U.S. patent application number 14/150359 was filed with the patent office on 2014-07-10 for use of foam with in situ combustion process.
This patent application is currently assigned to Conocophillips Company. The applicant listed for this patent is Conocophillips Company. Invention is credited to David A. BROWN, Logan A. WARREN, Thomas J. WHEELER, Siluni L. WICKRAMATHILAKA.
Application Number | 20140190689 14/150359 |
Document ID | / |
Family ID | 51060109 |
Filed Date | 2014-07-10 |
United States Patent
Application |
20140190689 |
Kind Code |
A1 |
WARREN; Logan A. ; et
al. |
July 10, 2014 |
USE OF FOAM WITH IN SITU COMBUSTION PROCESS
Abstract
The present invention relates to a novel method of maintaining a
steady and/or proper water-gas ratio for the wet in situ combustion
process for oil recovery. In particular, the method comprises
mixing water with a foaming agent, or some other colloid capable of
generating foam, in addition to gas. The foam carries the water
through heated reservoirs more efficiently and prevents separation
from the gas. As such, more heat can be scavenged, thus an
increased amount of steam is generated and transferred to the oil
to increase its recovery.
Inventors: |
WARREN; Logan A.; (Houston,
TX) ; WICKRAMATHILAKA; Siluni L.; (Katy, TX) ;
BROWN; David A.; (Katy, TX) ; WHEELER; Thomas J.;
(Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Conocophillips Company |
Houston |
TX |
US |
|
|
Assignee: |
Conocophillips Company
Houston
TX
|
Family ID: |
51060109 |
Appl. No.: |
14/150359 |
Filed: |
January 8, 2014 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61750253 |
Jan 8, 2013 |
|
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|
Current U.S.
Class: |
166/261 |
Current CPC
Class: |
E21B 43/243 20130101;
E21B 43/166 20130101 |
Class at
Publication: |
166/261 |
International
Class: |
E21B 43/24 20060101
E21B043/24; E21B 43/16 20060101 E21B043/16 |
Claims
1. An in situ combustion method of recovery of hydrocarbons from a
subterranean oil containing formation penetrated by at least one
injection well and at least one production well, which comprises:
igniting the hydrocarbons to form a combustion front by injecting
oxygen-containing gas and heat into the formation through an
injection well; injecting a water through an injection well and in
contact with a fluid that is at least one of a foam, an aerosol, a
hydrosol, an emulsion and a colloidal dispersion and has a density
and viscosity to carry the water via buoyancy forces; and
recovering hydrocarbons and other fluids at a production well.
2. The method of claim 1, wherein the density of the fluid is
between 0.000598-0.0770 g/cm.sup.3 and the viscosity is between
0.0123-0.0216 cP.
3. The method of claim 1, further comprising injecting an agent
into the injection well to form the fluid in situ.
4. The method of claim 3, wherein said agent is a surfactant.
5. The foaming agent of claim 4, wherein the surfactant is chosen
from a group comprising alkyl benzene, aromatic sulfonates,
alpha/internal olefin, sulfonates, alkyl aryl sulfonates, alkoxy
sulfates or any combination thereof.
6. The method of claim 3, wherein said agent is an alkali-based
salt.
7. The foaming agent of claim 6, wherein the alkali-based salt is
chosen from a group comprising sodium carbonate, sodium
bicarbonate, sodium hydroxide, potassium carbonate, potassium
bicarbonate, potassium hydroxide, magnesium carbonate, calcium
carbonate or any combination thereof.
8. The method of claim 3, wherein said water containing said agent
is injected continuously.
9. The method of claim 3, wherein said water containing the agent
is injected into vertical or horizontal wells.
10. The method of claim 3, wherein said water containing said agent
is injected in a slug.
11. The method of claim 0, wherein said water comprises oilfield
brine, produced water, seawater, aquifer water, and riverwater.
12. The method of claim 1, further comprising injecting a
non-oxygen containing gas.
13. The method in claim 1, further comprising injecting hydrogen,
nitrogen, methane, hydrogen sulfide, propane, butane, natural gas,
flue gas, or any combination thereof, and wherein said
oxygen-containing gas is air, oxygen, carbon dioxide, carbon
monoxide, or any combination thereof.
