Method for controlling combustion gas output in direct steam generation for oil recovery

Abstract

An apparatus, system, and method for controlling combustion gas output in direct steam generation for oil recovery. A direct combustion steam generator burns a fuel and an oxygen-containing gas mixture to produce combustion products including steam, CO.sub.2 and N.sub.2. Supplemental oxygen is separately supplied to the combustion steam generator to adjust the oxygen content of the oxygen-containing gas mixture during the combustion process in order to adjust the ratio of CO.sub.2 to N.sub.2 produced in the combustion products.

Claims

1. A method of recovery of oil from a hydrocarbon-containing reservoir using steam, comprising: (a) delivering a fuel and an oxygen-containing gas mixture to a direct combustion steam generator at a pressure exceeding atmospheric pressure, wherein a portion of the oxygen-containing gas mixture is provided by a supply of air delivered to the combustion steam generator; (b) delivering a supply of supplemental oxygen to the combustion steam generator at a delivery pressure exceeding atmospheric pressure, wherein a portion of the oxygen-containing gas mixture is provided by said supplemental oxygen; (c) burning the fuel and the oxygen-containing gas mixture in the direct combustion steam generator to generate an effluent stream comprising combustion products in the form of CO.sub.2, and N.sub.2 and water in the form of steam; (d) sensing a presence of, or a quantity of, one or more of said combustion products, or a ratio of one of said combustion products to another of said combustion products, in said effluent stream; (e) regulating, via one or more flow regulators, and without said effluent stream being recirculated to said combustion steam generator, a rate of said supplemental oxygen supplied to the combustion steam generator relative to a rate of said air supplied to said combustion steam generator to thereby adjust oxygen content of the oxygen-containing gas mixture so as to produce said effluent stream having a desired composition of one or more of said combustion products in said effluent stream; and (f) injecting the effluent stream into an injection well in said reservoir.

2. The method according to claim 1, further comprising delivering a supply of water to the combustion steam generator to add additional steam to said effluent stream produced by the combustion steam generator.

3. The method according to claim 1, wherein the method of recovery of oil from the reservoir is steam assisted gravity drainage (SAGD).

4. The method according to claim 1, wherein the method of recovery of oil from the reservoir is Cyclic Steam Stimulation (CSS).

5. The method according to claim 1, further comprising delivering a supply of water to the combustion steam generator to adjust the quality of the steam generated by the combustion steam generator.

6. The method according to claim 1, further comprising delivering a supply of water onto an inner wall of the combustion steam generator to cool the temperature of the inner wall of the combustion steam generator.

7. The method according to claim 6, further when delivering said supply of water to the combustion chamber further adjusting the quality of the steam generated by the combustion chamber.

8. The method according to claim 1, wherein the air is further supplemented by the supply of supplemental oxygen to adjust the oxygen content of the oxygen-containing gas mixture to a level sufficient to produce a combustion product having a ratio of CO.sub.2 to N.sub.2 that enhances the steam assisted recovery of oil from the hydrocarbon-containing reservoir.

9. The method according to claim 8, further comprising delivering a supply of water to the combustion steam generator to add additional steam to said effluent stream produced by the combustion steam generator.

10. The method according to claim 8, further comprising delivering a supply of water onto an inner wall of the combustion steam generator to cool the temperature of the inner wall of the combustion steam generator.

11. The method according to claim 8, further comprising delivering a supply of water to the combustion steam generator to adjust the quality of the steam generated by the combustion steam generator.

12. The method as claimed in claim 1, wherein said step of sensing a presence of, or a quantity of, one or more of said combustion products, or a ratio of one of said combustion products to another of said combustion products in said effluent stream, comprises sensing a ratio of CO.sub.2 to N.sub.2 in said effluent stream.

13. The method according to claim 12, further comprising delivering a supply of water to the combustion steam generator to add additional steam to said effluent stream produced by the combustion steam generator.

14. The method according to claim 12, further comprising delivering a supply of water to the combustion steam generator to adjust the quality of the steam generated by the combustion steam generator.

15. The method according to claim 12, further comprising delivering a supply of water onto an inner wall of the combustion steam generator to cool the temperature of the inner wall of the combustion steam generator.

16. The method according to claim 15, further when delivering said supply of water to the combustion chamber further adjusting the quality of the steam generated by the combustion chamber.

