Patent Grant
8960317
The present invention relates to an oil extraction process, and more particularly to a method of extracting oil from subterranean hydrocarbon deposits using horizontal wells.
Steam-based oil recovery processes are commonly employed to recover heavy oil and bitumen. For example, steam-assisted-gravity-drainage (SAGD) and cyclic steam injection are used for the recovery of heavy oil and cold bitumen. When the oil is mobile as native oil or is rendered mobile by some in situ pre-treatment, the steam drive process may also be used. A serious drawback of steam processes is the inefficiency of generating steam at the surface because a considerable amount of the heat generated by the fuel is lost without providing useful heat in the reservoir. Roger Butler, in his book “Thermal Recovery of oil and Bitumen’, p. 415, 416, estimates the thermal efficiency at each stage of the steam-injection process as follows: steam generator, 75-85%; transmission to the well, 75-95%' flow down the well to the reservoir, 80-95%; flow in the reservoir to the condensation front, 25-75%. It is necessary to keep the reservoir between the injector and the advancing condensation front at steam temperature so that the major energy transfer can occur from steam condensing at the oil face. In conclusion, 50% or more of the fuel energy can be lost before heat arrives at the oil face. The energy costs based on BTU in the reservoir are 2.6-4.4 times lower for air injection compared with steam injection. Several other drawbacks occur with steam-based oil recovery processes: natural gas may not be available to fire the steam boilers, fresh water may be scarce and clean-up of produced water for recycling to the boilers is expensive. In summary, steam-based oil recovery processes are thermally inefficient, expensive and environmentally unfriendly.
There are many well patterns that can be employed for the production of oil from subterranean reservoirs. Some of these use vertical wells or combine vertical and horizontal wells. Examples of pattern processes are the inverted 7-spot well pattern that has been employed for steam, solvent and combustion-based processes using vertical wells, and the staggered horizontal well pattern of U.S. Pat. No. 5,273,111 which has been employed (but limited to) a process using steam injection.
U.S. Pat. No. 5,626,191 discloses a repetitive method, termed “toe-to-heel” air injection (THAI™), whereby a horizontal well is subsequently converted to an air injection well to assist in mobilizing oil for recovery by an adjacent horizontal well, which is subsequently likewise converted into an air injection well, and the process repeated. THAI™ is a registered trademark of ARCHON Technologies Ltd. of Calgary, Alberta for “Oil recovery services, namely, the recovery of oil from subterranean formations through in-situ combustion techniques and methodologies and oil upgrading catalysts”
U.S. Pat. No. 6,167,966 employs a water-flooding process employing a combination of vertical and horizontal wells.
U.S. Pat. No. 4,598,770 (Shu et al, 1986) discloses a steam-drive pattern process wherein alternating horizontal injection wells and horizontal production wells are all placed low in a reservoir. In situ combustion processes are not contemplated.
Joshi in Joshi, S. D., “A Review of Thermal oil Recovery Using Horizontal wells”, In Situ, 11(2 & 3), 211-259 (1987), discloses a steam-based oil recovery process using staggered and vertically-displaced horizontal injection and production wells pattern. A major concern is the high heat loss to the cap rock when steam is injected at the top of the reservoir.
U.S. Pat. No. 5,273,111 (Brannan et al, 1993) teaches a steam-based pattern process for the recovery of mobile oil in a petroleum reservoir. A pattern of parallel offset horizontal wells are employed with the steam injectors. The horizontal sections of the injection wells are placed in the reservoir above the horizontal sections of the production wells, with the horizontal sections of the production wells being drilled into the reservoir at a point between the base of the reservoir and the midpoint of the reservoir. Steam is injected on a continuous basis through the upper injection wells, while oil is produced through the lower production wells. In situ combustion processes are not mentioned.
U.S. Pat. No. 5,803,171 (McCaffery et al, 1998) teaches an improvement of the Brennan patent wherein cyclic steam stimulation is used to achieve communication between the injector and producer prior to the application of continuous steam injection. In situ combustion processes are not mentioned.
U.S. Pat. No. 7,717,175 (Chung et al, 2010) discloses a solvent-based process utilizing horizontal well patterns where parallel wells are placed alternately higher and lower in a reservoir with the upper wells used for production of solvent-thinned oil and the lower wells for solvent injection. Gravity-induced oil-solvent mixing is induced by the counter-current flow of oil and solvent. The wells are provided with flow control devices to achieve uniform injection and production profiles along the wellbores. The devices compensate for pressure drop along the wellbores which can cause non-uniform distribution of fluids within the wellbore and reduce reservoir sweep efficiency. In situ combustion processes are not mentioned.
