US20140041867A1

US20140041867A1 - Enhanced oil recovery initiated with zero emission in-situ combustion

Info

Publication number: US20140041867A1
Application number: US13/568,394
Authority: US
Inventors: John Belgrave
Original assignee: Individual
Current assignee: Individual
Priority date: 2012-08-07
Filing date: 2012-08-07
Publication date: 2014-02-13
Also published as: CA2786217A1

Abstract

The invention provides an enhanced oil recovery process that may be used in light oil reservoirs, and which is particularly beneficial in high-relief formations. The process includes an initial injection of air into the formation through an injection well to support the in-situ combustion and mobilize formation fluids. Produced flue gas is recovered and recycled into the formation by injection through an injection well. Initially, gas production is restricted for the purpose of increasing the gas injection to recovery ratio to pressurize the formation. With an increase in formation pressure, the rate of air injection is gradually reduced as the rate of recovered flue gas injection increases. Combustion front propagation in the formation is controlled by the rate of production at each actively producing well to ensure good horizontal sweep across the well and to prevent channeling to one or more production wells.

Description

FIELD OF THE INVENTION

The present invention relates generally to the enhanced recovery of petroleum fluid from subterranean formations by in-situ combustion. More particularly, the present invention relates to an in-situ combustion method for the enhanced recovery of petroleum fluids that results in increased recovery efficiency and reduced environmental impact by controlling the gas production rate across each producing well and by recycling recovered combustion gas that is rich in carbon dioxide back into the formation.

BACKGROUND OF THE INVENTION

Various enhanced oil recovery processes are used to improve recovery of oil and other formation fluids from subterranean formations. Enhanced oil recovery processes include chemical injection, gas injection, and thermal recovery. The focus herein is primarily made in reference to gas injection and thermal recovery processes.
Gas injection involves the forced injection of various gas mixtures into the subterranean formation with the purpose of increasing formation pressure and to miscibly or immiscibly displace the petroleum fluids in the formation towards one or more production wells. Gases conventionally injected into the formation include carbon dioxide, nitrogen and/or natural gas. Carbon dioxide injection may be referred to as carbon dioxide flooding and is used in high pressure application with light oil for miscible displacement by reducing viscosity and surface tension. Although in lower pressure or heavy oil applications, carbon dioxide flooding only partially mixes with the oil and forms an immiscible fluid, oil viscosity may still be significantly reduced. While carbon dioxide flooding enhances oil recovery, economic considerations restrict the process to locations where a source of carbon dioxide is readily available.
Thermal recovery involves the in-situ heating of reservoir fluid to increase its mobility within the formation, which increases production. In-situ combustion is a thermal recovery process used in the enhanced recovery of oil. In-situ combustion involves the injection of a gas containing oxygen, such as air, into the formation in order to initiate and sustain combustion of a small fraction of the petroleum fluid in the formation. Combustion of the petroleum fluid in the formation creates a combustion front that progresses through the formation, pushing ahead of it a mixture of hot combustion or flue gases, steam and hot water, which in turn reduces oil viscosity and displaces the oil toward production wells. In-situ combustion has high thermal efficiency because the heat energy is generated in-situ where it is needed and is not subject to surface or wellbore heat loss as with other recovery methods, such as steam injection and electrical resistance heating. Additionally, air is readily available and does not require sourcing, transportation and storage. Although there are many advantages to in-situ combustion over other methods of enhanced oil recovery, there are several drawbacks including, the risk of high temperature propagation towards production wells causing the destruction of the well and the risk of gas high in oxygen concentration reaching the producing wells which can result in fire and/or explosion. An environmental concern of in-situ combustion is the release of produced flue gas, rich in carbon dioxide, into the atmosphere and increasing the atmospheric greenhouse gases.