17. The method according to claim 15, further when delivering said supply of water to the combustion chamber further adjusting the quality of the steam generated by the combustion chamber.

18. The method as claimed in claim 12, further comprising monitoring conditions of the reservoir to determine an optimum ratio of CO.sub.2 to N.sub.2 in said combustion products for optimum production of hydrocarbon from said reservoir, and adjusting said one or more flow regulators to maintain said optimum ratio.

19. The method according to claim 18, further comprising delivering a supply of water to the combustion steam generator to adjust the quality of the steam generated by the combustion steam generator.

20. The method according to claim 18, further comprising delivering a supply of water to the combustion steam generator to add additional steam to said effluent stream produced by the combustion steam generator.

21. The method according to claim 18, further comprising delivering a supply of water onto an inner wall of the combustion steam generator to cool the temperature of the inner wall of the combustion steam generator.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) These and other features of the invention will become more apparent in the following detailed description in which reference is made to the appended drawings.

(2) FIG. 1 is a schematic representation of a direct combustion steam generator for controlling combustion gas output in direct steam generation, according to embodiments of the present disclosure;

(3) FIG. 2 is a cross-sectional view of the direct combustion steam generator represented in FIG. 1, according to embodiments of the present disclosure;

(4) FIG. 3 is a schematic of the direct combustion steam generator illustrated in FIG. 1, applied to vertical well steam flood type enhanced oil recovery (EOR), according to embodiments of the present disclosure;

(5) FIG. 4 is a schematic of the direct combustion steam generator illustrated in FIG. 1, applied to horizontal well SAGD enhanced oil recovery (EOR), according to embodiments of the present disclosure; and

(6) FIG. 5 shows, in terms of control of the supply of air relative to the supply of pure or substantially pure oxygen, the relationship necessary to maintain stoichiometric (complete) combustion, and in particular the relationship between such two parameters followed in the Examples.

DETAILED DESCRIPTION OF THE INVENTION

Definitions

(7) Unless defined otherwise, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this invention belongs.

(8) As used herein, the term hydrocarbon-containing reservoir, refers to subterranean formations that are explored and exploited for hydrocarbon resources through drilling and extraction techniques.

(9) As used herein, the term about refers to an approximately +/10% variation from a given value. It is to be understood that such a variation is always included in any given value provided herein, whether or not it is specifically referred to.

(10) Steam injected into a hydrocarbon-containing reservoir facilitates heavy oil and bitumen flow in two waysreducing its viscosity by heating it, and increasing the pressure in the reservoir to help it flow. As the steam cools, however, it condenses back to a liquid state which results in a decline in pressure and inefficiency in production. Co-injection of a non-condensable gas with the steam can further enhance the oil recovery and compensate for this decline. For example, injected nitrogen (N.sub.2) gas can expand in the reservoir to create increased pressure that pushes or drives oil to a production wellbore. Other gases, such as CO.sub.2, are miscible in the oil i.e., dissolve in the oil, to further lower the viscosity of the oil and improve its flow rate.

(11) The combustion products derived from direct steam generation techniques can include N.sub.2 and/or CO.sub.2 depending on the burner oxidant used with the fuel. When fuels are burned with air, N.sub.2 forms part of the combustion product mixture, as illustrated by the exemplary equation using methane as the example fuel:
CH.sub.4+2O.sub.2+8N.sub.2.fwdarw.CO.sub.2+2H.sub.2O+8N.sub.2

(12) When combustion is carried out in pure oxygen (i.e. no air and thus absence of nitrogen), only CO.sub.2 and H.sub.2O are produced and provided to the effluent combustion stream, as illustrated by the below formula:
CH.sub.4+2O.sub.2.fwdarw.CO.sub.2+2H.sub.2O.

(13) The ratio of CO.sub.2 to N.sub.2 in the combustion products is controlled in the present invention by controlling the amount of pure oxygen in relation to the air input into the direct steam generator for combustion with the fuel. Typically, the required level of oxygen is provided as air, pure oxygen, or air with a pre-determined level of oxygen enrichment.

