a. injecting a heated non-condensable gas down the at least one injector well to the reservoir;
b. injecting steam down the at least one injector well to the reservoir;
c. producing a portion of the hydrocarbon to the surface; and
d. repeating steps a. through c. as desired.

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

a. drilling at least one well from surface to the reservoir;
b. heating a volume of non-condensable gas to a target temperature;
c. injecting the non-condensable gas down the at least one well to the reservoir at a desired volume per unit time and for a desired period of time;
d. ceasing injecting of the non-condensable gas and allowing the injected non-condensable gas to heat the reservoir and the hydrocarbon;
e. injecting steam down the at least one well to the reservoir;
f. ceasing injection of the steam and allowing the steam to heat the reservoir and the hydrocarbon; and
g. producing a portion of the hydrocarbon to the surface.

In exemplary embodiments of the third aspect of the present invention, the target temperature is preferably in the range of 100 to 400 degrees Celsius, although target temperatures outside this preferred range may have utility in a given context, and the desired volume per unit time is preferably in the range of 20 to 100 mmcfd, although a useful desired volume per unit time may fall outside this range in a given context. The desired period of time is contextual and is directed to process optimization, which would be within the knowledge of the skilled person. Steps b. through g. can be repeated as desired.

According to a fourth aspect of the present invention, there is provided a method for building a steam chamber in a fractured subsurface hydrocarbon reservoir having at least one injector well therein, the method comprising the steps of:

a. heating a volume of non-condensable gas to a target temperature;
b. injecting the non-condensable gas down the at least one injector well to the reservoir;
c. allowing the injected non-condensable gas to heat the reservoir and hydrocarbon in the reservoir;
d. injecting steam down the at least one injector well to the reservoir;
e. shutting in the at least one injector well and allowing the injected steam to heat the reservoir and the hydrocarbon in the reservoir; and
f. producing a portion of the hydrocarbon to the surface.

In exemplary embodiments of the fourth aspect of the present invention, the method can additionally comprise the step after injecting the non-condensable gas of shutting in the at least one injector well, followed by opening the at least one injector well before injecting the steam.

A detailed description of an exemplary embodiment 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 this embodiment.

BRIEF DESCRIPTION OF THE DRAWINGS

In the accompanying drawings, which illustrate an exemplary embodiment of the present invention:

FIG. 1 is a flowchart illustrating an exemplary method according to the present invention;

FIG. 2 is a chart presenting numerical simulation test results comparing three different flow and temperature regimes compared to a standard CSS base case; and

FIG. 3 is a chart presenting numerical simulation test results comparing two different temperature regimes compared to a standard CSS base case, with nitrogen as the non-condensable gas.

An exemplary embodiment of the present invention will now be described with reference to the accompanying drawings.

DETAILED DESCRIPTION OF EXEMPLARY EMBODIMENT

In the following detailed description, a specific application of the present invention is described, in particular an application for use with a CSS recovery method for bitumen housed in a fractured carbonate reservoir. However, it will be clear to those skilled in the art that other applications are possible within the scope of the present invention, including unique operating conditions and parameters specific to a particular reservoir context. That being the case, the following description is intended to be exemplary and non-limiting.

The present invention is intended for use with heavy hydrocarbons such as heavy oil and bitumen, although it can be used with lighter oils in appropriate circumstances that would be clear to one skilled in the art. Heavy and extra-heavy crude oils and bitumens are composed primarily of hydrocarbons, but they may also contain high molecular weight aliphatic and terpenoid hydrocarbons, asphaltenes, and oxygen-, nitrogen- and sulfur-bearing compounds. They occur naturally in porous and fractured reservoirs. Heavy oils and bitumens are commonly defined and characterized on the basis of both viscosity and density, and those skilled in the art will know of accepted viscosity and density ranges.

Turning toFIG. 1, anexemplary method10 according to the present invention is illustrated. Themethod10 begins with thestep12 of drilling a well into the reservoir to access the hydrocarbon deposit, which in the exemplary case is a bitumen housed in a massively fractured reservoir. Note that where the term “well” is used herein, it can mean either a vertical well or a horizontal well, and the term “wells” can mean vertical and/or horizontal wells or a combination of vertical and horizontal wells, as would be obvious to one skilled in the art. Once the well has been completed, a non-condensable gas is heated atstep14 and then injected down the well to the reservoir atstep16. The operator then continues the injection of the gas at a desired volume per unit time, for a desired period of time, allowing the non-condensable gas atstep18 to impart heat energy to the reservoir surrounding the wellbore. The well can optionally be shut in at this time, while the heat transfer continues. The specific volumes, time periods and even the heat level for the injected gas will depend in large part on the nature and structure of the reservoir, the type of hydrocarbon deposit being produced, and the availability of surface equipment. One skilled in the art will be able to select and operate available equipment to meet reasonable desired operating conditions for the method.

