Patent Publication Number: US-2012037370-A1

Title: Well completion and related methods for enhanced recovery of heavy oil

Description:
FIELD OF THE INVENTION 
     The present invention relates to petroleum production. More particularly, the invention relates to the utilization of pressurized and heated natural formation gas for enhanced recovery of petroleum from heavy oil formations. 
     BACKGROUND OF THE INVENTION 
     Although technically referring to liquid petroleum having an American Petroleum Institute (“API”) gravity of less than 22.3° (i.e., having a relative density of greater than about 0.92), “heavy oil” generally denotes any type of crude oil which does not flow easily. Compared to light or even medium crude oil, the production, transportation and refining of the denser and more viscous heavy crude oil present many special challenges, which not only increase the cost of production but also result in discounted pricing. Because it conservatively accounts for more than double the worldwide resources of conventional oil, however, heavy oil cannot be ignored to satisfy current and future oil demand notwithstanding that character generally renders conventional production methods ineffective. As a result, such tertiary techniques as steam flooding, steam assisted gravity drainage and cyclic steam injection have traditionally been employed in attempts to reach this increasingly important resource. 
     Steam flooding, also sometimes referred to as continuous steam injection or steam drive, is a method of thermal recovery in which steam is generated at the well surface and then injected into the reservoir through specially distributed injection wells. As the steam enters the reservoir, two mechanisms become available to improve the amount of oil recovered. First, the steam heats up the crude oil, reducing its viscosity and enabling it to more easily flow through the formation toward a producing well. Second, the hot water that condenses from the steam and the steam itself generate an artificial drive that sweeps oil toward the producing well. While steam flooding is for the most part regarded as a more generalized recovery method, steam assisted gravity drainage (“SAGD”) is a thermal production method typically only utilized for heavy oil. In any case, SAGD pairs a high-angle injection well with a nearby production well drilled along a parallel trajectory, the pair of wells being typically drilled with a vertical separation of only a few meters distance. Steam is then injected into the reservoir through the upper well and as the steam rises and expands it heats up the heavy oil, reducing its viscosity in the manner of steam flooding generally. In SAGD, however, gravity is relied upon to force the oil to drain into the lower well where it is otherwise produced. Both techniques, however, require enormous quantities of fresh water and considerable energy to generate the necessary large quantities of steam as well as multiple, specialized wells and, in the end, are only modestly effective for the enhancement of heavy oil production. 
     As an alternative to steam flooding, cyclic steam injection, which is sometimes referred to as steam soak or the “huff-n-puff” method, is a method of thermal recovery used extensively in heavy oil reservoirs in which a well is removed from production, injected with steam and then subsequently put back on production. In particular, cyclic steam injection is conducted in three phases: (1) the injection phase, during which a slug of steam is introduced into the reservoir; (2) the soak phase, which requires that the well be shut in for several days to allow uniform heat distribution to thin the oil; and (3) the production phase, during which the thinned oil is produced through the same well. While requiring less steam than steam flooding and capable of implementation through a single well, cyclic steam injection is nonetheless costly and, like steam flooding, is only modestly effective for the enhancement of heavy oil. 
     Given the shortcomings of more the generalized and closely related techniques, but faced with the fact that heavy oil has become increasingly more important in many countries, greater and greater resources have been focused on the task of improving the available methods for its recovery and, as a result, the state of the art increasingly encompasses more extreme or experimental as well as more costly techniques. For example, in a non-thermal process very similar to SAGD, hydrocarbon solvents, instead of steam, are injected into the upper well to dilute the bitumen and allow it to flow into the lower well. Although the process has garnered some attention due to its much better energy efficiency than steam injection, the process is thought to be cost effective only under narrow circumstances. 
     In a further example, however, of new and experimental methods being brought to bear for the recovery of heavy oil, toe-to-heel air injection is a method that modifies conventional fire flooding techniques to combine a vertical air injection well with a horizontal production well. The process ignites oil in the reservoir and creates a vertical wall of fire moving from the “toe” of the horizontal well toward the “heel,” which burns the heavier oil components and upgrades some of the heavy bitumen into lighter oil right in the formation. Like vapor extraction, however, toe-to-heel air injection is limited to only certain formations and also carries high well costs. 
