HYDROCARBON RECOVERY PROCESS
A process for hydrocarbon recovery from a hydrocarbon-bearing formation utilizing an injection well for the injection of a mobilizing and displacing fluid, such as steam, into the formation and a production well, spaced from the injection well, and through which hydrocarbon is recovered. The process includes injecting a surfactant and a gas into the production well for a first period of time to thereby emplace or form foam to an extent sufficient to modify the path of flow in an inter-well region between the injection well and the production well and in an area spaced from the inter-well region of the reservoir, which area is in fluid communication with at least one of the injection well and the production well. The process also includes injecting fluid into the injection well to cause the flow of hydrocarbon in the formation and recovering the hydrocarbon through the production well.
Any and all applications for which a foreign or domestic priority claim is identified in the Application Data Sheet as filed with the present application are hereby incorporated by reference under 37 CFR 1.57. This application claims the benefit of priority to U.S. Provisional Application No. 61/985,307, filed Apr. 28, 2014, the entire contents of which are hereby incorporated in their entirety.
BACKGROUND1. Field
The present invention relates to the production of hydrocarbons such as heavy oils and bitumen from an underground reservoir utilizing foam to distribute injected displacing and mobilizing fluids, such as steam, in the reservoir.
2. Description
Low recovery efficiency of hydrocarbons from oil reservoirs is common and, in large part, is due to the difference in viscosity between a typical displacing fluid and the oil. Displacement of the more viscous oil, by the less viscous water or steam or non-condensing gas, tends to promote non-uniform advance of the displacement front, including the development of channels or fingers, and consequent poor overall recovery. This may occur because of the inherent instabilities in the fluid displacement process even when a reservoir is generally homogeneous. Because of the heterogeneous nature of most reservoirs, the non-uniform displacement of hydrocarbons is that much more pronounced. This non-uniformity of displacement can also be abetted by differences in density between the displaced and displacing fluids in situations where segregation of the fluids due to the influence of gravity can occur and adversely affects recovery, for example, in a displacement process in which the desired direction of displacement is horizontal.
Extensive deposits of viscous hydrocarbons exist around the world, including large deposits in the Northern Alberta oil sands that are not susceptible to standard oil well production technologies. One problem associated with producing hydrocarbons from such deposits is that the hydrocarbons are too viscous to flow at commercially relevant rates at the temperatures and pressures present in the reservoir. For such reservoirs, thermal techniques may be used to heat the reservoir to mobilize the hydrocarbons and produce the heated, mobilized hydrocarbons from wells. One such technique for utilizing a horizontal well for injecting heated fluids and producing hydrocarbons is described in U.S. Pat. No. 4,116,275, which also describes some of the problems associated with the production of mobilized viscous hydrocarbons from horizontal wells, the entire contents of which are hereby incorporated by reference.
One thermal method of recovering viscous hydrocarbons using spaced horizontal wells is known as steam-assisted gravity drainage (SAGD). SAGD utilizes gravity in a process that relies on density difference of the mobile fluids to achieve a desirable vertical segregation within the reservoir. Various embodiments of the SAGD process are described in Canadian Patent No. 1,304,287 and corresponding U.S. Pat. No. 4,344,485 the entire contents of which are hereby incorporated by reference. In the SAGD process, pressurized steam is delivered through an upper, horizontal, injection well into a viscous hydrocarbon reservoir while hydrocarbons are produced from a lower, parallel, horizontal, production well that is vertically spaced and near the injection well. The injection and production wells are typically situated in the lower portion of the reservoir, with the producer located close to the base of the hydrocarbon deposit to collect the hydrocarbons that flow toward the bottom.
The SAGD process is believed to work as follows. The injected steam initially mobilizes the hydrocarbons to create a steam chamber in the reservoir around and above the horizontal injection well. The term steam chamber is utilized to refer to the volume of the reservoir that is saturated with injected steam and from which mobilized oil has at least partially drained. As the steam chamber expands, viscous hydrocarbons in the reservoir are heated and mobilized and move with aqueous condensate, under the effect of gravity, toward the bottom of the steam chamber, where the viscous hydrocarbons and aqueous condensate accumulate such that the liquid/vapor interface is located below the steam injector and above the producer. The heated hydrocarbons and aqueous condensate are collected and produced from the production well.