14. An in situ combustion method of recovery of hydrocarbons from a
Steam Assisted Gravity Drainage (SAGD) depleted reservoir
penetrated by at least one injection well and at least one
production well, which comprises: igniting the hydrocarbons to form
a combustion front by injecting oxygen-containing gas and heat into
the formation through an injection well; scavenging heat from a
rock formation by injecting a water containing an agent to generate
a fluid that is at least one of a foam, an aerosol, a hydrosol, an
emulsion and a colloidal dispersion; and, recovering hydrocarbons
and other fluids at a production well.
15. An improved method of wet in situ combustion oil recovery, the
method comprising igniting oil in a formation to form a burning
front and injecting water behind said burning front to capture heat
and drive oil towards a production well, wherein the improvement
comprises injecting water behind said burning front and in contact
with a fluid that is at least one of a foam, an aerosol, a
hydrosol, an emulsion and a colloidal dispersion and has a density
and viscosity to carry the water via buoyancy forces.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is a non-provisional application which
claims benefit under 35 USC .sctn.119(e) to U.S. Provisional
Application Ser. No. 61/750,253 filed Jan. 8, 2013, entitled "USE
OF FOAM WITH IN SITU COMBUSTION PROCESS," which is incorporated
herein in its entirety.
FEDERALLY SPONSORED RESEARCH STATEMENT
[0002] Not applicable.
REFERENCE TO MICROFICHE APPENDIX
[0003] Not applicable.
FIELD OF THE INVENTION
[0004] The invention relates to methods of improving the
effectiveness of wet in situ combustion (ISC) processes to
accelerate oil production and particularly to an improved wet in
situ combustion process utilizing foam. Water containing a foaming
agent is injected along with an oxygen-containing gas to maintain a
consistent water-gas ratio, to facilitate water-reservoir rock
contact and to prevent separation of water and gas.
BACKGROUND OF THE INVENTION
[0005] Conventional oil reserves are preferred sources of oil
because they provide a high ratio of extracted energy over energy
used in regards to the extraction and refining processes it
undergoes. Unfortunately, due to the physics of fluid flow, not all
conventional oil can be produced. Additionally, as conventional oil
sources become scarce or economically non-viable due to depletion,
unconventional oil sources are becoming a potential supply of oil.
But, unconventional oil production is also problematic because it
consists of extra heavy oils having a consistency ranging from that
of heavy molasses to a solid at room temperature and may also be
located in the reservoir rocks. These properties make it difficult
to simply pump the oil out of the ground; thus, its production is a
less efficient process than convention oil.
[0006] As a result, enhanced oil recovery (EOR) techniques are
often employed to increase the amount of subterranean crude oil
extracted. Using EOR, 30-60% or more of the original oil can be
extracted. Additionally, EOR finds applications in both
conventional and unconventional oil reserves.
[0007] During EOR, compounds not naturally found in the reservoir
are injected into the reservoir in a well other than the producing
well to assist in oil recovery. Simply stated, EOR techniques
overcome the physical forces holding the oil hydrocarbons
underground. There are many types of EOR techniques that are
categorized by the compound being injection: gas injection,
chemical injection, microbial injection or thermal recovery. While
there are many types of EOR techniques, reservoirs containing
heavier crude oils tend to be more amenable to thermal EOR methods,
which heat the crude oil to reduce its viscosity and thus decrease
the mobility ratio. The increased heat reduces the surface tension
of the oil and increases the permeability of the oil. A summary of
various EOR techniques is presented in Table 1.
TABLE-US-00001 TABLE 1 Enhanced Oil Recovery (EOR) Techniques CSS
Cyclic Steam Stimulation or "huff and puff." Steam is injected into
a well at a temperature of 300-340.degree. C. for a period of weeks
to months. The well is allowed to sit for days to weeks to allow
heat to soak into the formation, and, later, the hot oil is pumped
out of the well for weeks or months. Once the production rate falls
off, the well is put through another cycle of steam injection, soak
and production. This process is repeated until the cost of
injecting steam becomes higher than the money made from producing
oil. Recovery factors are around 20 to 25%, but the cost to inject
steam is high. SAGD Steam Assisted Gravity Drainage uses at least
two horizontal wells--one at the bottom of the formation and
another about 5 meters above it. Steam is injected into the upper
well, the heat melts the heavy oil, which allows it to drain by
gravity into the lower well, where it is pumped to the surface.