     With the foregoing limitations of the prior art clearly in mind, it is therefore an overriding object of the present invention to improve over the prior art by setting forth a well completion and related methods adapted to more generalized application for enhanced recovery of petroleum from heavy oil formations. Additionally, it is an object of the present invention to set forth such a well completion and related methods that are cost effective in practice. Still further, it is an object of the present invention to set forth such a well completion and related methods that are flexible in specific implementation. Finally, it is an object of the present invention to set forth such a well completion and related methods that are environmentally conscientious. 
     SUMMARY OF THE INVENTION 
     In accordance with the foregoing objects, the present invention—a well completion for use in enhanced recovery of heavy oil—generally comprises means for capture from a heavy oil formation of natural gas; means for pressurizing said captured natural gas, said means for pressurizing said captured natural gas comprising means for controlling the temperature of said pressurized natural gas; and means for reintroduction to said formation of said pressurized captured natural gas. 
     In use of the well completion, a method for enhancing production of petroleum from a heavy oil formation generally comprises comprising the steps of: producing a hydrocarbon mixture from within a heavy oil formation; extracting a quantity of natural formation gas from said hydrocarbon mixture; pressurizing said quantity of natural formation gas to a specified pressure; maintaining said pressurized natural formation gas at a specified temperature by controlling conduction from said pressurized natural formation gas of adiabatic heat produced in said pressurizing step; and reintroducing said pressurized and heated natural formation gas to said heavy oil formation. 
     Finally, many other features, objects and advantages of the present invention will be apparent to those of ordinary skill in the relevant arts, especially in light of the foregoing discussions and the following drawings, exemplary detailed description and appended claims. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       Although the scope of the present invention is much broader than any particular embodiment, a detailed description of the preferred embodiment follows together with illustrative figures, wherein like reference numerals refer to like components, and wherein: 
         FIG. 1  shows, in a functional block diagram, the preferred embodiment of the surface components of the well completion of the present invention; 
         FIG. 2  shows, in a partially cut away side-elevation cross-section view taken through the center axis of a well bore, a first preferred embodiment of the downhole components of the well completion of the present invention; 
         FIG. 3  shows, in a partially cut away side-elevation cross-section view taken through the center axis of a well bore, details of an extension of the embodiment of the downhole components as shown in  FIG. 2 , the details shown therein, however, being generally applicable to other embodiments as well; 
         FIG. 4  shows, in a partially cut away side-elevation cross-section view taken through the center axis of a well bore, a second preferred embodiment of the downhole components of the well completion of the present invention; 
         FIG. 5  shows, in a partially cut away side-elevation cross-section view taken through the center axis of a well bore, an alternative implementation of the embodiment of the downhole components as shown in  FIG. 4 ; 
         FIG. 6  shows, in a partially cut away side-elevation cross-section view taken through the center axis of a well bore, a third preferred embodiment of the downhole components of the well completion of the present invention; 
         FIG. 7  shows, in a functional block diagram, an alternative implementation of the embodiment of the surface components as shown in  FIG. 1 ; and 
         FIG. 8  shows, in a partially cut away side-elevation view cross-section view taken through the center axis of a well bore, an extension of the invention of the embodiments of  FIGS. 4 and 5 . 
     
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT 
     Although those of ordinary skill in the art will readily recognize many alternative embodiments, especially in light of the illustrations provided herein, this detailed description is exemplary of the preferred embodiment of the present invention, the scope of which is limited only by the claims appended hereto. 
     Referring now to the figures, the preferred embodiments of the well completion  10  for enhanced recovery of heavy oil of the present invention are shown to generally comprise various surface components  11 , such as particularly shown in  FIGS. 1 and 7 , cooperatively arranged at or adjacent one or more wellheads  53  and various cooperatively arranged downhole components  83 , such as particularly shown in  FIGS. 2 through 6 , placed within one or more wellbores  85  through a heavy oil containing formation  84 . Although it is to be understood that any particular implementation of the presently contemplated well completion  10  will in practice likely include many additional elements peculiar to the circumstances of the formation about which such implementation is had and, similarly, that in various circumstances many of the features described herein as being preferred or generally desirable will not be required to take at least some advantage of the teachings hereof, the various components  11 ,  83  of the well completion  10  of the present invention will in any case include or otherwise cooperatively comprise at least means for capture from the formation  84  of natural formation gas; means for temperature controlled pressurization of previously captured natural formation gas; and means for reintroduction to the formation  84  at a selected temperature and at a selected pressure of previously captured and pressurized natural formation gas, wherein the selected pressure is greater that the natural formation pressure and the selected temperature is greater than the natural formation temperature. Additionally, and as will be better understood further herein, the well completion  10  of the present invention realizes the necessary heating of previously captured natural formation gas as a byproduct of the necessary pressurization of the same natural formation gas, thereby resulting in extremely energy efficient utilization of natural formation gas for enhanced production of heavy oil. 
