Abstract:
A method for recovering subsurface hydrocarbons, including heavy oil or bitumen, wherein a downhole steam injection phase is followed by application of heat to the near-wellbore region of the reservoir, heat being applied only during periods without steam injection. The heat application can be achieved by any number of techniques including electrical heaters, radio frequency waves, electromagnetic waves and microwaves. Numerous advantages are possible by withholding heat application during the steam injection phase. While preferred for use with cyclic steam stimulation recovery techniques, the method can be applied with other steam-based recovery techniques.

Description:
FIELD OF THE INVENTION 
     The present invention relates to methods for hydrocarbon recovery from a subsurface reservoir, and specifically to recovery of heavy hydrocarbon deposits using steam-based recovery techniques. 
     BACKGROUND OF THE INVENTION 
     In the field of subsurface hydrocarbon production, it is known to employ various stimulation procedures and techniques to enhance production. For example, in the case of heavy oil and bitumen housed in subsurface reservoirs, conventional drive mechanisms may be inadequate to enable production to surface, and it is well known to therefore inject steam or steam-solvent mixtures to make the heavy hydrocarbon more amenable to movement within the reservoir permeability pathways, by heating the hydrocarbon and/or mixing it with lighter hydrocarbons or hot water. 
     Cyclic steam stimulation (CSS) is one of the most promising thermal recovery methods for producing high viscosity oil or bitumen. This oil recovery method requires a predetermined amount of steam to be injected into a well or wells drilled into the hydrocarbon deposit, which well or wells are then shut in to allow the steam and heat to soak into the reservoir surrounding the well and create what is known as a “steam chamber”. This assists the natural reservoir energy by thinning the oil (or, in the case of a steam-solvent injection, also mixing the heavy hydrocarbon with lighter hydrocarbons) so that it will more easily move into the production well or wells. Once the reservoir has been adequately heated and the steam chamber has been created, the production wells can be put back into production until the injected heat has been mostly dissipated within the fluids being produced and the surrounding reservoir rock and fluids. This cycle can then be repeated until the natural reservoir pressure has declined to a point that production is uneconomic, or until increased water production occurs. 
     Recovery from a CSS well depends on a number of factors, including the production rate for each phase and how long each is sustained. The production rate in turn depends on factors such as the viscosity of the hydrocarbon being produced, the permeability of the reservoir rock and the inflow performance. 
     Recovery of heavy hydrocarbons such as bitumen requires both mobilizing the hydrocarbon, and then displacing it from the initial position to the drainage points, the producing wells. Displacement is impacted by how mobilised hydrocarbon, condensed water and steam push each other through the reservoir. Each fluid has its own mobility, which depends in part on its viscosity and the permeability available to the fluid. Mobility depends on reservoir rock permeability, pore size distribution, fluid saturation and fluid viscosity. The mobility is a measure of how easy it is for a fluid with a particular viscosity to flow through a rock of a given permeability (Equation 1 below). Each fluid can only flow in its own part of the pore space, and the absolute or rock permeability must be reduced by the appropriate relative permeability to account for the presence of other fluids. 
     
       
         
           
             
               
                 
                   Mobility 
                   = 
                   
                     
                       
                         k 
                         abs 
                       
                       ⁢ 
                       
                         k 
                         r 
                       
                     
                     μ 
                   
                 
               
               
                 1 
               
             
           
         
       
         
         
           
             where k abs  is the absolute permeability in millidarcies (mD), k r  is the relative permeability and μ is the fluid viscosity. 
           
         
       
    
     The reduction in this relative permeability greatly affects the ability of the hydrocarbon to be produced at the wellbore. 
     The movable oil volume (MOV) for each CSS cycle is given by:
 
MOV=PV*(1 −S   wc   −S   orw )  2
         where PV is the total pore volume available for occupation, S wc  is the connate or irreducible water and S orw  is the residual oil saturation.       

