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CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application is a continuation of U.S. patent application Ser. No. 13/253,783, filed Oct. 5, 2011, which issued as U.S. Pat. No. 8,286,698, which is a continuation of U.S. patent application Ser. No. 11/358,390, which issued as U.S. Pat. No. 8,091,625, both of which are hereby incorporated by reference herein. 
    
    
     BACKGROUND OF THE INVENTION 
     Field of the Invention 
     This invention relates in general to methods for producing highly viscous hydrocarbons, and in particular to pumping partially-saturated steam to a downhole burner to superheat the steam and injecting the steam and carbon dioxide into a horizontally or vertically fractured zone. 
     There are extensive viscous hydrocarbon reservoirs throughout the world. These reservoirs contain a very viscous hydrocarbon, often called “tar”, “heavy oil”, or “ultraheavy oil”, which typically has viscosities in the range from 3,000 to 1,000,000 centipoise when measured at 100 degrees F., The high viscosity makes it difficult and expensive to recover the hydrocarbon. Strip mining is employed for shallow tar sands. For deeper reservoirs, heating the heavy oil in situ to lower the viscosity has been employed. 
     one technique, partially-saturated steam is injected into a well from a steam generator at the surface. The heavy oil can be produced from the same well in which the steam is injected by allowing the reservoir to soak for a selected time after the steam injection, then producing the well. When production declines, the operator repeats the process. A downhole pump may be required to pump the heated heavy oil to the surface. If so, the pump has to be pulled from the well each time before the steam is injected, then re-run after the injection. The heavy oil can also be produced by means of a second well spaced apart from the injector well. 
     Another technique uses two horizontal wells, one a few feet above and parallel to the other. Each well has a slotted liner. Steam is injected continuously into the upper well bore to heat the heavy oil and cause it to flow into the lower well bore. Other proposals involve injecting steam continuously into vertical injection wells surrounded by vertical producing wells. 
     U.S. Pat. No. 6,016,867 discloses the use of one or more injection and production boreholes. A mixture of reducing gases, oxidizing gases, and steam is fed to downhole-combustion devices located in the injection boreholes. Combustion of the reducing-gas, oxidizing-gas mixture is carried out to produce superheated steam and hot gases for injection into the formation to convert and upgrade the heavy crude or bitumen into lighter hydrocarbons. The temperature of the superheated steam is sufficiently high to cause pyrolysis and/or hydrovisbreaking when hydrogen is present, which increases the API gravity and lowers the viscosity of the hydrocarbon in situ. The ′867 patent states that an alternative reducing gas may be comprised principally of hydrogen with lesser amounts of carbon monoxide, carbon dioxide, and hydrocarbon gases. 
     The ′867 patent also discloses fracturing the formation prior to injection of the steam. The ′867 patent discloses both a cyclic process, wherein the injection and production occur in the same well, and a continuous drive process involving pumping steam through downhole burners in wells surrounding the producing wells. In the continuous drive process, the ′867 patent teaches to extend the fractured zones to adjacent wells. 
     SUMMARY OF THE INVENTION 
     A downhole burner is secured in the well, The operator pumps a fuel, such as hydrogen, into the burner and oxygen to the burner by a separate conduit from the fuel. The operator burns the fuel in the burner and creates superheated steam in the burner, preferably by pumping partially-saturated steam to the burner. The partially-saturated steam cools the burner and becomes superheated. The operator also pumps carbon dioxide into or around the combustion chamber of the burner and injects the carbon dioxide and superheated steam into the earth formation to heat the hydrocarbon therein. 
     Preferably, the operator initially fractures the well to create a horizontal or vertical fractured zone of limited diameter. The fractured zone preferably does not intersect any drainage or fractured zones of adjacent wells. The unfractured formation surrounding the fractured zone impedes leakage of gaseous products from the fractured zone during a soak interval. During the soak interval, the operator may intermittently pump fuel and steam to the burner to maintain a desired amount of pressure in the fractured zone. 
     After the soak interval, the operator opens valves at the wellhead to cause the hydrocarbon to flow into the borehole and up the well. The viscous hydrocarbon, having undergone pyrolysis and/or hydrovisbreaking during this process, flows to the surface for further processing. Preferably, the flow occurs as a result of solution gas created in the fractured zone from the steam, carbon dioxide and residual hydrogen. A downhole pump could also be employed. The carbon dioxide increases production because it is more soluble in the heavy hydrocarbon than steam or hydrogen or a mixture thereof. This solubility reduces the viscosity of the hydrocarbon, and carbon dioxide adds more solution gas to drive the production. Preferably, the portions of the carbon dioxide and hydrogen and warm water returning to the surface are separated from the recovered hydrocarbon and recycled. In some reservoirs, the steam reacts with carbonate in the rock formation and releases carbon dioxide, although the amount released is only a small percentage of the desired amount of carbon dioxide entering the heavy-oil reservoir, 
     When production declines sufficiently, the operator may repeat the procedure of injecting steam, carbon dioxide and combustion products from the burner into the fractured zone. The operator may also fracture the formation again to enlarge the fractured zone. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       So that the manner in which the above recited features of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments. 
         FIG. 1  is a schematic illustrating a well and a process for producing heavy oil in accordance with this invention. 
         FIG. 2  is a schematic illustrating the well of  FIG. 1  next to an adjacent well, which may also be produced in accordance with this invention. 
         FIGS. 3A and 3B  are schematic illustrations of a combustion device employed with the process of this invention. 
     