Other gravity-utilizing thermal recovery processes which are analogous to SAGD, and which have been performed in the field, include processes in which solvents are introduced either along with or in lieu of steam, as well as recovery processes in which non-condensing gases are injected along with or in lieu of steam. As recovery progresses in such processes, the efficiency of recovery may decline due to the non-uniform displacement of the hydrocarbons, as described above.
Further improvements in efficiency of recovery of hydrocarbons are desirable.
SUMMARYAccording to an aspect of an embodiment, a process is provided for hydrocarbon recovery from a hydrocarbon-bearing formation utilizing an injection well for the injection of a mobilizing and displacing fluid, such as steam, into the formation, and a production well, spaced from the injection well, and through which hydrocarbon is recovered. The process includes injecting a surfactant and a gas into the production well for a first period of time to thereby emplace or form foam to an extent sufficient to modify the path of flow in an inter-well region between the injection well and the production well and in an area spaced from the inter-well region of the reservoir, which area is in fluid communication with at least one of the injection well and the production well. A fluid, such as steam, is injected into the injection well to cause the flow of hydrocarbon in the formation and the hydrocarbon is recovered through the production well.
The surfactant and the gas may also be injected into the injection well to emplace or form foam for a second period of time that overlaps at least partially in time with the first period of time during which the surfactant and the gas are injected into the production well.
The surfactant and the gas injection into the production well to emplace or form foam may be repeated in the production well or in both the production well and the injection well.
The surfactant and the gas may be injected into the production well for a second period of time to further emplace or form foam.
The surfactant and the gas injection may be repeated after recovery of hydrocarbon through the production well. The volume of surfactant injected may increase with each repetition.
The surfactant in combination with the gas may form an aqueous foam. Alternatively, the surfactant in combination with the gas may form an oleic foam.
In another aspect disclosed herein, a process for hydrocarbon recovery from a hydrocarbon-bearing formation utilizing an injection well and a production well, spaced at least vertically from the injection well, the process comprises injecting a surfactant and a gas into the production well for a first period of time to thereby emplace or form foam within the formation to an extent sufficient to modify the pattern of flow in an inter-well region between the injection well and the production well and in an area spaced from the inter-well region of the formation, which area is in fluid communication with at least one of the injection well and the production well; injecting fluid, into the injection well to cause the flow of hydrocarbon in the formation; and recovering the hydrocarbon through the production well.
In some embodiments, the gas comprises steam and one or more non-condensing gases.
In some embodiments, the gas comprises one or more non-condensing gases.
In some embodiments, the gas or gases injected at the production well differ from the fluid injected at the injection well.
In some embodiments, the process comprises repeating the injecting the surfactant and the gas into the production well.
In some embodiments, the process comprises injecting the surfactant and the gas for a second period of time into the injection well to further emplace or form foam.
In some embodiments, the second period of time begins before the first period of time begins.
In some embodiments, the first period of time begins before the second period of time begins
In some embodiments, the second period of time during which the surfactant and the gas are injected into the injection well, overlaps at least partially in time with the first period of time during which the surfactant and the gas are injected into the production well.
In some embodiments, the process comprises periodically repeating injecting the surfactant and the gas into the production well and repeating injecting the surfactant and the gas in to the injection well.
In some embodiments, the process comprises, after recovering the hydrocarbon through the production well, repeating injecting the surfactant to create or emplace a foam within the formation, wherein a greater volume of surfactant is injected when the injecting is repeated.
In some embodiments, the surfactant is injected while the gas is injected.
In some embodiments, the surfactant is injected as foam such that the surfactant and the gas are injected together.
the surfactant is injected and is foamed in the formation.