     As particularly shown in  FIG. 1 , the preferred embodiment of the present invention contemplates a substantially conventional completion of the wellhead  53 , wherein a production string  90  terminates through a conventional casing spool  87  or like structure into the topside “Christmas tree,” through which, as also is conventional, the production string  90  will be placed in fluid communication with a production line  54  at the surface. In accordance with the present invention, fluid flow from the production string  90  into the production line  54  is under ordinary operations controlled through an automated flow control valve  55 . As is otherwise conventional, the automated flow control valve  55 , which is provided in connection with the Christmas tree structure, may be actuated by hydraulic, gas, electric or other means and is remotely operated through a provided valve controller  56 . While, for clarity, the graphical depictions of the figures as well as this exemplary only discussion omit many features necessary in actual implementation of a well completion, such as, for example, a manually operated backup flow control valve  57 , check valves and the like, all such features are otherwise conventional in the art and their necessity and manner of implementation will be well known to those of ordinary skill in the art. In any case, the production line  54  is in fluid communication with a means for the separation of natural formation gas from other production fluids with which such gas is associated. 
     In particular, the production line  54  terminates at the inlet  62  to a conventional two-phase or, as shown in  FIG. 1 , three-phase separator  61 , wherein oil, gas and water are separated from the total fluid stream flowing though the production line with any recovered free water flowing through the free water effluent  63  to a wastewater storage tank  64  for further treatment as may be necessary, any produced petroleum flowing through an oil effluent  65  to local storage battery  66  or production pipeline and any produced natural formation gas flowing through a gas outlet  67  (and, if necessary or otherwise desired, a provided mist extractor  68 ) to a raw gas line  69  from the separator  61 . 
     Because the raw formation gas flow stream will at this point likely still contain dirt or other foreign matter and water or other undesired liquids, none of which should be introduced to downstream rotating equipment or the gathering system pipeline  113 , the most preferred embodiment of the present invention contemplates that the raw gas line  69  from the separator  61  should terminate at the inlet  71  of a conventional scrubber  70 , the outlet  73  of which is preferably connected to an outlet gas line  74  also forming the inlet gas line  78  in fluid communication with the inlet  77  of a conventional dehydrator  76 . Although the present invention contemplates implementation with any dehydrator  76  otherwise appropriate for the circumstances of the greater completion, it is noted that the raw gas is at this point in the implementation likely not at the very high pressure required for solid-desiccant dehydration. As a result, the dehydrator  76  of the present is appropriately implemented as a glycol absorption dehydrator. 
     In any case, as particularly shown in  FIG. 1 , the well completion  10  of the present invention at this juncture departs from convention. In particular, whereas in a typical completion the outlet  79  from the dehydrator  76  would connect directly (or through a meter  115  or the like) to an offsite gas line  114  in communication with a gathering system pipeline  113 , in the present invention the outlet  79  from the dehydrator  76  connects through a provided outlet gas line  80  to a specially provided valve unit  116 , which valve unit  116  in turn connects to the offsite gas line  114  leading ultimately to the gathering system pipeline  113 . As will be better understood further herein, the provided valve unit  116  enables the gas flow through the offsite gas line  114  to be selectively controlled through an associated valve controller  117  such that in certain circumstances flow from the outlet gas line  80  from the dehydrator  76  provides raw gas to the gathering system pipeline  113  while in other circumstances the gathering system pipeline  113  acts as a source of gas for use by additional components of the well completion  10  of the present invention, which additional components are located in the completion  10  opposite the dehydrator  76  downstream of the valve unit  116 . As also will be better understood further herein, the associated valve controller  117  is in electrical communication with a system controller  82 , which controller  82  is programmed or otherwise adapted to collect and analyze data and other information, collected in real time and historically, and, based upon the analysis thereof, to operate the various valves (such as, for example, the previously discussed valve controller  56  associated with the automated flow control valve  55  upstream the production line  54 ), motors and other components of the well completion  10  in order to safely and efficiently enhance the production of petroleum from the heavy oil formation  84  in connection with which the well completion  10  of the present invention is implemented. 