    
    
     DETAILED DESCRIPTION 
     Referring to  FIG. 1 , well  11  extends substantially vertically through a number of earth formations, at least one of which includes a heavy oil or tar formation  15 . An overburden earth formation  13  is located above the oil formation  15 . Heavy-oil formation  15  is located over an underburden earth formation  17 . The heavy-oil formation  15  is typically a tar sand containing a very viscous hydrocarbon, which may have a viscosity from 3,000 cp to 1,000,000 cp, for example. The overburden formation  13  may be various geologic formations, for example, a thick, dense limestone that seals and imparts a relatively-high, fracture pressure to the heavy-oil formation  15 . The underburden formation  17  may also be a thick, dense limestone or some other type of earth formation. 
     As shown in  FIG. 1 , the well is cased, and the casing has perforations or slots  19  in at least part of the heavy-oil formation  15 . Also, the well is preferably fractured to create a fractured zone  21 . During fracturing the operator pumps a fluid through perforations  19  and imparts a pressure against heavy-oil formation  15  that is greater than the parting pressure of the formation. The pressure creates cracks within formation  15  that extend generally radially from well  11 , allowing flow of the fluid into fractured zone  21 . The injected fluid used to cause the fracturing may be conventional, typically including water, various additives, and proppant materials such as sand or ceramic beads or steam itself can sometimes be used. 
     In one embodiment of the invention, the operator controls the rate of injection of the fracturing fluids and the duration of the fracturing process to limit the extent or dimension of fractured zone  21  surrounding well  11 . Fractured zone  21  has a relatively small initial diameter or perimeter  21   a . In reference to  FIGS. 1 and 2 , the perimeter  21   a  of fractured zone  21  is limited such that it will not intersect any existing or planned fractured or drainage zones  25  of adjacent wells  23  that extend into the same heavy-oil formation  15 . Further, in the preferred method, the operator will later enlarge fractured zone  21  surrounding well  11 , thus the initial perimeter  21   a  should leave room for a later expansion of fractured zone  21  without intersecting drainage zone  25  of adjacent well  23 . Adjacent well  23  optionally may previously have undergone one or more of the same fracturing processes as well  11 , or the operator may plan to fracture adjacent well  23  in the same manner as well  11  in the future. Consequently, fractured zone perimeter  21   a  does not intersect fractured zone  25 , Preferably, fractured zone perimeter  21   a  extends to less than half the distance between wells  11 ,  23 . Fractured zone  21  is bound by unfractured portions of heavy-oil formation  15  outside perimeter  21   a  and both above and below fractured zone  21 . The fracturing process to create fractured zone  21  may be done either before or after installation of a downhole burner  29 , discussed below. If after, the fracturing fluid will be pumped through burner  29 . 
     A production tree or wellhead  27  is located at the surface of well  11  in FIG,  1 . Production tree  27  is connected to a conduit or conduits for directing fuel,  37 , steam  38 , oxygen  39 , and carbon dioxide  40  down well  11  to burner  29 . Fuel  37  may be hydrogen, methane, syngas, or some other fuel. Fuel  37  may be a gas or liquid. Preferably, steam  38  is partially-saturated steam, having a water vapor content up to about 50 percent. The water vapor content could be higher, and even water could be pumped down well  11  in lieu of steam, although it would be less efficient. Wellhead  27  is also connected to a conduit for delivering oxygen down well  11 , as indicated by the numeral  39 . Fuel  37  and steam  38  may be mixed and delivered down the same conduit, but fuel  37  should be delivered separately from the conduit that delivers oxygen  39 . 
     Because carbon dioxide  40  is corrosive if mixed with steam, preferably it flows down a conduit separate from the conduit for steam  38 . Carbon dioxide  40  could be mixed with fuel  37  if the fuel is delivered by a separate conduit from steam  38 . The percentage of carbon dioxide  40  mixed with fuel  37  should not be so high so as to significantly impede the burning of the fuel. If the fuel is syngas, methane or another hydrocarbon, the burning process in burner  29  creates carbon dioxide. In some instances, the amount of carbon dioxide created by the burning process may be sufficient to eliminate the need for pumping carbon dioxide down the well. 
     The conduits for fuel  37 , steam  38 , oxygen  39 , and carbon dioxide  40  may comprise coiled tubing or threaded joints of production tubing. The conduit for carbon dioxide  40  could comprise an annulus  12  in the casing of well  11 . For example, the annulus  12  is typically defined as the volumetric space located between the inner wall of the casing or production tubing and the exteriors of the other conduits. The carbon dioxide may be delivered to the burner by pumping it directly through the annulus  12 . 