In some embodiments, an oil recovery rate increases when the surfactant and the gas are injected.
In some embodiments, a steam-oil ratio decreases when the surfactant and the gas are injected.
In some embodiments, the production well and the injection well are housed, at least partially, in a single physical wellbore.
The process according to claim 1, wherein the production well and the injection well are functionally independent components, hydraulically isolated from each other, and housed within a single physical wellbore.
Embodiments of the present invention will be described, by way of example, with reference to the drawings and to the following description.
For simplicity and clarity of illustration, reference numerals may be repeated among the figures to indicate corresponding or analogous elements. Numerous details are set forth to provide an understanding of the examples described herein. The examples may be practiced without these details. In other instances, well-known methods, procedures, and components are not described in detail to avoid obscuring the examples described. The description is not to be considered as limited to the scope of the examples described herein.
The disclosure generally relates to a process for hydrocarbon recovery from a hydrocarbon-bearing formation utilizing an injection well for the injection of a mobilizing and displacing fluid, such as steam, into the formation and a production well, spaced from the injection well, and through which hydrocarbon is recovered. The process includes injecting a surfactant and a gas into the production well for a first period of time to thereby emplace or form foam to an extent sufficient to modify the path of flow in an inter-well region between the injection well and the production well and in an area spaced from the inter-well region of the reservoir, which area is in fluid communication with at least one of the injection well and the production well. After injecting the surfactant and the gas, steam is injected into the injection well to cause the flow of hydrocarbon in the formation and the hydrocarbon is recovered through the production well.
As noted above, the present disclosure relates to the injection of a mobilizing and displacing fluid, such as steam. In the present example, the process is described in relation to steam and, specifically to SAGD. Other processes may be utilized that do not involve steam or SAGD, however. Furthermore, throughout the description, reference is made to an injection well and a production well. The injection well and the production well may be physically separate wells. Alternatively, the production well and the injection well may be housed, at least partially, in a single physical wellbore, for example, a multilateral well. The production well and the injection well may be functionally independent components that are hydraulically isolated from each other, and housed within a single physical wellbore.
As described above, a steam assisted gravity drainage (SAGD) process may be utilized for mobilizing viscous hydrocarbons. In the SAGD process, a well pair, including a hydrocarbon production well and a steam injection well are utilized. One example of a well pair is illustrated in
During SAGD, steam is injected into the steam injection well to mobilize the hydrocarbons and create a steam chamber in the reservoir 106, around and above the generally horizontal segment 112. In addition to steam injection into the steam injection well, light hydrocarbons, such as the C3 through C10 alkanes, either individually or in combination, may optionally be injected with the steam such that the light hydrocarbons function as solvents in aiding the mobilization of the oil. The volume of light hydrocarbons that are injected is relatively small compared to the volume of steam injected. The addition of light hydrocarbons is referred to as a solvent-assisted process (SAP). Alternatively, or in addition to the light hydrocarbons, various non-condensing gases, such as methane or carbon dioxide, may be injected. Viscous hydrocarbons in the reservoir are heated and mobilized and the mobilized hydrocarbons drain, under the effects of gravity. Fluids, including the mobilized hydrocarbons along with aqueous condensate, are collected in the generally horizontal segment 102. The fluids may also include gases such as steam and production gases from the SAGD process.
As recovery progresses, the efficiency of recovery may decline in part due to the non-uniform displacement of the hydrocarbons by the steam and by the resulting aqueous condensate. To increase the efficiency of recovery, a surfactant is injected into the production well. The surfactant may be foamed surfactant or may be foamable or suitable for forming a foam in the formation. Surfactant may also be injected into the injection well.
The injection of a foam into an oil reservoir to inhibit such non-uniform displacement has been investigated in the laboratory and practiced in the field. The foam, upon entering the channels or fingers that have developed during the unstable displacement, acts to impede flow in those channels, thereby causing displacing fluids that are injected into the reservoir to be, at least in part, diverted to regions that might otherwise be by-passed, thereby achieving greater uniformity of advance of the displacement front and improved oil recovery.
