Abstract:
An in situ combustion process entailing the simultaneous production of oil and combustion gases that combines fluid drive, gravity phase segregation and gravity drainage to produce hydrocarbons from a subterranean oil-bearing formation, comprising initially injecting a gas through a pair of horizontal wells placed high in the formation and producing combustion gas and oil through parallel and laterally offset horizontal wells that are placed low in the formation intermediate the pair of horizontal wells placed high in the formation.

Description:
FIELD OF THE INVENTION 
       [0001]    The present invention relates to an oil recovery process, and more particularly to a method of recovering oil from subterranean hydrocarbon deposits using horizontal wells and in situ combustion. 
       BACKGROUND OF THE INVENTION 
       [0002]    There are many oil recovery processes of the prior art 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. 
         [0003]    U.S. Pat. No. 5,626,191 to Toe-to-Heel Air Injection (THAI) discloses a repetitive method whereby the vertical segment of a vertical-horizontal producer 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. 
         [0004]    U.S. Pat. No. 6,167,966 employs a water-flooding process employing a combination of vertical and horizontal wells. 
         [0005]    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. 
         [0006]    Joshi in Joshi, S. D., “A Review of Thermal oil Recovery Using Horizontal wells”, In Situ, 11(2 &amp;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. 
         [0007]    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 steam injectors. The horizontal sections of the injection wells are placed in the reservoir above the horizontal sections of the production wells, with a horizontal production well drilled into the reservoir at a point below the injection wells, but intermediate said injection wells. Steam is injected on a continuous basis through the upper injection wells, while oil is produced through the lower production wells. Neither in situ combustion nor line drive processes are taught. 
         [0008]    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. 
         [0009]    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. 
         [0010]    WO/2009/090477 (Xai et al) 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. 
         [0011]    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). 
         [0012]    As seen from the above patents, steam-based oil recovery processes are commonly employed to recover heavy oil and bitumen from underground formations. 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, such as a steam drive process, the thus-mobilized oil can then drain downwardly by gravity and be collected by a horizontal collector well. 
         [0013]    A serious drawback of steam drive 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&#39;, 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. 
         [0014]    Improved efficiency, shortened time on initial return on investment (i.e. 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. 
       SUMMARY OF THE INVENTION 
       [0015]    The present invention overcomes problems with the prior art steam-injection method of inter alfa U.S. Pat. No. 5,273,111 (Brannan) wherein reservoir heating is accomplished by the injection of large quantities of steam, typically under high pressure. Such prior art method has the drawbacks of needing to provide large and costly steam-generating equipment at surface, and as noted below is thermally inefficient in transferring heat to oil within the reservoir in order to achieve the necessary reduction in viscosity to be able to produce oil from a viscous oil reservoir. 
         [0016]    Thus substantial costs are further incurred in steam recovery methods which use steam to heat oil in heating the large quantities of steam needed, over and above the captical costs of acquiring, shipping, and assembling the necessary steam generating equipment in the form of boilers, burners, and associated piping. 
         [0017]    Moreover, although in situ combustion oil recovery techniques such as that disclosed in U.S. Pat. No. 5,626,191 are known, such typically involve a progression of a combustion front perpendicular to and along a horizontal collector well, which combustion front at any instant is travelling from a point along the horizontal production well. Accordingly, such prior art in situ combustion recovery method does not allow production of oil from within the underground formation simultaneously along an entire horizontal length of a production well. 
         [0018]    Advantageously, the applicant has created a method of recovering oil from within an underground formation, which is able to incorporate in a particular manner in situ combustion for generating heat (and thus unlike U.S. Pat. No. 5,273,111 does not require costly steam-generating equipment at surface and injection of steam), and which further, unlike prior art in situ recovery methods such as U.S. Pat. No. 5,626,191, is able to simultaneously utilize in situ heating and importantly attain production of oil from within a formation along an entire length of a horizontal collector well (or wells), and is able to have relatively high initial oil recovery rates. 
         [0019]    Specifically, the method of the present invention has been experimentally proven, in certain conditions as discussed later herein, to achieve a higher initial oil recovery rate than either the staggered well method of oil recovery using steam injection as taught in U.S. Pat. No. 5,273,111 [hereinafter the “staggered steam” method] and which disadvantageously need have costly steam generating equipment at surface], or a “crossed well” method of oil recovery which similarly uses in-situ combustion, the latter being a non-public method of oil recovery conceived by the inventor herein and in many respects itself an improvement, in certain respects and to varying degrees, over prior art methods and configurations. 
         [0020]    Specifically, for a comparable volumetric sweep area and identical total cumulative oil recovery in regard to a subterranean underground reservoir (formation), the staggered well (air injection) method of the present invention has been experimentally shown, under certain conditions as discussed herein, to provide a greater initial rate of recovery of oil than the “staggered steam” method or the “crossed well” method. Thus using the method of the present invention a greater and more rapid initial return on investment may be achieved. 
         [0021]    For oil companies incurring large expenditures in developing subterranean reservoirs, the ability to utilize a method which will generate revenue quickly and thereby permit quicker “pay-down” of initial expenses incurred with regard to search, locating, and acquiring, and initially drilling wells in a hydrocarbon-bearing formation is a significant advantage. 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 or can ever be made in the first place. 
         [0022]    Accordingly, in one broad embodiment of the oil recovery process of the present invention, such method comprises a continuous in situ combustion process using solely horizontal wells for injection of an oxidizing gas and for the simultaneous production of oil, using a symmetrical array of laterally and vertically offset (i.e. alternately ‘staggered’) parallel horizontal injection and production wells. 
         [0023]    More particularly, in one broad embodiment of the oil recovery method of the present invention such method comprises the steps of: 
         [0024]    (i) drilling a pair of parallel, spaced-apart, upper horizontal wells within said hydrocarbon-containing reservoir, substantially coplanar with each other; 
         [0025]    (ii) drilling, relatively low in said reservoir, a lower horizontal well situated below said upper horizontal wells and positioned substantially parallel to and intermediate said pair of upper horizontal wells; 
         [0026]    (iii) injecting an oxidizing gas into each of said upper horizontal wells and injecting said oxidizing gas into said reservoir via apertures in each of said pair of upper horizontal wells; 
         [0027]    (iv) igniting said oxidizing gas and hydrocarbons then contained within said formation and causing oil in said formation to become heated; 