     Combustion device or burner  29  is secured in well  11  for receiving the flow of file  37 , steam  38 , oxygen  39 , and carbon dioxide  40 . Burner  29  has a diameter selected so that it can be installed within conventional well casing, typically ranging from around seven to nine inches, but it could be larger. As illustrated in  FIGS. 3A and 3B , a packer and anchor device  31  is located above burner  29  for sealing the casing of well  11  above packer  31  from the casing below packer  31 . The conduits for fuel  37 , steam  38 , oxygen  39 , and carbon dioxide  40  extend sealingly through packer  31 . Packer  31  thus isolates pressure surrounding burner  29  from any pressure in well  11  above packer  31 . Burner  29  has a combustion chamber  33  surrounded by a jacket  35 , which may be considered to be a part of burner  29 . Fuel  37  and oxygen  39  enter combustion chamber  33  for burning the fuel. Steam  38  may also flow into combustion chamber  33  to cool burner  29 . Preferably, carbon dioxide  40  flows through jacket  35 , which assists in cooling combustion chamber  33 , but it could alternatively flow through combustion chamber  33 , which also cools chamber  33  because carbon dioxide does not burn. If fuel  37  is hydrogen, some of the hydrogen can be diverted to flow through jacket  35 . Steam  38  could flow through jacket  35 , but preferably not mixed with carbon dioxide  40  because of the corrosive effect. Burner  29  ignites and burns at least part of fuel  37 , which creates a high temperature in burner  29 . Without a coolant, the temperature would likely be too high for burner  29  to withstand over a long period. The steam  38  flowing into combustion chamber  33  reduces that temperature. Also, preferably there is a small excess of fuel  37  flowing into combustion chamber  33 . The excess fuel does not burn, which lowers the temperature in combustion chamber  33  because fuel  37  does not release heat unless it burns. The excess fuel becomes hotter as it passes unburned through combustion chamber  33 , which removes some of the heat from combustion chamber  33 . Further, carbon dioxide  40  flowing through jacket  35  and any hydrogen that may be flowing through jacket  35  cool combustion chamber  33 . A downhole burner for burning fuel and injecting steam and combustion products into an earth formation is shown in U.S. Pat. No. 5,163,511. 
     Steam  38 , excess portions of fuel  37 , and carbon dioxide  40  lower the temperature within combustion chamber  33 , for example, to around 1,600 degrees F., which increases the temperature of the partially-saturated steam flowing through burner  29  to a superheated level. Superheated steam is at a temperature above its dew point, thus contains no water vapor. The gaseous product  43 , which comprises superheated steam, excess fuel, carbon dioxide, and other products of combustion, exits burner  29  preferably at a temperature from about 550 to 700 degrees F. 
     The hot, gaseous product  43  is injected into fractured zone  21  due to the pressure being applied to the fuel  37 , steam  38 , oxygen  39  and carbon dioxide  40  at the surface. The fractures within fractured zone  21  increase the surface contact area for these fluids to heat the formation and dissolve into the heavy oil to lower the viscosity of the oil and create solution gas to help drive the oil back to the well during the production cycle. The unfractured surrounding portion of formation  15  can be substantially impenetrable by the gaseous product  43  because the unheated heavy oil or tar is not fluid enough to be displaced. The surrounding portions of unheated heavy-oil formation  15  thus can create a container around fractured zone  21  to impede leakage of hot gaseous product  43  long enough for significant upgrading reactions to occur to the heavy oil within fractured zone  21 . 
     If fuel  37  comprises hydrogen, the unburned portions being injected will suppress the formation of coke in fractured zone  21 , which is desirable. The hydrogen being injected could come entirely from excess hydrogen supplied to combustion chamber  33 , which does not burn, or it could be hydrogen diverted to flow through jacket  35 . However, hydrogen does not dissolve as well in oil as carbon dioxide does. Carbon dioxide, on the other hand, is very soluble in oil and thus dissolves in the heavy oil, reducing the viscosity of the hydrocarbon and increasing solution gas. Elevating the temperature of carbon dioxide  40  as it passes through burner  29  delivers heat to the formation, which lowers the viscosity of the hydrocarbon it contacts. Also, the injected carbon dioxide  40  adds to the solution gas within the reservoir. Maintaining a high injection temperature for hot gaseous product  43 , preferably about 700 degrees F., enhances pyrolysis and hydrovisbreaking if hydrogen is present, which causes an increase in API gravity of the heavy oil in situ. 
     Simulations indicate that injecting carbon dioxide and hydrogen into a heavy-oil reservoir that has undergone fracturing is beneficial. In three simulations, carbon dioxide at 1%, 10%, and 25% by moles of the steam and hydrogen being injected were compared to each other. The comparison employed two years of cyclic operation with  21  days of soaking per cycle. The results are as follows: 
     
