THERMAL HYDROCARBON RECOVERY METHOD USING SHOCK CYCLING FLUID STIMULATION

Abstract

A thermal hydrocarbon recovery method comprising cycling high pressure fluid injection for a period of time followed by low pressure fluid injection for a period of time, the high pressure injection primarily to dilate and enhance reservoir porosity/permeability and improve the subsequent low pressure fluid injectivity. The method is particularly useful for recovering heavy and extra heavy hydrocarbons from tight formations and/or low vertical permeability reservoirs under viscosity reduction and gravity drainage methods. This method is believed to be applicable for recovering heavy or extra heavy oil from reservoirs with geological risk associated with cap rock integrity.

Description

CROSS-REFERENCE TO RELATED APPLICATION

This application claims the benefit of and priority to U.S. Provisional Patent Application Ser. No. 62/098,607, filed Dec. 31, 2014, entitled “Thermal Hydrocarbon Recovery Method Using Shock Cycling Fluid Stimulation,” the contents of which are incorporated herein in its entirety for all purposes.

FIELD OF THE INVENTION

The present invention relates to thermal hydrocarbon recovery techniques, and more particularly to methods for extracting heavy oil resources from tight reservoirs.

BACKGROUND OF THE INVENTION

In the art of hydrocarbon recovery, it is known to use thermal recovery methods for producing heavy oil/bitumen from subsurface reservoirs. For example, steam-based methods such as cyclic steam stimulation (CSS) and steam assisted gravity drainage (SAGD) are commonly used for in-situ recovery operations. While surface mining of bitumen is employed in appropriate settings, the majority of reservoirs are located at depths where surface mining is not economically or technically feasible, and thus in-situ recovery techniques are conventionally employed.

Some subsurface reservoirs might be candidates for steam injection techniques such as high pressure CSS, especially where an operator is attempting to extract heavy oil/bitumen from a poor-quality reservoir with relatively low vertical permeability. However, in some geological settings, the cap rock overlying the reservoir is of insufficient integrity to support a prolonged high pressure injection regime. As a result of a low minimum stress gradient in some of the reservoirs, where capping shale is in a vertical fracture regime, high pressure fluid injection is not an alternative due to the risk of cap rock failure.

SUMMARY OF THE INVENTION

The present invention therefore seeks to provide a method for extracting heavy hydrocarbons from a subsurface reservoir, where the reservoir has reduced porosity and/or permeability, even if there are cap rock integrity issues.

According to a broad aspect of the present invention, then, a method is disclosed for recovering hydrocarbons from a subsurface reservoir using viscosity reduction and/or gravity drainage techniques, comprising a high pressure fluid injection for a certain period of time (preferably relatively short), followed by a low pressure fluid injection (e.g. steam) for a certain period of time (preferably longer than the high pressure fluid injection). The relatively brief high pressure fluid injection dilates the reservoir rock, thus enhancing porosity and permeability and improving subsequent injectivity of the low pressure fluid injection.

Methods according to the present invention may be especially useful in extracting heavy and extra heavy hydrocarbons from tight formations and/or low vertical permeability reservoirs.

The present invention may also have application for recovering heavy or extra heavy oil from reservoirs with geological risk associated with cap rock integrity.

According to a first broad aspect of the present invention, there is provided a method for recovering hydrocarbon from a subsurface reservoir, the method comprising the steps of:

a. drilling a wellbore from surface to the reservoir;
b. injecting a first fluid down the wellbore under a first pressure, the first fluid at the first pressure sufficient to substantially dilate at least a portion of the reservoir;
c. subsequently injecting a second fluid down the wellbore under a second pressure, the second pressure lower than the first pressure and the second fluid at the second pressure insufficient to substantially further dilate the at least a portion of the reservoir;
d. allowing the second fluid to mobilize the hydrocarbon in the reservoir; and
e. producing the hydrocarbon to the surface.

In some exemplary embodiments of the first aspect, the step of injecting the first fluid is for a first period of time, and the step of injecting the second fluid is for a second period of time, the first period of time being lesser than the second period of time.

The step of injecting the second fluid down the wellbore under the second pressure may be an injection phase of a cyclic steam stimulation hydrocarbon recovery process.