         [0028]    (v) recovering oil which has become heated and which has migrated downwardly in said subterranean reservoir, in said lower horizontal well; and 
         [0029]    (vi) recovering said oil from said lower horizontal well to surface. 
         [0030]    Such method meets the commercial need of having relatively low energy costs (in that a separate supply of fuel for boilers to generate steam is not needed), and has lower initial capital start-up costs due to lack of need to acquire steam-generating equipment. Moreover, as set out below, such novel method for recovering hydrocarbons from a subterranean formation has a high initial oil recovery rate which is a significant advantage in allowing income generated from the produced oil to be more quickly applied against the significant expenses of locating, acquiring, and developing a suitable hydrocarbon containing deposit. 
         [0031]    In a further preferred method of the present invention, such method may comprise the further steps of: 
         [0032]    (a) drilling a further upper horizontal well within an upper region of said hydrocarbon-containing reservoir substantially parallel to and laterally spaced apart from said upper horizontal wells; 
         [0033]    (b) drilling a further lower horizontal well intermediate said further upper horizontal well and a nearest of said previously-drilled upper horizontal wells, said lower horizontal well positioned below said upper horizontal wells and positioned substantially parallel therewith; 
         [0034]    (c) injecting said oxidizing gas into said further upper horizontal well and into said nearest of said previously-drilled upper horizontal wells so as to thereby inject said oxidizing gas into said reservoir via a plurality of apertures in both said further upper horizontal well and said nearest of said upper horizontal wells; 
         [0035]    (d) collecting oil which has become heated as a result of heat being produced during combustion of said oxidizing gas and hydrocarbons in said reservoir and which oil has migrated downwardly in said subterranean reservoir, in said further lower horizontal well; 
         [0036]    (e) recovering said oil from said further lower horizontal well to surface. 
         [0037]    In a further preferred embodiment, such above method may be used to progressively recover oil from an underground formation in a “line drive” manner. Accordingly, in such “line drive” embodiment, above steps (a)-(e) are successively repeated to thereby progress in a linear direction with drilled horizontal wells so as to progressively recover oil in said linear direction from said underground hydrocarbon reservoir. 
         [0038]    The distance between the parallel lower horizontal wells, the upper horizontal wells, as well as the respective upper and lower well lengths, will all depend upon specific reservoir properties. Such distances can, however, be adequately optimized by a competent reservoir engineer. The lateral spacing between 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. The vertical distance between the upper horizontal injection wells and the lower horizontal producer wells is typically dictated by the depth of the oil bearing seam within an underground formation, with such depths typically varying between 2 m to 50 m, but sometimes greater, with the upper horizontal injection wells being located in an upper region of the hydrocarbon-containing seam within the underground formation, and the lower horizontal production wells located along a lower base of the oil-containing seam within the underground formation. 
         [0039]    In each of the above methods it is further contemplated that hot combustion gases which are produced upon ignition of the hydrocarbons and oxidizing gas will travel from a high pressure area within the formation (i.e. typically proximate the upper horizontal injector wells) to a low pressure area (i.e. typically proximate the lower producer wells), and be further drawn into and recovered from said lower horizontal well along with said oil to surface. 
         [0040]    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 perforations in a well liner within the upper horizontal wells, and to utilize as best as possible equal oil entry rates at each perforation along well liner(s) contained within the lower horizontal (production) well. Considering that all horizontal wells typically have a ‘toe’ at a distal end thereof, and a ‘heel’ at a proximal end thereof where the horizontal well joins the downwardly-drilled vertical segment of a horizontal-vertical well pair, in a refinement of the present invention the upper horizontal wells are drilled so that the respective “heels” of the parallel upper horizontal (injection) wells are all on a same side of the reservoir, such side being opposite a side of the reservoir at which the respective heel (proximal end) of the adjacent laterally spaced apart lower horizontal production wells is situated. In other words, the vertical wells which are connected to each of the respective upper horizontal wells are on opposite sides of the reservoir that the vertical wells for the corresponding lower horizontal wells (and their associated respective heel portions) are located. In such manner oxidizing gas which is injected in the upper horizontal well (the pressure thereof being highest at the “heel” [i.e. proximal] end of such upper horizontal wells) has less of a tendency to “short-circuit” directly to the low pressure portion of the lower horizontal well which is at the heel (proximal) end of such lower horizontal well, then located on the opposite side of the reservoir. 
         [0041]    Accordingly, in a further preferred embodiment of the present invention the step of injecting said oxidizing gas into said upper injection wells comprises the step of injecting said oxidizing gas into proximal ends of said upper horizontal wells, such proximal ends situated on a side of said underground formation, and said step of withdrawing oil from said lower horizontal well comprises withdrawing said oil from a proximal end of said lower horizontal well which is situated on another side of said reservoir opposite said side at which said proximal ends of said upper horizontal wells are situated. 
         [0042]    In an alternative embodiment which accomplishes the same purpose of reducing the tendency of “short circuiting” and advantageously allows both the injection and production wells to be drilled with their respective vertical portions (i.e. proximal ends) situated on the same side of the reservoir (i.e. a drilling pad for drilling each of the upper and lower wells can thereby remain on the same side of the reservoir and need not be moved back and forth to opposite sides of the reservoir when drilling lower wells and then upper wells), internal tubing may be used in the upper injection wells and/ or the lower production well(s). 
         [0043]    Specifically, in an alternative embodiment where tubing is employed in the upper horizontal wells, such tubing is provided with an open end proximate the distal end of the upper horizontal wells. Such allows transfer of the point of injection of the oxidizing gas (and thus the high pressure point in such upper horizontal well) to the distal end thereof. In such manner the high pressure source in the upper horizontal injection wells will be at an end of the reservoir opposite the low pressure toe of the producing wells, thereby forcing heated gas to travel a longer distance through the formation and thereby more effectively heat and free oil trapped in the formation, and further avoid “short-circuiting” of combustion gases. Heated gases are thus caused to travel through the formation and be collected by the low pressure area at the toe of the production well. Such configuration has the benefit of permitting drilling pads to all be located on the same side of the reservoir. 