(14) In the prior art, there was little ability to adjust the ratio of CO.sub.2 to N.sub.2 within the produced combustion products, as the ratio of N.sub.2 to O.sub.2 in air is typically a fixed ratio of about 3.25:1, with normal air comprising 75.5% nitrogen gas (by weight) and 23.2% oxygen gas (by weight), namely a ratio of 3.25:1. Thus to maintain complete combustion (i.e., supply oxygen gas to the fuel in required stoichiometric relation) associated quantity of nitrogen was supplied to the steam generator in a fixed ratio. Thus any steam generation units having only air supply were not amenable to allow adjustment of the ratio of produced CO.sub.2 to N.sub.2 during enhanced oil recovery (EOR), and thus had no ability to optimize and vary, for a given well and given formation conditions, the amount of viscosity reduction (via CO.sub.2 injection) in relation to the amount of pressure increase provided by the injection of N.sub.2.

(15) More particularly, the phase behavior of the combustion gas mixtures and the heavy oil are strongly dependent on reservoir conditions such as temperature, pressure, and heavy oil composition. For example, in high pressure applications with lighter oils, CO.sub.2 is miscible with the oil, with resultant swelling of the oil, and reduction in viscosity, and possibly also with a reduction in the surface tension with the reservoir rock. In the case of low pressure reservoirs or heavy oils, CO.sub.2 will form an immiscible fluid, or will only partially mix with the oil. Some oil swelling may occur, and oil viscosity can still be significantly reduced. The ability to adjust the ratio of CO.sub.2 to N.sub.2 in response to the changing conditions of the reservoir can, therefore, be beneficial to the efficiency of EOR (enhanced oil recovery).

(16) In prior art methods, the manner of regulating the amount of CO.sub.2 to N.sub.2 injected in a formation has typically been through injection of either through a separate injector well. Drilling of a separate feeder well for injection of either of such gases was and is an expensive proposition, and an inexpensive and inefficient method to alter the proportion of CO.sub.2 to N.sub.2 being supplied to a formation.

(17) The embodiments of the present disclosure provide a system and method for controlling the combustion gas output in combination with steam generation and combined injection, which control simultaneously allows for not only injection of steam and CO.sub.2 to reduce viscosity of the oil but further allows for real-time adjustment of the ratio of CO.sub.2 to N.sub.2 ratio in response to the unique and sometimes changing pressure, temperature, viscosity, permeability, and porosity conditions of the reservoir.

(18) An embodiment of the present disclosure will now be described by reference to FIGS. 1 and 2, which show a schematic representation of a direct combustion steam generator of the present disclosure.

(19) Referring to FIGS. 1 and 2, a steam generator 1 of the present disclosure comprises a combustion container 10 having an inner wall defining a combustion chamber 15. The combustion container 10 includes a burner (not shown) for producing a flame 270 within the combustion chamber 15 for carrying out combustion of a fuel and an oxygen-containing gas mixture to produce combustion products that comprise steam, CO.sub.2, and N.sub.2. The combustion products exit the combustion chamber 15 through an outlet 50 at the opposite end of the combustion container 10 for injection into a hydrocarbon-containing reservoir, for example.

(20) Controlling Combustion Gas Output in Direct Steam GenerationReal-Time Oxygen Enrichment

(21) As discussed, when fuels are burned with air, only about 21% of the air, that is oxygen, is consumed in the combustion reaction, leaving about 79% of the air to remain as mostly inert N.sub.2 (by volume). When combustion is carried out in pure oxygen, on the other hand, only CO.sub.2 and H.sub.2O is the resulting combustion product. The ratio of CO.sub.2 to N.sub.2 in the combustion products can thus be controlled by the amount of oxygen input in relation to air which is input into the combustor for combustion with the fuel, which when water is further injected produces an effluent stream containing saturated or superheated steam and CO.sub.2, with the amount of N.sub.2 gas being variable for optimized control of pressurization of the formation in relation to CO.sub.2 being injected.

(22) As illustrated in FIGS. 1 and 2, the fuel and oxygen-containing gas enter the combustion container 10 and mix in a combustion area of the burner for the steam generator 1 and are ignited. Fuel is supplied through at least one fuel inlet 90 proximate the burner and configured to deliver the fuel to the burner at a delivery pressure exceeding atmospheric pressure. According to embodiments of the present disclosure, the fuel can be any hydrocarbon-containing mixture, for example heavy oil, methane, propane, natural gas liquids, and/or naphtha. In certain embodiments, the fuel supply is pressurized through a compressor.