The step of producing the hydrocarbon to the surface may occur through the wellbore. Alternatively, certain exemplary methods may further comprise drilling a second wellbore from the surface to the reservoir, wherein the step of producing the hydrocarbon to the surface occurs through the second wellbore.

The step of injecting the first fluid down the wellbore under the first pressure is most preferably insufficient to compromise integrity of cap rock overlying the reservoir.

The first fluid may comprise steam, a steam-solvent mixture or a non-condensable gas, in which case it may be sufficient to at least partially mobilize the hydrocarbon; however, it need not be a heat-conducting fluid but rather may simply be used to dilate the portion of the reservoir. The second fluid, though, is preferably steam, a steam-solvent mixture or a non-condensable gas. Where the second fluid is not already heated, exemplary methods may comprise the step before step c. of heating the second fluid, wherein step d. comprises allowing heat to transfer from the second fluid to the hydrocarbon to mobilize the hydrocarbon.

The first pressure may be approximately 9500 kPa, but the appropriate and useful pressure level will vary from one reservoir to another.

Steps b. through e. may be repeated at least one time where deemed appropriate by the skilled person.

In some exemplary embodiments, an initial permeability of the subsurface reservoir is assessed before injecting the first fluid down the wellbore at the first pressure. Where this is the case, the method may further comprise the step of determining a level for the first pressure sufficient to raise subsurface reservoir permeability above the initial permeability before injecting the first fluid down the wellbore at the first pressure.

According to a second broad aspect of the present invention, there is a provided a method for recovering hydrocarbon from a subsurface reservoir, the method comprising the steps of:

a. drilling a wellbore from surface to the reservoir;
b. injecting fluid down the wellbore under an initial pressure, the fluid at the initial pressure sufficient to substantially dilate at least a portion of the reservoir;
c. reducing pressure of the fluid to a reduced pressure and continuing to inject the fluid down the wellbore, the reduced pressure lower than the initial pressure and the fluid at the reduced pressure insufficient to substantially further dilate the at least a portion of the reservoir;
d. allowing the fluid to mobilize the hydrocarbon in the reservoir; and
e. producing the hydrocarbon to the surface.

In some exemplary embodiments of the second aspect, the step of injecting the fluid under the initial pressure is for a first period of time, and the step of injecting the fluid under the reduced pressure is for a second period of time, the first period of time being lesser than the second period of time.

The step of injecting the fluid down the wellbore under the reduced pressure may be an injection phase of a cyclic steam stimulation hydrocarbon recovery process.

The step of producing the hydrocarbon to the surface may occur through the wellbore. Alternatively, certain exemplary methods may further comprise drilling a second wellbore from the surface to the reservoir, wherein the step of producing the hydrocarbon to the surface occurs through the second wellbore.

The step of injecting the fluid down the wellbore under the initial pressure is most preferably insufficient to compromise integrity of cap rock overlying the reservoir.

The fluid preferably comprises steam, a steam-solvent mixture or a non-condensable gas. Where the fluid is not already heated, exemplary methods may comprise the step before step c. of heating the fluid, wherein step d. comprises allowing heat to transfer from the fluid to the hydrocarbon to mobilize the hydrocarbon.

The initial pressure may be approximately 9500 kPa, but the appropriate and useful pressure level will vary from one reservoir to another.

Steps b. through e. may be repeated at least one time where deemed appropriate by the skilled person.

In some exemplary embodiments, an initial permeability of the subsurface reservoir is assessed before injecting the fluid down the wellbore at the initial pressure. Where this is the case, the method may further comprise the step of determining a level for the initial pressure sufficient to raise subsurface reservoir permeability above the initial permeability before injecting the fluid down the wellbore at the initial pressure.

A detailed description of exemplary embodiments of the present invention is given in the following. It is to be understood, however, that the invention is not to be construed as being limited to these embodiments.

BRIEF DESCRIPTION OF THE DRAWING

In the accompanying drawing, which illustrates an exemplary embodiment of the present invention:

FIG. 1 is a chart illustrating a production performance comparison based on numerical simulation data.

