Abstract:
A variety of methods for thermal recovery of natural gas and bitumen from a formation containing the latter. In general, the methods incorporate a series of existing, but previously uncombined technologies. A modified flue gas from the steam generators conventionally used in a SAGD recovery operation is injected into the formation to enhance recovery with the produced fluids, natural gas, bitumen, inter alia are further processed. The injection of the flue gas conveniently is disposed of and further acts to repressurize the formation which otherwise becomes depressurized when depleted of natural gas. Accordingly, environmental and economic advantages are realized with the methodology.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
   This is the first application filed for the present invention. 
   TECHNICAL FIELD 
   The present invention relates to the thermal recovery of values from a subterranean formation by making use of a flue gas injection into the formation. 
   BACKGROUND OF THE INVENTION 
   In the heavy oil industry, there are a broad range of classifications attributable to the oil. The classes are essentially based on viscosity and density of the material and are generally broken down as follows:
         i) Medium Heavy Oil
           25°&gt;° API&gt;18°   100 cPs&gt;μ&gt;10 cPs, mobile at reservoir conditions   
           ii) Extra Heavy Oil
           20°&gt;° API&gt;12°   10,000 cPs&gt;μ&gt;100 cPs, production enhancement techniques required including reservoir stimulation such as thermal or water/solvent flooding   
           iii) Oil Sands and Bitumen
           12°&gt;° API&gt;6°, mined or thermal stimulation required   μ&gt;10,000 cPs, production enhancement techniques required including reservoir stimulation such as thermal or thermal/solvent injection.   
               

   In view of the recognized value of vast reserves of heavy oil and bitumen potentially available in Canada, Central America, Russia, China and other locations of the world, a varied panoply of extraction and handling techniques have come to light. 
   Currently, existing bitumen and extra heavy oil reservoirs are exploited using enhanced thermal recovery techniques resulting in efficiency of recovery in the range of between 20 and 25%. The most common thermal technique is steam injection where heat enthalpy from the steam is transferred to the oil by condensation. This, of course, reduces the viscosity of the oil allowing gravity drainage and collection. Injection may be achieved by the well known cyclic steam simulation (CSS), Huff and Puff and Steam Assisted Gravity Drainage (SAGD). 
   Although SAGD is becoming widely employed, it is not without several detriments regarding efficiency. An area which presents significant costs is the fuel to drive the steam generators to produce steam for injection. The most desirable fuel is natural gas, but the expense greatly reduces the overall efficiency and this problem is compounded with the fact that green house gases (GHG) are liberated in varied amounts during operation of the steam generators using all types of hydrocarbon fuels. As an example, approximately 8,000 to 15,000 Tonnes daily of carbon dioxide is generated to produce injection steam and produce 100,000 BOPD of bitumen. 
   A further problem in the SAGD process is the upgrading required in the produced product to increase its value. 
   As noted briefly above, another factor affecting SAGD is the limitation in recovery efficiency. 
   In an attempt to ameliorate some of the limitations noted, the use of alternate fuels other than natural gas has been proposed to at least reduce the ever increasingly impact of natural gas. An example of a suitable fuel for use in a SAGD operation is discussed in U.S. Pat. No. 6,530,965, issued to Warchol, Mar. 11, 2003. The document teaches the formation of predispersed residuum in an aqueous matrix which is burnable as a alternate fuel. 
   Considering the problems with existing technologies, it remains desirable to have a method of enhancing efficiency in a SAGD operation, reducing the formation of excessive amounts of GHG and lowering costs by providing an alternate fuel with the thermal performance of natural gas. 
   The present invention collates all of the most desirable features and advantages noted with an energy efficient, high yield green environmentally friendly process. 
   SUMMARY OF THE INVENTION 
   One object of the present invention is to provide an improved thermal recovery process with enhanced efficiency. 
   A further object of one embodiment is to provide a method for recovering heavy oil and bitumen from a subterranean formation containing heavy oil and bitumen, comprising: providing a fuel; burning the fuel in a flue gas recirculation circuit to produce an injection flue gas for injection into the formation; and injecting the injection flue gas into the formation to displace the heavy oil and bitumen. 