(23) The composition of the oxygen-containing gas that combusts with the fuel will depend on the particular reservoir conditions and the desired levels of CO.sub.2 and N.sub.2 required for EOR. According to embodiments of the present disclosure, the steam generator 1 comprises at least one air inlet 100 proximate the burner and configured to deliver air to the burner at a delivery pressure exceeding atmospheric pressure. In certain embodiments, the air supply is pressurized through a compressor. According to embodiments of the present disclosure, as shown in FIG. 1, the fuel inlet 90 is fluidly connected to the air inlet 100 to deliver a mixture of fuel and air to the burner.

(24) The steam generator 1 further comprises at least one oxygen inlet 80 located proximate the burner and configured to separately deliver a supply of supplemental oxygen to the burner at a delivery pressure exceeding atmospheric pressure. As shown in FIGS. 1 and 2, the supplemental oxygen inlet 80 is configured to supply supplemental O.sub.2 to the burner after the fuel and air is injected into the burner. In this way, the supplemental oxygen can be controllably added throughout any particular combustion process to adjust the oxygen content of the oxygen-containing gas mixture as needed. Moreover, the supplemental O.sub.2 can be added in response to the changing conditions of the reservoir. The addition of supplemental O.sub.2 can, therefore, be controlled and added to a combustion process in real-time to adjust the composition of the combustion products produced.

(25) The O.sub.2 delivered through the oxygen inlet 80 can be supplied from commercial containers, or by pipeline, or in situations where feasible, can be prepared by a physically adjacent air separation unit. According to such embodiments, air enters an air separation unit to separate out O.sub.2 from other components of the air and to provide a compressed supply of O.sub.2 for delivery through the supplemental oxygen inlet 80. Air separation can be carried out by any number of techniques known in the art, for example, by cryogenic fractional distillation or by O.sub.2 pressure swing adsorption (PSA).

(26) According to embodiments of the present disclosure, as shown in FIG. 1, the air inlet 100, fuel inlet 90, and oxygen inlet 80 each comprise a control means to control the fluid flow into the burner. The control means can include, for example, any combination of a control valve 110, 140, 170, a flow meter 120, 150, 180, and/or a check valve 130, 160, 190. According to certain embodiments, each control means can be controlled by a programmable controller.

(27) By offering the ability to control the combustion gas output, the steam generator 1 of the present disclosure allows supplemental O.sub.2 to be added to the fuel at various concentrations. In certain embodiments, it may be desirable to input air as the oxygen-containing gas. In such embodiments, supplemental O.sub.2 is not input into the steam generator 1. In further embodiments, it may be desirable to input pure O.sub.2 as the oxygen-containing gas. In such embodiments, air is not input into the steam generator 1. The desired O.sub.2 content of the oxygen-containing gas can be determined at the discretion of the operator of any given EOR operation.

(28) In certain embodiments, supplemental O.sub.2 can be added in relation to the quantum of air supplied to increase the CO.sub.2 content in the effluent stream, under stoichiometric conditions (where no supplemental H.sub.2O is added for steam generation) from a minimum of 20% (by weight) with no supplemental oxygen added and only air being supplied, to a maximum of 65% (by weight) with substantially pure oxygen and no air being supplied, where for example propane is used as the fuel.

(29) Similarly and correspondingly, the ratio of air to supplemental O.sub.2 added to the fuel can be controlled to reduce the N.sub.2 content of the combustion gas output to anywhere from 72% N.sub.2 (by weight, using a weight ratio of 75.47 nitrogen/23.2 oxygen, with no supplemental O.sub.2 being supplied) to 0% N.sub.2. For example, by supplying 33.3% (by weight) pure oxygen and 66.6% (by weight) air to the combustor, the N.sub.2 content of the resultant combustion gas (where for example propane is the fuel utilized) can be reduced from 72% to 63% (by weight) while the CO.sub.2 quantum in the effluent is correspondingly increased from 18% to about 24% (by weight) (when no water is added to the combustor to produce additional steam.