     In any case, the well completion  10  of the present invention comprises a gas heater  12  adapted to pressurize and heat a quantity of the natural formation gas extracted and captured from the heavy oil formation  84  through which the wellbore  85  extends, whereafter the pressurized and heated natural formation gas is reintroduced to the formation  84  in a manner that enhances production from the formation  84  of additional hydrocarbon products. As will be better understood further herein, and in a critical aspect of the present invention, the gas heater  12  is consistent with this purpose further adapted to enable precise control of both the temperature and the pressure at which the natural formation gas is reintroduced to the formation  84 , which precise control is necessary not only for maximizing production from the formation  84  but also for ensuring the safe operation of the well completion  10 . Still further, in order to provide an energy efficient contribution to the art, the gas heater  12  of the present invention is adapted to maintain the desired temperature of the reintroduced natural formation gas solely by controlling conduction heat from pressurization of the natural formation gas to the desired pressure of reintroduction. 
     As shown in  FIG. 1 , such a gas heater  12  may be readily implemented with a preferably multistage gas compressor  13 , such as the depicted three-stage gas compressor, having integrated therewith a controllable, preferably interstage, cooling system  23 . In the most preferred embodiment of the present invention, the natural formation gas from the upstream components is conveyed through a compressor gas supply line  75  into the gas inlet  15  of the first compressor stage  14  wherein the gas is pressurized by an initial amount. The initially pressurized natural formation gas then exits the first compressor stage  14  through a gas outlet  16  in fluid communication with a gas inlet  25  to a provided first radiator  24  or like heat exchanger. As will be better understood further herein, this first radiator  24  is adapted to conduct from the initially pressurized natural formation gas substantially all of the adiabatic heat produced in the gas in the first compressor stage  14 . In any case, the initially pressurized natural formation gas exits the first radiator  24  through a gas outlet  27  in fluid communication with the gas inlet  18  of the second compressor stage  17  wherein the gas is pressurized by an additional amount. 
     The subsequently pressurized natural formation gas then exits the second compressor stage  17  through a gas outlet  19  in fluid communication with a gas inlet  33  to a provided second radiator  32  or like heat exchanger. As will be better understood further herein, this second radiator  32  is adapted to conduct from the further pressurized natural formation gas substantially all of the adiabatic heat produced in the gas in the second compressor stage  17 . In any case, the subsequently pressurized natural formation gas exits the second radiator  32  through a gas outlet  35  in fluid communication with the gas inlet  21  of the third compressor stage  20  wherein the gas is pressurized by a final amount. 
     The finally pressurized natural formation gas then exits the third compressor stage  20  through a gas outlet  22  in fluid communication with a gas inlet  41  to a provided third radiator  40  or like heat exchanger. As will be better understood further herein, this third radiator  40  is adapted to conduct from the finally pressurized natural formation gas substantially all of the adiabatic heat produced in the gas in the third compressor stage  20 . In any case, the finally pressurized natural formation gas exits the third radiator  40  through a gas outlet  43  in fluid communication with an injection line  58 , which, as will also be better understood further herein, is configured to selectively convey the pressurized natural formation gas back to the wellhead  53  for reintroduction to the heavy oil formation  84  in accordance with the present invention through an injection string  93  originating at the casing spool  87  or like structure part of or adjacent the topside Christmas tree. As a safety feature, and to prevent damage to the gas compressor  13 , especially during periods of suspended operation, appropriate check valves and/or an automated flow control valve  59  is preferably provided in the injection line  58  between the gas outlet  43  from the third radiator  40  and the injection string  93 . In such a case, the automated flow control valve  59  is provided with an associated valve controller  60 , which valve controller  60  is like the other automated components of the present invention is electrical communication with and under the operable control of the system controller  82 . 