SUMMARY OF THE INVENTION

Embodiments of the present invention include an in-situ combustion method for the enhanced recovery of petroleum fluids from vertical or high relief subterranean formations or reservoirs. Flue gas generated by in-situ combustion reactions is produced and recycled back into the reservoir. The production rate of the flue gas is controlled in such a manner so as to promote gravity segregation between the gas and oil phases in the reservoir, high oil displacement efficiency, lower in-situ temperature and oxygen concentration levels, and a systematic reduction and elimination of the oxidizing gas injection. The methods described herein are particularly well suited for the enhanced recovery of light oil from high relief formations, such as, for example the Upper Devonian pinnacle reef pools found in Alberta, Canada and the like.
Enhanced oil recovery from the in-situ combustion methods described herein benefit from the recycling of recovered flue gas back into the formation by permitting a gradual reduction of injected oxidizing gas into formation. Recycling the flue gases reduces the oxygen concentration and temperature in the formation which considerably reduces the possibility of fires or explosions in the production wells. The methods herein are distinguishable from other in-situ combustion methods in that all of the flue gases generated by the combustion process are recycled back into the formation through the original air injection well in order to pressurize the formation to a target operating pressure and mobilize formation fluids towards production wells, while simultaneously reducing oxidizing gas injection. Formation pressurization and combustion front sweep through the formation are controlled by restricting flue gas production from each actively producing well such that the rate of flue gas produced at each well is about equal, and such that the collective flue gas production rate from the formation equals the rate of gas injected into the formation, which avoids excessive channeling of the flue gas to any one production well.
Enhanced oil recovery from the in-situ combustion methods described herein also benefit from the recycling of recovered flue gas back into the formation by burning or consuming less formation fluid to support the in-situ combustion compared to conventional or continuous air injection, since the recycled flue gas results in less air injection to recover formation fluids.
Embodiments of the present invention include an in-situ combustion method for the enhanced recovery of petroleum fluids from vertical or high relief subterranean formations with vertical injection and production wells penetrating the formation. In most instances, the methods herein are implemented as secondary or even later petroleum recovery processes, wherein the injection and production wells were originally placed during primary formation production. In these instances, the methods herein include re-perforating the production wells such that the perforation intervals of the producing wells are set at different elevations which together span the entire formation or reservoir vertically, prior to initiating in-situ combustion. With this arrangement, as the combustion front moves downwardly through the formation and across production well completions, these wells are shut-in, therefore production wells completed lower in the formation remain on production longer.
To achieve these and other advantages, in general, in one aspect, an enhanced oil recovery method is provided. The method includes the following process steps: (a) injecting an oxidizing gas into a subterranean formation through an injection well penetrating the formation to support in-situ combustion; (b) initiating an in-situ combustion operation in the formation forming a combustion front in the formation and producing a flue gas; (c) restricting production from all production wells penetrating the formation for a period of time during in-situ combustion until the formation is pressurized to a predetermined pressure by the flue gas and the oxidizing gas; (d) recovering formation fluids and the flue gas from the formation through a production well penetrating the formation; (e) separating the flue gas from the formation fluids; (f) injecting a gas mixture of oxidizing gas and all of the produced flue gas into the formation through an injection well penetrating the formation; (g) continuing injection of the gas mixture; and (h) continuing recovery of formation fluids and the flue gas from the formation. In general, in another aspect, amount of oxidizing gas in said gas mixture injected into said formation in step (g) is gradually reduced.
In general, in another aspect, the method further includes controlling the gas production rate at each actively producing well penetrating said formation such that each producing well produces gas at an equal gas production rate. Controlling the gas production rate at each actively producing well may be had such that the rate of gas produced from said formation equals the rate of gas injected into said formation.
There has thus been outlined, rather broadly, the more important features of the invention in order that the detailed description thereof that follows may be better understood and in order that the present contribution to the art may be better appreciated.
Numerous objects, features and advantages of the present invention will be readily apparent to those of ordinary skill in the art upon a reading of the following detailed description of presently preferred, but nonetheless illustrative, embodiments of the present invention when taken in conjunction with the accompanying drawings. The invention is capable of other embodiments and of being practiced and carried out in various ways. Also, it is to be understood that the phraseology and terminology employed herein are for the purpose of descriptions and should not be regarded as limiting.
As such, those skilled in the art will appreciate that the conception, upon which this disclosure is based, may readily be utilized as a basis for the designing of other structures, methods and systems for carrying out the several purposes of the present invention. It is important, therefore, that the claims be regarded as including such equivalent constructions insofar as they do not depart from the spirit and scope of the present invention.
For a better understanding of the invention, its operating advantages and the specific objects attained by its uses, reference should be had to the accompanying drawings and descriptive matter in which there are illustrated embodiments of the invention.