         [0044]    Similarly, where tubing is employed in the lower horizontal wells, such tubing is provided with an open end proximate the distal end of the lower horizontal wells, with the proximal ends of each of the upper production wells, and the lower production well(s) situated on the same side of the reservoir. Such tubing allows transfer of the point of recovery of the produced oil (and thus transfer of the lowest pressure point in such lower horizontal well) to the distal end of the lower production well. In such manner the high pressure source in the upper horizontal injection wells will again be at a proximal end thereof, namely at an end of the reservoir opposite the low pressure distal (toe) portion of the producing wells, thereby forcing heated gas to travel a longer distance through the formation and thereby more effectively heat and thus free oil trapped in the formation, and avoid “short-circuiting” of heated gas. Such configuration, wherein each of the proximal ends of the upper injector wells and lower production wells are on the same side of the reservoir, again has the benefit of permitting all drilling pads to be located on the same side of the reservoir. 
         [0045]    As an alternative 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 in 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. This has the advantage of utilizing gas flow in the annular space to further assist the homogeneous delivery of gas. 
         [0046]    Specifically, the number and size of perforations of the well liner in a injector producer well may progressively increase from the heel portion to the toe portion thereof, in order to more uniformly distribute such oxidizing gas to the reservoir along the entire length of the upper injector wells, and assist in preventing “fingering” of injectant gas directly into production wells. 
         [0047]    Accordingly, in one such embodiment each of said upper horizontal injector wells has a well liner in which said plurality of apertures are situated, and wherein a size of said apertures or a number of said apertures within said well liner progressively increases from a proximal end to a distal end of said upper horizontal wells, and said oxidizing gas is injected into said proximal end of each of said upper horizontal wells. 
         [0048]    Alternatively, or in addition, said lower horizontal well may be provided with a well liner in which a plurality of apertures are situated, and wherein a size of said apertures or a number of said apertures within said well liner progressively increases from a proximal end to a distal end of said lower horizontal well, in order to more uniformly collect mobile oil along substantially the entire length of the production well, and to assist in preventing “fingering” of injectant gas directly into production wells. 
         [0049]    Accordingly, in a further preferred refinement to better allow the upper production wells to more uniformly distribute the oxidizing gas to the formation to avoid “fingering” or “short circuiting” of high pressure oxidizing gas directly to production wells, and to further allow more uniform and efficient collection of oil from the formation by the lower production wells, each of said proximal ends of the upper horizontal injection wells are situated on the same side of the reservoir as the proximal ends of each of the lower horizontal producer wells, and 
         [0050]    (i) each of said upper horizontal injector wells has a well liner in which said plurality of apertures are situated, and wherein a size of said apertures or a number of said apertures within said well liner progressively increases from a proximal end to a distal end of said upper horizontal wells, and said oxidizing gas is injected into said proximal end of each of said upper horizontal wells; and 
         [0051]    (ii) said lower horizontal well(s) may be provided with a well liner in which a plurality of apertures are situated, and wherein a size of said apertures or a number of said apertures within said well liner progressively increases from a proximal end to a distal end of said lower horizontal well. 
         [0052]    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. 
         [0053]    The injected gas may be any oxidizing gas, including but not limited to, air, oxygen or mixtures thereof. In a preferred embodiment the oxidizing gas is air but is further diluted with a varying quantity a non-oxidizing gas such as carbon dioxide or steam, to thereby reduce (per injected volume) the relative concentration of oxygen in such quantity of injected gas, thereby allowing control over the temperature produced during combustion by decreasing the amount of oxygen allowed to combust with hydrocarbon within the formation. 
         [0054]    Alternatively, or in addition, such oxidizing gas contains water vapour, or water droplets, or water which turns to steam, which condenses when moving downwardly in the formation and which releases heat in the latent heat of condensation thereby assisting in transferring heat to oil in the lower portion of the formation and allowing such oil to become mobile and drain downwardly into the lower horizontal collector well. 
         [0055]    The maximum oxidizing 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. 
         [0056]    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. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0057]    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: 
           [0058]      FIG. 1  shows a perspective schematic view of a subterranean hydrocarbon-containing, showing the “staggered well” method of the present invention, having a plurality of upper horizontal injection wells and a plurality of alternatingly-spaced lower horizontal production wells situated low in the reservoir, which uses air injection and in-situ combustion to provide heat to mobilize oil in the formation ; 
           [0059]      FIG. 2  shows a cross-sectional view of  FIG. 1  taken along plane “A-A” in the direction of arrows “A-A; 
           [0060]      FIG. 3  is a perspective view of the staggered well method of the present invention, after a “line drive” method is employed; 
           [0061]      FIG. 4(   i )-( iii ) is a series of three cross-sectional view of  FIG. 1  taken along plane “A-A” in the direction of arrows ‘A-A’, showing a progression of oil recovery steps during successive time intervals during the carrying out of the staggered well “line drive” embodiment of the present invention; 
           [0062]      FIG. 6  shows a perspective schematic view of an alternative “staggered well” method of the present invention, wherein the proximal ends of each of the upper and lower horizontal wells are located on the same side of the underground hydrocarbon reservoir; 
           [0063]      FIG. 6  is an enlarged perspective view of various upper and lower horizontal wells, showing a manner of employing tubing in each of the upper horizontal wells in accordance with an embodiment of the method of the present invention; 
           [0064]      FIG. 7  is an enlarged perspective view of various upper and lower horizontal wells, showing a manner of employing tubing in the lower horizontal well(s) in accordance with an embodiment of the method of the present invention; 
           [0065]      FIG. 8  is an enlarged perspective view of various upper and lower horizontal wells, showing a manner of employing progressively increasing number of apertures in each of the well liners of the upper and lower horizontal wells, in accordance with a further alternative embodiment of the method of the present invention; 
           [0066]      FIG. 9  is an enlarged perspective view of various upper and lower horizontal wells, showing a manner of employing progressively increasing sizes of apertures in each of the well liners of the upper and lower horizontal wells, in accordance with a further alternative embodiment of the method of the present invention; 
           [0067]      FIG. 10  is an alternative oil recovery method, not part of the present invention herein, and is the configuration of the alternative method used for comparison purposes in comparing relative oil recovery factor of such method to that of the present invention, as shown in  FIG. 11 ; and 
           [0068]      FIG. 11  is a graph showing the percentage of oil recovered from a formation, using the method of the present invention (graph “X”); the method of  FIG. 10  (graph “Y”); and a method using staggered wells not forming part of the invention which utilizes steam injection for heating instead of oxidizing gas injection and in situ combustion for heating (graph “Z”). 
       