Foams are typically created by bringing a surfactant and a non-condensing gas into contact to generate the foam. Early applications of foam involved conventional oil reservoirs or reservoirs containing heavy, yet mobile oil. As such, the recovery process was often conducted at ambient reservoir temperature, meaning that the recovery process was generally conducted without attempting to increase or decrease the temperature within the reservoir.
A considerable amount of laboratory-scale work has been carried out to better characterize foam behavior. Attempts to describe foam behavior in mathematical relationships and to capture that behaviour in a mathematical model have been made. The behaviour of the foam is complex, however, and such models include both analytical principles and empirical findings.
For example, the effectiveness of a given gas-surfactant foam in reducing mobility of steam or aqueous condensate in channels or fingers within a reservoir is a function of the velocity of the gas, the concentration of surfactant, the resulting bubble size and foam texture, and the presence of oil. Furthermore, it has been found that the presence of oil can cause deterioration of a foam.
The surfactant may be injected into the injection well during the injection of surfactant into the production well such that the period of time during which surfactant is injected into the production well overlaps, at least partially in time, with the period of time during which surfactant is injected into the injection well. Alternatively, the surfactant may be injected into the production well, followed by injection of the surfactant into the injection well or surfactant may be injected into the injection well, followed by injection of surfactant into the production well.
The surfactant may be foamed by mixing with gas prior to or during injection into the reservoir. Alternatively, the surfactant may be injected into the reservoir prior to foaming such that the surfactant is emplaced, followed by injection of a gas to form foam. The gas may be, for example, steam injected into the hydrocarbon production well, after injection of the surfactant. Alternatively, the gas may be a non-condensing gas, such as carbon dioxide, methane, nitrogen, exhaust gases, or a combination thereof.
The surfactant is injected for a period of time to emplace or form foam to an extent such that the foam inhibits the flow of mobilizing and displacing fluids, such as steam or aqueous condensate along high mobility channels or fingers in the reservoir, thereby increasing uniformity of advance of the mobilizing and displacing fluids. Sufficient foam is injected or formed such that the path of flow of the mobilizing and displacing fluids in the inter-well region, which is the region of the reservoir between the injection and the production well pair, is modified, and the path of flow of mobilizing and displacing fluids in an area that is spaced from the inter-well region and is in fluid communication with the injection well and the production well, is also modified. Optionally, foam stabilizing agents may be added to the surfactant that is injected to reduce the amount or frequency or both amount and frequency of the surfactant injection.
Thus, the foam causes a change in the path or paths of flow of the mobilizing and displacing fluids, not only in the inter-well region between the well pair, but in regions spaced from or away from the inter-well region such that the path of the displacing fluid is altered in other regions of the reservoir. Accordingly, the foam is not only a localized foam treatment in the region around the injection well or in the region around the production well, but, because of the changes that the foam causes to temperature, pressure, and fluid distribution within the overall active recovery process area of the formation, the foam changes recovery process performance. The path of travel of the mobilizing and displacing fluids may also be altered at other well-pairs in the formation that are spaced from the well-pair at which the surfactant is injected. Thus, in the specific case of SAGD, following merger or coalescence of adjacent steam chambers, the path of steam and aqueous condensate toward a second production well, which is spaced from the production well into which the surfactant is injected, may also be altered.
After foam emplacement or formation in the reservoir, a mobilizing and displacing fluid, such as steam, is injected into the injection well to cause the hydrocarbons to flow in the formation. The production well is utilized again for the production of hydrocarbons.
After recovering the hydrocarbon through the production well, the process is repeated by repeating the injection of surfactant at least at the production well. The volume of surfactant injected may be greater when the injection is repeated. The volume of surfactant injected when repeated may be increased at the production well, at the injection well, or at both the production well and the injection well.
The process of creation or emplacement of a foam may be repeated several times, such that a plurality of injections are carried out over the life of the recovery of hydrocarbons from the reservoir. The length of time of injection and the volume of surfactant utilized may be increased with each repetition. As indicated, foam stabilizing agents may be utilized to reduce the amount or frequency or both amount and frequency of the surfactant injection to create or emplace foam.