BRIEF DESCRIPTION OF THE DRAWINGS

The following drawings illustrate by way of example and are included to provide further understanding of the invention for the purpose of illustrative discussion of the embodiments of the invention. No attempt is made to show structural details of the embodiments in more detail than is necessary for a fundamental understanding of the invention, the description taken with the drawings making apparent to those skilled in the art how the several forms of the invention may be embodied in practice. Identical reference numerals do not necessarily indicate an identical structure. Rather, the same reference numeral may be used to indicate a similar feature of a feature with similar functionality. In the drawings:

FIG. 1 is a diagrammatic horizontal cross-sectional view of a high-relief formation having vertical injection and production wells in an in-situ combustion method in accordance with the principles of an embodiment of the present invention showing an operational configuration and implementation in an initial phase of the in-situ combustion method;

FIG. 2 is a diagrammatic horizontal cross-sectional view of a high-relief formation having vertical injection and production wells in an in-situ combustion method in accordance with the principles of an embodiment of the present invention showing an operational configuration and implementation in a growth or pressurization phase of the in-situ combustion method;

FIG. 3 is a diagrammatic horizontal cross-sectional view of a high-relief formation having vertical injection and production wells in an in-situ combustion method in accordance with the principles of an embodiment of the present invention showing an operational configuration and implementation in a maintenance phase of the in-situ combustion method;

FIGS. 4 a to 4 d illustrate a time series of formation temperature and formation fluid mobilization in a modeled formation during recovery by an in-situ combustion process in accordance with an embodiment of the present invention;

FIGS. 5 a to 5 d illustrate the same time series of formation temperature and formation fluid mobilization in the modeled formation during recovery by conventional in-situ combustion processes;

FIGS. 6 a to 6 d illustrate a time series of formation oxygen concentration and formation fluid mobilization in the modeled formation during recovery an in-situ combustion processes in accordance with an embodiment of the present invention;

FIGS. 7 a to 7 d illustrate the same time series of formation oxygen concentration and formation fluid mobilization in the modeled formation during recovery by conventional in-situ combustion processes;

FIG. 8 is a graph illustrating recovery performance comparison overtime between the in-situ combustion processes of the present invention and conventional in-situ combustion processes in using vertical wells;

FIG. 9 is a graph illustrating gas production and injection rates and reservoir pressure overtime in the in-situ combustion processes of the present invention;

FIG. 10 is a graph showing recovery performance comparison overtime between the in-situ combustion process of the present invention and conventional in-situ combustion, both using a single producing well that is horizontal; and

FIG. 11 is a graph comparing the recovery performances of the present invention using vertical producers versus that of using a single producing well that is horizontal.