SAGD is cheaper than CSS, allows very high oil production rates,
and recovers up to 60% of the oil in place. VAPEX Vapor Extraction
Process is similar to SAGD, but instead of steam, hydrocarbon
solvents are injected into an upper well to dilute heavy oil and
enables the diluted heavy oil to flow into a lower well. ISC In
situ combustion involves a burning of a small amount of the oil in
situ, the heat thereby mobilizing the heavy oil. THAI Toe to Heel
Air Injection is an ISC method that combines a vertical air
injection well with a horizontal production well. The process
ignites oil in the reservoir and creates a vertical wall of fire
moving from the "toe" of the horizontal well toward the "heel",
which burns the heavier oil components and upgrades some of the
heavy bitumen into lighter oil right in the formation. COGD
Combustion Overhead Gravity Drainage is another ISC method that
employs a number of vertical air injection wells above a horizontal
production well located at the base of the bitumen pay zone. An
initial Steam Cycle similar to CSS is used to prepare the bitumen
for ignition and mobility. Following that cycle, air is injected
into the vertical wells, igniting the upper bitumen and mobilizing
(through heating) the lower bitumen to flow into the production
well. It is expected that COGD will result in water savings of 80%
compared to SAGD. EM A variety of electromagnetic methods of
heating oil in situ are also being developed. GAS A variety of gas
injection methods are also used or being developed, including
INJECTION the use of cryogenic gases. COMBO Any of the above
methods can be used in combination.
[0008] One technique less commonly used is in situ combustion
(ISC), which involves the oxidative generation of heat within the
reservoir itself. During a dry in situ combustion (FIG. 1), an
oxygen-containing gas such as air is injected into an underground
oil reservoir and burned with part of the hydrocarbons to create
heat. The fire can be started by either lowering an incendiary
device, such as a phosphorus bomb or a gas burner, into the well,
or the injection of a large amount of air can cause spontaneous
combustion. Once burning, large volumes of air, or other oxygen
source gas, must be continually injected into the reservoir to
sustain the fire. This combustion reaction also creates steam that,
along with light hydrocarbons, condenses and releases heat to the
nearby oil. During ISC, a frontal advance containing different
layers of combustion gases, steam, and heated oil is created. This
frontal advance acts as a production drive, thus driving the heated
oil towards producing wells.
[0009] Fireflood projects are not extensively used due to the
difficulty in controlling the flame front and a propensity to set
the producing wells on fire. However, the method uses less
freshwater, produces 50% less greenhouse gases, and has a smaller
footprint than other production techniques. Thus, there is a
certain interest in further developing combustion based methods for
future use.
[0010] ISC can either be forward or reverse combustion. In forward
combustion, the fire and injected oxygen source gas originate at
the injection well. Thus, the gas flow, combustion front and oil
flow advance in the same horizontal direction towards the producing
well. In reverse combustion, the gas flow is counter-current to the
combustion front.
[0011] The main cost associated with dry ISC is the cost of
compression for the air injection system. Furthermore, the
effectiveness of this technique depends on the velocity and
stability of the frontal advance, as well as the heat generated
from the combustion. During the dry ISC process, as the oil is
produced, depleted volumes remaining in the reservoir rock are
primarily filled with air, steam and other gases resulting from the
combustion. The rock absorbs much of the energy resulting from the
heat of combustion reaction and heat of condensation of the steam.
Thus, this energy is wasted because it is not used to further
produce oil, resulting in inefficiencies in the dry ISC
process.
[0012] Other novel techniques have been developed to increase the
efficiency of EOR oil production through the use of liquids instead
of gases.
[0013] Water has also been utilized in dry ISC methods. A polymer
colloidal system mixed with water was used to transport ozone gas
into the reservoir.[1] This system allowed for quicker autoignition
of the dry ISC process.
[0014] Also, the injection of water for a wet in situ combustion
process (FIG. 2) has been found to improve oil production. In the
wet ISC process, water and an oxygen gas source are injected
together into the reservoir. The heat in the reservoir converts the
water into steam. The generated steam from the water combines with
the frontal advance to help drive the oil. Additionally, water aids
in scavenging the heat left in the reservoir rock after the
combustion front has advanced through. The water is heated by the
rock, which creates more steam that can condense in the burning
front and transfer heat to nearby oil, resulting in increased oil
production. The addition of injected water also reduces the gas
injection rates, thereby reducing compression costs seen in dry
ISC.
[0015] However, a disadvantage of the wet combustion process is the
difficulty in maintaining proper water-gas ratios. If water-gas
ratio is too low, then there is not enough water to effectively
recover all of the available energy in the reservoir rock. If the
water-gas ratio is too high, then there is too much water that is
not converted into steam and interferes with the combustion front
by cooling the temperature or extinguishing the combustion front.