Exemplary embodiments of the present invention will now be described with reference to the accompanying drawing.

DETAILED DESCRIPTION OF EXEMPLARY EMBODIMENTS

Throughout the following description specific details are set forth in order to provide a more thorough understanding to persons skilled in the art. However, well known elements may not have been shown or described in detail to avoid unnecessarily obscuring the disclosure. The following description of examples of the invention is not intended to be exhaustive or to limit the invention to the precise forms of any exemplary embodiment. Accordingly, the description and drawings are to be regarded in an illustrative, rather than a restrictive, sense.

The present invention is directed to recovery of subsurface hydrocarbon resources, and in particular heavy oil or bitumen resources. Recovery of such heavy hydrocarbons is challenging due to high viscosity and the difficulty of getting the hydrocarbon to flow to a producing well, but this is exacerbated in reservoirs that are tight or otherwise have reduced porosity and/or permeability. In such situations, conventional steam-based thermal recovery techniques such as CSS and SAGD may have limited utility due to injectivity barriers. As stated above, high pressure injection techniques are a potential solution, but they are commonly and widely understood to be inapplicable in geological settings where cap rock integrity is low.

According to exemplary embodiments of the present invention, a high pressure fluid injection is employed for a relatively brief period of time, to dilate the reservoir and open up flow paths for the subsequent low pressure fluid injection activity. The high pressure fluid injection may also be designed to mobilize the reservoir fluids, for example by using steam as the injected fluid, but the focus is reservoir dilation. This can be repeated as cycles of high pressure, low pressure, high pressure, low pressure, etc., as desired and useful in a given context. The fluid may be steam, or it may be any other appropriate fluid, for example a steam-solvent mixture or a non-condensable gas. It is believed that this brief period of high pressure fluid injection will, in most cases, not be problematic in weak cap rock situations, but the skilled person would need to assess applicability in a particular geological context. The actual time period for the initial high-pressure injection will depend in part on the reservoir characteristics.

In the exemplary methods, an injection wellbore is drilled from surface down to the reservoir in a conventional manner.

In a first exemplary method, two separate fluids are injected into the reservoir. A first fluid is injected down the wellbore at a first pressure. While the level of the first pressure will vary from one reservoir to another, the first pressure should be selected based on reservoir properties so that the first fluid injected at the first pressure can substantially dilate at least a portion of the reservoir. By dilating the reservoir with a relatively short period of high-pressure fluid injection, the permeability flowpaths in the reservoir are opened up to enhance the pathways by which the second injected fluid can penetrate the reservoir to mobilize a greater percentage of the hydrocarbon resource. This fluid may optionally be heated, in order to transfer heat to the hydrocarbon, reducing viscosity and enhancing mobility for production to surface.

With the reservoir permeability opened further, a second fluid can then be injected down the wellbore under a second, lower pressure. The lower pressure is selected to not only be lower than the first pressure but to be less than the pressure required to further dilate the reservoir. In a CSS context, this second injection would act like a conventional injection phase but with enhanced injectivity due to the injection of the first fluid under the heightened pressure.

The second fluid can be steam, a steam-solvent mix or a heated non-condensable gas. The goal, as with a conventional CSS injection phase, is to introduce a heated fluid medium to the heavy hydrocarbon resource in the reservoir. After this second injection, the heated fluid is allowed to transfer heat to the hydrocarbon, reducing viscosity and enhancing mobility for production to surface.

In a CSS application of this exemplary method, production to surface would normally occur through the same wellbore that was used for injection. In a SAGD application, however, a second producer wellbore would be drilled, and the hydrocarbon would be produced to the surface through that second wellbore.

It should be noted that the first injection should be designed so as to be insufficient to compromise the integrity of any cap rock overlying the reservoir, particularly where there are indications of a cap rock that could fail due to high-pressure injection processes. The skilled person could look to the pressure and/or the injection period in designing an appropriate and useful first injection program. It should be noted that the skilled person would be able to determine if a particular reservoir could not benefit from the present invention due to a highly vulnerable cap rock that could not withstand any degree of higher-pressure injection.