DETAILED DESCRIPTION OF THE INVENTION

Several embodiments of the present invention are described below and illustrated in the accompanying drawings. In embodiments, there is an in-situ combustion method for the enhanced recovery of petroleum fluids from vertical or high relief subterranean formations or reservoirs where gravity segregation of flue gas and oil is utilized to provide increased sweep efficiency by controlling the rate in which flue gas is produced and by recycling recovered flue gas back into the well to establish and maintain well pressure, while reducing and ultimately eliminating oxidizing gas injection. Although the oxidizing gas may be any gas or mixture of gases that support combustion, in an embodiment, the oxidizing gas is atmospheric air. Advantages of using atmospheric air include being readily available at the well site and not requiring specialized equipment to provide a suitable supply for formation injection.
All of the flue gas produced from the formation is separated from formation fluid produced along with the flue gas, compressed and then recycled back into the formation by injection through an injection well. The flue gas may be combined with the oxidizing gas during injection or injected separately from the oxidizing gas. The flue gas, rich in carbon dioxide, reduces the oxygen concentration in the formation which has the effect of lowering formation temperatures and significantly reducing the risk of explosion in the producing wells. Additionally, the carbon dioxide in the flue gas readily dissolves in the formation oil reducing its viscosity, lowering the gas-oil interfacial tension, and under certain conditions is able to miscibly displace the oil in the formation. The occurrence of miscible displacement depends on several factors including the operating pressure. The methods herein do not require full miscibility to improve oil recovery, and rather the methods are directed, in one aspect, toward increasing formation pressure and lowering interfacial tension, and therefore residual oil saturation, by recycling the flue gas, and while permitting a reduction in oxidizing gas injection. In an aspect, an off-gas separation operation or other suitable fluid-gas separation operation may be performed in order to recover a stream of pure carbon dioxide from recovered flue gas. Here, the recovered, pure carbon dioxide stream would be injected (recycled) into the formation in a similar manner as the recovered flue gas comprising mix constitutes.
Referring now to FIGS. 1-3 of the drawings, there is diagrammatically illustrated an exemplary embodiment of the in-situ combustion, zero emission enhanced oil recovery system and method in accordance with the principals of the present invention, wherein FIG. 1 illustrates an initial operational and configuration phase; FIG. 2 illustrates a growth operational and configuration phase; and FIG. 3 illustrates a maintenance operational and configuration phase. Illustrated in FIGS. 1-3 is a diagrammatic cross-section of a high-relief petroleum-bearing formation or reservoir 10 having an injection well 12 that vertically penetrates the formation, and spaced apart production wells 14, 16 and 18 that vertically penetrate the formation. Although only a single injection well and three production wells are illustrated for the purpose of simplified discussion, any number of injection wells and/or production wells may be utilized in the methods and systems described herein. Horizontal producing wells positioned at low structural elevations may also be implemented in the current invention.
Injection well 12 is fluidically connected to the outlet of compressor 20, which in turn is fluidically connected to intake atmospheric air from the ambient surroundings, and fluidically connected via process line 22 to one or more gas-liquid separators 24 to receive a stream of recovered flue gas. Production wells 14, 16, 18 are fluidically connected to the one or more gas-liquid separators 24 via process line 26. Injection well 12 and production wells 14, 16, 18 are provided with wellheads configured to permit well injection and completion, respectively.
Further, production wells 14, 16, 18 are completed (perforated) at different elevations which together span the entire formation or reservoir vertical. For example, well 14 is completed to cover an upper vertical portion of the formation 10, well 16 is completed to cover a middle vertical portion of the formation, and well 18 is completed to cover a bottom vertical portion of the formation. In this manner, as will be described in more detail below, as the in-situ combustion process progresses through the formation, production wells 14, 16, 18 will be shut-in and taken off of production once the combustion or flue gas front reaches the completion interval associated with the respective production well.
With particular reference to FIG. 1, an initial operational and configuration phase of an in-situ combustion method in accordance with an embodiment of the present invention will be discussed. Initially, atmospheric air (oxidizing gas) is compressed via compressor 20 and injected under pressure into the formation 10 through injection well 12 in an amount sufficient to support in-situ combustion of petroleum fluid adjacent the injection well. In-situ combustion of these petroleum fluids is initiated by conventional means to establish a combustion front 28 and generate combustion or flue gas formed by the oxidation reaction with the petroleum formation fluids. The combustion or flue gas is rich in carbon dioxide and contains other gases such as nitrogen. Injection of the oxidizing gas is continued to advance the combustion front downwardly through the formation 10.
As the in-situ combustion progresses through the formation 10, the combustion front displaces a head of it mobilized formation fluids and flue gas toward the production wells 14, 16, 18 from which the formation fluids and flue gas are produced from the formation. The formation fluids and flue gas recovered from the production wells 14, 16, 18 are passed into a gas-liquid separator 24 via line 26 to separate the flue gas from the produced formation fluids. Formation fluids are recovered from the gas-liquid separator 24 by line 28 and all of the flue gas recovered from the gas-liquid separator is recycled to compressor 20 via line 22 for injection back into the formation along with the oxidizing gas. Although the flue gas is fed to compressor 20 for compression along with oxidizing gas for co-injection into the formation 10 through injection well 12, one or more separator compressors could be employed to compress recovered flue gas and inject the compressed flue gas into the formation through any desirable injection well.
For a time period after the start of the in-situ combustion in formation 10, the production of flue gas from production wells 14, 16, 18 is restricted for the purpose of increasing formation pressure by producing a lesser volume of gas from the formation than the volume of gas injected into the formation. As formation pressure increases towards a desired or predetermined formation operating pressure, the restriction on flue gas production is reduced resulting in increased recovery and recycling of flue gas back into the formation. As will be discussed further below, as the recovery and recycling rate of flue gas increases the rate of injection of oxidizing air is decreased with the purpose of reducing oxidizing air injection to a very minimum to maintain formation pressure at the predetermined formation pressure. In certain instances, dependent upon the geological frame work of the formation, the rate of oxidizing air injection may be eventually reduced to zero with the formation pressure being maintained entirely by the injection of recycled flue gas recovered from the formation.