(30) Direct Steam GenerationSteam Quality Adjustment

(31) As shown in FIGS. 1 and 2, the direct combustion steam generator 1, further comprises at least one water inlet 60 operatively connected to the combustion chamber 15 and configured to deliver a supply of water 70. According to certain embodiments, the water inlet 60 is configured to deliver the water through an inner annulus 5 formed with the inner wall about the circumference of the combustion container 10. The water enters the bottom end of the annulus to cool the inner wall of the combustion chamber 15 and spray over the top of the inner annulus 5 in direct contact and fluid communication with the combustion area of the flame. In this way, the temperature of the combustion chamber 15 as well as the steam output temperature can be managed.

(32) Transfer of heat from the flame to the water introduced through the water supply 70 into the steam generator 1 vaporizes the water into steam. Further, combustion of the fuel and the oxygen-containing gas also generates vaporized water. Thus, quantity of the steam made exceeds quantity of water input into the steam generator 1 since the steam includes vaporized water resulting from combustion of the fuel and the oxygen-containing gas mixed with the water inputted and heated. The quantity of the steam made and output through the outlet 50, therefore, exceeds the quantity of water input into the steam generator 1 from the water supply 70. For example, flow rate of water (steam) output may be between about 20% and 25% greater than flow rate of water input through the water supply 70. According to some embodiments, this increase in water may be sufficient to enable net water production within the steam generator 1 such that the steam generator 1 is self contained for water needs.

(33) According to certain embodiments, the water inlet 60 includes control means to control the water flow into the combustion chamber 15. The control means can include, for example, any combination of a control valve 200, a flow meter 210, and/or a check valve 220. According to certain embodiments, each control means can be controlled by a programmable controller.

(34) Steam production, therefore, can be subjected to quality adjustment. For example, the amount of water input into the combustion process can be controlled according to the embodiments described. In other embodiments, for example, the water may be preheated. In this way, the properties of the generated steam can be adjusted to the particular requirements of a given hydrocarbon-containing reservoir.

(35) Direct Combustion Steam Generation Process for Enhanced Oil Recovery

(36) As illustrated in FIGS. 3 and 4, in a steam assisted enhanced oil recovery (EOR) operation, the outlet 50 directs steam and combustion product output from the steam generator 1 at a pressure greater than about 450 psig, for example, into an injection well 400 to fluidize the hydrocarbon-containing reservoir 360. The steam from the output eventually condenses to create an oil/water mixture that migrates through the reservoir 360. The oil/water mixture is gathered at the production well 410 through which the oil/water mixture is recovered to surface via production line 320. In embodiments applied to SAGD operations (FIG. 4), the injection well 400 includes a horizontal borehole portion that is disposed above (e.g., 4 to 6 meters above) and parallel to a horizontal borehole portion of the production well 410. A separator 330 separates the oil/water mixture within the production line 320 and provides an oil product 340 and recovered water 350, which according to some embodiments can be recycled.

(37) In the embodiments shown in FIGS. 3 & 4, and similar to the numerical references earlier referred to in FIGS. 1-2, air flow inlet 100 communicates with steam generator 1, having air control valve 280 thereon for regulating flow and quantum of air entering steam generator 1. Similarly, line 90 designates the fuel flow inlet to steam generator 1, having fuel control valve 290 thereon for regulating flow and quantum of fuel entering steam generator 1. Likewise, line 80 is the supplemental oxygen flow inlet to steam generator 1, having oxygen control valve 300 thereon for regulating flow and quantum of oxygen entering steam generator 1. Lastly, line 310 is a water supply line for providing water to steam generator 1, for purposes previously described, namely for changing the quality and/or amount of superheated steam being supplied by steam generator 1 in effluent stream 50 and/or cooling the combustion container 10 of steam generator 1 as shown in FIG. 2.

(38) As discussed, the co-injection of combustion gases, CO.sub.2 and/or N.sub.2, with steam can increase oil production rates significantly. The effective ratio of CO.sub.2 and/or N.sub.2 for oil recovery of a given hydrocarbon-containing reservoir will depend on the reservoir conditions which can change during the oil recovery operation. According to embodiments of the present disclosure, this ratio of CO.sub.2 to N.sub.2 produced in the combustion products can be adjusted by adjusting the level of supplemental oxygen supplied to the combustion steam generator 1 to adjust the oxygen content of the oxygen-containing gas mixture burned with the fuel to generate the combustion products comprising steam, CO.sub.2, and N.sub.2.