     A power source  49  is provided in connection with the gas compressor  13  for operation thereof. Although any conventional power source otherwise utilized for the operation of gas compressors, such as, for example, an electric motor, may be utilized in connection with well completion  10  of the present invention, the most preferred implementations of the present invention will utilize a power source  49  that itself may be powered at least in part with natural formation gas otherwise produced in accordance with the teachings hereof. For example, a gas powered motor  50  or, in the alternative, a gas powered generator and electric motor combination, is preferably implemented. To this end, a T-connection  81  is provided for appropriating from the compressor gas supply line  75  an operable quantity of natural gas, which is conveyed from the T-connection  81  through a compressor motor gas supply line  52  to a gas inlet  51  provided on the gas powered motor  50  (or gas powered generator). Although for clarity not specifically depicted in the figures, it should be understood that the depicted T-connection  81  includes any check valves, pressure regulators, flow control valves and the like as may be necessary for actual implementation of this aspect of the present invention. These additional components, however, are, especially in light of this exemplary description, all well within the ordinary skill in the art and should be considered within the scope of the present invention. 
     As shown in  FIG. 1 , the provided radiators  24 ,  32 ,  40  are preferably provided in connection with a forced air system such as may be readily implemented with a preferably adjustable speed blower  48  in order to facilitate their operation in conduction from the pressurized gas flow of adiabatic heat. While, as previously mentioned in connection with the discussion of gas flow through the radiators  24 ,  32 ,  40 , the radiators are adapted to collectively conduct from the gas flow substantially all of the adiabatic heat of the pressurization applied by the three gas compressor stages  14 ,  17 ,  20 , the present invention further comprises means for precisely controlling the amount of adiabatic heat conducted from the gas flow following each compressor stage  14 ,  17 ,  20  by each of the provided radiators  24 ,  32 ,  40 , respectively. To this end, as shown in  FIG. 1 , each radiator  24 ,  32 ,  40  is provided with an independently controllable airflow regulator  29 ,  37 ,  45 , respectively. 
     In particular, in the most preferred embodiment of the present invention, a first adjustable louver  30  is provided adjacent the first radiator  24 , the first adjustable louver  30  being adapted and arranged to regulate the volume of airflow in convection about the first radiator  24  by selectively interfering with the portion of the airflow generated by the blower  48  that would without interference from the first louver  30  ordinarily flow through and about the first radiator  24 ; a second adjustable louver  38  is provided adjacent the second radiator  32 , the second adjustable louver  38  being adapted and arranged to regulate the volume of airflow in convection about the second radiator  32  by selectively interfering with the portion of the airflow generated by the blower  48  that would without interference from the second louver  38  ordinarily flow through and about the second radiator  32 ; and, finally, a third adjustable louver  46  is provided adjacent the third radiator  40 , the third adjustable louver  46  being adapted and arranged to regulate the volume of airflow in convection about the third radiator  40  by selectively interfering with the portion of the airflow generated by the blower  48  that would without interference from the third louver  46  ordinarily flow through and about the third radiator  40 . In order to effect independent control of the adjustable louvers  30 ,  38 ,  46 , the first adjustable louver  30  is provided with a remotely controllable actuator  31  in electrical communication with the system controller  82 , the second adjustable louver  38  is provided with a remotely controllable actuator  39  in electrical communication with the system controller  82  and, finally, the third adjustable louver  46  is provided with a remotely controllable actuator  47  in electrical communication with the system controller  82 . 
     Additionally, in order to provide the necessary system status data to enable precise control throughout the system of both the pressurization of the natural formation gas and the temperature thereof, one or more inlet gas monitoring transducers  26 , capable of measuring and reporting both gas pressure and gas temperature, are provided between the gas outlet  16  from the first compressor stage  14  and the gas inlet  25  to the first radiator  24 ; one or more outlet gas monitoring transducers  28 , capable of measuring and reporting both gas pressure and gas temperature, are provided between the gas outlet  27  of the first radiator  24  and the gas inlet  18  to the second compressor stage  17 ; one or more inlet gas monitoring transducers  34 , capable of measuring and reporting both gas pressure and gas temperature, are provided between the gas outlet  19  from the second compressor stage  17  and the gas inlet  33  to the second radiator  32 ; one or more outlet gas monitoring transducers  36 , capable of measuring and reporting both gas pressure and gas temperature, are provided between the gas outlet  35  of the second radiator  32  and the gas inlet  21  to the third compressor stage  20 ; one or more inlet gas monitoring transducers  42 , capable of measuring and reporting both gas pressure and gas temperature, are provided between the gas outlet  22  from the third compressor stage  20  and the gas inlet  42  to the third radiator  40 ; and one or more outlet gas monitoring transducers  44 , capable of measuring and reporting both gas pressure and gas temperature, are provided between the gas outlet  43  of the third radiator  40  and the injection line  58  leading to the injection string  93 . 