       
         
               
               
               
               
               
             
               
               
               
               
               
             
           
               
                   
                   
               
               
                   
                   
                   
                 Cumulative Oil 
                 Steam/Oil 
               
               
                   
                 Simulation 
                 % C02 
                 Produced 
                 Ratio 
               
               
                   
                   
               
             
             
               
                   
               
             
          
           
               
                 1. 
                 No Fracture 
                 0 
                 3,030 
                 14.3 
               
               
                 2. 
                 Fracture 
                 1 
                 9,561 
                 13.2 
               
               
                 3. 
                 Fracture 
                 10 
                 20,893 
                 8.99 
               
               
                 4. 
                 Fracture 
                 25 
                 22,011 
                 5.65 
               
               
                   
               
             
          
         
       
     
     The table just above shows that 25% carbon dioxide is better than 10% carbon dioxide for production and steam/oil ratio. Preferably, the carbon dioxide percentage injected into the reservoir is 10% to 25% or more, by moles of the steam and hydrogen being injected, but is at least 5%. 
     In the preferred method, the delivery of fuel  37 , steam  38 , oxygen  39  and carbon dioxide  40  into burner  29  and the injection of hot gaseous product  43  into fractured zone  21  occur simultaneously over a selected period, such as seven days. White gaseous product  43  is injected into fractured zone  21 , the temperature and pressure of fractured zone  21  increases. At the end of the injection period, fractured zone  21  is allowed to soak for a selected period, such as 21 days. During the soak interval, the operator may intermittently pump fuel  37 , steam  38 , oxygen  39  and carbon dioxide  40  to burner  29  where it burns and the hot combustion gases  43  are injected into formation  15  to maintain a desired pressure level in fractured zone  21  and offset the heat loss to the surrounding formation. No further injection of hot gaseous fluid  43  occurs during the soak period. 
     Then, the operator begins to produce the oil, which is driven by reservoir pressure and preferably additional solution-gas pressure. The oil is preferably produced up the production tubing, which could also be one of the conduits through which fuel  37 , steam  38 , or carbon dioxide  49  is pumped. Preferably, burner  29  remains in place, and the oil flows through parts of burner  29 . Alternatively, well  11  could include a second borehole a few feet away, preferably no more than about 50 feet, with the oil flowing up the separate borehole rather than the one containing burner  29 . The second borehole could be completely separate and parallel to the first borehole, or it could be a sidetracked borehole intersecting and extending from the main borehole. 
     The oil production will continue as long as the operator deems it feasible, which could be up to 35 days or more. When production declines sufficiently, the operator may optionally repeat the injection and production cycle either with or without additional fracturing. It may be feasible to extend the fracture in subsequent injection and production cycles to increase the perimeter  21   a  of fractured zone  21 , then repeat the injection and production cycle described above. Preferably, this additional fracturing operation can take place without removing burner  29 , although it could be removed, if desired. The process may be repeated as long as fractured zone  21  does not intersect fractured zones or drainage areas  25  of adjacent wells  23  ( FIG. 2 ). 