(39) According to certain embodiments, the conditions of the reservoir are monitored during the oil recovery operation to determine the amount of supplemental oxygen to deliver to the combustion steam generator throughout the process. In this way, adjustments to the ratio of steam and combustion products (i.e., ratio of CO.sub.2 and N.sub.2) can be made in real-time during the oil recovery process in response to the changing conditions of the reservoir in order to maximize oil production.

(40) Direct Combustion Steam Generator and Process for Enhanced Oil Recovery Using Control of Each of Fuel, Air, Supplemental Oxygen, and Water Supplied by Steam Generator to Control Amounts of CO.sub.2, N.sub.2, and Amount and Degree of Superheated Steam Produced

(41) In a further refinement, it is often desirable to further be able to control not only the ratio of CO.sub.2 to N.sub.2 produced by the resultant combustion gas, but to further control the quality of steam within such combustion gases and also the degree of superheating, if desired, of such steam within such combustion gases. This can be done by further controlling the rate of fuel input, as well as the rate of water input which is converted to steam. Some H.sub.2O may also appear in the combustion byproduct, due to humidity of air if air is used instead of pure oxygen.

(42) For example, for a given hydrocarbon fuel C.sub.xH.sub.y, burning of such fuel will liberate a quantity of heat H.sub.(heat of combustion), as per the below formula:
C.sub.xH.sub.y+a(O.sub.2+3.25N.sub.2).fwdarw.xCO.sub.2+(y/2)H.sub.2O+3.25aN.sub.2+H.sub.(heat of combustion), where a=x+y/4

(43) For a situation where a percentage P of oxygen supplied and (1P) is the corresponding percentage of air supplied, such equation becomes:
C.sub.xH.sub.y+PO.sub.2+(1P)a(O.sub.2+3.25N.sub.2).fwdarw.xCO.sub.2+(y/2)H.sub.2O+3.25(1P)aN.sub.2+H.sub.(heat of combustion), where a=x+y/4

(44) Conversely, addition of water to the combustor, which vaporizes due to the presence of heat in the combustor, will absorb heat due to the latent heat of vaporization H.sub.(heat of vaporization).

(45) In controlling the rate of fuel supplied to the combustor, the net heat balance need always be exothermic [and thus a specific amount of fuel, oxygen (in the form of a specific desired ratio of air to supplemental oxygen), as well as the rate of input of the water Q] must all be adjusted relative to each other to allow stoichiometric combustion requirements for optimum combustion and so that the resultant heat is ultimately positive so that all water supplied is turned to steam in at least a saturated state, as shown below:
C.sub.xH.sub.y+PO.sub.2+(1P)a(O.sub.2+3.25N.sub.2)+QH.sub.2O.sub.(liquid).fwdarw.xCO.sub.2+(y/2)H.sub.2O+3.25aN.sub.2+QH.sub.2O.sub.(gas)+H.sub.(heat of combustion)H.sub.(heat of vapourization)0
where H.sub.(heat of vapourization)=Q.sub.(unit of volume/time)Latent heat of vaporization.sub.(unit of heat/unit time)Time.sub.(unit of time)

(46) To the extent that the heat balance is positive for the above equation, assuming all supplied components are supplied at 100 C., is greater than zero, such will provide a degree of superheating to the steam.

(47) Accordingly, in a preferred embodiment as shown in FIG. 1, the steam generator 1 of the present invention and the method of the present invention utilize control valves 140, 110, 170, and 200 situated respectively on each of the supply of the fuel, air, supplemental oxygen, and water which are each separately supplied to the steam generator 10, to further allow such additional control capability of each of such constituents to allow the degree of superheating, quality of steam in the effluent, and the ratio of CO.sub.2 to N.sub.2 in the resultant produced gaseous effluent stream.

(48) Thus in a preferred embodiment (see FIG. 2) the present invention comprises a combustor 10, having a separate fuel supply inlet 90, an air supply inlet 100, a substantially pure oxygen supply inlet 80, and a water supply inlet 70, each controlled by valves 140, 110, 170, and 200 respectively to allow variation of the rate of supply of each of the foregoing to the combustor 1. In a further preferred embodiment, such valves 140, 110, 170, and 200 are automated valves which may be individually electrically, hydraulically, or pneumatically controlled to allow individual variation of the rate of supply of each of the fuel, air, supplemental oxygen, and water to the combustor unit 10.