     As generally shown in  FIGS. 2 through 6 , the well completion  10  of the present invention will generally include a well casing  86  extending substantially throughout the length of the wellbore  86  through a heavy oil formation  84 . As is otherwise conventional, the well casing  86  will comprise a number of perforations  88  through the walls thereof in the production zone of the heavy oil formation  84 . In accordance with the present invention, the well completion will also comprise at least one injection string  93  extending into the interior of the wellbore  85  as bounded by the well casing  86  and at least one production string  90  extending therefrom. The particular arrangement of the injection strings  93  and production strings  90 , including the termination and origination, respectively, thereof, however, will vary among multiple possible embodiments. While several embodiments are shown and described herein, it should be noted that the present invention is broader in scope than represented by the particular downhole components  83  shown herein. 
     In any case, a first preferred embodiment of the downhole components  83  of the well completion  10  of the present invention is particularly shown in  FIG. 2 . As shown in  FIG. 2 , an otherwise conventional dual string packer  107  is operably placed within the wellbore  85  at a location just above the production zone perforations  88  through the well casing  86  and otherwise conventionally seated against the interior of the well casing  86  with its provided preferably high temperature rated elastomeric packer elements  108 . As shown in the figure, the injection string  93  terminates below the packer  107  in the area of the production zone. Similarly, as also shown in the figure, the production string  90  originates below the packer  107  in the area of the production zone. 
     Referring now to  FIGS. 1 and 2 , in particular, and with a view toward exemplifying the broader concepts of the present invention, the simplest mode of operation of the well completion  10  of the present invention is described. As previously discussed, the well completion  10  of the present invention is particularly adapted to reintroduce into a heavy oil formation  84  some quantity of natural formation gas, which gas, as will be appreciated by those of ordinary skill in the art, may generally be regarded as being “wet” gas. Wet gas, as is known in the art, denotes natural gas containing significant heavy hydrocarbons, often referred to as condensate. Unlike dry gas, which is composed almost entirely of methane, Applicant has found that wet, natural formation gas is particularly suited for conveyance into the heavy oil formation  84  of heat due to its unique ability to hold heat for an extended time period. With that in mind, a first mode of operation of the well completion  10  of the present invention comprises the creation of a simple gas lift type arrangement, wherein the lift gas comprises natural formation gas introduced through the injection string  93  to the production zone at a controlled, elevated temperature wherein the temperature is selected with a view toward heating up the heavy crude oil, reducing its viscosity and enabling it to more easily flow from the formation  84  and into the production string  90 . Because, in this embodiment, a quantity of the heated formation gas will also travel with and draw the heated heavy oil through the production string  90 , the heated natural formation gas will operate to maintain the heavy oil in a flowable viscosity throughout the production string  90  to the wellhead  53 . 
     In this mode of operation, the produced hydrocarbon mixture, which will typically comprise petroleum and some quantity of associated natural gas in addition to some recovered quantity of previously injected natural formation gas, passes normally through the valves  55 ,  57  at the wellhead  53  and into the production line  54  leading to the separator  61 . Although not shown in the figures, it should at this point be noted that in actual implementation a conventional boiler system or and/or other heating apparatus will likely be necessary to maintain a flowable viscosity in the recovered hydrocarbon mixture. Such systems and their implementations, however, are well known to those of ordinary skill in the art. In any case, the recovered natural formation gas (considered to encompass the combination of newly produced and previously injected gases) passes normally through the separator  61 , scrubber  70  and dehydrator  76 . 
     As previously discussed, however, in accordance with the present invention the outlet gas line  80  from the dehydrator  76  terminates into a specially provided valve unit  116 , which valve unit is remotely operated by a specially provided valve controller  117  under the operable control of the system controller  82 . As also previously discussed, the valve unit  116  is adapted to selectively enable and/or otherwise control gas flow between the well completion  10  of the present invention and a gathering system pipeline  113 . In all operations of the present invention, however, the valve unit  116  is operable in one of two basic modes. In particular, if the quantity of natural formation gas produced through the production line  54  from the wellhead  53  is at any particular time sufficient to support all other requirements of the present invention (which, as will be better understood further herein, include primarily delivery of natural formation gas through the compressor gas supply line  75  for delivery through the injection line  58  to the formation  84 , but also include any requirements such as operation of a gas powered motor  50 , boiler system, or the like), then the valve unit is operated through the valve controller  117  by the system controller  82  to deliver any excess gas through the offsite gas line  114  and meter  115  where it is sold into the gathering system pipeline  113 . If, on the other hand, for any reason the quantity of natural formation gas is produced through the production line  54  from the wellhead  53  is at any particular time insufficient to support all other requirements of the present invention (which may, as will also be better understood further herein, include times of “suspended” production during which no gas is produced from the formation  84 ), then the valve unit is operated through the valve controller  117  by the system controller  82  to draw any additionally required gas from the gathering system pipeline  113 . 