   A still further object of one embodiment of the present invention is to provide a method for recovering heavy oil and bitumen from a subterranean formation containing heavy oil and bitumen, comprising: providing a fuel; burning the fuel in a flue gas recirculation circuit to produce a flue gas for injection into the formation; and injecting the flue gas into the formation to displace the heavy oil and bitumen and natural gas. 
   Still another object of one embodiment of the present invention is to provide a method for recovering gas and bitumen from at least one of a steam assisted gravity drainage formation containing gas over bitumen within the volume of the formation and/or from a geographically proximate formation, comprising; providing a flue gas recirculation circuit to produce modified flue gas; injecting the modified flue gas within the volume at a pressure sufficient to displace the gas over the bitumen and to displace the bitumen from within the formation; recovering displaced gas and bitumen; and maintaining the pressure or repressurizing the volume with the modified flue gas to a pressure substantially similar to a pressure prior to injection of the modified flue gas. 
   Yet another object of one embodiment of the present invention is to provide a method for recovering gas and bitumen from at least one of a steam assisted gravity drainage formation containing gas over bitumen within the volume of the formation and from a geographically proximate formation, comprising; a steam generation phase for generating steam for injection into the formation; a flue gas recirculation phase for modifying flue gas for injection into the formation; an injection phase for injecting modified flue gas into the formation for displacing gas over the bitumen and maintaining the pressure or repressurizing the formation; and a processing phase for processing produced displaced gas and liquid liberated from the injection phase. 
   Having thus generally described the invention, reference will now be made to the accompanying drawings illustrating preferred embodiments. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
     Further features and advantages of the present invention will become apparent from the following detailed description, taken in combination with the appended drawings. 
       FIG. 1  is a schematic illustration of the generic methodology according to one embodiment; 
       FIG. 2  is a more detailed schematic illustration of  FIG. 1 ; 
       FIG. 3  is a graphical illustration of the oxygen requirement for flue gas carbon dioxide enrichment on a dry basis; 
       FIG. 4  is a graphical illustration of the oxygen requirement for flue gas carbon dioxide enrichment on a wet basis; 
       FIG. 5  is a schematic illustration of natural gas steam production in a SAGD environment; 
       FIG. 6  is a schematic illustration of bitumen or emulsion fuel steam production in a SAGD environment; 
       FIG. 7  is a schematic illustration of residuum emulsion fuel steam production in a SAGD environment; 
       FIG. 8  is a schematic illustration of a cogeneration flue gas compression operation; and 
       FIG. 9  is a schematic illustration of a cogeneration electric power generation operation. 
   

   Similar numerals employed in the description denote similar elements 
   It will be noted that throughout the appended drawings, like features are identified by like reference numerals. 
   DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS 
   Preface 
   Unless otherwise indicated, SAGD refers to steam assisted gravity drainage, SYNGAS, refers to synthetic gas, OTSG refers to once through steam generation, GHG refers to green house gas, BOPD refers to barrels of oil per day, COGEN refers to combined production of electric generation or compression service with heat recovery and steam generation, HRSG refers to heat recovery steam generator, and “heavy oil” embraces heavy oil, extra heavy oil and bitumen as understood in the art. 
   Referring now to  FIG. 1 , shown is a schematic illustration of one embodiment of the present invention. Numeral  10  broadly denotes the overall process. An air, fuel and oxygen mixture combined with a Flue Gas Recirculation (FGR) stream is fed to a steam generation system  12  to generate steam  16  and flue gas  35 . The air, fuel, oxygen and FGR mixture is selected to create an enriched flue gas  35  to optimize recovery of gas and heavy oil from within a formation containing these. This will be discussed in greater detail herein after. 
   The fuel, contained in any of air or oxygen mixture, may be selected from any suitable hydrocarbon fuel, non limiting examples of which include natural gas, bitumen, fuel oil, heavy oil, residuum, emulsified fuel, multiphase superfine atomized residue (MSAR, a trademark of Quadrise Canada Fuel Systems), asphaltenes, petcoke, coal, and combinations thereof. 