     By incrementally increasing the fractured zone  21  diameter from a relatively small perimeter up to half the distance to adjacent well  23  ( FIG. 2 ), the operator can effectively produce the viscous hydrocarbon formation  15 . With each new fracturing operation, the previously fractured portion would provide flow paths for the injection of hot gaseous product  43  and the flow of the hydrocarbon into the well. Also, the previously fractured portion retains heat from the previous injection of hot combustion gases  43 . The numeral  21   b  in  FIGS. 1 and 2  indicates the perimeter of fractured zone  21  after a second fracturing process. The operator could be performing similar fracturing, injection, soaking and production cycles on well  23  at the same time as on well  11 , if desired. The cycles of injection and production, either without or without additional fracturing may be repeated as long as feasible. 
     Before or after reaching the maximum limit of fractured zone  21 , which would be greater than perimeter  21   b , the operator may wish to convert well  11  to a continuously-driven system. This conversion might occur after well  11  has been fractured several different times, each increasing the dimension of the perimeter. In a continuously-driven system, well  11  would be either a continuous producer or a continuous injector. If well  11  is a continuous injector, downhole burner  29  would be continuously supplied with fuel  37 , steam  38 , oxygen  39 , and carbon dioxide  40 , which burns the fuel and injects hot gaseous product  43  into fractured zone  21 . The hot gaseous product  43  would force the oil to surrounding production wells, such as in an inverted five or seven-spot well pattern. Each of the surrounding production wells would have fractured zones that intersected the fractured zone  21  of the injection well. If well  11  is a continuous producer, fuel  37 , steam  38 , oxygen  39 , and carbon dioxide  40  would be pumped to downhole burners  29  in surrounding injection wells, as in a normal five- or seven-spot pattern. The downhole burners  29  in the surrounding injection wells would burn the fuel and inject hot gaseous product  43  into the fractured zones, each of which joined the fractured zone of the producing well so as to force the oil to the producing well. 
     The invention has significant advantages. The injection of carbon dioxide along with steam and unburned fuel into the formation increases the resulting heavy-oil production. Heating the carbon dioxide as it passes through the burner increases the temperature of the fractured heavy-oil formation. The carbon dioxide also adds to the solution gas in the formation. The unfractured, heavy-oil formation surrounding the fractured zone impedes leakage of excess fuel, steam and other combustion products into adjacent formations or to the surface long enough for significant upgrading reactions to occur to the heavy oil in the formation. The container maximizes the effects of the excess fuel and other hot gases flowing into the fractured zone. By reducing leakage from the fractured zone, the expense of the fuel, oxygen, and steam is reduced. Also, containing the excess fuel increases the safety of the well treatment. At least part of the fuel, carbon dioxide and heat contained in the produced fluids may be recycled. 
     While the invention has been shown in only one of its forms, it should be apparent to those skilled in the art that it is not so limited but is susceptible to various changes without departing from the scope of the invention. For example, the fractures could be vertical rather than horizontal. In addition, although the well is shown to be a vertical well in  FIG. 1 , it could be a horizontal or slanted well. The fractured zone could be one or more vertical or horizontal fractures in that instance. The burner could be located within the vertical or the horizontal portion. The system could include a horizontal injection well and a separate horizontal production well with a slotted liner located a few feet below and parallel to the horizontal portion of the injection well. In some formations, fracturing may not be needed.

Summary:
A method for producing hydrocarbons from a reservoir. The method includes positioning a burner having a combustion chamber in a first well, supplying a fuel, an oxidant, and one of water or steam from the surface to the burner in the first well, supplying a viscosity-reducing gas from the surface to the reservoir in a conduit separate from the fuel, igniting the fuel and the oxidant in the combustion chamber to generate heat and steam in the burner, injecting the viscosity-reducing gas and steam into the reservoir to reduce the viscosity of and heat hydrocarbons within the reservoir, and recovering hydrocarbons from the reservoir.