     In any case, the system controller  82  for the well completion  10  of the present invention is programmed and/or otherwise adapted to determine and effect, based upon the desired quantity, pressure and temperature of natural formation gas to be injected into the heavy oil formation  84 , the quantity of natural formation gas to be delivered through the compressor gas supply line  75  to the gas compressor  13 ; the levels of compression to be applied to the natural formation gas by each individual compression stage  14 ,  17 ,  20 ; the positioning of each adjustable louver  30 ,  38   46 ; and, as will be better understood further herein, the states of the injection side automated control valve  60  and production side automated control valve  55  (often referred to as the “motor control valve” due to the propensity for implementation with a “motorized” valve). 
     As will be appreciated by those of ordinary skill in the art, especially now in light of the foregoing exemplary description, the basic operation of the present invention as thus far described is readily extensible to any number of more complex modes. For example, it should be recognized that because the present invention contemplates the ability to automatically supplement locally produced natural formation gas with natural formation gas produced in neighboring wells, the present invention may be operated in a gas flooding type mode. In this case, the controller  82  operates to shut off the automated flow control valve  55  ahead of the production line  54 , thereby enabling the injection through the injection line  58  of high pressure natural formation gas, which, of course, can be injected at the very high temperatures resultant such high pressurization. The result, as will be understood by those of ordinary skill in the art, is that the highly pressurized, hot formation gas will force its way through the production zone perforations  88  into the formation  84  and, over time, will heat the heavy oil located therein resulting in the highly enhanced recovery thereof. In the extreme, the technique may also be applied to fracture the formation  84 . Finally, as also will be appreciated by those of ordinary skill in the art, this technique can be cycled at any desired interval with the previously described mode of operation in order to optimize recovery. 
     The exact mode of operation of the well completion  10  of the present invention will vary widely depending upon the peculiarities of any given formation. In all cases, however, it must be recognized that special attention should be vigilantly given to considerations of safety. To this end, the present invention is particular adapted to stepwise application. For example, in order to “purge” a well of any oxygen content, such as may result in inadvertent flashing of superheated natural formation gases, the well completion  10  of the present invention may readily be operated to flood the formation  84  with pressurized cool gas prior to the heating thereof in subsequent operations. Likewise, by operating. the well completion  10  of the present invention with close reference to the logged characteristics of the well and production therefrom, the well completion  10  is particularly suited to gradually introduce heat and pressure and, over time, to refine, injection gas quantity, injection gas temperature and injection gas pressure to maximize safe well operation while minimizing the chances of such occurrences as premature formation breakthrough and the like. 
     While the foregoing description is exemplary of the preferred embodiment of the present invention, those of ordinary skill in the relevant arts will recognize the many variations, alterations, modifications, substitutions and the like as are readily possible, especially in light of this description, the accompanying drawings and claims drawn thereto. For example, as particularly shown in  FIGS. 2 and 3 , one or more check valves  91 , such as are conventionally implemented with caged ball and seat valves  92  are preferably interposed the production string  90  between the packer  107  and casing spool  87  in order to facilitate extraction from the wellbore  85  of recovered products. Likewise, as particularly shown in  FIG. 3 , a conventional heater rod  94  may be located in the lower section of the injection string  93  in order to supplement the adiabatic heat already applied to the natural formation gas. While such an implementation should be required in only the most extreme circumstances, it is nonetheless readily within the ordinary skill in the art utilizing, for example, a wireline  95  or the like. 
