US20090194278A1

US20090194278A1 - Enhanced Oil Recovery In Oxygen Based In Situ Combustion Using Foaming Agents

Info

Publication number: US20090194278A1
Application number: US12/366,990
Authority: US
Inventors: Errico De Francesco
Original assignee: LAir Liquide SA pour lEtude et lExploitation des Procedes Georges Claude
Current assignee: LAir Liquide SA pour lEtude et lExploitation des Procedes Georges Claude
Priority date: 2008-02-06
Filing date: 2009-02-06
Publication date: 2009-08-06
Also published as: CA2653099A1

Abstract

An in situ combustion process is utilized to extract hydrocarbons from a subterranean oil formation. The process includes injecting a foaming agent solution into the formation via an injection well that penetrates the oil formation, injecting an oxygen containing gas into the formation via the injection well and facilitating a combustion reaction between oxygen and hydrocarbons within the formation. The combustion gases formed by the combustion reaction force the flow of hydrocarbons within the formation. Hydrocarbons that are displaced within the formation are extracted from the formation via a production well that penetrates the formation.

Description

CROSS REFERENCE TO RELATED APPLICATION

This application claims the benefit of U.S. Provisional Application No. 61/026,589 filed Feb. 6, 2008 the entire contents of which are incorporated herein by reference.

BACKGROUND

1. Field
The disclosure pertains to an enhanced oil recovery process from subsurface earth formations utilizing an in-situ combustion process.
2. Related Art
According to current estimates, unconventional heavy oil reserves alone can be utilized to satisfy global oil demands for about twenty years. Different techniques have been suggested and implemented for in-situ extraction of extra heavy oils and bitumen from hydrocarbon bearing formations such as the Oil Sands reservoirs in Alberta, Canada and the Orinoco Belt in Venezuela.
One exemplary in-situ extraction technique is referred to as steam assisted gravity drainage, or SAGD. The SAGD technique utilizes steam within a configuration of two horizontal wells, where one well is for steam injection and the other well facilitates bitumen extraction. The steam heats the subsurface formation, which in turn decreases the viscosity of bitumen so it can flow into the production well. The main drawbacks of the SAGD process are a high steam to oil ratio (SOR) that is required, the sensibility to reservoir heterogeneities, and a potentially larger gas to bitumen extraction particularly related to the growth of the steam chamber in the presence of a gas cap.
Another process is a vapor extraction process which involves the injection of a gaseous hydrocarbon solvent (e.g., propane, butane or carbon dioxide) into an underground oil reservoir, where the solvent dissolves bitumen and allows it to flow and drain into a horizontal well for extraction. The drawbacks associated with this process are that there is very little oil recovery without heating of the solvent, and also that the solvent is typically very expensive which can render the process cost prohibitive.
Other in-situ extraction processes combine the use of solvents with steam, but these techniques can also be expensive (due to solvent losses during the process) and have certain disadvantages.
Extraction processes that have shown considerable promise relate to in-situ combustion (ISC) within a subterranean oil formation or reservoir, where an oxygen containing gas is injected via an injection well into the oil reservoir to oxidize some portion of the hydrocarbons present in the reservoir, which results in heating of the reservoir and a reduction in the viscosity of the bitumen to facilitate its extraction in a production well. In-situ combustion processes have many advantages over some of the other proposed enhanced oil recovery processes. However, one disadvantage with ISC processes is the potential for oxygen breakthrough from the oil reservoir into the production well.
It would be desirable to provide a safe method for utilizing ISC to enhance oil recovery, where the oxygen permeability is limited within the oil reservoir to reduce the risk of breakthrough into the production well so as to enhance the longevity of the process and the amount of oil which can be produced from the reservoir.