The creation or emplacement of foam by injecting a surfactant and a gas into the production well to an extent sufficient to modify the pattern of flow in an inter-well region between the injection well and the production well and in an area spaced from the inter-well region of the formation, which area is in fluid communication with at least one of the injection well and the production well beneficially alters temperatures, pressures, and fluid distribution throughout the active area of the reservoir.
The formation or emplacement of foam by injection in a direction opposite to the direction in which the network of flow non-uniformities was originally induced results in successful enhancement of performance. The creation or emplacement of foam is advantageous in reducing undesirable “hotspots” or regions of particularly high temperature by comparison to a remainder of the hydrocarbon reservoir and by comparison to a remaining path of flow in an inter-well region generally between the injection well and the production well. Specifically, the creation or emplacement of a foamed or foamable surfactant through the production well such that the paths of displacing and mobilizing fluids are modified in the inter-well region, as well as in a region that is spaced from the inter-well region and is in fluid communication with the injection well and the production well, leads to a surprising increase in the efficiency of recovery of hydrocarbons. In addition, the injection of foamable surfactant in both the production well and the injection well further increases efficiency beyond the increase expected by injecting a similar volume of foamable surfactant at only the production well. These performance enhancements and the breadth of influence of the foam within the reservoir are deduced from field-measured data, and are evident at least in the increase in oil production rate in response to the foam injection.
Rather than two separate well bores, the production well and the injection well may be functionally independent components that are hydraulically isolated from each other and are housed within a single physical wellbore.
The following examples are submitted to further illustrate various embodiments of the present invention. These examples are intended to be illustrative only and are not intended to limit the scope of the present invention.
A summary of examples is provided in table 1.
In which:
CUM OIL is the cumulative oil produced over the entire 5 years;
CUM STEAM is the cumulative steam injected over the entire 5 years;
CUM STEAM/OIL RATIO is the cumulative ratio of steam injected to oil produced over the entire 5 years; and
CUM FOAM/OIL RATIO is the cumulative ratio of foam formed or emplaced to oil produced over the entire 5 years.
The examples were carried out by computer modeling and the results illustrate the expected results of such an operation.
EXAMPLE 1Example 1 demonstrates the performance of the well pair after 5 years (1825 days) of operation without any foam injection or emplacement, and is referred to herein as the baseline.
Table 2 is a summary of the cycles of injection of surfactant and subsequent days of production of hydrocarbons, referred to generally as oil, from the production well for each of examples 2, 3, 4, and 5.
Example 2 demonstrates the performance of the well pair with foam injected via the injection well only, over 5 cycles during the 5 year period. Steam was injected via the injection well during the injection of foam at the injection well in each of the cycles. Oil was produced via the production well during the injection of foam in each of the cycles. Thus, in this example, oil production was continuous.
EXAMPLE 3Example 3 demonstrates the performance of the well pair with foam injected via the production well only, over 5 cycles during the 5 year period. Steam was injected via the production well during the injection of foam at the production well in each of the cycles. Oil was not produced via the production well during the injection of foam in each of the cycles.
EXAMPLE 4Example 4 demonstrates the performance of the well pair with foam injected via the injection well and the production well alternately such that foam was injected for a period of time in the production well followed by foam injected for the same period of time in the injection well. The injection was carried out over 5 cycles during the 5 year period. Steam was injected via the production well during the injection of foam at the production well in each of the cycles. Steam was also injected via the injection well and oil was produced via the production well during the injection of foam at the injection well in each of the cycles. Oil was not produced via the production well during the injection of foam via the production well.
EXAMPLE 5Example 5 demonstrates the performance of the well pair with foam injected via the injection well and the production well concurrently. The injection was carried out over 3 cycles during the 5 year period. Steam was injected during the injection of foam at both the production well and the injection well. Oil was not produced via the production well during the injection of foam. In this example, only 3 cycles were carried out because the injection of foam was very effective in re-distributing steam within the reservoir, resulting in a higher oil production rate and reduced foam volume per unit of oil produced by comparison to Examples 2 through 4.