Thus, an optimum water-gas ratio would effectively recover the
energy stored in the reservoir rock by converting the water to
steam, but not cool or quench the combustion front such that it is
extinguished. Furthermore, the proper ratio will all reduce the
amount of fuel needed, which decreases the gas requirements needed
to heat the oil.
[0016] Another disadvantage of the wet combustion process is the
separation of water and the gas in the reservoir. This separation
is also dependent on the water-gas ratio. If the water does not
travel horizontally or vertically through the reservoir to scavenge
the heat, then only gas will reach the combustion front, which will
essentially be a dry combustion. If there is too much water, then
the gas cannot travel through the reservoir to reach the combustion
front, thus potentially allowing water to extinguish the combustion
front. Also, because water is denser, it could cumulate at the base
of the reservoir and not reach hotter rock. As such, it is
imperative that a proper water-gas ratio is maintained for the
water and the as to travel together through the oil reserve for
optimal oil production efficiencies.
[0017] Finding the optimum water-gas ratio is difficult because the
reservoir heterogeneities and gravity override can affect the fluid
movement. Usually, water and gas injection rates are varied until a
reasonable water-gas ratio is found. The rates are then adjusted
throughout the wet ISC to maintain this ratio. This method produces
inconsistent results, nor is there a method to quickly determine
the proper ratio or injection rates.
[0018] U.S. Pat. No. 4,691,773 discloses a wet in situ combustion
method wherein a non-oxygen containing fluid, such as water, is
introduced along with air cyclically to produce periodic high
volume rates of injected fluid. However, both techniques can result
in over-injecting water and extinguishing the combustion front can
occur, leading to a loss of time and money to re-start the
process.
[0019] U.S. Pat. No. 7,882,893 discloses the use of surfactant,
salt brine and oxygen to create a foam during ISC. The foam
decreases the mobility of the displacing fluid (brine) in the
higher permeability zones and diverts more oxygen-containing gas
into the lower permeability zones. Thus, the foam prevents the
water from segregating from the oxygen gas. As the displacing fluid
evaporates from the foam, the foam breaks and becomes an
oxygen-rich steam and alkaline brine.
[0020] U.S.20090194278 discloses an ISC technique that uses a
surfactant-based foam that is injected with or prior to the oxygen
gas. The purpose of the foam is to increase the amount of oxygen
available for combustion and to control the mobility of the oxygen
through the already swept zones. The foam also prevents the heated
gas from seeping into porous sections of the reservoir.
Furthermore, water or steam can be mixed with the foam to enhance
the effectiveness of the oxygen utilization and displacement of
oil. The focus of this technique is the prevention of heat transfer
to the surrounding reservoir rock. It does not address the
possibility of scavenging heat.
[0021] Therefore, what is needed in the art is a better method for
maintaining water-gas ratios during the wet in situ combustion
process and scavenging heat from rocks after the combustion front
advances that also prevents separation of water and air.
SUMMARY OF THE DISCLOSURE
[0022] The present disclosure describes an improved wet ISC
technique to recover oil from depleted reservoirs. During wet ISC,
water containing a foaming agent, an oxygen-containing gas, and,
optionally, additional gases, are injected into a subterranean oil
containing reservoir. The foaming agent aids in maintaining a
consistent water-gas ratio and prevents separation of water and gas
as they move through the reservoir.
BRIEF DESCRIPTION OF THE DRAWINGS
[0023] FIG. 1 is a schematic depicting dry forward in situ
combustion.
[0024] FIG. 2 is a schematic depicting wet forward in situ
combustion
[0025] FIG. 3 is a schematic depicting foam-assisted wet forward in
situ combustion
DESCRIPTION OF EMBODIMENTS OF THE INVENTION
[0026] The disclosure relates to a heat scavenging method using an
agent for forming foams/aerosols/hydrosols/other emulsions or
colloidal dispersions. For conciseness hereafter hereafter, foaming
agent is used for exemplary purposes only given possibility of
creating the aerosols/hydrosols/other emulsions or colloidal
dispersions.
[0027] Generally, the invention provides an improved wet in situ
combustion process in which a foaming agent is injected together
with the water. The novel feature of this improved method is the
ability of the foam to carry water through the reservoir and
combustion zone. The foaming agent has a low density and viscosity,
which can efficiently carry water into overburden rock. The use of
such a foaming agent ensures proper water-to-oxygen-containing gas
ratios are maintained during wet in situ combustion by carrying
water throughout the reservoir. Consistent water-to-oxygen ratios
will allow for maximum heat scavenging and minimum combustion
quenching by the water. Another advantage of using foam to carry
water through the reservoir is an increase in contact between the
water and heated reservoir rock. This will create more steam, which
will heat the oil and allow for greater production of oil. The foam
will also prevent the water from pooling.