(49) Thus in a further embodiment the present invention comprises a process 1 for supplying steam and carbon dioxide to a formation using a combustor 10 for creating and supplying an effluent gas stream containing steam and carbon dioxide to an underground formation 360, the process comprising adjusting the rate, via valves 140, 110, 170, and 200 on the respective lines of supply of each of fuel 90, air 100, supplemental oxygen 80, and water 70 to said combustor 10, during injection of said effluent gas stream into an underground formation 360 to heat and reduce the viscosity of oil and/or bitumen in such underground formation 360.

(50) To gain a better understanding of the invention described herein, the following examples are set forth. It will be understood that these examples are intended to describe illustrative embodiments of the invention and are not intended to limit the scope of the invention in any way.

EXAMPLES

Example 1: Controllable Combustion Gas Output

(51) The combustion products generated by the steam generator of the present disclosure were determined over a range of O.sub.2 and air feeds that were combusted with a hydrocarbon-containing fuel, in this case being propane as the model fuel, although clearly any alternative readily available fuel may be used, such as methane or natural gas. The steam generator was operated at a pressure of 45 psig. and 292 F. Stoichiometric ratios of the feeds were maintained. The results are presented in Table 1.

(52) TABLE-US-00001 TABLE 1 Controllable Production of Combustion Product Input Flow Rate Output Flow Rate (grams per minute) (grams per minute) Oxygen Propane Air Water CO.sub.2 Steam Nitrogen 916 252 4640 755 5052 252 3931 4600 755 5000 3015 4581 1260 23200 3775 25262 1260 19655 23000 3775 25062 15074 3023 1260 8036 23135 3775 25197 5024 1527 1260 16073 23067 3775 25129 10,049
No CO or water was detected in the output, therefore total combustion was assumed and conversion of all injected water to steam
(a) Propane Fuel with Substantially Pure Oxygen
C.sub.3H.sub.8+5O.sub.2.fwdarw.3CO.sub.2+4H.sub.2O

(53) On the first run 252 gm/min of propane and 916 gm/min of oxygen and were fed to the burner along with 4640 gm/min of water. This resulted in 5052 gm/min of saturated steam and 755 gm/min of CO.sub.2. The mass ratio of CO.sub.2/steam was 0.149, meaning that for every gram of water input into the steam generator 0.149 grams of CO.sub.2 and no nitrogen is produced. The percent composition of the CO.sub.2 in the effluent stream was (755/5052+755)=13% (by weight), with no N.sub.2.

(54) On the second run for the above reaction, 4581 gm/min of oxygen and 1260 gm/min of propane along with 23200 gm/min of water was fed to the burner. (The 4581 gm/min of oxygen is the stoichiometric mass of oxygen required for 1260 gm/min of propane). This resulted in 3775 gm/min of CO.sub.2 and 25262 gm/min of saturated steam. The mass ratio of CO.sub.2/steam was 0.149, and the percent composition of the CO.sub.2 in the effluent stream was again 13% [i.e., 3755/(25262+3755)=13% (by weight)], with no N.sub.2, the remainder being steam. This is a relatively high content of CO.sub.2 in the effluent would be expected to significantly reduce the viscosity of heavy oil in EOR.

(55) (b) Propane Fuel with Air
C.sub.3H.sub.8+5(O.sub.2+3.25N.sub.2).fwdarw.3CO.sub.2+4H.sub.2O+5(3.25N.sub.2)

(56) On the first run 252 gm/min of propane and 3931 gm/min of air (i.e., slightly in excess of the stoichiometric requirement of air required of 3895 gm/min) were fed to the burner along with 4600 gm/min of water. This resulted in 5000 gm/min of saturated steam, 755 gm/min CO.sub.2, and 3015 gm/min of nitrogen. The mass ratio of CO.sub.2/steam was 0.151 and the mass ratio of nitrogen/steam was 0.603, indicating that with the use of air for combustion 4.0 (four) times as much N.sub.2 as CO.sub.2 is produced. This may be beneficial in EOR particularly if the hydrocarbon-containing formation needs pressure, however the percentage of CO.sub.2 in the effluent stream dropped to 8.6% [755/(755+5000+3015)]=8.6% (by weight). Even if only a stoichiometric amount of air been supplied (3895 gm/min) for 252 gm/min propane, this would have stoichiometrically produced 2798 g/min N and 755 gm/min CO.sub.2, such still would have resulted in nearly 3.7 times the amount of N.sub.2 per amount of CO.sub.2 produced (by weight) (2798/756=3.7)

