Patent Publication Number: US-9410408-B2

Title: Electrical heating of oil shale and heavy oil formations

Description:
BACKGROUND 
     1. Field 
     The present application relates to methods and systems for heating subterranean hydrocarbon formations. 
     2. State of the Art 
     The term “oil shale” is a misnomer because the organic phase is not oil, but kerogen that has never been exposed to the temperatures and pressures required to convert organic matter into oil. It is estimated that there is roughly 3 trillion barrels of potential shale oil in place, which is comparable to the original world endowment of conventional oil. About half of this immense total is to be found near the common borders of Wyoming, Utah, and Colorado, where much of the resource occurs at reasonable saturation of at least 30 gallons/ton (roughly 0.25 v/v) in beds that are 30 m to 300 m thick. Oil shales are found relatively near the surface, ranging from outcrops down to about 1000 m. 
     The most common oil shale production technology to date involves mining the shale and retorting it at the surface. This requires rapidly heating the oil shale to 500° C., upgrading the produced shale oil in downstream refineries, and disposing of vast quantities of spent rock or sediment. These steps have significant economic and environmental problems. Another oil shale production technology involves in-situ conversion where the reservoir is slowly heated to a temperature that converts the kerogen to oil and gas. Petroleum produced by in-situ conversion is a good quality refinery feedstock requiring no further upgrading. Waste products remain underground, minimizing environmental impacts. 
     Several electrical methods have been proposed to heat oil shale formations, but none have gained widespread acceptance. Shell Oil Company has proposed the use of electrically heated rods inserted into boreholes in the oil shale formation. These rods transfer heat to the borehole, and the heat then diffuses into the surrounding formation. This method has the virtue of simplicity, since the production of heat is precisely controlled. However, this method has several problems.  FIG. 1  shows the limitations of thermal diffusion in heating earth formations from within a borehole. The borehole is quickly heated to 350° C. (623 K) as depicted by the t0 line. Heat diffuses into the formation and the resulting temperature profiles are shown for one month intervals. After six months, significant heating is still confined to within a few meters of the borehole. Because the thermal diffusivity of the earth is quite low, it requires several months for the heat to spread just a few meters distance from the wellbore. Moreover, heat must be applied very slowly to prevent overheating the borehole and the oil shale in the immediate vicinity of the borehole. 
     Texaco and Raytheon experimented with a monopole antenna radiating at a frequency of a few megahertz. The antenna radiates vertically-polarized electric field from the borehole into the formation. This field drives a current which is proportional to electrical conductivity of the medium. Heating is due to ionic conduction in water or, less commonly, electronic conduction in metallic minerals. However, hydrocarbons in contact with water quickly come to pore-scale thermal equilibrium via heat conduction. An advantage of electromagnetic heating over heating via a resistive element in the borehole is that electromagnetic heating is distributed in the formation. The heating is not uniform, but is greatest where the electric field and electrical conductivity are greatest. The electric field drops off inside the formation due to geometrical spreading and the skin effect.  FIG. 2  illustrates electromagnetic skin depth as a function of frequency and formation electrical resistivity for a formation with a dielectric constant of 10. For a frequency of 3 MHz and a formation resistivity of 10 ohm-m, the skin depth is about 1 m. The penetration of electromagnetic waves is deeper in the vadose zone above the water table, where, for example, the resistivity of the formation is in the range of 100-1000 ohm-m. The skin depth also increases if formation water is vaporized. The skin depth is limited in many applications, which increases the costs for field development and reduces the economic viability of the electromagnetic heating approach. 