[0028] Additionally, the foam will also prevent the water and gas
from separating in the reservoir, thus preventing a dry ISC
process. Additionally, the foam can also contain oxygen, which will
help in providing a consistent amount of oxygen to the combustion
front.
[0029] In a preferred embodiment, the oxygen-containing gas is air.
Further preferred embodiments include generating foam on the
surface before injection into the subterranean oil formation.
[0030] In one embodiment, the water being mixed with the foaming
agent is brine water recovered from the reservoir being treated.
Alternatively, surface water or sea water can be used.
[0031] In another embodiment, the foaming agent contains oxygen,
which will aid in maintaining a consistent amount of oxygen at the
combustion front.
[0032] In yet another embodiment, the water and foaming agent are
injected some time after the oxygen-containing gas and optional
additional gases have been injected into the subterranean
formation.
[0033] In the present disclosure, the foaming agent can generate
foam on the surface before injection into the oil formation. In
another variation, the foaming agent can generate foam in situ in
the subsurface after injection into the oil formation.
[0034] The invention also describes the use of the above methods to
recover more oil from steam assisted gravity drainage (SAGD)
depleted reservoirs.
[0035] The foaming agent can include, but is not limited to, other
colloidal foams, aerosols, hydrosols, emulsions, or dispersions
capable of creating a suitable foam. Preferred foam components have
thermal and chemical properties that are stable at the high
temperatures (>200.degree. C.) used in ISC and should have low
adsorption onto reservoir rock/clay surfaces. Additionally, the
foaming capabilities should be effective at the particular
reservoir brine pH. Thus, the foaming agent can be any foaming
agent that is stable under reservoir conditions, and increases the
transport of water, thus maintaining a consistent water-to-gas
ratio.
[0036] Foam agents can be surfactant- or alkali-based. Thermally
and chemically stable, non-ionic, anionic, cationic, and
amphoteric/zwitterionic surfactants including, but are not limited
to, alkyl benzene, aromatic sulfonates, alpha/internal olefin,
sulfonates, alkyl aryl sulfonates, and alkoxy sulfates can be used.
High alkyl chain lengths should be chosen since the efficiency of
foam generation increases with increases in chain length.
[0037] Examples of alkali-based components are alkaline metal
carbonates, bicarbonates and hydroxides, including but not limited
to, sodium carbonate, sodium bicarbonate, sodium hydroxide,
potassium carbonate, potassium bicarbonate, potassium hydroxide,
magnesium carbonate, and calcium carbonate.
[0038] Other agents that can be used are in other colloidal foams,
aerosols, hydrosols, emulsions, or dispersions which could create a
suitable and stable foam.
[0039] The chosen foaming agent will depend of the characteristics
of the reservoir. Because the foaming agent is being used to
increase the sweep efficiency of the water/gases, the foaming agent
should not react with the formation. For example, cationic and
amphoteric surfactants have strong interactions with sand
particles, thus they would not be ideal foaming agents for a sandy
reservoir. Interactions with reservoir formation will result in an
increase in concentration of foaming agent and will be cost
prohibited, or at least less cost effective.
[0040] The chosen foaming agent also depends on the water. High
salinity water can cause precipitation of surfactant molecules,
especially when high divalent ion concentrations are present.
Non-ionic surfactants and alkali-based surfactants are considered
to be more resistant to high salinity water.
[0041] Many high temperature surfactant- and alkali-based foaming
agents are commercially available from vendors such as BASF,
ChemEOR Inc., Down Chemical Company, Huntsman Corporation, OilChem
Technologies, Sasol and Tiorco.
[0042] The desired properties of the generated foam are densities
in the range of 0.000598-0.0770 g/cm3 and viscosities in the range
of 0.0123-0.0216 cP. The lightness of the foam enables it to
transport/lift the water and gas(es) being injected instead of
blocking the high permeability zones in the reservoir. This will
maintain the water-gas ratio as it moves through the reservoir.
[0043] The foam can be generated on the surface or sub-surface.
Sub-surface methods for generating foam include a static mixer
downhole, foam generation through a perforation in the well,
natural mixing in the well, in situ foam generation in the
reservoir or any combination thereof.
