Oilfield Enhanced in Situ Combustion Process

Abstract

A method for recovery of oil in toe-to-heal in-situ combustion processes from underground petroleum formations, having at least one injection well for injecting oxidizing gas into the underground formation and one production well having a substantially horizontal leg and a substantially vertical production well connected thereto wherein the substantially horizontal leg extends towed the injection well, the horizontal leg having a heel portion in the vicinity of its connection to the vertical production well and a toe portion at the opposite end of the horizontal leg proximate the injection well. The improvement comprises either i) providing tubing inside the production well and injecting steam or water into the horizontal leg portion via the tubing so that steam/water is conveyed to the toe portion, ii) injecting steam/water into the injection well in additional to oxidizing gas, or iii) providing and carrying out both of steps i) and ii).

Description

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic of the THAI™ in situ combustion process with labeling as follows:

Item A represents the top level of a heavy oil or bitumen reservoir, and B represents the bottom level of such reservoir/formation.

C represents a vertical well with D showing the general injection point of a oxidizing gas such as air.

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

F represents a partially perforated horizontal well casing. Fluids enter the casing and are typically conveyed directly to the surface by natural gas lift through another tubing located at the heel of the horizontal well (not shown).

G represents a tubing placed inside the horizontal leg. The open end of the tubing may be located near the end of the casing, as represented, or elsewhere. The tubing can be ‘coiled tubing’ that may be easily relocated inside the casing. This is part of the present invention.

The elements E and G are part of the present invention and steam or non-oxidizing gas may be injected at E and/or at G. E may be part of a separate well or may be part of the same well used to inject the oxidizing gas. These injection wells may be vertical, slanted or horizontal wells or otherwise and each may serve several horizontal wells.

For example, using an array of parallel horizontal leg as described in U.S. Pat. Nos. 5,626,191 and 6,412,557, the steam, water or non-oxidizing gas may be injected at any position between the horizontal legs in the vicinity of the toe of the horizontal legs.

FIG. 2 is a schematic diagram of the Model reservoir. The schematic is not to scale. Only an ‘element of symmetry’ is shown. The full spacing between horizontal legs is 50 meters but only the half-reservoir needs to be defined in the STARS™ computer software. This saves computing time. The overall dimensions of the Element of Symmetry are:

length A-E is 250 m; width A-F is 25 m; height F-G is 20 m.

The positions of the wells are as follows:

Oxidizing gas injection well J is placed at B in the first grid block 50 meters (A-B) from a corner A. The toe of the horizontal well K is in the first grid block between A and F and is 15 m (B-C) offset along the reservoir length from the injector well J. The heel of the horizontal well K lies at D and is 50 m from the corner of the reservoir, E. The horizontal section of the horizontal well K is 135 m (C-D) in length and is placed 2.5 m above the base of the reservoir (A-E) in the third grid block.

The Injector well J is perforated in two (2) locations. The perforations at H are injection points for oxidizing gas, while the perforations at I are injection points for steam or non-oxidizing gas. The horizontal leg (C-D) is perforated 50% and contains tubing open near the toe (not shown, see FIG. 1).

DESCRIPTION OF THE PREFERRED EMBODIMENT

The operation of the THAI™ process has been described in U.S. Pat. Nos. 5,626,191 and 6,412,557 and will be briefly reviewed. The oxidizing gas, typically air, oxygen or oxygen-enriched air, is injected into the upper part of the reservoir. Coke that was previously laid down consumes the oxygen so that only oxygen-free gases contact the oil ahead of the coke zone. Combustion gas temperatures of typically 600° C. and as high as 1000° C. are achieved from the high-temperature oxidation of the coke fuel. In the Mobile Oil Zone (MOZ), these hot gases and steam heat the oil to over 400° C., partially cracking the oil, vaporizing some components and greatly reducing the oil viscosity. The heaviest components of the oil, such as asphaltenes, remain on the rock and will constitute the coke fuel later when the burning front arrives at that location. In the MOZ, gases and oil drain downward into the horizontal well, drawn by gravity and by the low-pressure sink of the well. The coke and MOZ zones move laterally from the direction from the toe towards the heel of the horizontal well. The section behind the combustion front is labeled the Burned Region. Ahead of the MOZ is cold oil.

