HK1109438B

HK1109438B - Oilfield enhanced in situ combustion process

Info

Publication number: HK1109438B
Application number: HK08100092.9A
Authority: HK
Inventors: Conrad Ayasse
Original assignee: Archon Technologies Ltd.
Priority date: 2004-06-07
Filing date: 2005-06-07
Publication date: 2012-02-24

Description

Improved in situ combustion process for oil field

Technical Field

The present invention relates to a process for enhancing safety and recovery when conducting oil production from a subterranean reservoir by a toe-to-heel in situ combustion process (toe-to-heel in situ combustion process) using horizontal production wells, such as disclosed in U.S. Pat. Nos. 5,626,191 and 6,412,557.

Background

U.S. Pat. Nos. 5,626,19 and 6,412,557, all of which are incorporated herein in their entirety, disclose in situ combustion processes for producing oil from a subterranean reservoir (100) that utilize relatively high injection wells (102) disposed in the reservoir (100) and relatively low overall production wells (103-106) in the reservoir (100). The production well has a horizontal section (107) that is generally oriented perpendicular to a generally straight and laterally vertically extending combustion front that diverges from the injection well (102). The segment (107) is positioned in the path of the advancing combustion front. Air, or other oxidizing gas, such as oxygen-enriched air, is injected through the well 102, which well 102 may be a vertical well, a horizontal well, or a combination of such wells. The process of U.S. Pat. No. 5,626,19 is referred to as "THAI^TM", is an abbreviation for" tip to heel air injection ", AmericaThe process in U.S. Pat. No. 6,412,557 is referred to as "Capri^TM", Archhon technologies, Inc. owns the trademark, which is Alberta Carr Calgary, Canada, southwestern City, Canada]Petrobank Energy and Resources ltd.

Of concern is THAI when oxygen enters a horizontal well^TMAnd Capri^TMThe safety of the process, which may cause oil burning in the well and in the case of extremely high temperatures, will destroy the well. Such oxygen breakthrough will not occur if the injection rate is kept low, however, a high injection rate is desirable in order to maintain a high oil production rate and a high oxygen flow at the combustion front. It is known that high oxygen flow rates maintain combustion in a High Temperature Oxidation (HTO) regime, reaching temperatures above 350 ℃, and burning the fuel to essentially carbon dioxide. At low oxygen flow rates, Low Temperature Oxidation (LTO) occurs and the temperature does not exceed 350 ℃. In the LTO regime, oxygen becomes incorporated into the organic molecule, forming polar compounds that stabilize the deleterious water-oil emulsion and accelerate corrosion due to the formation of carboxylic acids. In summary, the use of relatively low oxidant injection rates is not an acceptable method of preventing combustion in horizontal wells.

What is needed is a method of increasing the velocity of oxidizing gas injection while preventing oxygen from entering horizontal wells. The present invention provides such a method.

Disclosure of Invention

THAI^TMAnd Capri^TMThe process relies on two forces that drive oil, water and combustion gases into a horizontal wellbore for transport to the surface. These are gravity drainage and pressure. The liquid, primarily oil, drains into the wellbore under the force of gravity because the wellbore is disposed in a lower region of the reservoir. The liquid and gas flow together down into the horizontal wellbore under the influence of a pressure gradient established between the reservoir and the wellbore.

During the reservoir preheating phase, or start-up procedure, steam is circulated in the horizontal well through pipes extending to the end of the well. The steam flows back to the surface through the annulus of the casing. This process is necessary in bitumen reservoirs because cold oil that can enter the well will be very viscous and flow poorly, potentially plugging the wellbore. Steam is also circulated through the injection well and also injected into the reservoir in the region between the injection well and the end of the horizontal well to heat the oil and increase its mobility before initiating the injection of oxidizing gas into the reservoir.

The aforementioned patents show that by continuous oxidizing gas injection, a quasi-vertical combustion front is formed and moves laterally from the toe direction to the heel of the horizontal well. Thus, two regions of the reservoir are formed relative to the location of the combustion zone. Towards the end, there is an oil depleted zone that is primarily filled with oxidizing gas, and on the other side there is a reservoir zone that includes cold oil or bitumen. At higher oxidant injection rates, the reservoir pressure rises, which can exceed the fuel deposition rate, so that gas containing residual oxygen can be pushed into the horizontal wellbore in the oil-depleted zone. The result of the oil and oxygen together in the wellbore is combustion and when high temperatures are reached, perhaps in excess of 1000 c, explosions may occur. This can result in irreparable losses to the wellbore, including failure of the sand screen. For safe and continuous oil recovery operations, the presence of oxygen and wellbore temperatures in excess of 425 ℃ must be avoided.

