Introduction Foam to Improve Oil Recovery
Introduction:
The continued use of gas injection to improve oil recovery and the
prospects for its increased use throughout the world provides impetus to
improve sweep efficiency of injected gas. Work is being carried out to improve
understanding and the economics of mobility control agents.
There are no reservoirs that are completely homogeneous. The porous
media in the reservoir are characterized by a size distribution of pores and pore
throats, which leads to non-uniform displacement. According to
Darcy’s law, the mobility of a single phase in porous media is inversely
proportional to its viscosity. Gases used in gas-flooding (such as CO2, hydrocarbons, N2, etc.) are
normally less viscous (more than one order of magnitude less) and less dense
than both water and crude oil, which results in gas channeling through the high
permeability zones and gravity overriding. Thus, gas flooding normally has poor
volumetric sweep efficiency, especially in an immiscible displacement, with the
displacing phase being a lower viscosity. A need for mobility control in gas
flooding has led to the use of foam for sweep improvement and profile
modification.
Various oil recovery processes are known and used in the industry,
such as waterflood, fireflood, micellar flood, gas drive, miscible flood, and
polymer flood. As mentioned above, the foam process is also known and used. Foam
is employed to improve the efficiency by which the displacing fluid sweeps the
reservoir and contacts and recovers oil. The utility of the invention lies in
the improvement in sweep efficiency when used in enhanced oil recovery
processes. Sweep efficiency is broadly defined as volume of formation
swept/total volume.
Foam is colloidal disersion in which a gas is dispersed in a continuous
liquid phase. Surfactants are added to the solution to stabilize foam by
reducing interfacial tension. Many studies demonstrated that surfactant
stabilized foam could drastically reduce the gas mobility in the porous media,
consequently improving volumetric sweep efficiency and oil recovery.
There is considerable interest in the application of foams in
enhanced oil recovery processes involving miscible or immiscible gas
displacement (CO2, hydrocarbon gases etc.). From a reservoir perspective foams can
provide a means to counteract the displacing agent's naturally high mobility
and low density and therefore can reduce fingering (channeling) and gravity
override. Foams can also be applied near-well to reduce gas coning.
Gases such as steam, carbon dioxide (CO2) and hydrocarbon
gases are injected into oil reservoirs to increase the recovery of oil. These
gases are much less dense and less viscous than the oil they attempt to
displace, so they tend to finger through or migrate to the top of the reservoir,
leaving most of the oil behind. Foams can help these gases to sweep oil
reservoirs more efficiently.
Use of Foam:
Foams are injected into the geological formations for gas diversion
in Improved Oil Recovery (IOR), acid diversion in matrix acid well stimulation,
and environmental remediation. Foam can be injected continuously or in
alternating slugs of gas and liquid. In IOR and environmental remediation, it
is often useful to inject gas and surfactant solution in alternating slugs,
called surfactant-alternating-gas or SAG injection. SAG injection holds several
advantages over continuous co-injection of gas and liquid. As a part of
Improved Oil Recovery (IOR); foams can be used in the following ways (details
of which can be found later when the field cases are discussed):
1) Foam used as stimulant
to increase gas production
2) Foams used to reduce
water cut
3) Foams used to reduce
the gas mobility
4) Gas shut off using foam
Reason for using Foam:
Water-soluble polymers of high molecular weight such as partially
hydrolyzed polyacrylamides are the usual method of providing mobility control
and thus improving sweep efficiency in surfactant and alkaline/surfactant
processes for enhanced oil recovery. Foam offers the prospect of further
improvement in sweep efficiency, especially in heterogeneous reservoirs,
because foam mobility is lower (apparent viscosity is higher) in layers of high
permeability than in those of low permeability. While additional surfactant is
needed to generate the foam, its amount and cost is less than the decrease in
the amount and cost of polymer because half or more of the injected fluid is
gas in the foam case. Recovery of residual oil is excellent in both cases for
the surfactant mixture used. Apparent viscosity of the foam is approximately a
factor of five larger in the sand pack with the higher permeability, confirming
the ability of foam to provide a more uniform sweep than polymer.
The use of foam to improve the sweep efficiency of the displacing
fluid involves the utilization of two foam properties. The first is the high
resistance to flow that is associated with foam. The second property is the
high gas-liquid surface area. Thus, only relatively small amounts of an aqueous
solution of a foaming agent need be used with relatively large amounts of gas
or dense fluid. The gas disperses in the liquid, generating a large interfacial
area and a large volume of foam, thereby increasing the resistance to flow. If
this resistance to flow is in those regions of the reservoir where the
resistance is least, then the displacing fluid is forced to flow through
regions of higher resistance, sweeping larger portions of the reservoir and
recovering larger quantities of oil. Thus, the use of foam improves sweep
efficiency.
The foaming agent is selected for a particular reservoir brine
because the foam-producing characteristics are influenced by the nature of
reservoir rock, such as carbonate or sandstone, the properties of the
reservoir, such as temperature and pressure, and composition of the reservoir
fluids, such as salinity, divalent ion concentration, pH, etc. The
water used in the aqueous solution may be fresh water, produced reservoir
brine, or carbonated water.
Under typical reservoir conditions of temperature and pressure, the
foam is comprised of thin films of a liquid which are separated by the
displacing fluid, which is either a gas or a dense fluid.