SUMMARY

A method is provided for removing hydrocarbons disposed within a subterranean oil containing formation, where the formation is penetrated by at least one injection well to facilitate injection of fluids into the formation and the formation is further penetrated by a production well to facilitate extraction of fluids from the formation. The method comprises injecting a foaming agent solution into the formation via the at least one injection well, injecting an oxygen containing gas into the formation via the at least one injection well and facilitating a combustion reaction between oxygen and hydrocarbons within the formation, where combustion gases formed by the combustion reaction enhance a flow of hydrocarbons within the formation toward the production well, and extracting hydrocarbons from the formation via the production well.
The method can include a number of different features including, without limitation, any one or combination of the following features:

- the foaming agent solution comprises at least one polyglucoside compound (for example, an alkyl polyglucoside compound including an alkyl group having from about 4 to about 36 carbon atoms);
- the foaming agent solution comprises at least one compound selected from the group consisting of alkyl sulfates, alkoxy sulfates, alkyl sulfonates, alkoxy sulfonates, aromatic sulfonates, alkyl aromatic sulfonates, organosilicone compounds, polypeptide compounds, and carboxylic acid compounds having at least 10 carbon atoms;
- injecting steam into the formation via the injection well prior to injection of the oxygen containing gas into the formation;
- the amount of foaming agent solution injected into the formation is from about 0.1% to about 5% by weight of steam injected into the formation;
- at least some foaming agent solution is injected into the formation prior to injection of the oxygen containing gas into the formation;
- at least some foaming agent solution is co-injected with oxygen containing gas into the formation;
- co-injecting the oxygen containing gas into the formation with at least one of water and steam; and
- injection of water, steam, and foaming agent solution into a single injection well or in two or more injection wells.

Utilizing an in-situ oxygen based combustion method combined with one or more foaming agents (e.g., a polyglucoside compound) for hydrocarbon recovery improves the use and efficiency of oxygen being injected into the reservoir while minimizing or preventing breakthrough of oxygen from occurring within the production well.
The above and still further features and advantages will become apparent upon consideration of the following detailed description of specific embodiments thereof particularly when taken in conjunction with the accompanying drawings wherein like reference numerals in the figures are utilized to designate like components.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic diagram of an oil well employing an in situ combustion process in which oxygen is injected within the oil reservoir to facilitate the extraction of hydrocarbons in a production well.

FIG. 2 is a schematic diagram of a portion of an oil reservoir including the injection well portion when utilizing a conventional in situ combustion process.

FIG. 3 is a schematic diagram of another oil well employing an in situ combustion process in which oxygen is injected within the oil reservoir via a first injection well and water with foaming agent is injected in a second injection well to facilitate the extraction of hydrocarbons in a production well.

FIG. 4 is a schematic diagram of a portion of an oil reservoir including the injection well portion when utilizing an in situ combustion process combined with the use of foaming agents.

FIG. 5 is a plot of oil saturation vs. use of oxygen (and oxygen content in the production well) data for a conventional in situ oil extraction process where no foaming agent is used.

FIG. 6 is a plot of projected oil saturation vs. use of oxygen (and oxygen content in the production well) data for an in situ oil extraction process in which a foaming agent is injected with an oxygen containing gas into the reservoir in a manner as described herein.

FIG. 7A is a microphotograph of simulated oil sand (without any additive) after performance of the Blaine Permeability Test.

FIG. 7B is a microphotograph of simulated oil sand (with Na alkyl sulfonate additive) after performance of the Blaine Permeability Test.

FIG. 7C is a microphotograph of simulated oil sand (with Simulsol SL8) after performance of the Blaine Permeability Test.