Several methods of preventing oxygen from entering the production well are based on reducing the pressure differential between the reservoir and the horizontal wellbore. These are: 1. the rate of injection of oxidizing gas is reduced in order to reduce reservoir pressure, and 2. the rate of fluid reduction is reduced in order to increase wellbore pressure. Both of these methods result in a reduction in the rate of oil recovery, which is economically detrimental. Conventional wisdom has also been that injecting fluids directly into the wellbore will increase wellbore pressure, but is very detrimental to production rates.

Accordingly, to overcome the disadvantages of the prior art and to increase the safety and productivity of the recovery of hydrocarbons from a subterranean reservoir, the present invention in a first broad embodiment comprises an in situ combustion process for the recovery of liquid hydrocarbons from a subterranean reservoir, the process comprising the steps of:

(a) providing at least one injection well for injecting an oxidizing gas into the subterranean reservoir;

(b) providing at least one production well having a substantially horizontal section and a substantially vertical production well connected to said horizontal section, wherein the substantially horizontal section extends toward the injection well, the horizontal section having a heel portion near its connection point to the vertical production well and an end portion at an opposite end of the horizontal section, wherein the end portion is closer to the injection well than the heel portion;

(c) injecting an oxidizing gas through an injection well for in situ combustion such that combustion gases are generated and caused to progressively advance laterally as a leading edge along and generally perpendicular to the horizontal leg in a direction from the tip portion to the heel portion of the horizontal leg and a fluid is discharged into the horizontal leg;

(d) providing a conduit within a production well for injecting steam, water or non-oxidizing gas into the horizontal leg portion of the production well;

(e) injecting a medium selected from the group of media consisting of steam, water and a non-oxidizing gas into said conduit such that said medium is transported through said conduit to said end portion proximate said horizontal leg portion; and

(f) producing hydrocarbons from a production well within a horizontal section of the production well.

In a further broad embodiment of the invention, the invention comprises a process for producing liquid hydrocarbons from a subterranean reservoir, the process comprising the steps of:

(a) providing at least one injection well for injecting an oxidizing gas into an upper portion of the subterranean reservoir;

(b) providing at least one injection well for injecting steam, a non-oxidizing gas or water which is subsequently heated to steam into a lower portion of the subterranean reservoir;

(c) providing at least one production well having a substantially horizontal section and a substantially vertical production well connected to said horizontal section, wherein the substantially horizontal section extends toward the injection well, the horizontal section having a heel portion near its connection point to the vertical production well and an end portion at an opposite end of the horizontal section, wherein the end portion is closer to the injection well than the heel portion;

(d) injecting an oxidizing gas through an injection well for in situ combustion such that combustion gases are produced, wherein the combustion gases progressively progress laterally as a leading edge along and generally perpendicular to the horizontal leg in a direction from the tip portion to the heel portion of the horizontal leg and the fluid drains into the horizontal leg;

(e) injecting a medium into said injection well, wherein said medium is selected from the group of media consisting of steam, water and a non-oxidizing gas; and

In a further embodiment of the invention, the invention comprises the above steps of injecting a medium into the reservoir via the injection well and the step of injecting the medium into the horizontal section via the tubing. Accordingly, in this additional embodiment, the present invention includes a method of recovering liquid hydrocarbons from a subterranean reservoir, the method comprising the steps of:

(e) injecting an oxidizing gas through an injection well for in situ combustion such that combustion gases are produced, wherein the combustion gases progressively progress laterally as a leading edge along and generally perpendicular to the horizontal leg in a direction from the tip portion to the heel portion of the horizontal leg and the fluid drains into the horizontal leg;

(f) injecting a medium into said injection well, wherein said medium is selected from the group of media consisting of steam, water and a non-oxidizing gas; and

(g) producing hydrocarbons from a production well within a horizontal section of the production well.

If the medium is steam, it is injected into the reservoir/reservoir through either or both of the pipelines in the injection or production wells, typically at a pressure of 7000Kpa in this state.

Alternatively, when the injected medium is water, such a method contemplates that when water is supplied to the reservoir, the water is heated to become steam. When water reaches the reservoir through either or both of the pipes in the injection and/or production wells, the water may be heated to steam during such transport, or immediately upon entering the reservoir out of the pipes of the injection and/or production wells.