A preferred method of generating the foam in-situ within the
reservoir comprises injecting the aqueous slug together with or ahead of a slug
of the displacing fluid. The aqueous slug can also be injected between two
slugs of the displacing fluid. The size or volume of the aqueous slug varies
between about 1 and 90% (vol.) of the pore volume. The size of the displacing
fluid slug is dictated by reservoir size, well spacing, reservoir fluids
saturation, and reservoir and rock properties. The ratio of the displacing
fluid slug size to the aqueous slug size can vary between about 100:1 and 1:1.
The displacing fluid can be one or a mixture of the following carbon dioxide,
nitrogen, air, methane, ethane, propane, butane, hydrogen sulfide, flue or
exhaust gas, or stream.
What is it? How is it
formed? Elaborate on foam quality, viscosity etc.
Foams, which are mixtures of a gas phase, a liquid phase and a
surfactant, meet all the basic requirements for a good fracturing fluid;
however, the fluid properties of foam are derived from a structure different
from that found in gelled water.
The quality of the foam is defined as the volume of gas divided by
the total volume of the foam. Generally, the higher the quality of the foam the
higher its viscosity.
The high apparent viscosity of foam is due to the interfacial
structure of the foam bubbles.4 In very low quality foams, e.g.
Below 50 quality, the spherical gas bubbles have freedom to move with little
restriction from adjacent bubbles. In foams above approximately 50 quality, the
bubbles touch each other and allow less freedom of movement within the total
fluid. In high quality foams, i.e. above 75 quality, the bubbles are crowded
together and no longer have spherical shapes. Movement within the fluid is very
restricted; hence, high apparent viscosity results.
In a static foam, liquid will drain from the fluid, and the foam
that remain on top effectively increases in quality. As the quality of the foam
increases, viscosity also increases as the bubbles distort from a spherical
shape and the lamella assumes a planar configuration. Sand particles are held
in place by the foam structure and do not readily settle through it. When the
quality of the static foam increases, the structure becomes somewhat rigid,
lending greater support to the sand.
Foams in the range of 65 to 80 quality are typically used in foam
fracturing. So proppant is easily transported by the foam and then supported
once the fracture has been created. As a result the proppant is more uniformly
distributed within the fracture rather than simply allowed to settle to the
bottom of the fracture. Foam has shown to have excellent fluid loss properties
for low permeability formation.
Formation clays which are water sensitive can either expand to
reduce permeability or migrate to block flow channels upon contact with water.
Foam helps minimize water damage to the formation because of the overall low
water content of the fluid. Additional clay protection can be achieved by the
use of inorganic salts and polymeric clay stabilizers.
A major advantage of a foam fracturing fluid is its fluid recovery
efficiency.4When pressure is released at the wellhead, the low
hydrostatic head in the wellbore presents lower resistance to production of the
foam frac fluid than for a gelled water fluid. The compressible nature of foam
also helps bring the liquid back due to expansion of the gas in its return to
the wellbore. This gas expansion is most beneficial to wells with low formation
pressure. The clean up of a foam fracturing treatment is usually accomplished
within two days, whereas, a gelled water fracturing treatment may require
several days.
A particularly preferred procedure for carrying out the process of
this invention comprises the following steps:
1) A displacing fluid, such as carbon dioxide, is introduced into the formation at an injector well. As the injection of the fluid is continued, the fluid flows through the regions of least flow resistance, contacting the oil and displacing it. Thus, oil recovery is achieved within the shortest period.
2) When the produced gas (displacing fluid)/oil ratio approaches levels that are too high for the process to be economical, an aqueous slug comprising the mixed surfactant system, such as 0.5 wt. % of each of the surfactant foaming agent and a lignosulfonate foaming agent is injected. This slug will again preferentially flow through those regions of the reservoir where resistance of flow is least, where most of the oil was recovered as in step 1. The size of the aqueous slug is about 5% of the total pore volume.
3) Injection of the displacing fluid is resumed. Initially, the displacing fluid will flow through those portions of the reservoir where resistance to flow is least, or regions of high permeability. There the displacing fluid will disperse throughout the aqueous slug and generate foam. As more foam is generated, the resistance to flow increases in these regions of high permeability. Consequently, the displacing fluid is forced to flow through regions of lower permeability and displace additional quantities of oil. During the execution of this step, the size of the displacing fluid slug depends on the displacing fluid itself, as well as on the reservoir size, well spacings, reservoir fluids saturations and properties, and reservoir and rock properties.
4) Steps two and three may be repeated as frequently as deemed necessary, until the economics of the process become unfavorable.
References:
1) Sweep improvement in enhanced oil recovery
http://www.patentstorm.us/patents/4703797-description.html
Accessed on: 28th
June, 2007
2) Foams can be effective in the presence
of oil! By Laurier L. Schramm
Accessed
on: 28th June,
2007
3) Foams for Improved Oil Recovery
Accessed
on: 28th June,
2007
4) Foam for Mobility Control in Enhanced Oil Recovery Processes
Using Surfactants
Accessed
on: 28th June,
2007
5) Liu.Y., Grigg.R.B., R.K. Svec.: “Foam Mobility and adsorption in
carbonate core”, 2006
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