DETAILED DESCRIPTION

As noted above, in situ combustion (ISC) is a useful technique for recovering hydrocarbons in subterranean oil-containing formations or reservoirs, where oxygen is injected into the oil reservoir to facilitate combustion therein. This process is particularly useful for extracting hydrocarbons in reservoirs containing oil too viscous or “heavy” to be forced through the reservoir into a production well utilizing other extraction techniques. Oxygen is injected into the reservoir at some suitable injection point distanced from the production well so as to facilitate combustion and burning of the oil in situ within the reservoir. A “combustion zone” is established within the oil reservoir which begins at a location proximate the injection point and advances toward the production well, providing a heated gas driving force that reduces the viscosity of bitumen and other heavy hydrocarbons within the reservoir and forces these hydrocarbons toward and into the production well for extraction from the reservoir.
An exemplary in situ combustion process is schematically depicted in FIG. 1. An oil reservoir 2 includes an injection well 4 which is spaced a suitable location from a production well 6 that extracts oil from the reservoir. Each of the injection well 4 and production well 6 includes a suitable conduit or piping that is embedded into the ground to a suitable location within the oil reservoir so as to provide a fluid pathway between the reservoir and an above ground location. A supply of air or oxygen (e.g., an air compressor) is connected with the injection well 4 to facilitate injection of oxygen at a suitable flow rate into the oil reservoir. At the start of the process, a heater or ignition device can be provided within the injection well as oxygen is injected to initiate combustion of hydrocarbons within the reservoir. Upon achieving combustion, the heater or ignition device can be removed. The production well 6 includes any suitable production equipment that facilitates extraction of oil from the reservoir through the well.
A combustion zone is formed by the ignition of hydrocarbons in oxygen, where hydrocarbons within the combustion zone are burned to generate heated gases and/or steam (depending upon the water content within the oil reservoir) that force the heavy oil in the direction toward the production well. Oil reaching the production well is extracted from the reservoir and withdrawn to the earth surface via the production well. Thus, the gases in the combustion zone facilitate movement or a “sweeping” of the heavy oils in the reservoir toward the production well.
As further noted above, one potential problem that exists with in situ combustion techniques for oil extraction is penetration or breakthrough of the combustion zone from the oil reservoir into the production well. This can lead to a flammable and potentially dangerous condition within the production well, where hot combustion gases from the combustion zone combine with oil being extracted and delivered to the earth surface.
Another problem is the reduction in oxygen utilization efficiency, particularly in reservoirs having lower oil saturations and/or higher levels of permeability. In such reservoirs, the injected oxygen will typically flow into more porous areas within the reservoir, reducing the sweep effect and efficient use of oxygen to force hydrocarbons toward the production well. An example of this is schematically depicted in FIG. 2, Oxygen gas (e.g., air) is delivered into the reservoir 2 as shown in FIG. 2 via injection well 4, with sweep zones forming along the outer, more porous portions of the reservoir (as shown by arrows 10). The sweep zones basically form “short cuts” through the more porous regions within the oil reservoir, leaving the more dense and viscous central regions intact and not swept by the heated gases. Thus, the injected oxygen tends to follow the swept and more permeable areas within the reservoir rather than displacing the more dense and less permeable unswept hydrocarbon regions toward the production well. The potential for breakthrough of the heated gases into the production well is also increased, since the oxygen penetrates further within the reservoir toward the production well rather than fully forcing or displacing a major portion of the hydrocarbons in the direction toward the production well.
Oxygen efficiency and the reduced potential and risk of oxygen breakthrough using in situ combustion is achieved in accordance with the invention by injecting one or more suitable foaming agents in addition to a gas comprising oxygen into the subterranean oil formation or reservoir. In particular, a foaming agent solution can be injected into the oil reservoir (via the injection well) prior to and/or during oxygen injection (i.e., co-injected with the oxygen containing gas) so as to reduce the mobility of oxygen within already swept zones and/or porous regions of the reservoir. The foaming agent solution fills in and occupies the spaces or porous sections of the reservoir, thus preventing or substantially minimizing oxygen and/or heated gases from seeping into such porous sections and diverting the flow of oxygen and heated gases from higher permeability (e.g., porous or swept) zones into denser and lower permeability (e.g., unswept) zones.
Suitable foaming agents solutions that can be injected within the reservoir can include any one or combination of surfactants. Exemplary surfactants suitable for use in the methods described herein include can be ionic and/or non-ionic surfactants that provide foaming formations (e.g., when utilized with water or steam) including, without limitation, alkyl or alkoxy sulfates such as ethoxy sulfates and propoxy sulfates (e.g., hydrocarbons with ethoxylated or propoxylated sulfate head groups), alkyl and/or alkoxy sulfonates, aromatic and/or alkyl aromatic sulfonates (e.g., toluene sulfonates), and organosilicone compounds.
Preferred surfactants that are suitable for the foaming agent solutions are polyglucoside compounds. Alkyl polyglucoside compounds including straight and/or branched chain alkyl groups (e.g., saturated alkyl groups) can be useful as surfactants. The alkyl group in the alkyl polyglucoside compound can have from about 4 to about 36 carbon atoms. In particular, alkyl polyglucoside compounds having the following formula are considered to be effective as foaming agents for in situ combustion oil extraction processes:
CH₃—(CH₂)_n—O-(G)_x-H
where:

- G is a residue of glucose (C₆H₁₀O₅);
- X is from 1 to 5; and
- N is from 4 to 36.