    
    
     DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS 
       [0069]      FIGS. 1-3  &amp;  5  show a developed subterranean formation/reservoir  22  using an embodiment of the “staggered well” method of oil recovery of the present invention (hereinafter the “Staggered Well” method). In such “Staggered Well” method parallel upper horizontal injection wells  1 ,  1 ′, &amp;  1 ″ of each of length “b” are placed parallel to each other in mutually spaced relation, all situated high in a hydrocarbon-containing portion  20  of thickness “a” which forms part of subterranean formation/reservoir  22  situated below ground-level surface  24 . Parallel horizontal, spaced apart lower horizontal production wells  2 ,  2 ′ &amp;  2 ″ of similar length “b” are respectively placed low in the reservoir  22 , both below and approximately intermediate 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 ′, &amp;  1 ″ and oil production wells  2 ,  2 ′ &amp;  2 ″ as shown in  FIGS. 1-3  &amp;  5 . 
         [0070]    The hydrocarbon-containing reservoir  22  shown in  FIG. 1  possesses two and one-half injection wells  1 ,  1 ′, &amp;  1 ″ and two and one-half production wells  2 ,  2 ′, &amp;  2 ″ (edge injection well  1  and edge production well  2 ″ each respectively constituting one-half well) for a total of five horizontal wells in the pattern. Conducting three repetitions of the method of  FIG. 1  requires fifteen horizontal wells, as shown in  FIG. 3 . 
         [0071]    The lateral spacing “c” of the upper horizontal injection wells  1 ,  1 ′, &amp;  1 ″ and the lower horizontal injection wells  2 ,  2 ′ &amp;  2 ″ is preferably uniform. 
         [0072]    In the embodiment of the Staggered Well method shown in  FIG. 1 , the vertical segments  8  of the horizontal injection wells  1 ,  1 ′ &amp;  1 ″ are at opposite sides of reservoir  22  compared with the vertical segments  9  of the horizontal production wells  2 ,  2 ′ &amp;  2 ″, each vertical segment  8  of associated respective horizontal well  1 ,  1 ′ &amp;  1 ″ extending upwardly to surface  24  and likewise each vertical segment  9  of associated respective horizontal production well  2 ,  2 ′ &amp;  2 ″ extending upwardly to surface  24 . (For purposes of clarity, only vertical segments portions  8 ,  9  of the respective vertical wells extending to surface  24  are depicted in  FIG. 1 ). Accordingly, the vertical segments  8  of the each of injection wells  1 ,  1 ′, &amp;  1 ″ in the embodiment of the method shown in  FIG. 1  are thus longitudinally offset by the well length ‘b’ from the respective vertical segments  9  (and corresponding associated horizontal production wells  2 ,  2 ′ &amp;  2 ″. 
         [0073]    Vertical segments  9  and associated horizontal production wells  2 ,  2 ′, &amp;  2 ″ which are situated intermediate horizontal injection wells  1 ,  1 ′ &amp;  1 ″, are laterally offset from horizontal injection wells  1 ,  1 ′ &amp;  1 ″ and associated vertical segments  8   a  distance “c”. The reason for such lateral offset “c” is to eliminate or at least minimize “short-circuiting” of injected oxidizing gas directly from injection wells  1 ,  1 ′, &amp;  1 ″ into production wells  2 ,  2 ′ &amp;  2 ″ as explained above. 
         [0074]    The pattern shown in  FIG. 1  can be extended indefinitely away from the face  3  and/or the face  6  as desired to cover a specific volume of oil reservoir  22 . In further phases of the reservoir development, as shown in  FIG. 3 , an additional array of injections wells  1 ,  1 ′, &amp;  1 ″ and production wells  2 ,  2 ′ &amp;  2 ″ are drilled adjacent to the first array of  FIG. 1 , and such process repeated, eventually exploiting the entire reservoir  22 . 
         [0075]    Referring to  FIG. 1  showing one embodiment of the invention, horizontal injector wells  1  &amp;  1 ′ and production well  2  are drilled, in a preferred embodiment each being provided with well liner segments  30  situated in each of horizontal wells  1 ,  1 ′, &amp;  1 ″ and  2 ,  2 ′ &amp;  2 ″. Well liner segments  30  each contain apertures or slots  24  from which an oxidizing gas, which may further include carbon dioxide and/or steam, is injected into formation  22  via an injector wells  1 ,  1 ′. 
         [0076]    Upon ignition of the so-formed oxidizing gas and hydrocarbon mixture in the reservoir  22 , and in particular in the oil-bearing seam  20  thereof, heated oil and combustion gas (not shown) contained with reservoir partition segments  50   a,    50   b  flow and are drawn downwardly due to lower pressures toward production well  2 , and are drawn into and enter production well  2  via apertures  24  therein. Thereafter such collected oil and combustion gases (not shown) are drawn to surface  24  via gas lift or pump means. 