Description of the drawings:

FIG. 1 is THAI^TMSchematic representation of an in situ combustion process, wherein the notation is as follows:

the designation a represents the top horizon of a heavy oil or bitumen reservoir and B represents the bottom horizon of such reservoir/reservoir.

C represents a vertical well and D shows a typical injection point for an oxidizing gas such as air.

E represents the usual location for injecting steam or non-oxidizing gas into the reservoir. This is part of the present invention.

F represents a partially perforated horizontal well casing. The fluid enters the casing and is typically carried directly to the surface by natural gas lift through another pipe (not shown) disposed at the heel of the horizontal well.

G represents a pipe placed in the horizontal section. The open end of the conduit may be located near the end of the sleeve, as shown, or elsewhere. The conduit may be "coiled tubing" that is easily repositioned within the casing. This is part of the present invention.

Elements E and G are part of the invention and steam or non-oxidizing gas may be injected at E and/or G. E may be part of a separate well or may be part of the same well used for injecting the oxidizing gas. These injection wells may be vertical, slanted or horizontal or otherwise, and each may supply several horizontal wells.

For example, steam, water or non-oxidizing gas may be injected anywhere between the horizontal segments near the ends of the horizontal segments using an array of parallel horizontal segments as described in U.S. Pat. Nos. 5,626,191 and 6,412,557.

FIG. 2 is a schematic of a reservoir used as a model. The schematic is not drawn to scale. Only "symmetric cells" are shown. The total spacing between horizontal segments is 50 meters, but only half of the reservoir needs to be at STARS^TMDefined in computer software. This saves computation time. The overall dimensions of the symmetric unit are:

the lengths A-E are 250 meters; widths A-F are 25 meters; the height F-G is 20 meters.

The well locations are as follows:

the oxidizing gas injection well J is arranged in the first grid at point B at an angle a50 meters (a-B). Horizontal well K ends in a first grid between a and F, which is offset from injection well J15 meters (B-C) along the length of the reservoir. The heel of horizontal well K is located at point D, E50 meters from the corner of the reservoir. The horizontal section of horizontal well K is 135 meters (C-D) long and is arranged in a third grid 2.5 meters (A-E) above the reservoir bottom.

The injection well J is perforated at two (2) locations. The perforations at H are the injection points for the oxidizing gas, while the perforations at I are the injection points for the steam or non-oxidizing gas. The horizontal segments (C-D) are perforated 50% and have pipe openings near the ends (not shown, see fig. 1).

Detailed Description

THAI^TMThe operation of the process has been described in U.S. Pat. Nos. 5,626,19 and 6,412,557, which are briefly reviewed here. An oxidizing gas, typically air, oxygen, or oxygen-enriched air, is injected into the upper portion of the reservoir. Previously placed coke consumed oxygen so only oxygen-free gas contacted the petroleum before the coke zone. Typically 600 c and up to 1000 c combustion gas temperatures are achieved by high temperature oxidation of coke fuel. In the Mobile Oil Zone (MOZ), these hot gases and vapors heat the oil to over 400 ℃, partially cracking the oil, gasifying some components and greatly reducing the oil viscosity. The heaviest components of the petroleum, such as asphaltenes, remain on the rock and when the combustion front reaches this location later, it will constitute coke fuel. At the MOZ, gas and oil are discharged down into the horizontal well under gravity and low pressure settling of the well. The coke and MOZ zones move laterally in the direction from the end of the horizontal well to the heel. The area behind the combustion front is labeled as the burned area. The MOZ was preceded by cold oil.

As the combustion front progresses, the burned region of the reservoir becomes depleted of liquid (oil and water), becoming saturated with oxidizing gases. The portion of the horizontal well opposite this zone of combustion has the risk of receiving oxygen which will burn oil present in the well and create extremely high wellbore temperatures which will damage the steel casing and especially the sand screen used to admit fluid but block the sand. If the sand screen fails, loose reservoir sand will enter the wellbore, which must be shut in for thorough cleanup and remediation with a cement plug. Such operations are difficult and dangerous because of the explosive levels of oil and oxygen that can be present in the wellbore.

To quantify the effect of fluid injection into a horizontal wellbore, a number of computer numerical simulations of the process were performed. Steam is injected into the horizontal well at various rates in two ways: 1. through tubing placed within the horizontal well, and 2. through a separate well extending near the bottom of the reservoir around the end of the horizontal well. Both of these approaches reduce the preference for oxygen to enter the wellbore, but provide surprising and counterintuitive benefits: oil recovery is increased and coke build-up in the wellbore is reduced. Thus, a higher oxidizing gas injection rate can be used while maintaining safe operation.