Compared with Example 1, the baseline, all of the examples involving foam achieve improved hydrocarbon recovery rates, with the greatest improvement realized when foam is introduced concurrently at producer and injector.
A low steam to oil ratio is desirable. The steam to oil ratios are generally similar in the examples, with the exception of Example 4. The lowest, steam to oil ratio is realized when foam is introduced alternately at the producer and the injector.
A lower ratio of foam to steam is more economical. The lowest ratio of foam to steam occurs in the case where foam is introduced concurrently at the producer and the injector.
The Examples illustrate that beneficial alterations to flow in the inter-well region and in the steam chamber, are realized as a result of the introduction of foam at least at the producer.
The described embodiments are to be considered in all respects only as illustrative and not restrictive. The scope of the claims should not be limited by the preferred embodiments set forth in the examples, but should be given the broadest interpretation consistent with the description as a whole. All changes that come with meaning and range of equivalency of the claims are to be embraced within their scope.
Claims
1. A process for hydrocarbon recovery from a hydrocarbon-bearing formation utilizing an injection well and a production well, spaced at least vertically from the injection well, the process comprising:
- injecting a surfactant and a gas into the production well for a first period of time to thereby emplace or form foam within the formation to an extent sufficient to modify the pattern of flow in an inter-well region between the injection well and the production well and in an area spaced from the inter-well region of the formation, which area is in fluid communication with at least one of the injection well and the production well;
- injecting fluid, into the injection well to cause the flow of hydrocarbon in the formation; and
- recovering the hydrocarbon through the production well.
2. The process according to claim 1, wherein the gas comprises steam and one or more non-condensing gases.
3. The process according to claim 1, wherein the gas comprises one or more non-condensing gases.
4. The process according to claim 1, wherein the gas or gases injected at the production well differ from the fluid injected at the injection well.
5. The process according to claim 1, comprising repeating the injecting the surfactant and the gas into the production well.
6. The process according to claim 1, comprising injecting the surfactant and the gas for a second period of time into the injection well to further emplace or form foam.
7. The process according to claim 6, wherein the second period of time begins before the first period of time begins.
8. The process according to claim 6 wherein the first period of time begins before the second period of time begins.
9. The process according to claim 6, wherein the second period of time during which the surfactant and the gas are injected into the injection well, overlaps at least partially in time with the first period of time during which the surfactant and the gas are injected into the production well.
10. The process according to claim 6, comprising periodically repeating injecting the surfactant and the gas into the production well and repeating injecting the surfactant and the gas in to the injection well.
11. The process according to claim 1, wherein the gas comprises steam.
12. The process according to claim 1, comprising, after recovering the hydrocarbon through the production well, repeating injecting the surfactant to create or emplace a foam within the formation, wherein a greater volume of surfactant is injected when the injecting is repeated.
13. The process according to claim 1, wherein the surfactant is injected while the gas is injected.
14. The process according to claim 1, wherein the surfactant is injected as foam such that the surfactant and the gas are injected together.
15. The process according to claim 1, wherein the surfactant is injected and is foamed in the formation.
16. The process according to claim 1, wherein an oil recovery rate increases when the surfactant and the gas are injected.
17. The process according to claim 1, wherein a steam-oil ratio decreases when the surfactant and the gas are injected.
18. The process according to claim 1, wherein the production well and the injection well are housed, at least partially, in a single physical wellbore.
19. The process according to claim 1, wherein the production well and the injection well are functionally independent components, hydraulically isolated from each other, and housed within a single physical wellbore.
Type: Application
Filed: Apr 28, 2015
Publication Date: Oct 29, 2015
Inventors: Sam Chen (Calgary), Subodh Gupta (Calgary), Alvin Winestock (Calgary)
Application Number: 14/698,679