   Flue gas  35  from the system  12  is treated or modified in a treatment operation  14  prior to injection within a formation. This flue gas may contain numerous gaseous compounds including carbon dioxide, carbon monoxide, nitrogen, nitrogen oxides, hydrogen, sulfur dioxide, syngas inter alia. At excess oxygen burning conditions, where oxygen levels are present in the flue gas  35 , then the flue gas  35  will primarily contain carbon dioxide, nitrogen and water vapour. The treated injection gas  45  is injected into gas and heavy oil formation(s) generically denoted by numeral  18 , shown in the example as a SAGD (steam assisted gravity drainage) formation. As is well known, this technique involves the use of steam to assist in reducing the viscosity of viscous hydrocarbons to facilitate mobility. These formations also contain natural gas, bitumen and a variety of other hydrocarbons which have value, but which were previously marginally economic or fiscally unfeasible to recover. Steam  16  from system  12  is introduced into the formation  18  as illustrated. 
   The gas in the formation  18  is now made recoverable in an efficient manner in view of the flue gas circuit in combination with injection of the modified flue gas  45 . The union of these operations has resulted in the success of the methodology of the present invention. Advantageously, the techniques set forth herein can be applied not only to gas over bitumen formations, but also geographically proximate formations. As a non limiting example, laterally or vertically displaced formations can be exploited as well. This is generally shown in  FIG. 1  and denoted by numeral  18 ′. The benefits of the instant technology also accrue for abandoned SAGD chambers or for blowdown where flue gas can be injected to not only maintain heavy oil recovery but also to displace the heavy oil. 
   Natural gas  20  displaced from formation  18  is collected and may be subjected to additional unit operations or a portion may be recirculated into the system as fuel for steam generation. This latter step is not shown in  FIG. 1 , but is well within the purview of one skilled. 
   Mobilized production fluids, containing bitumen denoted by numeral  22  are then subjected to an oil treatment operation  24  where the bitumen  26  is processed for the removal of entrained water to produce a saleable product. Produced water  26  is further treated in a suitable water treatment unit  28  to remove bitumen, hardness compounds, silica and any other undesirable compounds making the water suitable of boiler feed water  30 . Any suitable water treatment operations may be employed to achieve the desired result. Boiler feed water  30  may then be recirculated into system  12  for steam  16  production, thus reducing water demands in the process to augment efficiency. Further to this, water evolved from the flue gas treatment operation, the water being represented by numeral  52  may be recirculated at  28 , also to augment efficiency. 
   Having broadly discussed the overall process, numerous advantages attributable to the process are evinced. These include:
         i) an efficient and environmentally safe disposal of harmful flue gas;   ii) improved gas recovery from the formation;   iii) enhanced thermal recovery operation to produce more bitumen per unit steam;   iv) carbon dioxide sequestering to reduce GHG emissions;   v) volumetric replacement within the formation; and   vi) any combination of these features.       

   Referring now to  FIG. 2 , shown is a more detailed schematic of the process according to one embodiment. In the embodiment shown, an air separator unit  40  is provided for gaseous separation prior to injection of fuel and oxygen into the steam generation system  12 . A flue gas recirculation (FGR) circuit is provided for the system  12 . The flue gas recirculation is useful to reduce the temperature of the combustion zone in the system  12  in order to maintain compatible steam generator performance for the full range of oxygen input versus combustionair used in steam generation process. Without the flue gas recirculation (FGR) for higher levels of oxygen, the heat generator temperature would exceed the design limitations of the steam generators. The flue gas exiting the circuit is then processed in treatment unit  14 , where it is subjected to particulate removal, such as electrostatic precipitation or baghouse  44 , with the ash discharged at  46 . The so treated gas is further quenched prior to being compressed at  48  and further dehydrated at  50 . Water  52  from the operation can be circulated to the water treatment unit  28  or a MSAR formulation phase  70  discussed herein after. By product gas from  14  if produced, can be separated and recovered from the flue gas and used for further operations such as CO fuel for process furnaces or boilers, SO2 for commercial sales or H2 hydrogen supply for bitumen upgrading. 
   In this example, bitumen leaving oil treatment  24  may be processed in a partial or full upgrader  56  with partially upgraded bitumen or synthetic crude being discharged at  58  and a hydrocarbon mixture consisting of bitumen, residuum, asphaltenes, or coke etc. may be further processed into MSAR, an efficient fuel discussed in detail in U.S. Pat. No. 6,530,965 comprising essentially a predispersed residuum in an aqueous matrix which greatly reduces the fuel cost to operate the steam generation system. Traditionally, the latter was done with natural gas, the cost for which greatly exceeded the cost involved with the use of MSAR. As an option, the fuel may be supplanted or augmented by those fuels previously taught. 