         [0077]    In the case of horizontal production wells  2 ,  2 ′ &amp;  2 ″, well liners  30  and the apertures  24  therein may take the form of slotted liners, wire-wrapped screens, FacsRite™ well liners having sand screen plugs, or combinations thereof, to reduce the flow of sand and other undesirable substances such as drill cuttings from within the formation  22  into production wells  2 ,  2 ′ &amp;  2 ″. 
         [0078]    The Staggered Well (Air Injection) method may utilize a “line drive” configuration, by drilling another injection well  1 ″ and a corresponding production well  2 ′, as shown in  FIG. 1 . Such method is better illustrated in  FIG. 4(   i )-( iii ), in which three successive phases are implemented and depicted. In this regard,  FIG. 4  shows views on section A-A of  FIG. 1 , at successive respective time intervals (i), &amp; (iii), showing a method of causing a “line drive” of oil recovery in the direction “Q”, and in particular the remaining portions of oil bearing seam  20  which continue to possess oil and thus illustrates the progressive recovery of oil from oil bearing seam  20 . Specifically, as seen from the first phase [ FIG. 4(   i )], the injector wells  1 ,  1 ′, and  1 ″, and producer well  2  and  2 ′ are first drilled, and after injection of oxidizing gas into formation  22  via injection wells  1 ,  1 ′ &amp;  1 ″ and ignition of the so-formed mixture of oxidizing gas and hydrocarbons in reservoir  22 , production of oil from well  2  and  2 ′ is commenced, causing depletion of oil from oil bearing seam  20 , as shown in  FIG. 4(   i ). Thereafter in a second phase [ FIG. 4(   ii )], a further producer well  2 ″ is drilled, and injection and production commenced respectively in regard to injector wells  1 ,  1 ′, and production well  2 ′. In a third phase [ FIG. 4(   iii )], a fourth injector  1 ′″ and a fourth producer  2 ′″ are drilled, with production ceasing from production well  2 , and injection and production commenced in injection well  1 ′″ and production well  2 ′″ respectively. The process may be continued indefinitely as shown in  FIG. 3 , until reaching an end of reservoir  22 . 
         [0079]    Alternatively, as mentioned above, such “Staggered Well (Air Injection)” method may simply consist of simultaneously drilling a set number of injector wells (e.g. such as three wells  1 ,  1 ′, &amp;  1 ″) and a corresponding number of producer wells (e.g. such as three wells  2 ,  2 ′ &amp;  2 ″), so as to produce the “pattern” of staggered wells of wells  1 ,  1 ′, &amp;  1 ″ and  2 ,  2 ′ &amp;  2 ″ shown in  FIG. 1 , and produce oil from reservoir partition segments  50   a,b ,  50   c,d,  and  50   e.  Such pattern may be repeated as necessary, as shown in  FIG. 3  through well partition segments  50   f - 50   o , in order to exploit an entire reservoir  22 . 
         [0080]      FIG. 5  shows an alternate embodiment of the Staggered Well (Air Injection) method of unregistered trademark of Absolute Completion Technologies for well liners having sand screens therein the present invention, where each of vertical segments  8 ,  9  of corresponding horizontal wells  1 ,  1 ′, &amp;  1 ″ and  2 ,  2 ′, &amp;  2 ″ respectively, are drilled on the same side  4  of reservoir  22 . Advantageously, as discussed above, such configuration allows a drilling pad for drilling wells  1 ,  1 ′, &amp;  1 ″ and  2 ,  2 ′, &amp;  2 ″ to remain on the same side  4  of reservoir  22 , thus increasing the speed and ease by which the wells  1 ,  1 ′, &amp;  1 ″ and  2 ,  2 ′, &amp;  2 ″ may be drilled. 
         [0081]    When vertical segments  8 , 9  of corresponding horizontal wells  1 ,  1 ′, &amp;  1 ″ and  2 ,  2 ′, &amp;  2 ″ respectively are drilled on the same side  4  of reservoir  22  as shown in  FIG. 5 , to better and more uniformly inject oxidizing gas into formation  22  via horizontal wells  1 ,  1 ′, &amp;  1 ″, and/or to more uniformly collect oil in horizontal wells  2 ,  2 ′, &amp;  2 ″, it is preferred to use tubing  40  in the manner described below. 
         [0082]    Specifically, in a first embodiment employing tubing  40 , tubing  40  is inserted in upper horizontal injection wells  1 ′,  1 ″,  1 ′″ of  FIG. 1  and in all injection wells, if desired.  FIG. 6  shows an exemplification of such concept using tubing  40  in two adjacent injection wells  1 ′,  1 ″. Such tubing  40  preferentially extends from the heel  43  at the vertical portion  8  of each of wells  1 ′,  1 ″ to the toe portion  44  of each of such wells  1 ′,  1 ″. Gaseous air “G” is injected into tubing  40 , which air “G” thereafter flows into injection wells  1 ′,  1 ″ and thereafter into oil bearing seam  20  of formation  22  via apertures  24  in well liner segments  30  as shown in  FIG. 6 . Heated oil “O” flows into apertures  24  in well liners  30  of producer well  2 ′, and is thereafter produced to surface  24  (see  FIG. 1 ) 