After the injected gas has imparted heat energy to the reservoir surrounding the wellbore, steam is then injected downhole to the reservoir atstep20. The skilled person will again know how to manage steam injection in a thermal hydrocarbon recovery operation. A mixture of steam and a selected solvent could also be used for this step, as is well known in the art. As the exemplary method is described in the context of a CSS operation, the next step22 is shutting in the well. The injected steam is then allowed to heat the bitumen deposit atstep24. As is noted above, in prior art CSS methods, highly fractured carbonate reservoirs would sometimes drain away the steam or cause the heat energy to dissipate too quickly, making it a challenge to create the steam chamber necessary to enable hydrocarbon production atstep26. Due to injection of the non-condensable gas atstep16 and heating of the reservoir rock atstep18, the reservoir is already heated and the heat energy from the steam injection will accordingly not be as quickly dissipated. It is believed that this will enhance mobility of the heavy hydrocarbon material.

After the target hydrocarbon has been mobilized and produced, the cycle can be repeated atstep28. It is also possible to repeat the injection cycles one or more times before initial production.

Turning now toFIGS. 2 and 3, numerical simulation tests were conducted to assess the potential impact of the present invention when compared to a conventional CSS method. A series of dual-permeability flow simulation models were constructed based on the average geological properties from the Grosmont fractured carbonate formation. In this work STARS™ (advanced process and thermal reservoir simulator, version 2012) from Computer Modeling Group Ltd. was used to simulate and evaluate the process.

In the tests giving rise to the data presented inFIG. 2, simulations were run in which heated nitrogen gas at different volumes and temperatures was injected into the reservoir prior to the steam injection in each cycle, and the results were compared with the base case (CSS only). Note that in all cases, three full cycles are illustrated with increasing oil recovery factors. Each cycle begins with injection of NCG and steam, and then the plateau illustrates the elevated recovery level achieved by the dual injection method. In the base CSS case30, a conventional CSS approach is used for a period over 300 days involving steam injection alone, shutting in and subsequent production, and the oil recovery factor (RF) was found to be only 1.4% in the simulation. In the first NCG case32, nitrogen was heated to 400 degrees Celsius and injected at 20 mmcfd, with a result that the RF after three full cycles increased to 5.2%. This combination of a heated gas and a modest injection rate demonstrates a substantial potential improvement over CSS alone.

In the second NCG case34, the gas is heated to a lower temperature, specifically 200 degrees Celsius, but injected at a higher rate of 100 mmcfd, with the result that the RF was increased to 9.5%. In the third NCG case36, the gas was heated to 400 degrees Celsius and injected at a rate of 100 mmcfd, with the result that the RF was increased to 13.3%.

The results based on three simulated cycles illustrate that hydrocarbon recovery can be substantially increased by implementing the present invention by a factor of 3 to 9 compared to a conventional CSS recovery technique alone.

In the tests giving rise to the data presented inFIG. 3, simulations were run in which heated nitrogen gas was injected into the reservoir prior to the steam injection in each cycle, and the results were compared with the base case (CSS only). Note that in all cases, three full cycles are illustrated with increasing oil recovery factors. Each cycle begins with injection of NCG and steam, and then the plateau illustrates the elevated recovery level achieved by the dual injection method. Unlike the test results shown inFIG. 2, the test results shown inFIG. 3 are the result of NCG temperature modification alone, without reference to injection rate as the injection rate was the same for each run. In the base CSS case40, a conventional CSS approach is used for a period over 300 days involving steam injection alone, shutting in and subsequent production, and the RF was found to be only 1.4% in the simulation. In the first NCG case42, nitrogen was heated to 200 degrees Celsius, with a result that the RF after three full cycles increased to 9.5%. In the second NCG case44, nitrogen was heated to 400 degrees Celsius, with a result that the RF after three full cycles increased to 13.3%. The preliminary results of three cycles illustrate that hydrocarbon recovery may be increased by a factor of 6 to 9 compared to a conventional CSS recovery technique alone.

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 embodiment set forth in the foregoing, but should be given the broadest interpretation consistent with the specification as a whole.