     The term “heavy oil” refers to crude oil which does not flow easily. It is referred to as “heavy” because its density or specific gravity is higher than that of light crude oil. Heavy crude oil has been defined as any liquid petroleum with an API gravity less than 20°. Physical properties that differ between heavy crude oil and lighter grades include higher viscosity and specific gravity, as well as heavier molecular composition. Natural bitumen from oil sands is a type of heavy crude oil with an API gravity of less than 10°. Production, transportation, and refining of heavy oil present special challenges compared to light crude oil. Efficient production of heavy oil requires raising the temperature of the formation to reduce the viscosity of the heavy oil. Steam is commonly used for this purpose. However, there are many circumstances in which steam is difficult or impossible to use. In some cases, the heavy oil formations are very shallow, and steam would readily break through to the earth&#39;s surface and escape. In other cases, heavy oil formations are found in deepwater plays, where it is infeasible to maintain the temperature of steam as it is pumped down from a generating unit at the sea surface. 
     SUMMARY OF THE INVENTION 
     This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter. 
     A method (and system) is provided that enhances production of hydrocarbons from a subterranean formation having a plurality of intervals. The method (and system) identifies at least one target interval of the subterranean formation that is in proximity to a pay interval, wherein the at least one target interval has an electrical resistance less than electrical resistance of the pay interval. A plurality of electrodes are placed in respective positions spaced apart from one another and adjacent the at least one target interval. Electrical current is injected into the at least one target interval by supplying electrical signals to the plurality of electrodes. The electrical current injected into the at least one target interval passes through at least a portion of the at least one target interval in order to heat the at least one target interval and heat the pay interval by thermal conduction for enhancement of production of hydrocarbons from the pay interval. 
     In one embodiment, the electrodes are supported by corresponding downhole tools that are located in distinct wellbores at positions adjacent the at least one target interval. At least one of the electrodes can be configured to contact mudcake lining a respective wellbore. Alternatively, at least one of the electrodes can be configured to extend through such mudcake toward the uninvaded zone of the target interval. At least one of the downhole tools can include a pad that is configured to contact mudcake lining a respective wellbore and to surround a corresponding electrode during current injection operations. 
     In one configuration, the electrodes can be positioned adjacent a target interval that extends therebetween. A large portion of the injected electrical current can flow through the formation along a path that extends generally parallel to bedding of this target interval. 
     In another configuration, the electrodes can be positioned adjacent two distinct target intervals that straddle the pay interval. A large portion of the injected electrical current can flow through the formation along a path that extends generally parallel to bedding of the two distinct target intervals and that also extends generally perpendicular to bedding of the pay interval. 
     In one embodiment, the electrical signals supplied to the electrodes comprise AC electrical signals. The AC electrical signals can have a frequency less than 100 HZ (such as a frequency in the range of 50 Hz to 60 Hz). 
     In one application, the pay interval can include kerogen, and the heating of the pay interval can be sufficient to convert in-situ the kerogen of the pay interval to shale oil and hydrocarbon gases. In another application, the pay interval includes heavy oil, and the heating of the pay interval is sufficient to reduce in-situ the viscosity of the heavy oil. In either application, the least one target interval can hold connate water to provide a low resistance path for the injected current and the desired heating. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a graph showing heating temperature as a function of radial distance from borehole over time for a prior art method where electrically heated rods are inserted into the borehole that traverses an oil shale formation. 
         FIG. 2  is a graph showing skin depth as a function of RF frequency for different formation resistivities for a prior art method where electromagnetic energy is injected into a formation for heating the formation. 
         FIG. 3  is a schematic diagram illustrating an exemplary embodiment of a method and system that employs downhole tools to heat a subterranean shale formation for in-situ conversion of kerogen to shale oil and hydrocarbon gases in accordance with the present application. 
         FIG. 4A  is a schematic diagram illustrating an exemplary electrode configuration for the downhole tools of  FIG. 3 . 
         FIG. 4B  is a schematic diagram illustrating another exemplary electrode configuration for the downhole tools of  FIG. 3 . 
         FIG. 5A  is a graph illustrating thermal diffusivity of Green River oil shale perpendicular to the bedding planes as a function of temperature. 
         FIG. 5B  is a graph illustrating thermal diffusivity of Green River oil shale parallel to the bedding planes as a function of temperature. 