         [0083]    Alternatively, in a second alternative embodiment employing tubing  40 , tubing  40  is inserted in lower production wells  2 ,  2 ″,  2 ′″, and  2 ″″ of  FIG. 1  and in all injection wells, if desired.  FIG. 7  shows an exemplification of such concept using tubing  40  in one production well  2 ′. Such tubing  40  preferentially extends from the heel  43  at the vertical portion  9  of production  2 ′ to the toe portion  44  thereof, as shown in  FIG. 7 . Oil “O” is withdrawn from toe  44  of production well  2 ′ via tubing  40 , such oil “O” entering apertures  24  in well liners  30  in production well  2 ′, and is thereafter produced to surface  24  (see  FIG. 1 ). 
         [0084]    Alternatively, instead of using tubing  40  within the method of the present invention to more uniformly heat the oil in the formation, prevent short-circuiting between injector wells  1 ,  1 ′,  1 ′″, and producer wells  2 ,  2 ′,  2 ″, and  2 ″, and thereby better collect oil “O” in horizontal wells  2 ,  2 ′, &amp;  2 ″, it is contemplated that either the number or size of apertures  24  in well liners  30  in production wells  2 ,  2 ′,  2 ″, be progressively increased from heel  42  to toe  44 . 
         [0085]    Specifically,  FIG. 8  shows one such embodiment being utilized in respect of a single production well  2 ′, where the number of apertures  24  in well liners  30  in production wells  2 ,  2 ′,  2 ″, is progressively increased from heel  42  to toe  44 . 
         [0086]      FIG. 9  shows another alternative embodiment of such concept being utilized in respect of a single production well  2 ′, where the size of apertures  24  in well liners  30  in production wells  2 ,  2 ′,  2 ″, is progressively increased from heel  42  to toe  44 . 
       EXAMPLES 
       [0087]    Extensive computer simulation of processes for the recovery of mobile oil were undertaken using the STARS™ Thermal Simulator 2010.12 provided by the Computer Modelling Group, Calgary, Alberta, Canada. 
         [0088]    The model dimensions used in comparative Examples 1-3 below in number of grid blocks were 20×50×20 and the grid block sizes were respectively 5.0 m, 5.0 m and 1.0 m, resulting in the same total reservoir volume in each case of 500,000 m 3  (i.e. 100 m×250 m×20 m). 
         [0089]    The modelling reservoir used in each of comparative Examples 1-3 below contained bitumen at elevated temperature (54.4°) with high rock permeability. 
         [0090]    In each of comparative Examples 1-3 below, the total number of wells used for comparative purposes was the same. 
         [0091]    Specifically, for the Staggered Well (Air Injection) method, namely a method of the present invention (Example 1 below), a total of five wells were employed, namely 2.5 injection wells  1 ,  1 ′, and  1 ″, and 2.5 production wells  2 ,  2 ′, and  2 ″, keeping in mind that injection well  1  and production well  2 ″ which appear at the end of grid block  50   a  and  50   e,  respectively, are counted as half-wells. 
         [0092]    For the Staggered Steam configuration and method (e.g. as per  FIG. 1 , but not using air injection or in situ combustion-see Example 2 below), a total of five wells consisting of 2.5 injection wells  1 ,  1 ′, and  1 ″, and 2.5 production wells  2 ,  2 ′, and  2 ″, again keeping in mind that injection well  1  and production well  2 ″ which appear at the end of grid block  50   a  and  50   e , respectively, are counted as half-wells. 
         [0093]    With regard to the “crossed-wells” configuration/method as shown in  FIG. 10  (see Example 3, below), a similar total of five wells were used, namely two (2) injection wells  1 ′,  1 ″, and three (3) production wells  2 ,  2 ′,  2 ″, and  2 ′″, again keeping in mind that production well  2  and production well  2 ″″ which each appear at the end of the grid block shown in  FIG. 10  are counted as half-wells. 
         [0094]    With regard to each comparative model described in Examples 1-3 below, each model received an identical amount of gaseous injection, namely a total of 50,000 m 3 /day, with Examples 1 and 3 receiving air injection, and Example 2 receiving gaseous steam injection. 
         [0095]    For combustion simulations with air the reactions used:
       1. 1.0 Oil→0.42 Upgrade (C 16 H 34 )+1.3375 CH 4 +29.6992 Coke   2. 1.0 Oil+13.24896 O 2 →5.949792 H 2 O+6.0 CH 4 +9.5 CO 2 +0.5 CO/N2+27.3423 Coke   3. 1.0 Coke+1.2575 O 2 →0.565 H 2 O+0.95 CO 2 +0.05 CO/N2       
 