     Compaction in a reservoir causes reduction in the movable oil volume as more oil and water are trapped in the pores, whereas dilation increases the movable oil volume. Dilation decreases the residual oil saturation, while the connate water saturation may initially increase to dilate the reservoir grains and later decrease at higher pore volume. 
     The production of heat from the reservoir also forces the density and viscosity of the downhole hydrocarbon to increase. The former then reduces the rate of hydrocarbon production by decreasing the efficiency of the lifting techniques used, while the latter decreases mobility to the wellbore. This zone of high viscosity that develops in the low-pressure region near the wellbore is commonly referred to as “visco-skin”. 
     Since at least the 1970s, the use of electrical heaters has been studied for application in heavy oil production. It has been proposed that electrical heaters be introduced in the near-wellbore region of a hydrocarbon production well to optimize production by reducing bitumen viscosity and density resulting from temperature decline and permeability reduction. See for example U.S. Pat. No. 5,339,898 to Yu et al. In the case of visco-skin and reduced productivity, electrical resistance heating has been proposed as a possible solution; see for example Vinsome et al., “Electrical heating”, Journal of Canadian Petroleum Technology, vol. 33, no. 4, April 1994. It has also been noted in the technical literature that continuous, non-cyclic, application of electrical heating has been attempted on several occasions with encouraging results; see for example McGee et al., “Electrical heating with horizontal wells, the heat transfer problem,” Society of Petroleum Engineers Paper No. SPE 37117 (1996); McGee et al., “Field test of electrical heating with horizontal and vertical wells,” Journal of Canadian Petroleum Technology, vol. 38, no. 3, March 1999; McGee et al., “The mechanisms of electrical heating for the recovery of bitumen from oil sands.” Journal of Canadian Petroleum Technology, vol. 46, no. 1, January 2007. 
     However, the use of electrical heaters appears to have certain disadvantages. For example, the cost of running electrical heaters may be undesirably high depending on the number of wells in production in a given reservoir. Also, the utility of certain types of heaters may be negatively impacted by the presence of steam, which presence is a key driver in a number of thermal recovery methods such as CSS. 
     SUMMARY OF THE INVENTION 
     The present invention is accordingly directed to applying heat only during those phases of a steam-based recovery technique when steam is not being injected into the reservoir. 
     According to a first aspect of the present invention, then, there is provided a method for recovering a hydrocarbon from a reservoir, the method comprising the steps of:
     a. drilling at least one well from surface to the reservoir;   b. injecting steam down the at least one well to the reservoir;   c. after injecting the steam, applying heat to a portion of the reservoir adjacent the well;   d. allowing the steam to elevate the temperature of the reservoir and the hydrocarbon while applying the heat; and   e. producing a portion of the hydrocarbon to the surface while applying the heat.   

     In some exemplary embodiments of the first aspect, the hydrocarbon is preferably a heavy hydrocarbon, which heavy hydrocarbon may be heavy crude oil or bitumen. The at least one well may be a single well used for both injection and production, or it may comprise at least two wells, at least one of which is an injector well and at least one of which is a producer well. 
     Exemplary embodiments of the first aspect may further comprise a step f. in which application of the heat is ceased after producing the portion of the hydrocarbon, and further exemplary embodiments may comprise repeating steps a. through f. as desired. Exemplary embodiments may further comprise the step of maintaining reservoir temperature above 80 degrees Celsius in the portion of the reservoir adjacent the well, and the heat being applied may arise from means selected from the group consisting of electrical heaters, radio frequency waves, electromagnetic waves, and microwaves. 
     According to a second aspect of the present invention, there is provided a method for recovering a hydrocarbon from a reservoir having at least one injector well therein, the method comprising the steps of:
     a. injecting steam down the at least one injector well to the reservoir;   b. after injecting the steam, applying heat to a portion of the reservoir adjacent the injector well; and   c. producing a portion of the hydrocarbon to the surface while applying the heat.   

     In some exemplary embodiments of the second aspect, the hydrocarbon is preferably a heavy hydrocarbon, which heavy hydrocarbon may be heavy crude oil or bitumen. The at least one injector well may be a single injector well used for both injection and production, or it may comprise at least two injector wells, at least one of which is also configured for use as a producer well. 
     Exemplary embodiments of the second aspect may further comprise a step d. in which application of the heat is ceased after producing the portion of the hydrocarbon, and further exemplary embodiments may comprise repeating steps a. through d. as desired. Exemplary embodiments may further comprise the step of maintaining reservoir temperature above 80 degrees Celsius in the portion of the reservoir adjacent the injector well, and the heat being applied may arise from means selected from the group consisting of electrical heaters, radio frequency waves, electromagnetic waves, and microwaves. 
     According to a third aspect of the present invention, there is provided a method for recovering a hydrocarbon from a reservoir having at least one injector well therein, the method comprising the steps of:
     a. injecting steam down the at least one injector well to the reservoir;   b. shutting in the at least one injector well and allowing the injected steam to elevate the temperature of the reservoir and the hydrocarbon in the reservoir;   c. during shutting in of the at least one injector well, applying heat to a portion of the reservoir adjacent the at least one injector well; and   d. producing a portion of the hydrocarbon to the surface while applying the heat.   