With the advancement of the combustion front, the Burned Zone of the reservoir is depleted of liquids (oil and water) and is filled with oxidizing gas. The section of the horizontal well opposite this Burned Zone is in jeopardy of receiving oxygen which will combust the oil present inside the well and create extremely high wellbore temperatures that would damage the steel casing and especially the sand screens that are used to permit the entry of fluids but exclude sand. If the sand screens fail, unconsolidated reservoir sand will enter the wellbore and necessitate shutting in the well for cleaning-out and remediation with cement plugs. This operation is very difficult and dangerous since the wellbore can contain explosive levels of oil and oxygen.

In order to quantify the effect of fluid injection into the horizontal wellbore, a number of computer numerical simulations of the process were conducted. Steam was injected at a variety of rates into the horizontal well by two methods: 1. via tubing placed inside the horizontal well, and 2. via a separate well extending near the base of the reservoir in the vicinity of the toe of the horizontal well. Both of these methods reduced the prediliction of oxygen to enter the wellbore but gave surprising and counterintuitive benefits: the oil recovery factor increased and build-up of coke in the wellbore decreased. Consequently, higher oxidizing gas injection rates could be used while maintaining safe operation.

It was found that both methods of adding steam to the reservoir provided advantages regarding the safety of the THAI™ Process by reducing the tendency of oxygen to enter the horizontal wellbore. It also enabled higher oxidizing gas injection rates into the reservoir, and higher oil recovery.

Extensive computer simulation of the THAI™ Process was undertaken to evaluate the consequences of reducing the pressure in the horizontal wellbore by injecting steam or non-oxidizing gas. The software was the STARS™ In Situ Combustion Simulator provided by the Computer Modelling Group, Calgary, Alberta, Canada.

TABLE 4
List the Model Parameters.
Simulator: STARS ™ 2003.13, Computer Modelling Group Limited
Model dimensions:
Length 250 m, 100 grid blocks, eac
Width 25 m, 20 grid blocks
Height 20 m, 20 grid blocks
Grid Block dimensions: 2.5 m × 2.5 m × 1.0 m (LWH).
Horizontal Production Well:
A discrete well with a 135 m horizontal section extending from
grid block 26, 1, 3 to 80, 1, 3
The toe is offset by 15 m from the vertical air injector..
Vertical Injection Well:
Oxidizing gas(air) injection points: 20, 1, 1:4 (upper 4-grid blocks)
Oxidizing gas injection rates: 65,000 m3/d, 85,000 m3/d or 100,000 m3/d
Steam injection points: 20, 1, 19:20 (lower 2-grid blocks)
Rock/fluid Parameters:
Components: water, bitumen, upgrade, methane, CO2, CO/N2, oxygen,
coke
Heterogeneity: Homogeneous sand.
Permeability: 6.7 D (h), 3.4 D (v)
Porosity: 33%
Saturations: Bitumen 80%, water 20%, gas Mole fraction 0.114
Bitumen viscosity: 340,000 cP at 10° C.
Bitumen average molecular weight: 550 AMU
Upgrade viscosity: 664 cP at 10° C.
Upgrade average molecular weight: 330 AMU
Physical Conditions:
Reservoir temperature: 20° C.
Native reservoir pressure: 2600 kPa.
Bottomhole pressure: 4000 kPa.
Reactions:
1. 1.0 Bitumen ----> 0.42 Upgrade + 1.3375 CH4 + 20 Coke
2. 1.0 Bitumen + 16 O2{circumflex over ( )}0.05 ----> 12.5 water + 5.0 CH4 + 9.5 CO2 +
0.5 CO/N2 + 15 Coke
3. 1.0 Coke + 1.225 O2 ----> 0.5 water + 0.95 CO2 + 0.05 CO/N2

EXAMPLES

Example 1

Table 1a shows the simulation results for an air injection rate of 65,000 m3/day (standard temperature and pressure) into a vertical injector (E in FIG. 1). The case of zero steam injected at the base of the reservoir at point I in well J is not part of the present invention. At 65,000 m3/day air rate, there is no oxygen entry into the horizontal wellbore even with no steam injection and the maximum wellbore temperature never exceeds the target of 425° C.

However, as may be seen from the data below, injection of low levels of steam at levels of 5 and 10 m3/day (water equivalent) at a point low in the reservoir (E in FIG. 1) provides substantial benefits in higher oil recovery factors, contrary to intuitive expectations. Where the injected medium is steam, the data below provides the volume of the water equivalent of such steam, as it is difficult to otherwise determine the volume of steam supplied as such depends on the pressure at the formation to which the steam is subjected to. Of course, when water is injected into the formation and subsequently becomes steam during its travel to the formation, the amount of steam generated is simply the water equivalent given below, which typically is in the order of about 1000× (depending on the pressure) of the volume of the water supplied.