The production rate of flue gas at each production well 14, 16, 18 is controlled so that the rate of flue gas production at each well is about the same with the purpose of preventing flue gas channeling and maintaining good horizontal and vertical sweep of the combustion front through the formation as the combustion progresses downward. Additionally, once the formation target or predetermined operating pressure is achieved, the rates of injected gas, oxidizing gas and recovered flue gas, and produced liquids and gases are controlled so that the operating pressure is held constant or such that the voidage replacement ratio is unity. That is, at the formation conditions of temperature, the rate at which fluids are injected is equal to the rate as which fluids are produced.
As the in-situ combustion progresses through the formation 10, the in-situ combustion method in accordance with an embodiment of the present invention enters into a growth operational configuration and implementation phase, which is illustrated in FIG. 2. During this phase, formation pressure approaches the target or predetermined formation operation pressure, flue gas production and injection rate increases and oxidizing gas injection rate decreases. The increased rate of flue gas injection, rich in carbon dioxide, and the decreased rate of oxidizing gas injection results in oxidizing gas dilution and lower in-situ combustion temperatures. The combustion front progression in formation 10 is further illustrated in FIG. 2 to have reached the completion interval of production well 14, which has been shut-in and brought off of production leaving remaining production wells 16 and 18 on production.
In FIG. 3, there is illustrated a maintenance operational configuration and implementation phase of the in-situ combustion method in accordance with an embodiment of the present invention. During this phase, formation pressure has reached the target or predetermined formation operation pressure, flue gas production and injection rate is at system capacity, and oxidizing gas injection rate is decreased to only maintain formation operation pressure. Formation temperatures decline further from quenching by the recycled flue gas and formation oxygen concentrations decline further by dilution from the recycled flue gas. Additional production wells are shut-in (production well 16) as gas to formation fluid production ratios increases due to the vertical, downward movement of the flue gas and thermal front. The in-situ combustion method of the present invention remains at this phase and continues to produce formation fluids until Vertical sweep of the reservoir is practically complete. At this time the lowest perforation intervals have experienced significant gas breakthrough and producing gas-oil ratios are excessively high.
To illustrate the advantages of the present in-situ combustion method over a conventional in-situ combustion method for the enhanced recovery of petroleum fluids from vertical or high relief subterranean formations both processes have been modeled using an advanced state-of-the-art reservoir simulator. The simulation rigorously accounted for inter-phase mass transfer, oxidation reaction kinetics, and energy and mass transport in a porous medium. The model tracked combustion temperatures, phase saturations, phase compositions, and formation pressure distribution. In particular, oxygen concentration in the gas phase was investigated.
FIGS. 4 a through 4 d illustrate a time series of formation temperature and formation fluid mobilization in the modeled formation during recovery by in-situ combustion processes of the present invention. In comparison, FIGS. 5 a through 5 d illustrate the same time series of formation temperature and formation fluid mobilization in the modeled formation during recovery by conventional in-situ combustion processes. This comparison illustrates the substantially reduced formation temperatures utilizing the in-situ combustion processes of the present invention over conventional in-situ combustion processes.
FIGS. 6 a through 6 d illustrate a time series of formation oxygen concentration and formation fluid mobilization in the modeled formation during recovery by in-situ combustion processes of the present invention. In comparison, FIGS. 7 a through 7 d illustrate the same time series of formation oxygen concentration and formation fluid mobilization in the modeled formation during recovery by conventional in-situ combustion processes. This comparison illustrates the substantially reduced formation oxygen concentrations utilizing the in-situ combustion processes of the present invention over conventional in-situ combustion processes.
FIG. 8 is a graph illustrating recovery performance comparison overtime between the in-situ combustion processes of the present invention and conventional in-situ combustion processes in using vertical wells. These profiles show that there very little loss in recovery efficiency associated with the current invention compared to the conventional process. However at the end of the process described by the current invention, all flue gases have been completely sequestered in the formation which is environmentally desirable.
FIG. 9 is a graph illustrating gas production and injection rates and corresponding formation pressures overtime in the in-situ combustion processes of the present invention. The graph shows the relative duration and quantity of air injected compared to flue gas injection. Significantly less air is injected compared to the volume of flue gas recycled. Air is injected essentially for pressurization of the formation and to generate an adequate volume of flue gas for fluid displacement.
Although the above discussion of the present in-situ combustion method is made in reference vertical wells in high-relief formations, horizontal wells can also benefit from the processes of the present in-situ combustion method. With reference to FIG. 10, there is illustrated a graph showing recovery performance comparison over time between the in-situ combustion processes of the present invention and conventional in-situ combustion processes. Both scenarios use a single producing well that is horizontal and situated at the base of the formation. FIG. 10 shows that very little loss in recovery efficiency is to be expected with the current invention, compared to the conventional process, when a horizontal well is used to produce reservoir fluid. The current invention, however, consumes less formation fluid and sequesters all of the flue gases.
Further, new horizontal and the more common existing vertical producing wells can benefit from the processes of the present in-situ combustion method. With reference to FIG. 11, there is illustrated a graph comparing the performance of a horizontal producer versus that using vertical producers. The horizontal well is observed to drain the formation fluids with higher recovery efficiency, but both implementations of the current invention are effective in recovering additional oil.
A number of embodiments of the present invention have been described. Nevertheless, it will be understood that various modifications may be made without departing from the spirit and scope of the invention. Accordingly, other embodiments are within the scope of the following claims.