     In some exemplary embodiments of the third aspect, the hydrocarbon is preferably a heavy hydrocarbon, which heavy hydrocarbon may be heavy crude oil or bitumen. The at least one injector well may be a single injector well used for both injection and production, or it may comprise at least two injector wells, at least one of which is also configured for use as a producer well. 
     Exemplary embodiments of the third aspect may further comprise a step e. in which application of the heat is ceased after producing the portion of the hydrocarbon, and further exemplary embodiments may comprise repeating steps a. through e. as desired. Exemplary embodiments may further comprise the step of maintaining reservoir temperature above 80 degrees Celsius in the portion of the reservoir adjacent the injector well, and the heat being applied may arise from means selected from the group consisting of electrical heaters, radio frequency waves, electromagnetic waves, and microwaves. 
     According to a fourth aspect of the present invention, there is provided a method for reducing hydrocarbon viscosity in a near-wellbore region of a hydrocarbon reservoir having at least one well therein, thereby enhancing hydrocarbon recovery, the method comprising the steps of:
     a. injecting steam down the at least one well to the reservoir;   b. after injecting the steam, applying heat to at least a portion of the near-wellbore region of the hydrocarbon reservoir; and   c. allowing the heat to reduce the viscosity of hydrocarbon in the near-wellbore region of the hydrocarbon reservoir.   

     In some exemplary embodiments of the fourth aspect, the hydrocarbon is preferably a heavy hydrocarbon, which heavy hydrocarbon may be heavy crude oil or bitumen. Exemplary embodiments may further comprise the step of maintaining reservoir temperature above 80 degrees Celsius in the near-wellbore region of the hydrocarbon reservoir, and the heat being applied may arise from means selected from the group consisting of electrical heaters, radio frequency waves, electromagnetic waves, and microwaves. 
     A detailed description of an exemplary embodiment of the present invention is given in the following. It is to be understood, however, that the invention is not to be construed as being limited to this embodiment. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       In the accompanying drawings, which illustrate an exemplary embodiment of the present invention: 
         FIG. 1  is a flowchart illustrating an exemplary method according to the present invention; 
         FIG. 2  is a simplified elevation view showing placement of an exemplary heater on a horizontal leg of a well; 
         FIG. 3  is a chart illustrating the change in bitumen density as a function of temperature; 
         FIG. 4  is a chart illustrating a temperature-pressure saturation curve; 
         FIG. 5  is an idealised CSS region illustration; 
         FIG. 6  is a porosity distribution illustration from a simulation test; 
         FIG. 7  is a permeability distribution illustration from a simulation test; 
         FIG. 8  is an illustration of initial water saturation from a simulation test; 
         FIG. 9  is a chart illustrating viscosity variation with temperature; 
         FIG. 10  is a table with relative permeability values used in a simulation test; 
         FIG. 11  is a table showing simulation test data; 
         FIG. 12  is a chart illustrating production and injection profiles for a conventional CSS method; 
         FIG. 13  is a chart illustrating Cumulative Steam Oil Ratio and Depletion Index for a conventional CSS method; 
         FIG. 14  is a chart illustrating comparative production profiles for conventional CSS and heater-assisted CSS; 
         FIG. 15  is a chart illustrating comparative Cumulative Steam Oil Ratio and Depletion Index for conventional CSS and heater-assisted CSS; and 
         FIG. 16  is a table summarizing production data from a simulation test. 
     