TABLE 1a
AIR RATE 65,000 m3/day-Steam injected at reservoir base.
Steam
Injection Rate	Maximum well			Bitumen recovery	Average oil
m3/day	Temperature,	Maximum coke	Maximum Oxygen	Factor	Production Rate
(water equivalent)	° C.	in wellbore %	in wellbore %	% OOIP	m3/day
*0	410	90	0	35.1	28.3
5	407	79	0	38.0	29.0
10	380	76	0	43.1	29.8
*Not part of the present invention.

Example 2

Table 1b shows the results of injecting steam into the horizontal well via the internal tubing, G, in the vicinity of the toe while simultaneously injecting air at 65,000 m3/day (standard temperature and pressure) into the upper part of the reservoir. The maximum wellbore temperature is reduced in relative proportion to the amount of steam injected and the oil recovery factor is increased relative to the base case of zero steam. Additionally, the maximum volume percent of coke deposited in the wellbore decreases with increasing amounts of injected steam. This is beneficial since pressure drop in the wellbore will be lower and fluids will flow more easily for the same pressure drop in comparison to wells without steam injection at the toe of the horizontal well.

TABLE 1b
AIR RATE 65,000 m3/day-Steam injected in well tubing.
Steam
Injection Rate	Maximum well			Bitumen recovery	Average oil
m3/day	Temperature,	Maximum coke	Maximum Oxygen	Factor	Production Rate
(water equivalent)	° C.	in wellbore %	in wellbore %	% OOIP	m3/day
*0	410	90	0	35.1	28.6
5	366	80	0	43.4	30.0
10	360	45	0	43.4	29.8
*Not part of the present invention.

Example 3

In this example, the air injection rate was increased to 85,000 m3/day (standard temperature and pressure) and resulted in oxygen breakthrough as shown in Table 2a. An 8.8% oxygen concentration was indicated in the wellbore for the base case of zero steam injection. Maximum wellbore temperature reached 1074° C. and coke was deposited decreasing wellbore permeability by 97%. Operating with the simultaneous injection of 12 m3/day (water equivalent) of steam at the base of the reservoir via vertical injection well C (see FIG. 1)provided an excellent result of zero oxygen breakthrough, acceptable coke and good oil recovery.

TABLE 2a
AIR RATE 85,000 m3/day-Steam injected at reservoir base.
Steam
Injection Rate	Maximum well			Bitumen recovery	Average oil
m3/d	Temperature,	Maximum coke	Maximum Oxygen	Factor	Production Rate
(water equivalent)	° C.	in wellbore %	in wellbore %	% OOIP	m3/day
*0	1074	97	8.8
5	518	80	0
12	414	43	0	36.1	33.4
*Not part of the present invention.

Example 4

Table 2b shows the combustion performance with 85,000 m3/day air (standard temperature and pressure) and simultaneous injection of steam into the wellbore via an internal tubing G (see FIG. 1) . Again 10 m3/day (water equivalent) of steam was needed to prevent oxygen breakthrough and an acceptable maximum wellbore temperature.

TABLE 2b
AIR RATE 85,000 m3/d. Steam injected in well tubing.
Steam
Injection Rate	Maximum well			Bitumen recovery	Average oil
m3/d	Temperature,	Maximum coke	Maximum Oxygen	Factor	Production Rate
(water equivalent)	° C.	in wellbore %	in wellbore %	% OOIP	m3/day
*0	1074	100	8.8
5	500	96	1.8
10	407	45	0	37.3	33.2
*Not part of the present invention.

Example 5

In order to further test the effects of high air injection rates, several runs were conducted with 100,000 m3/day air injection. Results in Table 3a indicate that with simultaneous steam injection at the base of the reservoir (ie at location B-E in vertical well C-ref. FIG. 1), 20 m3/day (water equivalent) of steam was required to stop oxygen breakthrough into the horizontal leg, in contrast to only 10 m3/day steam (water equivalent) at an air injection rate of 85,000 m3/day.