Examples of alkyl polyglucoside compounds that are useful as surfactants for enhancing an in situ combustion include such compounds as are provided under the tradename Simulsol and commercially available from Seppic Inc. (New Jersey). In particular, the following Simulsol compounds are considered effective for in situ oil extraction processes: a composition comprising n-octyl polyglucoside and n-decyl polyglucoside (including linear and saturated alkyl chains, CAS number 68515-73-1) and sold under the tradename Simulsol SL8; a composition comprising undecyl polyglucoside (including ramified and saturated alkyl chains, CAS number 98283-67-1) sold under the tradename Simulsol SL 11W; and a composition including undecyl polyglucoside, n-dodecylpolyglucoside, n-tetradecylpolyglucoside and n-hexadecylpolyglucoside (including ramified and linear saturated alkyl chains, CAS numbers 110615-47-9 and 132778-08-6) sold under the tradename Simulsol SL55. The polyglucoside compounds are preferred for use as surfactants since they are more stable in their use with oxygen and are further more environmentally friendly in comparison to other, conventional surfactants.
In addition, a solution combining one or more surfactants with one or more polypeptides can be provided to achieve an effective foam-forming mixture. Further, fatty acid salts (e.g., carboxylic acids having at least 10 carbon atoms, preferably carboxylic acids having 10-24 carbon atoms) can be also used as suitable foaming agents for injection in the reservoir.
Water or steam can also be provided in the reservoir with the foaming agents to enhance the effectiveness of oxygen utilization and displacement of hydrocarbons within the reservoir toward the production well. The oxygen can be provided at any suitable concentrations within a carrier gas. For example, an oxygen containing gas can be provided as substantially oxygen (e.g., the oxygen containing gas having an oxygen content of 90% by volume or greater). Alternatively, air can be provided with a selected oxygen content (e.g., 20% by volume or greater). The oxygen containing gas can also be provided including oxygen with a suitable inert gas (e.g., nitrogen and/or carbon dioxide).
In an exemplary method of utilizing in situ combustion with foaming agents in accordance with the invention, an oil reservoir is prepared for production by drilling the injection well and the production well sites at suitably spaced locations from each other (as schematically depicted in FIG. 1), with appropriate equipment placed at these locations to facilitate injection of oxygen into the injection well and extraction of hydrocarbons from the production well. Steam or water can initially be injected within the injection well to initiate fluidizing (by thermal flooding) of the bitumen and other heavy hydrocarbons within the reservoir. Alternatively, or in addition to injection of steam of water prior to oxygen injection, steam or water can be co-injected with an oxygen containing gas into the oil reservoir.
A foaming agent solution (e.g., comprising any one or combination of the surfactants, polypeptides and fatty acids as described above) is injected into the reservoir via the injection well. The amount of foaming agent solution to be provided will depend upon a particular process and the state of the oil reservoir being processed. Exemplary amounts of foaming agent solution to be injected into the reservoir range from about 0.1% to about 5% by weight, preferably from about 1.5% to about 3% by weight, in relation to an amount of steam injected into the reservoir.
An oxygen containing gas (e.g., air) is also injected into the reservoir via an injection well. The oxygen containing gas can be co-injected (i.e., injected at about the same time) with the foaming agent solution and/or water or steam, However, a preferable method is to inject the oxygen containing gas separately from the foaming agent solution. When using the same injection well (e.g., using the oil well system with single injection site as depicted in FIG. 1), the foaming agent solution (comprising water and/or steam and also one or more surfactants and/or other foaming agents as described above) and oxygen containing gas are injected in pulses, plugs or cycles within the injection well. For example, the process can include the following process steps: (1) injecting the oxygen containing gas into the reservoir via the injection well for a selected period of time, and then ceasing flow of the oxygen containing gas within the injection well; (2) injecting the foaming agent solution into the reservoir via the same injection well for a selected period of time, and then ceasing flow of the foaming agent solution into the injection well; and (3) repeating steps (1) and (2) for a selected number of cycles.
In another embodiment, two or more injection wells may be utilized, such as is depicted in FIG. 3. In particular, the in situ combustion process of FIG. 3 is similar to that depicted in FIG. 1, with the exception that two injection wells 4-1 and 4-2 provide a fluid flow path between the reservoir and an above ground location. The two injection wells 4-1 and 4-2 are separate from each other and facilitate separate injection of the oxygen containing gas and the foaming agent solution within the reservoir. In this embodiment, a continuous or periodic flow of the oxygen containing gas can be provided to the reservoir via injection well 4-1, while a continuous or periodic flow of the foaming agent solution can be provided to the reservoir via injection well 4-2.