WO/2009/090477 (Xiai and Mauduit, 2009) discloses an in situ combustion pattern process wherein a series of vertical wells that are completed at the top are placed between horizontal producing wells that are specifically above an aquifer. This arrangement of wells is claimed to be utilizable for oil production in the presence of an aquifer.
US Patent Application 2010/0326656 (Menard, 2010) discloses a steam pattern process entailing the use of alternating horizontal injection and production wells wherein isolated zones of fluid egress and ingress are created along the respective wellbores in order to achieve homogeneous reservoir sweep. The alternating wellbores may be in the same vertical plane or alternating between low and high in the reservoir, as in U.S. Pat. No. 5,803,171. Hot vapour is injected in the upper wells (e.g. Steam).
Improved efficiency, shortened time on initial return on investment (ie quicker initial oil recovery rates to allow more immediate return on capital invested), and decreased initial capital cost, in various degrees, are each areas in the above methods which may be improved.
An ideal oil recovery processes for recovering oil from an underground reservoir has a high sweep efficiency, uses a free (no cost) and infinitely available injectant, requires no purchased fuel, generates heat precisely where it is needed—at the oil face, and scavenges heat from the reservoir where heating of a reservoir was used. Additionally, a high oil production rate, especially in the initial stage of the exploitation, is critical to the viability and/or profitability of an oil recovery process.
The present invention, a horizontal well line-drive process for recovery of oil from hydrocarbon-containing underground reservoirs, has two advantages over a “Staggered Well” pattern configuration of oil recovery, the latter being a non-public method of oil recovery conceived by the inventor herein and more fully disclosed below, which “Staggered Well” method in many respects is itself an improvement, in certain respects and to varying degrees, over the above prior art methods and configurations.
Specifically, for a comparable volumetric sweep area and identical total cumulative oil recovery in regard to a hydrocarbon-containing subterranean reservoir (formation), the horizontal well line-drive (hereinafter “HWLD”) process of the present invention has been experimentally shown, as discussed herein, to provide a greater initial rate of recovery of oil than the “Staggered Well” method discussed herein. Thus a greater and more rapid initial return on investment for oil companies incurring large expenditures in developing subterranean reservoirs may be achieved. This is a significant advantage, since investment in developing oil reservoirs is very high, and the time in which a return on investment may be realized is frequently a very real and substantial consideration as to whether the investment in such a capital project is ever made in the first place.
In addition, the horizontal well line-drive process of the present invention, for a comparable volumetric sweep area and near identical total oil recovery, has been experimentally shown to require fewer wells than the “Staggered Well” configuration, thus significantly reducing the capital costs to an oil company to develop and produce oil from an underground hydrocarbon-containing formation.
Accordingly, by way of broad summary, in one broad embodiment of the HWLD oil recovery process of the present invention, a first horizontal well is drilled high in a subterranean hydrocarbon-containing reservoir, and a medium such as a gas is injected into the reservoir via perforations in a well liner in such first horizontal well. Oil, water and gas are co-produced via a second parallel laterally offset horizontal well, placed low in the reservoir. When the oil rate at the second horizontal (production) well falls below an economical limit, a third parallel horizontal well is drilled low in the reservoir laterally spaced apart from the second horizontal well, and used to produce oil, while at the same time the second horizontal well (initially a production well) is converted to an injection well, and such gas likewise injected into the formation via such second horizontal well so as to allow the combustion front to be continually supplied with oxidizing gas to permit continued progression of the combustion front and thus continued heating of oil ahead of the advancing combustion front, which drains downwardly and is collected by the horizontal wells drilled low in the formation ahead of (or at least below) the advancing combustion front. The steps of drilling further horizontal, parallel, laterally spaced apart wells low in the formation, and successively converting “exhausted” production wells to injection wells to further the recovery of oil from remaining production wells is continued in a substantially linear direction along the reservoir in order to exploit the reservoir in a single direction as a ‘line-drive-process’ that achieves high reservoir sweep efficiency. The injectant, if a gas, may be a solvent gas such as CO2 or light hydrocarbon or mixtures thereof, steam or an oxidizing gas such as oxygen, air or mixtures thereof. Alternatively the injectant may be any mixture of solvent, steam or oxidizing gas. A favoured embodiment utilizes steam injectant and the most favoured embodiment utilizes oxidizing gas as the injected medium.