    
    
     An exemplary embodiment of the present invention will now be described with reference to the accompanying drawings. 
     DETAILED DESCRIPTION 
     In the following detailed description, a specific application of the present invention is described, in particular an application for use with a CSS recovery method for bitumen housed in a subsurface reservoir. However, it will be clear to those skilled in the art that other applications are possible within the scope of the present invention, including unique operating conditions and parameters specific to a particular reservoir context. That being the case, the following description is intended to be exemplary and non-limiting. 
     The present invention is intended for use with heavy hydrocarbons such as heavy oil and bitumen, although it can be used with lighter oils in appropriate circumstances that would be clear to one skilled in the art. Heavy and extra-heavy crude oils and bitumens are composed primarily of hydrocarbons, but they may also contain high molecular weight aliphatic and terpenoid hydrocarbons, asphaltenes, and oxygen-, nitrogen- and sulfur-bearing compounds. Heavy oils and bitumens are commonly defined and characterized on the basis of both viscosity and density, and those skilled in the art will know of accepted viscosity and density ranges. 
     Turning to  FIG. 1 , an exemplary method  10  according to the present invention is illustrated. The method  10  begins with the step  12  of drilling a well into the reservoir to access the hydrocarbon deposit. Note that where the term “well” is used herein, it can mean either a vertical well or a horizontal well, and the term “wells” can mean vertical and/or horizontal wells or a combination of vertical and horizontal wells, as would be obvious to one skilled in the art. Once the well has been completed, steam is injected downhole at step  14 . The skilled person will know how to manage steam injection in a thermal hydrocarbon recovery operation. A mixture of steam and a selected solvent could also be used for this step, as is well known in the art. As the exemplary method is described in the context of a CSS operation, the next step  16  is shutting in the well. The injected steam is then allowed to heat the bitumen deposit at step  18 . 
     After steam injection has been completed at step  14 , heat is applied to the near-wellbore region of the reservoir at step  20 . As indicated above, the heat could be applied by any number of techniques, including for non-limiting example electrical heaters, radio frequency waves, electromagnetic waves, and microwaves, and one skilled in the art would be able to determine which technique would be appropriate for a given context. While this step  20  is illustrated as occurring after shut-in of the well and simultaneously with the so-called “steam soak” of step  18 , the heat could be applied at or before the time of shut-in, as long as the steam injection has ceased. 
     After the steam soak phase of the CSS method, and while heat continues to be applied, the hydrocarbon is produced to surface at step  22 . Production may occur through the same well that was used for injection at step  14 , or it could be a separate well, as would be known to those skilled in the art. Heat losses are common during production, and the continued application of heat during production counters this to at least an extent, thereby helping to prevent visco-skin formation and increased viscosity in the near-wellbore region. 
     After the target hydrocarbon has been mobilized and produced, the cycle can be repeated. However, before the next round of steam (or steam-solvent) injection, the heat application is terminated at step  24 . Although not shown, it is also possible to repeat the discrete steam injection and heat application cycles one or more times before initial production. 
     The exemplary method involves installation of an electrical heater inside a vertical or horizontal wellbore, as shown in  FIG. 2 . The well  30  comprises a horizontal leg  32  extending at least partially through a target reservoir. The horizontal leg  32  is provided with an electrical heater  34  in a manner known to those skilled in the art. 
     The heat source is used in optimizing production from the wellbore and the near-wellbore region. Optimal benefit strongly depends on near-wellbore bitumen mobilization, flashing, dilation and temperature dependent end points. As those skilled in the art will know, a decrease in the temperature increases the residual oil saturation, and decreases the permeability to oil. This negative effect on these temperature dependent end points is arrested during the production phase. The efficiency of the flow pump is also enhanced by reducing the viscosity of the near-wellbore bitumen due to heating as shown in  FIG. 3 . As the pressure declines especially in the wellbore region during the production phase, condensed water is flashed to vapour, as is illustrated by the temperature-pressure saturation curve in  FIG. 4 . To maximize the efficiency of the pump, it is desirable to operate the heat source to maintain water in a liquid state based on the drawdown pressure. Turning to an idealised CSS region illustration in  FIG. 5 , the temperature increase in the near-wellbore region due to the electric heater creates a pseudo-steady state heat flux region in Region  1 , and the rate of decline in temperature in Regions  2  and  3  of the reservoir is accordingly reduced despite the heat production from the reservoir. The bitumen mobility in the near-wellbore region in this case is enhanced due to the reduction in viscosity and temperature dependent end points, unlike conventional CSS processes where a decline in reservoir pressure often creates recompaction which reduces the movable oil volume in the near-wellbore region. 