As noted above, an air compressor or other suitable oxygen containing gas supply source is connected with an injection well (e.g., the injection well 4 depicted in FIG. 1, or injection well 4-1 depicted in FIG. 3) to provide the desired amount of oxygen within the reservoir. The amount of oxygen containing gas and concentration of oxygen in the oxygen containing gas to be provided to the reservoir will depend upon a number of factors, including the amount and types of oil and/or other carbonaceous species to be extracted from the reservoir. For example, the amount of oxygen injected in the reservoir can be from about 10 kg to about 90 kg, preferably from about 35 kg to about 70 kg, per barrel of oil (about 159 liters) to be recovered from the production well. The oxygen concentration in the oxygen containing gas can also be modified during the process so as to initially include about 20% or more oxygen (by volume), where the oxygen content is continuously increased during the oil production process (at any selected rate) to concentrations as high as about 95% to about 99.5% (by volume).
The amount of foaming agent solution to be provided in the reservoir will depend upon a number of factors, including the amount of oxygen that is provided within the reservoir. For example, the ratio (by mass) of foaming agent solution to oxygen to be provided within the reservoir can be in the range of about 1:4.
As noted above, a heater or ignition device can be provided within the injection well or at some suitable location underground within the reservoir to facilitate ignition and combustion of hydrocarbons in the presence of oxygen. The preferred temperature within the reservoir is from about 250° C. to about 600° C. to ensure adequate combustion of the oxygen is occurring within the reservoir. The heater or ignition device can be used to control the initial temperature at the beginning of the process for achieving a desired combustion of oxygen. A combustion zone is formed by the combusted and heated gases and/or steam, which heats the bitumen and heavy hydrocarbons to reduce their viscosity and force or “sweep” such hydrocarbons toward the production well.
An exemplary embodiment of FIG. 4 shows an oil reservoir near an injection well that is similar to the reservoir depicted in FIG. 2. In the embodiment of FIG. 4, an injected foaming agent solution is provided within the oil reservoir utilizing the method as described above.
Foaming agent solution 12 (shown in FIG. 3) penetrates and effectively plugs or fills the outer, porous sections and/or swept areas of the reservoir. This in turn reduces the mobility of the injected oxygen containing gas within such porous regions of the reservoir and results in the injected oxygen, combustion gases and steam being diverted toward the central portion of the reservoir, so as to force or displace the denser and previously unswept regions of hydrocarbons within the reservoir toward the production well. The foaming agent solution plugs the porous and high permeability regions, cutting off the “short cuts” or less dense pathways for oxygen flow, which results in an increase in the amount of displaced or “swept” hydrocarbons within the reservoir (rather than the formation of long and narrow swept zones that penetrate through the reservoir).
Utilizing foaming agent solutions as described above significantly enhances oil recovery when utilizing an in situ combustion process, since the injected oxygen is utilized more efficiently by being diverted to denser areas having lower permeability within an oil reservoir rather than flowing to the higher permeable locations (i.e., already swept and/or porous regions). This further slows the injected gas flow through the oil reservoir and reduces the potential for breakthrough of the sweeping gas into the production well.
The enhancing effect of using a foaming agent solution for in situ combustion in oil recovery techniques can be seen by a comparison of the two charts depicted in FIGS. 5 and 6. A plot is depicted in FIG. 5 of oil saturation (i.e., mass concentration of oil in reservoir) vs. use oxygen use, where the left hand side of the chart depicts oxygen use efficiency (i.e., amount of oxygen consumed) and the right hand side of the chart depicts oxygen concentration within the production well. The data from this chart was determined from a conventional in situ oil extraction process where no foaming agent is used. A similar plot of oil saturation vs. oxygen use efficiency is depicted in FIG. 6 for an in situ oil extraction process in which a foaming agent is injected with an oxygen containing gas into a reservoir in accordance with the invention.
As can be seen from the data plotted in both charts of FIGS. 5 and 6, the risk of flammability or an unsafe condition is established when the oxygen content within the production well is at about 20-22%. Comparing the data in both charts, it can be seen that the in situ combustion process utilizing a foaming agent solution will result in a lower oil saturation within the reservoir at the point at which the oxygen content within the production well reaches an unsafe level. Thus, using the foaming agent solution results in a more efficient use of oxygen and enhanced recovery of oil from the reservoir, which provides a larger domain of safe operation during the oil extraction process.
The curves plotted in FIG. 6 further show the additional enhancement provided by increasing the amount of foaming agent solution provided in the reservoir, where the swelling of each curve in an outward direction (i.e., swelling upward for the higher curve and swelling downward for the lower curve) is the result of increasing the amount of foaming agent solution (e.g., from no foaming agent solution to a selected concentration level in relation to the amount of oxygen injected into the reservoir). As can be seen from the plots in FIG. 6, the enhancement of the oil recovery process can be optimized by increasing the foaming agent solution within the reservoir to an effective amount during the in situ combustion oil recovery process.
The oxygen-foaming agent in situ combustion (ISC) methods described herein are also useful in enhancing other oil recovery techniques, such as steam assisted gravity drainage (SAGD) or other steam extraction techniques. For example, an oxygen-foaming agent ISC method can be used as a secondary or tertiary oil recovery technique utilized in combination with steam or other oil recovery techniques to enhance the amount of hydrocarbons recovered from a subterranean formation or reservoir.