[0044] Additionally, the foaming agent/water mix can be injected at
the same time as the gas(es), or can be injected some time after
the gas(es) has been injected. Furthermore, the foaming agent/water
can be injected continuously or in slugs. Also, the foaming
agent/water can be injected into vertical or horizontal wells to
improve the wet ISC process, including both forward and reverse
combustion.
[0045] An oxygen-containing gas is injected to fuel the combustion
process in the reservoir. Typical gases include air, oxygen, carbon
dioxide, carbon monoxide or any combination thereof. An additional
non-oxygen containing gas can also be injected to fill in gas
drive, including hydrogen, nitrogen, methane, hydrogen sulfide,
propane, butane, natural gas, flue gas and any combination thereof.
Gases may be in a liquid form, a liquid/gas mixture, or gas
form.
[0046] As used herein, "oil," "crude oil," and "hydrocarbons" are
used interchangeable to describe the hydrocarbons remaining in oil
reservoirs after conventional drilling methods.
[0047] As used herein, "foaming agent" means an additive to water
used to generate foam either above the surface before injection or
sub-surface using a mechanical or natural mixing method. The
additive can include, but is not limited to, colloidal foams,
aerosols, hydrosols, emulsions, or dispersions.
[0048] As used herein, "oxygen-containing gas" or "oxygen source
gas" mean a gas containing oxygen and capable of igniting and
fueling the combustion front within the reservoir.
[0049] The use of the word "a" or "an" when used in conjunction
with the term "comprising" in the claims or the specification means
one or more than one, unless the context dictates otherwise.
[0050] The term "about" means the stated value plus or minus the
margin of error of measurement or plus or minus 10% if no method of
measurement is indicated.
[0051] The use of the term "or" in the claims is used to mean
"and/or" unless explicitly indicated to refer to alternatives only
or if the alternatives are mutually exclusive.
[0052] The terms "comprise", "have", "include" and "contain" (and
their variants) are open-ended linking verbs and allow the addition
of other elements when used in a claim.
[0053] The phrase "consisting of" is closed, and excludes all
additional elements.
[0054] The phrase "consisting essentially of" excludes additional
material elements, but allows the inclusions of non-material
elements that do not substantially change the nature of the
invention.
[0055] The following abbreviations are used herein:
TABLE-US-00002 ABBREVIATION TERM ISC In situ combustion SAGD Steam
assisted gravity drainage PSI Pounds per square inch
[0056] FIG. 1 depicts a dry forward ISC. Here, dry air is injected
into a reservoir to fuel the combustion process and help push the
combustion front towards the oil production well. Note that the
heat formed during the combustion process is absorbed by the
reservoir rock. Also, the heated oil bank, i.e. displaced oil, has
not traveled close to the oil production well.
[0057] In contrast, the addition of water to the air injection
results in the contact of water with heated reservoir rock, as
shown in FIG. 2. After contacting the heated rock, the water is
converted into steam and is pushed forward the water-air injection.
As the steam contacts cooler rock in the reservoir, it condenses
and transfers heat to the nearby oil. This additional heat results
in the heated oil bank travelling further towards the oil
production well then the dry forward ISC depicted in FIG. 1.
[0058] FIG. 3 depicts the present invention--use of a foaming agent
in the water. Here, the foaming agent helps carry the water into
the reservoir, thus facilitating increased contact with the heated
reservoir rock. Furthermore, the foam also prevents the water and
air from separating due to differences in density. As before, the
resulting steam heats the oil; however, the increased water/rock
contact has allowed water to scavenge more heat from the rock to
transfer to the oil. As such, the oil is able to move towards the
oil production well more efficiently than either a water-air
injection or air only injection.
[0059] The following references are incorporated by reference in
their entirety.
[0060] 1. Limkar, Parikshit S., "Novel In-Situ Combustion Technique
Using a Semi-Permeable Igniter Assembly," Society of Petroleum
Engineers, SPE 125583, 2009.
[0061] 2. Burger, Jacques G., Sahuquet, Bernard C., "Laboratory
Research on Wet Combustion," Journal of Petroleum Technology, 1973,
1137-46.
[0062] 3. Falls, Andrew H., Lawson, Jimmie B. and Hirasaki, George
J., "The Role of Noncondensable Gas in Steam Foams", Journal of
Petroleum Technology, January 1988.
[0063] U.S. Pat. No. 3,993,133
[0064] U.S. Pat. No. 3,994,345
[0065] U.S. Pat. No. 4,691,773
[0066] U.S. Pat. No. 7,882,893
[0067] U.S.20090194278
* * * * *