Claims

What is claimed is:

1. An enhanced oil recovery method, comprising:

(a) injecting an oxidizing gas into a subterranean formation through an injection well penetrating said formation to support in-situ combustion;

(b) initiating an in-situ combustion operation in said formation forming a combustion front in said formation and producing a flue gas;

(c) restricting production from all production wells penetrating said formation for a period of time during in-situ combustion until said formation is pressurized to a predetermined pressure by said flue gas and said oxidizing gas;

(d) recovering formation fluids and said flue gas from said formation through a production well penetrating said formation;

(e) separating said flue gas from said formation fluids;

(f) injecting a gas mixture of oxidizing gas and substantially all of said recovered flue gas into said formation through an injection well penetrating said formation;

(g) continuing injection of said gas mixture; and

(h) continuing recovery of formation fluids and said flue gas from said formation.

2. The method of claim 1, wherein the amount of oxidizing gas in said gas mixture injected into said formation in step (g) is gradually reduced.

3. The method of claim 1, wherein said formation is a high-relief formation.

4. The method of claim 1, wherein said injection well is a vertical well.

5. The method of claim 1, wherein said production well is a vertical or horizontal well.

6. The method of claim 1, wherein said oxidizing gas is atmospheric air.

7. The method of claim 1, further comprising:

(i) controlling the gas production rate at each actively producing well penetrating said formation such that each producing well produces gas at an equal gas production rate.

8. The method of claim 7, wherein during controlling step (i) further controlling the gas production rate at each actively producing well such that the rate of gas produced from said formation equals the rate of gas injected into said formation.

9. The method of claim 1, further comprising:

(i) shutting-in a production well vertically penetrating said formation when in-situ combustion in said formation reaches the perforation interval of said production well.

10. The method of claim 9, wherein the amount of oxidizing gas in said gas mixture injected into said formation in step (g) is gradually reduced.

11. The method of claim 9, wherein said oxidizing gas is atmospheric air.

12. The method of claim 9, further comprising:

(j) controlling the gas production rate at each actively producing well penetrating said formation such that each producing well produces gas at an equal gas production rate.

13. The method of claim 12, wherein during controlling step (j) further controlling the gas production rate at each actively producing well such that the rate of gas produced from said formation equals the rate of gas injected into said formation.

14. The method of claim 13, wherein the amount of oxidizing gas in said gas mixture injected into said formation in step (g) is gradually reduced.