EXAMPLES

A Blaine permeability test was performed on simulated oil sands for three conditions: oil sand without any additive, oil sand with Hostapur SAS60 Na alkyl sulfonate additive, and oil sand with SIMULSOL SL8 additive (a composition comprising n-octyl polyglucoside and n-decyl polyglucoside (including linear and saturated alkyl chains, CAS number 68515-73-1). The M2 and M3 times were recorded and specimens of the oil sands were observed after performance of the test.
Simulated oil sand was prepared by blending 7.5% water, 77.5% sand, and 15% bitumen. The oil sand water was prepared from reagents to simulate the water found in the Alberta Oil Sands Reservoirs (final properties found in Table I). The sand was Millisil E1 sand milled through a SIFRACO mill (properties found in Table II). The bitumen properties are found in Table III.

TABLE I

Water Properties

			Reconstituted
		Concentration	Water
Analyte	Reading	(mol/L)	Composition (g/L)

pH

7.72

9.9

SO₄(ppm)	77.9	8.12 × 10⁻⁴	Na₂SO₄	0.12
chloride (ppm)	5.97	1.68 × 10⁻⁴	NaCl	0.22
total hardness (ppm	344.3		CaCO₃	0.35
CaCO₃)

total iron (ppm Fe)	2.94	0.53 × 10⁻⁴	—
sodium (ppm Na)	105.8	4.6 × 10⁻³	—

TABLE II

Sand Properties

	Concentration

Chemical Analysis

SiO2

>99.7%

	Fe2O3	180	ppm
	Al2O3	1600	ppm
	TiO2	150	ppm
	CaO
100	ppm
	K2O	99	ppm
Initial Granulometry	D50	98	μm
	D10	241	μm
	D90	17	μm

* corresponds to an average average pore size of 80-100 μm

TABLE III

Bitumen Properties
Heavy Crude

density (g/cm³) at 21° C.