When the process utilizes oxidizing gas injectant and in situ combustion, it meets the commercial needs of relatively low energy costs and low operating costs by providing a novel and efficient method for recovering hydrocarbons from a subterranean formation containing mobile oil.
The distance between the parallel and offset horizontal well producers, as well as the well lengths, will depend upon specific reservoir properties and can be adequately optimized by a competent reservoir engineer. The lateral spacing of the horizontal wells can be 25-200 meters, preferably 50-150 meters and most preferably 75-125 meters. The length of the horizontal well segments can be 50-2000 meters, preferably 200-1000 meters and most preferably 400-800 meters.
In a homogeneous reservoir using the method of the present invention it is beneficial for high reservoir sweep efficiency to deliver the injectant equally to each perforation in the injection well liner and to compel equal fluid entry rates at each perforation at each perforation in the production well liner. Considering that horizontal wells typically have a ‘toe’ at the end of the horizontal segment, and a ‘heel’ where the horizontal segment joins the vertical segment, in a refinement of the present invention it is preferred to place the horizontal wells so that the heel of the injector (injection) well is opposite the toe of the adjacent laterally spaced apart producer (production) well so that “short-circuiting” of gas between injector and producer wells is minimized. Short circuiting otherwise occurs because the point of highest pressure in the injector well is at the heel since a pressure drop is typically incurred as the injectant is pumped under pressure and flows along the horizontal leg from heel to toe. Conversely, the point of highest pressure in a producer (production) well is at the toe, as gas and oil is typically drawn from the heel. Accordingly, it is preferred to have the heel of the injector well opposite the toe of the adjacent production well, so that high pressure (typically heated) gas is forced to travel a greater distance through the formation to the low pressure portion at the heel of the adjacent production well.
Alternatively, both the injection and production wells may be placed with the respective heel and toe portions in mutually juxtaposed position. In such case it is then preferred to use internal tubing to inject the gas at the toe of the injection well, thereby moving the high pressure source from the heel of the injection well to its toe. In such manner the high pressure source will be at an end of the reservoir opposite the low pressure heel of the production well, thereby forcing the gas to travel a longer distance through the formation and thereby more effectively free oil trapped in the formation, so as to then travel and be collected by the low pressure area at the heel of the production well. Such configuration has the benefit of requiring only a single drilling pad located on the same side of the reservoir, since the vertical portion of the injector wells and the producer wells will all be on the same side of the reservoir.
In addition to the employment of configurations which transpose (reverse) the respective heel and toe portions of adjacent horizontal wells or alternatively use internal tubing in the injector well, the uniform delivery of gas along the length of the injection well and uniform collection of oil along the production well may be obtained, or further enhanced, by varying the number and size of perforations along the well liner in an injector well, to balance the pressure drop along the well. A pressure-drop-correcting perforated tubing can be placed inside the primary liner of the injector well. This has the advantage of utilizing gas flow in the annular space to further assist the homogeneous delivery of gas. Alternatively, or in addition, similar methodologies may be applied to the production wells in order to more uniformly collect mobile oil along substantially the entire length of the production well, and assist in preventing “fingering” of injectant gas directly into production wells.
The outside diameter of the horizontal well liner segments can be 4 inches to 12 inches, but preferably 5-10 inches and most preferably 7-9 inches. The perforations in the horizontal segments can be slots, wire-wrapped screens, Facsrite™ screen plugs or other technologies that provide the desired degree of sand retention. Facsrite™ is an unregistered trademark of Absolute Completion Technologies for well liners having sand screens therein.
The injected gas may be any oxidizing gas, including but not limited to, air, oxygen or mixtures thereof.
It is desirable to achieve equal gas injection rates along the injector well and equal fluid production rates along the horizontal production well in order to obtain the greatest reservoir sweep efficiency and uniform recovery. The maximum gas injection rate will be limited by the maximum gas injection pressure, which must be kept below the rock fracture pressure, and will be affected by the length of the horizontal wells, the reservoir rock permeability, fluid saturations and other factors.
The use of a numerical simulator such as that used in the Examples below is beneficial for confirming the operability and viability of the design of the present invention for a specific reservoir, and can be readily conducted by reservoir engineers skilled in the art.