It has been found that both methods of adding steam to the reservoir provide for a THAI-related process by reducing the tendency of oxygen to enter the horizontal wellbore^TMThe process safety is high. It also makes higher rates of injection of oxidizing gas into the reservoir and higher recovery rates feasible.

To evaluate the consequences of reducing the pressure in a horizontal wellbore by injecting steam or non-oxidizing gas, a large amount of THAI was performed^TMComputer simulation of the process. The software was STARS, provided by the Calgary computer model group, Alberta, canada^TMAn in situ combustion simulator.

Table 4. list model parameters.

A simulator: SARTS^TM2003.13, computer modeling group, Inc

The size of the model is as follows:

250 m long, 100 grids, eac

Grid width of 25 m and 20 grids

20 grids with height of 20 m

The grid size is: 2.5 m.times.2.5 m.times.1.0 m (LWH)

Horizontal production wells:

a discontinuous well having a horizontal length of 135 meters extends from grid 26,1, 3 to 80, 1, 3. The horizontal segment ends were offset 15 meters from the vertical air injectors.

Vertical injection well:

oxidizing gas (air) injection point: 20, 1, 1:4 (upwards 4 grids)

Oxidizing gas injection rate: 65,000 cubic meters per day, 85000 cubic meters per day or 100000 cubic meters per day

Vapor injection point: 20, 1, 19:20 (2 grids downwards)

Rock/fluid parameters:

the components are as follows: water, bitumen, upgrading (upgrade), methane, carbon dioxide, carbon monoxide/nitrogen, oxygen, coke

Heterogeneity: homogeneous sandstone

Permeability: 6.7 Daxi (h), 3.4 Daxi (v)

Porosity: 33 percent

Saturation degree: 80% of asphalt, 20% of water and 0.114% of gas mole fraction

Asphalt viscosity: 340,000 centipoise at 10 ℃.

Average molar weight of pitch: 550AMU

Modifier (upgrade) viscosity: 664 cP at 10 deg.C

Modifier (upgrade) average molecular weight: 330AMU

Physical conditions:

oil reservoir temperature: 20 deg.C

Natural reservoir pressure: 2600kPa

Bottom hole pressure: 4000kPa

Chemical reaction:

1.1.0 Pitch- > 0.42 modifier (upgrade) +1.3375 methane +20 Coke

2.1.0 asphalt +16 oxygen ^0.05 ^ 12.5 water +5.0 methane +9.5 carbon dioxide +0.5 carbon monoxide/nitrogen +15 coke

3.1.0 Coke +1.225 oxygen- > 0.5 Water +0.95 carbon dioxide +0.05 carbon monoxide/Nitrogen

Example (b):

example 1

Table 1a shows the results of a simulation in which air is injected into a vertical injector (E in fig. 1) at a rate of 65,000 cubic meters per day (at standard temperature and pressure). The case of zero steam injection at point I of the reservoir bottom well J is not part of the invention. At an air injection rate of 65,000 cubic meters per day, no oxygen enters the horizontal wellbore even without steam injection, and the maximum wellbore temperature never exceeds the target value of 425 ℃.

However, as can be seen from the data below, contrary to the intuitive expectation, a low degree of steam injection at a point where the reservoir is relatively low (E in fig. 1) at a level of 5 to 10 cubic meters per day (water equivalent) provides a great benefit for enhanced recovery. Where the injected medium is steam, the following data provides the water equivalent volume of such steam, since otherwise determining the volume of steam supplied is difficult in terms of its dependence on the pressure of the formation at which the steam was formed. Of course, when water is injected into the formation and subsequently becomes steam as it moves toward the formation, the amount of steam produced is simply the water equivalent given below, which is typically on the order of 1000x (depending on pressure) of the volume of water supplied.

TABLE 1a air velocity 65,000 cubic meters per day-steam injection at the bottom of the reservoir

Example 2

Table 1b shows the results of injecting steam into the horizontal well through the internal tubing G near the end and simultaneously injecting air into the upper portion of the reservoir at a rate of 65,000 cubic meters per day (at standard temperature and pressure). The maximum wellbore temperature is reduced in proportion to the amount of steam injected, and the recovery of oil is increased relative to a zero steam baseline. In addition, the maximum volume ratio of coke deposited in the wellbore decreases as the amount of steam injected increases. This is beneficial because the pressure drop in the wellbore will be lower and fluid will flow more easily at the same pressure drop than in a well without steam injection at the end of the horizontal well.