     As stated above, applying heat to the near-wellbore region of the reservoir can be used to reduce visco-skin formation and undesirable viscosity levels generally. The actual target temperature for the near-wellbore region will be situation-specific, and it may vary based on a number of factors including the reservoir type and the type and general density of the hydrocarbon in the reservoir. In the case of bitumen in a carbonate formation, for example, it might be advantageous to maintain the near-wellbore region at no less than 80 degrees Celsius. As the target temperature may be determined on a case-by-case basis, exemplary methods according to the present invention may also incorporate the use of temperature monitoring techniques and equipment known to those skilled in the art. When a drop in temperature occurs, that might for example be used as an indication that steam injection for the next cycle can commence. 
     Turning now to  FIGS. 6 to 16 , simulation tests were conducted to assess the potential impact of the present invention when compared to a conventional CSS method. The model contained 17 grid blocks in the x-direction, 31 grid blocks in the y-direction and 41 layers, for a total of 21,607 grid blocks. The dimension for each grid block was 1×50×1 m. The depth to the top of the grid was 194 m. The porosity varied from 15% to 38% as shown in  FIG. 6 , while horizontal permeability varied from 37 md to 6,354 md as shown in  FIG. 7 . The vertical permeability was 75% of the horizontal permeability. 
     The initial water saturation varied from 0.17 to 0.75 as shown in  FIG. 8 . The bitumen contained in the reservoir had a viscosity of 3.5 million centipoises at 12 degrees Celsius and pressure of 2700 kPa at a reference depth of 217 m.  FIG. 9  illustrates how viscosity will respond to changes in in-situ temperature. The pore volume compressibility was 2.90E-06 kPa −1  at a reference pressure of 800 kPa. The relative permeability data used is shown in  FIG. 10 . 
     A flow simulation was conducted using Computer Modeling Group&#39;s STARS™ thermal reservoir simulator to evaluate the incremental recovery over the base forecast (a conventional CSS process) when a heater was included in the production periods. Proportional heat transfer coefficient (UHTR), used in conjunction with temperature setpoint (TMPSET) of a temperature controller entered for the grid blocks in which the well was completed, was used in modeling the heater.  FIG. 11  shows the STARS™ method adopted for the calculation of the heat transfer coefficient giving the grid block volume, reservoir temperature, heat capacity and reference temperature. A steam at 85% quality was injected at a pressure of 6 MPa. A pressure boundary condition was also applied to the model to simulate a fluid loss scenario. 
       FIG. 12  shows the results of the daily and total produced oil  42 ,  44  and daily injected water  40  under the simulation tests for the conventional CSS method, and  FIG. 13  shows the results for the Cumulative Steam Oil Ratio (CSOR)  50  and Depletion Index (DI)  52  for the conventional CSS method. It can be seen from  FIGS. 14 and 15  that the heater-assisted CSS method produced an additional 34.09 Mm3 of oil and a lower CSOR which decreased with production. The DI for the heater-assisted CSS method also increased to 0.45 at the end of the simulation forecast compared to the conventional CSS which gave 0.27. A summary of the production results from the simulation exercise is shown in  FIG. 16 . 
     As noted above, applying heat to the near-wellbore region of a hydrocarbon reservoir can have significant advantages over CSS alone, such as visco-skin reduction, increased hydrocarbon mobility and reduced viscosity. In addition, embodiments of the present invention may manifest further substantial advantages. For example, limiting heat application to only the soak and production phases of a CSS project can accordingly reduce the operating costs and energy consumption generally, while still obtaining the benefits of the heat application for production. Further, power lines have a certain capacity, and heating can therefore be applied to more wellbores if an intermittent heat application is used as in the present invention. Also, applying certain heat sources (for example radio frequency, resistive heating and inductive heating) during steam injection may actually reduce the efficacy of the heating activity, so the impact of the heating activity can be optimized by selectively not employing it during steam injection. Finally, if heat is applied during steam injection, this could potentially create a back pressure that might negatively impact the effectiveness of the steam injection. 
     The foregoing is considered as illustrative only of the principles of the invention. The scope of the claims should not be limited by the exemplary embodiment set forth in the foregoing, but should be given the broadest interpretation consistent with the specification as a whole.