Accordingly, and more particularly, in a first broad aspect of the method of the present invention, such method is directed to a method for recovering oil from a hydrocarbon-containing subterranean reservoir, comprising the steps of:
Each of said second, third, and further subsequently-drilled horizontal wells are all preferably co-planar with each other, but not with said first well, and laterally spaced from one another.
In order to make use of the “line drive” aspect of the invention and allow a sweeping of a significant volume of oil from within a substantially-sized hydrocarbon-containing reservoir, such method further comprises additional repeated steps to allow a progressive “sweep” in a generally linear direction along said formation, including the further steps of:
successively drilling additional horizontal wells low in said reservoir substantially parallel to and substantially co-planar with the third horizontal well but laterally spaced apart therefrom and from each other; and
successively converting penultimate wells of said additional horizontal wells from a production well to an injection well for injecting said gas, steam, or a liquid so as to cause oil in said reservoir to move from within said reservoir downwardly into a last of said additional horizontal wells.
In a preferred embodiment, the first medium and the second medium are one and the same medium. In a further preferred embodiment, such medium is a gas which is soluable in the oil. Alternatively, the medium is a gas, namely CO2, light hydrocarbons, or mixtures thereof.
In yet a further preferred embodiment such medium comprises oxygen gas, air, or mixtures thereof for the purpose of conducting in situ combustion, and said method further comprises the step, after step (iii), of igniting hydrocarbons in the reservoir in a region proximate the first horizontal well, and withdrawing oil and combustion by-products from the subterranean formation via the second well and/or simultaneously or subsequently via the third well. The step of igniting the hydrocarbons and withdrawing combustion by-products and oil via said second horizontal well and/or said third horizontal well causes a combustion front to move laterally from said first horizontal well in the direction of said second and third horizontal wells, thereby heating oil in said reservoir and causing said oil to drain downwardly for collection by said second and/or third horizontal wells.
Accordingly, in a most preferred embodiment of the HWLD method of the present invention for recovering oil from a hydrocarbon-containing subterranean reservoir, such method comprises:
Where oxidizing gas is used as the injected medium, for the purposes of conducting in situ combustion, combustion ignition (ie step (iv) above) can be accomplished by various means well known to those skilled in the art, such as pre-heating the near-wellbore oil with hot fluids such as steam or the injection of spontaneously ignitable fluid such as linseed oil prior to injection of oxidizing gas. In this case, hot nitrogen (400° C.) was injected at the rate of 16,667 m3/d for one month prior to switching to air at 100° C. The air does not have to be heated at the surface: it is heated by the act compression.
As mentioned above, to ensure high pressure ends of an injector well are not situated immediately adjacent the lowest pressure point (ie the heel portion) of an adjacent producer well thus giving rise to “short circuiting” or “fingering” of high pressure gas directly to the heel portion of the production well, in a preferred embodiment said step (iii) of injecting a gas, steam, or liquid into said first horizontal well comprises the step of injecting said gas, steam, or liquid into one end of said first horizontal well, and said step of withdrawing oil from said second horizontal well comprises the step of withdrawing said oil from one end of said second well, said one end of said second well situated on a side of said reservoir opposite a side thereof at which said one end of said first horizontal well is situated. Such configuration allows more uniform injection of such gas into the formation and reduces (and preferably avoids) “fingering” (“short-circuiting”) of high pressure gas directly from the injector well to the production well.
Such approach may likewise be adopted not only with regard to the first and second wells, but also with regard to the second well relative to the third, and so on. For example, with regard to the arrangement of the second well relative to the third well, said step of injecting said gas, steam, or liquid into said second horizontal well may comprise the step of injecting said gas, steam, or liquid into an end of said second horizontal well situated on a side of said reservoir opposite an end of said third horizontal well from which said oil is collected from. In other words, proximal ends of mutually adjacent wells may be situated on mutually opposite sides of said reservoir.
Alternatively, the first end of each of the second well and third well may be situated on the same side of the reservoir. In such case, to reduce or avoid the “fingering” problem, said step of injecting said gas, steam, or liquid into said second horizontal well comprises injecting said gas, steam, or liquid into a second end of said second well via tubing, which tubing extends internally within said second well substantially from said first end to said second end of said second well.
Alternatively, where a first end of each of said second and third horizontal wells are located on a same side of said reservoir, said step of injecting said gas, steam, or liquid into said second horizontal well may comprise injecting said gas, steam, or liquid into said first end of said second well, and said step of withdrawing oil from said third well comprises withdrawing such oil from a second end of said third well via tubing, said tubing extending internally within said third well from said first end to substantially said second end of said third well.