TABLE 3a
AIR RATE 100,000 m3/day-Steam injected at reservoir base.
Steam
Injection Rate	Maximum well			Bitumen recovery	Average oil
m3/day	Temperature,	Maximum coke	Maximum Oxygen	Factor	Production Rate
(water equivalent)	° C.	in wellbore %	in wellbore %	% OOIP	m3/day
*0	1398	100	10.4
5	1151	100	7.2
10	1071	100	6.0
20	425	78	0	34.5	35.6
*Not part of the present invention.

Example 6

Table 3b shows the consequence of injecting steam into the well tubing G(ref. FIG. 1) while injecting 100,000 m3/day air into the reservoir. Identically with steam injection at the reservoir base, a steam rate of 20 m3/day (water equivalent) was required in order to prevent oxygen entry into the horizontal leg.

TABLE 3b
AIR RATE 100,000 m3/d. Steam injected in well tubing.
Steam
Injection Rate	Maximum well			Bitumen recovery	Average oil
m3/day	Temperature,	Maximum coke	Maximum Oxygen	Factor	Production Rate
(water equivalent)	° C.	in wellbore %	in wellbore %	% OOIP	m3/day
*0	1398	100	10.4
5	997	100	6.0
10	745	100	3.8
20	425	38	0	33.9	35.6
*Not part of the present invention.

SUMMARY

For a fixed amount of steam injection, the average daily oil recovery rate increased with air injection rate. This is not unexpected since the volume of the sweeping fluid is increased. However, it is surprising that the total oil recovered decreases as air rate is increased. This is during the life of the air injection period (time for the combustion front to reach the heel of the horizontal well).

Although the disclosure described and illustrates preferred embodiments of the invention, it is to 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 to be made to the appended claims.

The embodiments of the invention in which an exclusive property or privilege is claimed are defined as follows:

Claims

1. A process for extracting liquid hydrocarbons from an underground reservoir comprising the steps of: (a) providing at least one injection well for injecting an oxidizing gas into the underground reservoir;(b) providing at least one production well having a substantially horizontal leg and a substantially vertical production well connected thereto, wherein the substantially horizontal leg extends toward the injection well, the horizontal leg having a heel portion in the vicinity of its connection to the vertical production well and a toe portion at the opposite end of the horizontal leg, wherein the toe portion is closer to the injection well than the heel portion;(c) injecting an oxidizing gas through the injection well to conduct in situ combustion, so that combustion gases are produced so as to cause the combustion gases to progressively advance as a front, substantially perpendicular to the horizontal leg, in the direction from the toe portion to the heel portion of the horizontal leg, and fluids drain into the horizontal leg;(d) providing a tubing inside the production well within said vertical leg and at least a portion of said horizontal leg for the purpose of injecting steam, water or non-oxidizing gas into said horizontal leg portion of said production well proximate a combustion front formed at a horizontal distance along said horizontal leg of said production well;(e) injecting a medium selected from the group of mediums comprising steam, water, or non-oxidizing gas, into said tubing so that said medium is conveyed proximate said toe portion of said horizontal leg portion via said tubing; and(f) recovering hydrocarbons in the horizontal leg of the production well from said production well.

2. The process of claim 1 wherein said medium is water, and said water is heated at the time of supply to the reservoir to become steam.

3. The process of claim 1 wherein the injection well is a vertical, slant or 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 permit injection of said medium into the underground reservoir.

5. The process of claim 1 wherein a non-oxidizing gas is injected into said tubing alone or in combination with steam or water.

6. The process of claim 1 wherein an open end of the tubing is in the vicinity of the toe of the horizontal section so as to permit delivery of steam or heated non-oxidizing gas to said toe.

7. The process of claim 1 or 6 wherein the tubing is partially pulled back or otherwise repositioned for the purpose of altering a point of injection of the steam, water or non-oxidizing gas along the horizontal leg.

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

9. A process for extracting liquid hydrocarbons from an underground reservoir, comprising the steps of: (a) providing at least one injection well for injecting an oxidizing gas into an upper part of an underground reservoir;(b) said at least one injection well further adapted for injecting steam, a non-oxidizing gas, or water which is subsequently heated to steam, into a lower part of an underground reservoir;(c) providing at least one production well having a substantially horizontal leg and a substantially vertical production well connected thereto, wherein the substantially horizontal leg extends toward the injection well, the horizontal leg having a heel portion in the vicinity of its connection to the vertical production well and a toe portion at the opposite end of the horizontal leg, wherein the toe portion is closer to the injection well than the heel portion;(d) injecting an oxidizing gas through the injection well for in situ combustion, so that combustion gases are produced, wherein the combustion gases progressively advance as a front, substantially perpendicular to the horizontal leg, in the direction from the toe portion to the heel portion of the horizontal leg, and fluids drain into the horizontal leg;(e) injecting a medium, wherein said medium is selected from the group of mediums comprising steam, water or a non-oxidizing gas, into said injection well ; and(f) recovering hydrocarbons in the horizontal leg of the production well from said production well.