         [0099]    In order to improve sweep efficiency, the transmissibility of the oil production wells  2 ,  2 ′,  2 ″, and  2 ′″ was varied monotonically from 1.0 at the toe to 0.943 at the heel. Practically speaking, as described herein, such diminished transmissibility of the oil along the length of a production well  2 ,  2 ′,  2 ″, and/or  2 ″″ can be accomplished by progressively decreasing either the aperture  24  size, or number of apertures  24  of sequential slotted liner segments  30  from toe  44  to heel  42  of production wells  2 ,  2 ′,  2 ″, or  2 ″″ (see for example  FIG. 8 ,  FIG. 9 , respectively). 
         [0100]    Additional reservoir properties for each of the reservoirs  22  and comparative methods of oil extraction modelled in Examples 1-3 below were set out in TABLE 1, below: 
         [0000]    
       
         
               
             
               
               
               
               
             
               
               
               
               
             
           
               
                 TABLE 1 
               
             
             
               
                   
               
               
                 Reservoir properties, oil properties and well control. 
               
             
          
           
               
                   
                 Parameter 
                 Units 
                 Value 
               
               
                   
                   
               
             
          
           
               
                   
                 Reservoir Properties 
                   
                   
               
               
                   
                 Pay thickness 
                 m 
                 20 
               
               
                   
                 Porosity 
                 % 
                 30 
               
               
                   
                 Oil saturation 
                 % 
                 80 
               
               
                   
                 Water saturation 
                 % 
                 20 
               
               
                   
                 Gas mole fraction 
                 fraction 
                 0.263 
               
               
                   
                 H. Permeability 
                 mD 
                 5000 
               
               
                   
                 V. Permeability 
                 mD 
                 3400 
               
               
                   
                 Reservoir temperature 
                 ° C. 
                 54.4 
               
               
                   
                 Reservoir pressure 
                 kPa 
                 3000 
               
               
                   
                 Rock compressibility 
                 /kPa 
                  3.5E−5 
               
               
                   
                 Conductivity 
                 J/m.d.C 
                  1.5E+5 
               
               
                   
                 Rock Heat capacity 
                 J/m 3 -C 
                 2.35E+6 
               
               
                   
                 Oil Properties 
               
               
                   
                 Density 
                 Kg/m 3   
                 1009 
               
               
                   
                 Viscosity, dead oil @ 20 C. 
                 cP 
                 77,000 
               
               
                   
                 Viscosity, in situ 
                 cP 
                 1139 
               
               
                   
                 Average molecular weight oil 
                 AMU 
                 598 
               
               
                   
                 Average molecular weight 
                 AMU 
                 224 
               
               
                   
                 Upgrade 
               
               
                   
                 Oil mole fraction 
                 Fraction 
                 0.737 
               
               
                   
                 Compressibility 
                 /kPa 
                 1.06E+3 
               
               
                   
                 The wells were controlled 
               
               
                   
                 using the following 
               
               
                   
                 parameters: 
               
               
                   
                 Maximum air injection pressure 
                 kPa 
                 7,000 
               
               
                   
                 Horizontal well length 
                 m 
                 500 
               
               
                   
                 Producer BHP minimum 
                 kPa 
                 2600 
               
               
                   
                 Total air or steam injection rate 
                 m 3 /d 
                 50,000 
               
               
                   
                   
               
             
          
         
       