Alternatively, or in addition, to avoid or reduce “fingering” of high pressure gas from an injection well to a production well, such as from the first horizontal injector well to the second well when such second well acts as a producer well, in one embodiment the first horizontal well has a well liner in which said plurality of apertures are situated, and a size of said apertures or a number of said apertures within said liner within said first horizontal well progressively increase from a first end to a second end of said first horizontal well.
Likewise, progressive increase in aperture size or number of apertures along the length of well liners in each of second, third, or subsequent wells may likewise be utilized. In such manner, by having larger or more numerous apertures at one end of a well than at another, pressure (and thus flow) can be more uniform over the length of the well, or even made higher at one end than another, and provided an adjacent well similarly employs progressive variation in an opposite direction, direct “short-circuiting” of gas from an injector well to an adjacent production well can be reduced or avoided. Instead, cross-flow of gas through the formation is thereby inducted to better expose the (typically high temperature) gas to more oil in the formation, thus increasing recovery rate of oil from the formation.
In the accompanying drawings, which illustrate one or more exemplary embodiments and are not to be construed as limiting the invention to these depicted embodiments:
a shows a similar perspective schematic view of a subterranean hydrocarbon-containing reservoir of the “staggered well” configuration, to show the model used in Example 1 of the computer simulation, and which produced the experimental test results (line “B”) of
a (i)-(iii) are views on section B-B of
b (i)-(iii) are views on section B-B of
c (i)-(iv) are views on section B-B of
a show a developed hydrocarbon-containing subterranean formation/reservoir 22 of the “staggered well” (hereinafter “Staggered Well” configuration), which does not form part of the invention claimed herein but forms subject matter of another application of the undersigned inventor, such other application being commonly assigned with the present invention.
In such “Staggered Well” configuration, parallel horizontal injection wells 1, 1′, & 1″ of each of length 6 are placed parallel to each other in mutually spaced relation, all situated high in a hydrocarbon-containing portion 20 of subterranean formation/reservoir 22 of thickness 4, situated below ground-level surface 24. Parallel horizontal, spaced apart production wells 2, 2′ & 2″ of similar length 6 are respectively placed low in the reservoir 22, midway between respective injection wells 1, 1′, and 1″, to make a well pattern array of staggered and laterally separated parallel and alternating horizontal gas injection wells 1, 1′, & 1″ and fluid production wells 2, 2′ & 2″, as shown in
The hydrocarbon-containing reservoir 22 shown in
The lateral spacing 5 of the injection wells 1, 1′, & 1″ and production wells 2, 2′ & 2″ is preferably uniform.
In a preferred embodiment shown in
Referring to
In the “Staggered Well” configuration of
The Staggered Well method, in one embodiment, may alternatively utilize a line drive configuration, such method shown in
Alternatively, as mentioned above, such “Staggered Well” method may simply consist of simultaneously drilling a set number of injector wells (eg. such as three wells 1, 1′, & 1″) and a corresponding number of producer wells (eg. such as three wells 2, 2′ & 2″) so as to produce the “pattern” of staggered wells of wells 1, 1′, & 1″ and 2, 2′ & 2″ shown in
In such HWLD configuration and method, a first horizontal injection well 1 is drilled high within oil-containing portion 20 of reservoir 22, along edge 7, and a second parallel horizontal well 2 is drilled low in oil-containing portion 20 of reservoir 22, laterally spaced apart from first injector well 1.
Horizontal wells 2 & 2′ have vertical portions 3 at each of their respective heel portions 42 which extend to surface 24. The distance separating planes 7 and 8 represent the edges of the oil-swept volume of oil containing portion 20 of reservoir 22 in a first phase of the method of the present invention.
In the embodiment of the HWLD method shown in
a-c, namely in various alternative sub-phases (i), (ii), (iii), and (iv) thereof, each show the residual oil in oil containing portion 20 which is remaining after each sub-phase of the method of the present invention, in shaded portion.
In a first phase of the method of the present invention [identical in each of various methods shown in
In a preferred embodiment, where vertical ends 3 of production well 2, 2′ are on the same side of reservoir 22 as shown in
a(iii), 4b(iii), and 4c(iii) each show slightly different third phases of the method of the present invention.
As regards the embodiment of the method disclosed in
Thereafter the fourth well 2″ may be drilled, and a similar process repeated wherein a former production well (well 2′) is converted into an injection well 2′, and production commenced from fourth well 2″, while gas continues to be injected via well 1.