While the first fluid may be any fluid sufficient to produce the desired dilation effect, it may comprise steam, a steam-solvent mixture or a heated non-condensable gas if the operator wishes to apply heat to the reservoir during the first injection.

In a given reservoir, it may also be advantageous to repeat the dual injection stages and the single production stage, and the number of repetitions can be determined by the skilled person having recourse to the within teaching.

In a second exemplary method, there is only one fluid being injected, but the pressure at which that fluid is supplied varies over the course of the method.

In this second exemplary method, the injection wellbore is drilled as described above, and a fluid is injected downhole at a sufficient pressure to dilate a portion of the reservoir without risking cap rock integrity failure. However, this injected fluid is the same fluid that is subsequently injected in the lower-pressure injection stage. There could be continuous injection of the fluid with a reduction in pressure at a certain stage, or there could be a cessation between the high-pressure and low-pressure injection stages for the same fluid. As the fluid is the same, or from the same source, in both injection phases, the fluid would normally comprise steam, a steam-solvent mixture or a non-condensable gas that would be useful for hydrocarbon viscosity reduction. If the fluid is not heated during the first injection phase, it can be heated prior to injection in the second, lower-pressure injection phase; for example, a non-condensable gas could be injected at high pressure in the first stage, and then heated before or as being injected at lower pressures for the second stage.

In all other respects, this second exemplary method is similar to the first exemplary method described above.

A series of numerical simulations were conducted to evaluate the potential of cycling high pressure fluid injection for a short time for reservoir dilation to occur, followed by the normal operation strategy of low pressure fluid injection in a typical CSS recovery method. In this particular study, the high pressure steam injection (a “shock cycle”) was assigned to be 9500 kPa with assumption of the dilation parameters. Note that these design parameters are case dependent and can be optimized as required.

Turning to FIG. 1, the results from the simulation are illustrated, utilizing steam as the injected fluid. Line 10 illustrates a conventional CSS case alone, without any high pressure injection as a precursor. Lines 20 and 30 illustrate embodiments of the present invention, with shock cycling.

As can be seen, FIG. 1 illustrates that the oil recovery (as cumulative oil on the vertical axis) can be considerably increased over time (horizontal axis) when compared to CSS alone. Recovery can potentially be improved, based on this simulation data, by up to approximately 50% in incremental oil production for approximately six years of operation, which translates to incremental oil recovery of over 5%.

FIG. 1 also illustrates that increasing the number of shock cycles can lead to better performance with higher oil recovery, as can be seen when comparing lines 20 and 30 (Case 1 and Case 2, respectively). The application of the shock cycles can be utilized prior to the low pressure steam injection cycles and repeated as required.

Note that the operation conditions (injection pressures, fluid injected, dilation parameters, length of the cycles, number of the shock cycles, etc.) are reservoir and\or case dependent, and need to be designed accordingly by the skilled person.

As will be clear from the above, those skilled in the art would be readily able to determine obvious variants capable of providing the described functionality, and all such variants and functional equivalents are intended to fall within the scope of the present invention.

Specific examples have been described herein for purposes of illustration. These are only examples. The technology provided herein can be applied to contexts other than the exemplary contexts described above. Many alterations, modifications, additions, omissions and permutations are possible within the practice of this invention. This invention includes variations on described embodiments that would be apparent to the skilled person, including variations obtained by: replacing features, elements and/or acts with equivalent features, elements and/or acts; mixing and matching of features, elements and/or acts from different embodiments; combining features, elements and/or acts from embodiments as described herein with features, elements and/or acts of other technology; and/or omitting combining features, elements and/or acts from described embodiments.

The foregoing is considered as illustrative only of the principles of the invention. The scope of the claims should not be limited by the exemplary embodiments set forth in the foregoing, but should be given the broadest interpretation consistent with the specification as a whole.

Claims

1. A method for recovering hydrocarbon from a subsurface reservoir, the method comprising the steps of:

a. drilling a wellbore from surface to the reservoir;

b. injecting a first fluid down the wellbore under a first pressure, the first fluid at the first pressure sufficient to substantially dilate at least a portion of the reservoir;

c. subsequently injecting a second fluid down the wellbore under a second pressure, the second pressure lower than the first pressure and the second fluid at the second pressure insufficient to substantially further dilate the at least a portion of the reservoir;

d. allowing the second fluid to mobilize the hydrocarbon in the reservoir; and

e. producing the hydrocarbon to the surface.

