocks towards the producing wells. For water flooding the most common pattern of injection and production wells is a five-spot configuration as shown in
figures 3 and 4 show from different angles, where the water is injected in the central well
displacing oil to the four surrounding production wells.
Gas Injection
It is the oldest of the fluid injection processes. This idea of using a gas for the purpose of
maintaining reservoir pressure and restoring oil well productivity was suggested as early as
1864 just a few years after the Drake well was drilled.
The first gas injection projects were designed to increase the immediate productivity and were
more related to pressure maintenance rather to enhanced recovery. Recent gas injection
applications, however, have been intended to increase the ultimate recovery and can be
considered as enhanced recovery projects.
In addition, gas because of its adverse viscosity ratio (higher mobility ratio) is inferior to water
in recovering oil. Gas may offer economical advantages. Gas injection may be either a miscible
or an immiscible displacement process. The characteristics of the oil and gas plus the
temperature and pressure conditions of the injection will determine the type of process
involved.
The primary problems with gas injection in carbonate reservoirs are the high mobility of the
displacing fluid and the wide variations of permeability. It is required a much greater control
over the injection process than the one necessary with water-flooding. In order to evaluate the
weep efficiency of the planned gas injection, a short-term pilot gas injection test should be
driven. At the same time, this test would provide the necessary data to calculate the required
volumes of gas; this in turn, will aid in the design of compressor equipment and estimating the
number of injection well which will be required.
In some cases gas injection can increase the ultimate recovery of oil such cases like having
carbonate reservoirs. The benefits obtained by the gas injection are dependent upon horizontal
and vertical sweep efficiency of the injected gas. The sweep efficiency depends on the type of
porosity system present.