TABLE 1b air velocity 65,000 cubic meters per day-steam injection in well tubing

Example 3

In this example, the air injection rate was increased to 85,000 cubic meters per day (at standard temperature and pressure), resulting in oxygen breakthrough as shown in table 2 a. For the baseline case of zero steam injection, an oxygen concentration of 8.8% is shown in the wellbore. The maximum wellbore temperature reaches 1074 ℃, and coke deposition reduces the wellbore permeability by 97%. While the operation of injecting 12 cubic meters per day (water equivalent) of steam at the bottom of the reservoir through the vertical injection well C (see figure 1) provides excellent results with zero oxygen breakthrough, acceptable coke and good oil recovery,

table 2a air velocity 85,000 cubic meters per day-steam injection at the bottom of the reservoir

Example 4

Table 2b shows the combustion performance of 85,000 cubic meters per day (at standard temperature and pressure) of air and simultaneous injection of steam into the wellbore through the internal pipe G. Again, 10 cubic meters per day (water equivalent) of steam is required to prevent oxygen breakthrough and an acceptable maximum wellbore temperature.

Table 2b air velocity 85,000 cubic meters per day-steam injection in well tubing

Example 5

To further test the effect of high air injection velocity, several runs were performed with 100,000 cubic meters per day of air injection. The results in table 3a show that while injecting steam simultaneously into the bottom of the reservoir (i.e., locations B-E in vertical well C-ref in fig. 1), 20 cubic meters/day of steam is required to prevent oxygen breakthrough into the horizontal section, in contrast to only 10 cubic meters/day of steam (water equivalent) when injected with 85,000 cubic meters/day of air.

TABLE 3a air velocity 100,000 cubic meters per day-steam injection at the bottom of the reservoir

Example 6

Table 3b shows the results of injecting steam into the well pipe G (see figure 1) and air into the reservoir at 100,000 cubic meters per day. Steam is also injected at the bottom of the reservoir, and in order to prevent oxygen from entering the horizontal section, the steam velocity needs to be 20 cubic meters per day (water equivalent).

Table 3b air velocity 100,000 cubic meters per day-steam injection in well tubing

Summary of the invention

For a fixed number of steam injections, the average daily oil recovery increases with increasing air injection rate. This is not unexpected because the volume of displacement fluid increases. However, it is surprising that the total amount of oil produced decreases with increasing air velocity. This occurs during the life of the air injection cycle (the time for the combustion front to reach the heel of the horizontal well).

Although preferred embodiments of the invention have been disclosed and illustrated, it should be understood that the invention is not limited to these particular embodiments. Many variations and modifications will now occur to those skilled in the art. For definition of the invention, reference is made to the appended claims.

Claims

1. An in situ combustion process for producing liquid hydrocarbons from an underground reservoir, comprising the steps of:

(a) providing at least one injection well for injecting an oxidizing gas into said subterranean reservoir;

(b) providing at least one production well having a substantially horizontal section and a substantially vertical production well connected to said horizontal section, wherein said substantially horizontal section extends toward said injection well, the horizontal section having a heel portion near its connection point to said vertical production well and an end portion at the opposite end of said horizontal section, wherein said end portion is closer to said injection well than said heel portion;

(c) injecting an oxidizing gas through said injection well for in situ combustion in the formation such that combustion gases are produced and such that said combustion gases progressively progress laterally as a leading edge along and generally perpendicular to said horizontal leg in a direction from an end portion to a heel portion of said horizontal leg and fluids drain into said horizontal leg;

(d) providing a conduit within said vertical section and at least a portion of said horizontal section within said production well for injecting steam, water or non-oxidizing gas along said horizontal section of said production well into said horizontal section portion of said production well that is horizontally spaced adjacent to the formed combustion front;

(f) producing hydrocarbons from the production well in a horizontal section of the production well.

2. The process of claim 1, wherein the medium is water that is heated to become steam when supplied to the reservoir.

3. The process of claim 1, wherein the injection well is a vertical well, an inclined well, or a horizontal well.

4. The process of claim 1, said step of injecting said medium further serving to pressurize said horizontal well to a pressure to allow injection of said medium into a subterranean reservoir.

5. The process of claim 1 wherein a non-oxidizing gas is injected into the conduit, alone or with steam or water.

6. The process of claim 1 wherein the open end of said conduit is near the end of said horizontal section to allow steam or heated non-oxidizing gas to be delivered to said end.