     
       Example 1 
     Staggered Well (Air Injection) Method 
       [0101]      FIGS. 1 and 4(   i )-( iii ) depict a method of oil recovery (using air injection and in situ combustion heating) of the present invention, and in particular depict the method used in Example 1 [Staggered Well (Air Injection)], utilizing a total air injection volume of 50,000 m 3 /d. 
         [0102]    For the Staggered Well (Air Injection) Method as shown in  FIGS. 1 , 2.5 injection wells  1 ,  1 ′, and  1 ″, and 2.5 production wells  2 ,  2 ′, and  2 ′ as part of grid blocks  50   a - 50   e , were all simultaneously drilled, for a total of five wells. The reservoir thickness ‘a’ was 20 m and the well offset ‘c’ was 50 m for each grid block  50   a - 50   o . Air injection rates were 10,000 m 3 /d for well  1  and 20,000 m 3 /d for each of injectors  1 ′ and  1 ″, for a total of 50,000 m 3 /d for the grid block pattern  50   a - 50   e.    
         [0103]    A summary of results, namely the Oil Recovery Factor over time (1,825 days=5 years) for Example 1, is shown in  FIG. 11  as line ‘X’. 
       Example 2 
     Crossed-Wells Method 
       [0104]      FIG. 10  shows an alternative method of oil recovery from a subterranean reservoir  22 , which is not the subject matter of this application but of another patent application of the within inventor and commonly assigned (hereinafter the “crossed wells” method). 
         [0105]    In the crossed-well method depicted in  FIG. 10 , injector wells  1 ,  1 ′ are perpendicularly disposed to the horizontal collection wells  2 ,  2 ′,  2 ″, and  2 ′″. Specifically in this crossed-well method, parallel horizontal well injection wells  1 ,  1 ′ are placed high in reservoir  22 , and parallel horizontal production wells  2 ,  2 ′,  2 ″, &amp;  2 ″ are placed low in reservoir  22  perpendicular to injection wells  1 ,  1 ′. Horizontal Injection well  1 ′ is located distance ‘q’ (25 m) from the front edge of the model and injection well  1  is placed distance ‘q’ from the back side of reservoir  22 , namely with injectors  1 ,  1 ′ separated by a distance ‘2 q’. The well length is “b”. The spacing of the horizontal production wells is “c”, for a total grid block volume of 500,000 m 3 . 
         [0106]    The air injection rate into the upper injection wells  1 ,  1 ′ was 50,000 m31/d, divided equally between injector wells  1 ,  1 ′. Air was injected continuously and oil, water and gas were produced continuously from the lower wells  2 ,  2 ′,  2 ″ &amp;  2 ″. 
         [0107]    A summary of results, namely the Oil Recovery Factor over time (1,825 days=5 years) for Example 2, is shown in  FIG. 11  as line ‘Y’. 
       Example 3 
     Staggered Steam Method 
       [0108]    Example 3 (method of  FIG. 1 , but with hot steam injection instead of air injection and not employing in situ combustion) is not part of the present invention, and is only provided to illustrate the comparative efficiency with other oil recovery methods (e.g. Example 1 and Example 2). 
         [0109]    Saturated steam was injected continuously at the rate of 150, 300 and 300 m 3 /d (water equivalent—for a total of 50,000 m 3 /d gaseous equivalent) into injection wells  1 ,  1 ′ and  1 ″ respectively, while production wells  2 ,  2 ′ and  2 ″ were open to production. 
         [0110]    A summary of results of the Staggered Steam method, showing the Oil Recovery Factor over time (1,825 days=5 years) for Example 3, is shown in  FIG. 11  as line ‘Y’. 
       COMPARISON AND PROVEN ADVANTAGES 
       [0111]    Comparing lines ‘Y’ (Crossed-wells) and line “X” [the present invention, Staggered Wells (Air Injection) it is clear that at any selected time the oil recovery is higher with the present invention. 
         [0112]    Comparing line “Z” (Staggered Steam injection) with line “X” of the present invention [Staggered Wells (Air Injection) ] the benefit of higher early oil rate with the present invention is even greater. 
         [0113]    The higher Oil Recovery Factors at 2.4 years and 5.0 years of the present invention (Line “X”) show the significant financial advantage of the present invention considering the earlier return on investment in the form of earlier and greater oil recovery. Also, with a lower Air/Oil ratio than the steam injection method (Example 3), the present invention (Example 1) will carry lower air compression costs. Because of the thermal inefficiency of steam processes, the Staggered Steam process is not competitive. 
         [0000]    
       
         
               
             
               
               
               
               
               
               
               
             
           
               
                 TABLE 2 
               
             
             
               
                   
               
               
                 Oil recovery Factors and energy requirements. 
               
             
          
           
               
                   
                   
                 Oil recovery 
                 Cumulative 
                   
                   
                   
               
               
                   
                   
                 factor, % 
                 Oil 
                 Oil recovery 
                 Cumulative 
                 Relative 
               
               
                 Well 
                   
                 2.4-years 
                 5-year, km 3   
                 factor at 
                 Air/Oil 
                 energy 
               
               
                 Arrangement 
                 Line 
                 (874 days) 
                 (1827 days) 
                 5-years, % 
                 Ratio 
                 cost 
               
               
                   
               
               
                 Crossed Wells* 
                 “Y” 
                 49.9 
                 93.3 
                 80.0 
                 980 
                 1.0 
               
               
                 (Example 2 and 
               
               
                 FIG. 10)* 
               
               
                 Staggered Steam 
                 “Z” 
                 40.7 
                 98.2 
                 82.7 
                 N/A 
                 2.2-4.4 
               
               
                 Injection* 
               
               
                 (Example 3 and 
               
               
                 FIG. 1) 
               
               
                 Staggered Wells 
                 “X” 
                 56.5 
                 98.2 
                 81.2 
                 866 
                 1.0 
               
               
                 (Air Injection) 
               
               
                 (Example 1 and 
               
               
                 FIG. 1) 
               
               
                   
               
               
                 *Does not form part of the invention claimed herein 
               
             
          
         
       
     
         [0114]    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.