2. The method of claim 1 wherein the step of injecting the first fluid is for a first period of time, and the step of injecting the second fluid is for a second period of time, the first period of time being lesser than the second period of time.

3. The method of claim 1 wherein the step of injecting the second fluid down the wellbore under the second pressure is an injection phase of a cyclic steam stimulation hydrocarbon recovery process.

4. The method of claim 1 wherein the step of producing the hydrocarbon to the surface occurs through the wellbore.

5. The method of claim 1 further comprising drilling a second wellbore from the surface to the reservoir, wherein the step of producing the hydrocarbon to the surface occurs through the second wellbore.

6. The method of claim 1 wherein the step of injecting the first fluid down the wellbore under the first pressure is insufficient to compromise integrity of cap rock overlying the reservoir.

7. The method of claim 1 wherein the first fluid comprises steam, a steam-solvent mixture or a non-condensable gas.

8. The method of claim 1 wherein the second fluid comprises steam, a steam-solvent mixture or a non-condensable gas.

9. The method of claim 1 further comprising the step before step c. of heating the second fluid, wherein step d. comprises allowing heat to transfer from the second fluid to the hydrocarbon to mobilize the hydrocarbon.

10. The method of claim 1 wherein the first pressure is approximately 9500 kPa.

11. The method of claim 1 further comprising repeating steps b. through e. at least one time.

12. The method of claim 1 wherein an initial permeability of the subsurface reservoir is assessed before injecting the first fluid down the wellbore at the first pressure.

13. The method of claim 12 further comprising the step of determining a level for the first pressure sufficient to raise subsurface reservoir permeability above the initial permeability before injecting the first fluid down the wellbore at the first pressure.

14. A method for recovering hydrocarbon from a subsurface reservoir, the method comprising the steps of:

a. drilling a wellbore from surface to the reservoir;

b. injecting fluid down the wellbore under an initial pressure, the fluid at the initial pressure sufficient to substantially dilate at least a portion of the reservoir;

c. reducing pressure of the fluid to a reduced pressure and continuing to inject the fluid down the wellbore, the reduced pressure lower than the initial pressure and the fluid at the reduced pressure insufficient to substantially further dilate the at least a portion of the reservoir;

d. allowing the fluid to mobilize the hydrocarbon in the reservoir; and

e. producing the hydrocarbon to the surface.

15. The method of claim 14 wherein the step of injecting the fluid under the initial pressure is for a first period of time, and the step of injecting the fluid under the reduced pressure is for a second period of time, the first period of time being lesser than the second period of time.

16. The method of claim 14 wherein the step of injecting the fluid down the wellbore under the reduced pressure is an injection phase of a cyclic steam stimulation hydrocarbon recovery process.

17. The method of claim 14 wherein the step of producing the hydrocarbon to the surface occurs through the wellbore.

18. The method of claim 14 further comprising drilling a second wellbore from the surface to the reservoir, wherein the step of producing the hydrocarbon to the surface occurs through the second wellbore.

19. The method of claim 14 wherein the step of injecting the fluid down the wellbore under the initial pressure is insufficient to compromise integrity of cap rock overlying the reservoir.

20. The method of claim 14 wherein the fluid comprises steam, a steam-solvent mixture or a non-condensable gas.

21. The method of claim 14 further comprising the step before step c. of heating the fluid, wherein step d. comprises allowing heat to transfer from the fluid to the hydrocarbon to mobilize the hydrocarbon.

22. The method of claim 14 wherein the initial pressure is approximately 9500 kPa.

23. The method of claim 14 further comprising repeating steps b. through e. at least one time.

24. The method of claim 14 wherein an initial permeability of the subsurface reservoir is assessed before injecting the fluid down the wellbore at the initial pressure.

25. The method of claim 24 further comprising the step of determining a level for the initial pressure sufficient to raise subsurface reservoir permeability above the initial permeability before injecting the fluid down the wellbore at the initial pressure.