(57) On the second run 1260 gm/min of propane and 19655 gm/min of air (i.e., containing oxygen in the amount of 19655/3.25=6042 gm/min substantially in excess of the stoichiometric requirement of oxygen required of 4581 gm/min) were fed to the burner along with 23000 gm/min of water. This resulted in 25062 gm/min of saturated steam, 3755 gm/min CO.sub.2, and 15074 gm/min of nitrogen. The mass ratio of CO.sub.2/steam was 0.151 and the mass ratio of nitrogen/steam was 0.603, again indicating that with this proportion of air in relation the propane supplied four (4) times as much N.sub.2 than CO.sub.2 is produced in the effluent stream. This may be beneficial in EOR particularly if the hydrocarbon-containing formation needs pressure, however the percentage of CO.sub.2 in the effluent stream dropped to 8.6% [755/(755+5000+3015)]=8.6% (by weight) as compared to 13% when pure oxygen was used. Even if only a stoichiometric amount of air been supplied (4581 gm/min) for 1260 gm/min propane, this would have stoichiometrically produced 14,888 g/min N (i.e., 3.254581 gm/min) and 3779 gm/min CO.sub.2, such still would have resulted in nearly 3.9 times the amount of nitrogen per amount of CO.sub.2 produced (by weight). (i.e., 14,888/3779=3.9)

(58) (c) Propane Fuel with 1/3 Oxygen and 2/3 Air
C.sub.3H.sub.8+(1/3)5O.sub.2+(2/3)*5(O.sub.2+3.25N.sub.2).fwdarw.3CO.sub.2+4H.sub.2O+2*(5)/3(3.25N.sub.2)

(59) 1527 gm/min of oxygen and 16073 gm/min of air (i.e., a total of 5255 gm/min oxygen which is in substantial excess of the stoichiometric amount of oxygen of 4582 g/min required for 1260 gm/min of propane) were fed to the burner along with 1260 gm/min of propane and 23067 gm/min of water. This resulted in 3775 gm/min of CO.sub.2, 25129 gm/min of saturated steam, and 10,049 gm/min of nitrogen exhausting from the burner system. This gives a CO.sub.2/steam ratio of 0.150 and a nitrogen/steam ratio of 0.518, with thus 3.45 times the mass of nitrogen being produced relative to the mass of produced CO.sub.2. Even if only the amount of air to provide the stoichiometric total amount of oxygen required had been supplied (i.e. 4582 gm/min oxygen), this would have produced 9927 gm/min of N (and 3780 gm/min of CO.sub.2), this would have resulted in 2.63 times the amount of N.sub.2 to CO.sub.2 (by weight). It is expected that this supplied mixture of 1/3 pure oxygen and 2/3 air would nonetheless pressurize a hydrocarbon-containing formation, but more slowly than using only air alone as shown above.

(60) (d) Propane Fuel with 2/3 Oxygen and 1/3 Air
C.sub.3H.sub.8+(2/3)5O.sub.2+(1/3)5(O.sub.2+3.25N.sub.2).fwdarw.3CO.sub.2+4H.sub.2O+5/3(3.25N.sub.2)

(61) 3023 gm/min of oxygen and 8036 gm/min of air (i.e. 3023+8036/3.25=5497 gm/min of oxygen) substantially in excess of the stoichiometric amount of oxygen required (4582 gm/min) for 1260 gm/min of propane, were fed to the burner along with 1260 gm/min of propane and 23135 gm/min of water. This resulted in 3775 gm/min CO.sub.2, 25197 gm/min of saturated steam, and 5024 gm/min of N.sub.2 exhausting from the system. This gave a CO.sub.2/steam ratio of 0.150 and a N.sub.2/steam ratio of 0.200, indicating that if 1/3 air to 2/3 pure oxygen is input into the system, only 1.33 times more N.sub.2 as compared to CO.sub.2 is produced. It is thus the situation that the formation in this instance would be pressurized with nitrogen less readily than in above example (c), but whose viscosity would be lessened more than in above example (c) due to the substantially higher percentage of end product CO.sub.2 being injected into the formation.