10. A process for extracting liquid hydrocarbons from an underground reservoir, comprising the steps of: (a) providing at least one oxidizing gas injection well for injecting an oxidizing gas into an upper part of an underground 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 part of an underground reservoir;(c) providing at least one production well having a substantially horizontal leg and a substantially vertical production well connected thereto, wherein the substantially horizontal leg extends toward the injection well, the horizontal leg having a heel portion in the vicinity of its connection to the vertical production well and a toe portion at the opposite end of the horizontal leg, wherein the toe portion is closer to the oxidizing gas injection well than the heel portion;(d) injecting an oxidizing gas through the oxidizing injection well for in situ combustion, so that combustion gases are produced, wherein the combustion gases progressively advance as a front, substantially perpendicular to the horizontal leg, in the direction from the toe portion to the heel portion of the horizontal leg, and fluids drain into the horizontal leg;(e) injecting a medium, wherein said medium is selected from the group of mediums comprising steam, water or a non-oxidizing gas, into said other injection well; and(f) recovering hydrocarbons in the horizontal leg of the production well from said production well.

11. The process of claim 9 or 10 wherein said medium is water, and said water is subsequently heated to become steam and said steam is provided to said lower part of the formation via a distal end of said injection well.

12. A method for extracting liquid hydrocarbons from an underground reservoir, comprising the steps of: (a) providing at least one injection well for injecting an oxidizing gas into an upper part of an underground reservoir;(b) said at least one injection well further adapted for injecting steam, a non-oxidizing gas, or water which is subsequently heated to steam, into a lower part of an underground reservoir;(c) providing at least one production well having a substantially horizontal leg and a substantially vertical production well connected thereto, wherein the substantially horizontal leg extends toward the injection well, the horizontal leg having a heel portion in the vicinity of its connection to the vertical production well and a toe portion at the opposite end of the horizontal leg, wherein the toe portion is closer to the injection well than the heel portion;(d) providing a tubing inside the production well within said vertical leg and at least a portion of said horizontal leg for the purpose of injecting steam, water or non-oxidizing gas into said horizontal leg portion of said production well;(e) injecting an oxidizing gas through the injection well for in situ combustion, so that combustion gases are produced, wherein the combustion gases progressively advance as a front, substantially perpendicular to the horizontal leg, in the direction from the toe portion to the heel portion of the horizontal leg, and fluids drain into the horizontal leg;(f) injecting a medium, wherein said medium is selected from the group of mediums comprising steam, water or a non-oxidizing gas, into said injection well and into said tubing; and(g) recovering hydrocarbons in the horizontal leg of the production well from said production well.

13. The method of claim 12 wherein said medium is water, and said water is heated at the time of supply to the reservoir to become steam.

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

15. A method for extracting liquid hydrocarbons from an underground reservoir, comprising the steps of: (a) providing at least one injection well for injecting an oxidizing gas into an upper part of an underground 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 part of an underground reservoir;(c) providing at least one production well having a substantially horizontal leg and a substantially vertical production well connected thereto, wherein the substantially horizontal leg extends toward the injection well, the horizontal leg having a heel portion in the vicinity of its connection to the vertical production well and a toe portion at the opposite end of the horizontal leg, wherein the toe portion is closer to the injection well than the heel portion;(d) providing a tubing inside the production well within said vertical leg and at least a portion of said horizontal leg for the purpose of injecting steam, water or non-oxidizing gas into said horizontal leg portion of said production well;(e) injecting an oxidizing gas through the injection well for in situ combustion, so that combustion gases are produced, wherein the combustion gases progressively advance as a front, substantially perpendicular to the horizontal leg, in the direction from the toe portion to the heel portion of the horizontal leg, and fluids drain into the horizontal leg;(f) injecting a medium, wherein said medium is selected from the group of mediums comprising steam, water or a non-oxidizing gas, into said other injection well and into said tubing; and(g) recovering hydrocarbons in the horizontal leg of the production well from said production well.

16. The method of claim 15 wherein said medium is water, and said water is heated at the time of supply to the reservoir to become steam.

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