     FIGS. 3 and 4  graphically depict the oxygen requirement for flue gas carbon dioxide enrichment on a dry and wet basis, respectively. As pure oxygen is introduced to the steam generator operation, the flue gas  35  will contain less nitrogen for a fixed quantity of carbon dioxide. Therefore both the volume of flue gas is reduced and the concentration of carbon dioxide in the injection treated gas  45  is increasing. For example, on a dry basis with reference to  FIG. 3 , as the oxygen level used approaches 100% (0% combustion air), then the composition of the treated flue gas approaches near 100% CO 2 , including minor compounds of carbon monoxide, sulfur dioxide, nitrogen dioxide, etc.  FIG. 3  represents the primary composition of the treated injection gas  45 . Referring to  FIG. 4 , graphically illustrated is the primary composition of the flue gas stream  35  prior to flue gas treatment in  14 . 
     FIG. 5  is a schematic illustration of a natural gas steam production circuit. In the example, at least a portion of the displaced natural gas  20  may be recirculated as a fuel to drive the steam generation system  12 . This is denoted by numeral  60 . The enriched injection flue gas, which may be customized to contain between 30% and 50% nitrogen and between 70% and 50% carbon dioxide, is injected to displace the produced fluids, bitumen, natural gas, water etc processed for upgrading at  62 . The choice of operations conducted at  62  will depend upon the desired products. 
   Recovered water  52  from the flue gas treatment unit  14  may be recirculated to  62 . 
   Referring to  FIG. 6 , shown is a further variation on the process where the steam generation is achieved by making use of a liquid alternate fuel, shown in the example is a bitumen or heavy oil fuel, or alternatively, the bitumen or heavy oil is transformed into an emulsion fuel. In this arrangement, processed bitumen exiting central treatment plant  62  at line  66  may be diverted in terms of a portion of the material only at line  68  directly as heavy fuel oil or alternatively, directed into an emulsion unit for generating an alternate fuel. The emulsion unit stage being indicated by numeral  70 . An additional amount of water recovered and circulated at  52  may be diverted and introduced into the unit  70  via line  72 . In the emulsion fuel unit, the suitable chemicals are added to the bitumen material (surfactants, etc.) in order to generate the alternate fuel. At this point, once formulated, the alternate fuel exiting the unit at  74  may be introduced as a fuel to drive the steam generation system  12 . The natural gas feed from the displaced gas in the formulation  18  used as fuel ceases and the process does not deplete any further volume of the natural gas. In this manner, once the emulsion unit is operational and stabilized, the process simply relies on alternate fuel that it generates on its own. 
   Referring to  FIG. 7 , shown is a further variation in the arrangement shown in  FIG. 6  where a bitumen upgrader  76  is shown added to the unit operation of the central treatment plant. In this manner, materials leaving central treatment plant  66  are upgraded in the upgrader  76  to formulate heavy residuum exiting at  80  which then can be formulated into an emulsified alternate fuel and introduced into steam system  12  as noted with respect to  FIG. 6 . Subsequent benefit can be realized in the upgrading of the bitumen quality to deasphalted oil or synthetic crude oil. 
   Referring to  FIG. 8 , whereby one embodiment of the current invention is employed in combination with a conventional gas cogeneration (COGEN) plant  600  to enhance the overall thermal heavy oil recovery operation. Uniquely, when the current embodiment is combined, the steam generators  12  as described previously can be suitably fitted with COGEN heat recovery steam generator (HRSG) to produce the required total injection steam and provide the required power to drive the treated injection flue gas compressors. 
     FIG. 9  further illustrates a further embodiment whereby the steam generators  12  are combined with a COGEN plant  600  to generate electric power. The electric power generated could be used to drive the treated flue gas compressors and power the full facility  10  to make it self sufficient in energy. 
   Although embodiments of the invention have been described above, it is limited thereto and it will be apparent to those skilled in the art that numerous modifications form part of the present invention insofar as they do not depart from the spirit, nature and scope of the claimed and described invention.