Alternatively, as regards the third phase shown in step (iii) of
Alternatively, as shown in
As noted above, where the vertical portions 3 of wells 2, 2′, 2″, 2′″, and 2iv are all situated on the same side of reservoir 22 (see
As an alternative configuration to reducing or avoiding the “fingering” or short-circuiting problem between an injector and mutually-adjacent production wells 2, 2′, 2″, 2′″, 2iv having respective vertical portions 3 of such wells on the same side of reservoir 22 as shown in
Alternatively, to likewise more uniformly inject gaseous medium such as oxidizing gas, steam, carbon dioxide, hydrocarbon diluents (in either gaseous or liquid form) along the length of an injector well (e.g. 2′) and also to more uniformly collect oil along a length of a mutually adjacent collector well (e.g. 2″), in an embodiment shown in
Conversely, vertical portions 3 of mutually-adjacent wells 2, 2′, 2″, 2′″, 2iv and so forth may be situated on respective opposite sides of the reservoir 22 as shown in
Alternatively, in an embodiment shown in
For the purpose of making a direct performance comparison of the “Staggered Well” configuration shown in
Specifically, extensive computer numerical simulation of each of the Staggered Well Pattern and HWLD, using an in situ combustion process for the recovery of mobile oil in a homogeneous reservoir, were undertaken using the STARS™ Thermal Simulator 2010.12 provided by the Computer Modelling Group, Calgary, Alberta, Canada. The modelling reservoir used in the Examples contained bitumen at elevated temperature (54.4° C.) with high rock permeability.
In each of the modelled Staggered Well well (
Specifically, for each of the Staggered Well Pattern shown in
For the HWLD process, a first phase of which is shown in
For combustion simulations with air the reactions used:
The transmissibility of the oil production wells was varied monotonically along the well from 1.0 at the toe to 0.943 at the heel, in order to improve sweep efficiency.
For the Staggered Well configuration, the oil containing portion 20 of reservoir 22 comprising grid blocks 50a-50o shown in
For the Staggered Well Pattern shown in
For the computer modelling of the Staggered Well pattern the first phase comprised grid blocks 50a-50e. A second pattern comprised an identical pattern (grid blocks 50f-50j), modelled as exploited over a further 5-years and in a third phase (grid blocks 50k-50o) comprised another identical pattern which was modelled as being exploited over a final 5-years. The reservoir volume of each part was 500,000 m3 for a total field exploitation volume of 1,500,000 m3 (i.e. 3×100 m×250 m×20 m) over 15-years. The final oil recovery factor was 79% of original oil in place. A summary of results is shown in Table 2 and
For the HWLD process which was modelled using computer simulation, and as shown in
In
The air injection rate was 16,667 m3/d for each of the injectors for a total of 50,000 m3/d throughout Phase 1.
In a second phase [
After 5-years, a final drawdown phase (
Comparison and Proven Advantages
A summary of comparative results of each of Examples 1 & 2 is shown in Table 2 below.
The significant and important differences in the two methods are shown in grey.
Specifically,
Referring to Table 2 and
Firstly, only half the number of horizontal wells (7.5 wells, as compared to 15 wells) are needed for the same compressed air volume and cumulative oil rates are substantially higher over most of the life of the process.
Secondly, the cumulative oil recovery for the HWLD process as compared to the Staggered Well process is initially higher, resulting in a higher initial return on investment. Specifically in this regard, as may be seen from
The scope of the claims should not be limited by the preferred embodiments set forth in the foregoing examples, but should be given the broadest interpretation consistent with the description as a whole, and the claims are not to be limited to the preferred or exemplified embodiments of the invention.
| Number | Date | Country | Kind |
|---|---|---|---|
| 2759362 | Nov 2011 | CA | national |
| PCT/CA2011/001308 | Nov 2011 | WO | international |
| Number | Name | Date | Kind |
|---|---|---|---|
| 20050072567 | Steele et al. | Apr 2005 | A1 |
| 20090139716 | Brock et al. | Jun 2009 | A1 |
| 20100012331 | Larter et al. | Jan 2010 | A1 |
| Number | Date | Country |
|---|---|---|
| 2058255 | Jun 1993 | CA |
| 2650130 | Jul 2009 | CA |
| WO2010043034 | Apr 2010 | WO |
| Number | Date | Country | |
|---|---|---|---|
| 20130133884 A1 | May 2013 | US |