0.889

Composition w/w	saturated fraction	34.5
	aromatic fraction	47.1
	resinous fraction	10.5
	asphaltene	7.9

Performance of the Blaine Permeability Test yields the data shown in Table IV. In comparison to no additive, one can see that the use of Simulsol SL8 greatly increases the resistance to permeability of the gases through the oil sands.

TABLE IV

Blaine Permeability Test Results

		Initial	Final
Product	Duplicate	Permeability	Permeability

no additive	A	M2 = 4 s	M2 = 1 s
		M3 = 23 s	M3 = 4 s
	B	M2 = 9 s	M2 = 3 s
		M3 = 45 s	M3 = 15 s
Hostapur	A	M2 = 4 s	M2 = 90 s
SAS60 Na alkyl		M3 = 21 s	M3 = 480 s
sulfonate	B	M2 = 3 s	M2 = 27 s
		M3 = 16 s	M3 = 117 s
Simulsol SL8	A	M2 = 4 s	M2 = >10 min
		M3 = 20 s	M3 = >10 min
	B	M2 = 10 s	M2 = 26 s
		M3 = 55 s	M3 = 120 s

Microphotographs of the oil sands after performance of the Blaine Permeability Test may be found in FIGS. 7A, 7B, and 7C. White spots on the grains of sand indicate localized removal of bitumen, while a light foamy appearance indicates widespread removal of bitumen. As seen in FIG. 7A, the presence of few white spots show that relatively little bitumen was removed in the absence of an additive. As seen in FIGS. 7A and 7B, a foamy appearance indicates that widespread bitumen removal from the sand grains occurred.
Having described novel enhanced oil recovery techniques utilizing in situ combustion with foaming agents, it is believed that other modifications, variations and changes will be suggested to those skilled in the art in view of the teachings set forth herein. It is therefore to be understood that all such variations, modifications and changes are believed to fall within the scope as defined by the appended claims.

Claims

1. A method of removing hydrocarbons disposed within a subterranean oil containing formation, wherein the formation is penetrated by at least one injection well to facilitate injection of fluids into the formation and the formation is further penetrated by a production well to facilitate extraction of fluids from the formation, the method comprising:

injecting a foaming agent solution into the formation via the at least one injection well;

injecting an oxygen containing gas into the formation via the at least one injection well and facilitating a combustion reaction between oxygen and hydrocarbons within the formation, wherein combustion gases formed by the combustion reaction enhance a flow of hydrocarbons within the formation toward the production well; and

extracting hydrocarbons from the formation via the production well.

2. The method of claim 1, further comprising:

injecting steam into the formation via the at least one injection well prior to injection of the oxygen containing gas into the formation.

3. The method of claim 1, wherein the amount of foaming agent solution injected into the formation is from about 0.1% to about 5% by weight of water and/or steam injected into the formation.

4. The method of claim 1, wherein the amount of foaming agent solution injected into the formation is from about 1.5% to about 3% by weight of water and/or steam injected into the formation.

5. The method of claim 1, wherein the foaming agent solution and oxygen containing gas are co-injected together into the formation.

6. The method of claim 1, wherein the foaming agent solution and oxygen containing gas are each injected into the formation via a single injection well.

7. The method of claim 1, wherein the injection of foaming agent solution and oxygen containing gas into the formation further comprises:

(a) injecting a selected amount of oxygen containing gas into the formation via the at least one injection well;

(b) after step (a); injecting a selected amount of foaming agent solution into the formation via the at least one injection well; and

(c) repeating steps (a) and (b) for a selected number of cycles.

8. The method of claim 1, wherein the foaming agent solution is injected into the formation via a first injection well and the oxygen containing gas is injected into the well via a second injection well.

9. The method of claim 1, wherein the foaming agent solution comprises a polyglucoside compound.

10. The method of claim 9, wherein the polyglucoside compound comprises an alkyl polyglucoside compound including an alkyl group having from about 4 to about 36 carbon atoms.