7. The process of claim 1 or 6, wherein the conduit is partially pulled back or otherwise repositioned to vary the injection point of steam, water or non-oxidizing gas along the horizontal segment so that the conduit continues to remain proximate to the combustion front as the combustion front moves a lateral horizontal distance along the horizontal segment.

8. The process of claim 1, wherein steam, water, or one or more non-oxidizing gases are injected continuously or periodically.

9. An in situ combustion process for producing liquid hydrocarbons from an underground reservoir, comprising the steps of:

(b) the at least one injection well is further adapted to inject steam, a non-oxidizing gas, or water that will subsequently be heated to steam into a lower portion of the subterranean reservoir;

(c) providing at least one production well having a substantially horizontal section and a substantially vertical production well connected to said horizontal section, wherein said substantially horizontal section extends toward an injection well, the horizontal section having a heel portion near its connection point to said vertical production well and an end portion at the opposite end of said horizontal section, wherein said end portion is closer to said injection well than said heel portion;

(d) injecting an oxidizing gas through said injection well for in situ combustion such that combustion gases are produced, wherein said combustion gases progressively progress laterally as a front along and generally perpendicular to said horizontal leg in a direction from an end portion to a heel portion of said horizontal leg and a fluid drains into said horizontal leg;

(e) injecting a medium into said injection well, wherein said medium is selected from the group of media consisting of steam, water or a non-oxidizing gas; and

(f) producing hydrocarbons from the production well within the horizontal section of the production well.

10. An in situ combustion process for producing liquid hydrocarbons from an underground reservoir, comprising the steps of:

(a) providing at least one oxidizing gas injection well for injecting oxidizing gas into an upper portion of the subterranean reservoir;

(b) providing at least one other injection well for injecting steam, a non-oxidizing gas or water which is subsequently heated to steam into a lower portion of the subterranean reservoir;

(c) providing at least one production well having a substantially horizontal section and a substantially vertical production well connected to said horizontal section, wherein said substantially horizontal section extends toward said injection well, the horizontal section having a heel portion near its connection point to said vertical production well and an end portion at the opposite end of said horizontal section, wherein said end portion is closer to said oxidizing gas injection well than said heel portion;

(d) injecting an oxidizing gas through said oxidizing gas injection well for in situ combustion such that combustion gases are generated and caused to progressively advance laterally as a flow along said horizontal leg and generally perpendicular to the leading edge of the horizontal leg in a direction from the terminal portion to the heel portion of said horizontal leg and a fluid is discharged into said horizontal leg;

(e) injecting a medium into said other injection well, wherein said medium is selected from the group of media consisting of steam, water and a non-oxidizing gas; and

(g) producing hydrocarbons from the production well within the horizontal section of the production well.

11. The process as claimed in claim 9 or 10 wherein the medium is water which is subsequently heated to become steam which is provided to the lower portion of the formation through the distal end of the injection well.

12. An in situ combustion method for producing liquid hydrocarbons from a subterranean reservoir, comprising the steps of:

(c) providing at least one production well having a substantially horizontal section and a substantially vertical production well connected to said horizontal section, wherein said substantially horizontal section extends toward said injection well, the horizontal section having a heel portion near its connection point to said vertical production well and an end portion at the opposite end of said horizontal section, wherein said end portion is closer to said injection well than said heel portion;

(d) providing a conduit within at least a portion of said vertical section and said horizontal section within said production well for injecting steam, water or non-oxidizing gas into said horizontal section portion of said production well;

(e) injecting an oxidizing gas through said injection well for in situ combustion such that combustion gases are produced, wherein said combustion gases progressively progress laterally as a front along and generally perpendicular to said horizontal leg in a direction from an end portion to a heel portion of said horizontal leg and a fluid drains into said horizontal leg;

(f) injecting a medium into said injection well and into said tubing, wherein said medium is selected from the group of media consisting of steam, water and a non-oxidizing gas; and

13. The method of claim 12, wherein the medium is water that is heated to become steam when supplied to the reservoir.

14. The method of claim 12, wherein the injection well is a vertical well, an inclined well, or a horizontal well.

15. An in situ combustion method for producing liquid hydrocarbons from a subterranean reservoir, comprising the steps of:

(f) injecting a medium into said other injection well and into said tubing, wherein said medium is selected from the group of media consisting of steam, water and a non-oxidizing gas; and

16. The method of claim 15, wherein the medium is water that is heated to become steam when supplied to the reservoir.

17. The method of claim 15, wherein the injection well is a vertical well, an inclined well, or a horizontal well.