     Additionally, as particularly shown in  FIGS. 4 and 5 , Applicant has found that implementation of the well completion  10  of the present invention may be facilitated by the provision of a specialized downhole packer tool  96 . As shown in the figures, such a downhole packer tool  96  generally comprises an otherwise typical packer body  97  modified to provide for the intersection at an interior location  98  thereof of an injection joint  99  and a production joint  103 . To this end, the production joint  103 , which extends top to bottom entirely through the packer body  97 , comprises a section of upwardly oriented tubing  105  extending above the packer body  97  and a downwardly oriented stub  106  extending below the packer body  97 . The injection joint  99 , on the other hand, comprises an upwardly oriented tubing  102  originating above the packer body  97 , but terminates in a J-shaped return  100  within the interior location  98  of the packer body  97 . As shown in the figures, the distal end  101  of the return  100  then forms an upwardly oriented intersection with an injection aperture  104  from in the side wall of the production joint  103 . 
     As particularly shown in  FIG. 5 , the specialized downhole packer tool  96  may be advantageously utilized in a very shallow well (as is often the case for heavy oil formations) to omit some of the otherwise required injection string  93 , thereby reducing well completion costs. In particular, as shown in  FIG. 5 , the injection string  93  may in such a case terminate just below the casing spool  87  in a downwardly oriented stub  121 , the pressurized and/or heated natural formation gas injected therethrough being contained by the well casing  86  down to an upwardly oriented stub  122  extending from above the specialized packer tool  96  to the short injection joint  99  contained substantially within the tool  96 . 
     As shown in  FIG. 6 , the well completion  10  of the present invention may be implemented with a plurality of injection strings  93 ,  123 , whereby natural formation gas may be simultaneously injected into multiple zones. For example, as shown in the figure, a first injection string  93  and a production string  90  may extend into a production zone as previously described, the only difference being that a triple string packer  109  is seated above this production zone and an additional injection string  123  is passed though the packer  109 . As shown, the second injection string  123  extends beyond the production zone and through a single string packer  111  seated below the production zone, but above a flood zone defined by additional perforations  89  through the well casing  86 . As is otherwise conventional, preferably high temperature rated elastomeric packer elements  110  about the triple string packer  109  and preferably high temperature rated elastomeric packer elements  112  about the single string packer  111  separate the well zones, enabling different injection pressures and/or temperatures to be applied as desired. 
     On the other hand, the gas flooding type mode as previously discussed may be implemented in an embodiment of the present invention comprising a single string doubling as both an injection string and a production string. In such an embodiment, a single string packer as generally shown in  FIG. 7  suffices to isolate the production zone of the formation  84  from the upper regions of the wellbore  85 . As will be apparent to those of ordinary skill in the art, such an embodiment will also required that both the injection line  58  and the production line  54  be placed in fluid communication with the single, dual purpose string into the wellbore  85 , the respective automated flow control valves  59 ,  55  being adapted to control the mode of use of the string to toggle the same between “injection” mode and “production” mode as required. 
     Still further, as particularly shown in  FIG. 7 , it should be appreciated that the gathering system pipeline valve unit  113  may be located between the raw gas line  69  from the separator  61  and an inlet gas line  72  leading to the inlet of the scrubber  70 . This configuration, of course, will be recognized as particularly advantageous in implementations of the present invention where a single very large gas compressor  13  is implemented for providing injection gas to a single injection well servicing multiple production wells and/or a number of otherwise described completions. In these cases, of course, it is to be expected that the gathering pipeline implemented between the related wells may not be “clean.” 
     Further still yet, and as particularly shown in  FIG. 8 , the specialized downhole packer tool  96  as otherwise described with respect to  FIGS. 4 and 5  may readily be implemented to form an aspirator  127  (also referred to as an eductor-jet pump) embedded within the interior  98  of the tool  96 . As shown in  FIG. 8 , the aspirator  127  is formed by gradually narrowing the injection string  102  over the region thereof extending generally between the section of upwardly oriented tubing  102  and the intersection of the aperture  104  into the production string  106 , thereby forming a constriction  125 . Additionally, the production string  103  is gradually widened between the downwardly oriented stub  106  and the upwardly oriented tubing  105 , thereby forming an expansion  126 . In this manner, a region of relatively low pressure will through the Venturi effect be formed as the constriction  125  gives way to the expansion  126 , in turn causing a suction to be formed at the inlet to the production tubing  103 . In any case, because the scope of the present invention is much broader than any particular embodiment, the foregoing detailed description should not be construed as a limitation of the scope of the present invention, which is limited only by the claims appended hereto.