         FIGS. 6A and 6B  depict the results of exemplary models that simulate the methodology and system of  FIG. 3  in a formation with contrasting electrical resistivities have thicknesses of 1 meter each and approximate an oil shale formation with dips of 0°. The electrodes of the downhole tools are placed adjacent a formation layer in two wells 10 m apart. In the model of  FIG. 6A , the two electrodes are placed adjacent a rich layer with a high resistivity of 1000 ohm-m in order to inject current flow into and through the rich layer. In the model of  FIG. 6B , the two electrodes are placed adjacent a lean layer with a low resistivity of 100 ohm-m in order to inject current flow into and through the lean layer, from which heat diffuses vertically into neighboring rich beds. 
         FIG. 7A  is a graph showing a temperature profile over time through the center of the rich layer heated by the electrode configuration of the model of  FIG. 6A . Each line shows the effect of an additional day of heating. 
         FIG. 7B  is a graph showing a temperature profile over time through the center of the rich layer heated by the electrode configuration of the model of  FIG. 6B . Each line shows the effect of an additional day of heating. 
         FIG. 8  depicts the results of an exemplary model that simulates the methodology and system of  FIG. 3  in a formation with contrasting electrical resistivities have thicknesses of 1 meter each and approximate an oil shale formation with dips of 0°. The two electrodes of the downhole tools are placed adjacent two lean layers with a low resistivity of 100 ohm-m in two wells 10 m apart, where the two lean layers straddle a rich layer with a high resistivity of 1000 ohm-m in order to inject current flow into and through the lean layers and across the adjacent rich layer, from which heat diffuses vertically into neighboring rich beds. 
         FIG. 9  is a graph showing a temperature profile over time through the center of the rich layer heated by the electrode configuration of the model of  FIG. 8 . Each line shows the effect of an additional day of heating. 
         FIGS. 10, 11 and 12  are graphs showing temperature profiles over time for the heating of a saline zone modeled by 1 meter thick layers of alternating resistivities of 10 ohm-m (lean layer) and 50 ohm-m (rich layer). The same electrode configurations were modeled as for the cases of  FIGS. 6A, 6B and 8 . For each figure, the respective lines show the effect of an additional day of heating. 
         FIG. 13  is a graph showing the boiling point of water as a function of temperature and pressure. 
         FIG. 14  is a graph showing the resistivity of saline water (water with 30 ppt NaCl) as a function of temperature. 
     
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS 
     According to one embodiment of the present application, a methodology (and system) is provided for in-situ conversion of kerogen within a kerogen rich zone of a subterranean formation into shale oil and gas phase hydrocarbons through heating of at least one adjacent lower resistance zone of the formation. The heating is accomplished by AC current injection into and through the adjacent lower resistance zone(s). The heat deposited into the adjacent lower resistance zone(s) is transferred by conduction (also referred to as “diffusion”) to the kerogen rich zone in order to heat the kerogen to a temperature where the kerogen is converted into shale oil and gas phase hydrocarbons. 
     The system and methodology assumes that the subterranean formation has been analyzed to identify the kerogen rich zone (referred to herein a “pay interval”) of relatively high kerogen content within the formation as well as at least one lower resistance zone (referred to herein as a “target interval) that is adjacent to or otherwise in proximate to the pay interval. The target interval has a lower resistivity than the resistivity of the pay interval and thus is better suited for current injection. The target interval can hold connate water or other suitable electrically conductive matter. The formation analysis that identifies the pay interval and the at least one target interval can involve downhole analysis involving wireline testing, logging while drilling, measurement while drilling or other suitable methods. Such formation analysis can also involve core sampling and analysis. 
     As shown in  FIG. 3 , two wellbores (referred to herein as first wellbore  303  and second wellbore  313 ) are drilled through the formation and completed such that the wellbores intersect the target interval at locations that are spaced apart from one another. The target interval is labeled  305  and the pay interval is labeled  307 . A first downhole tool  301  is positioned in the first wellbore  303 . The first downhole tool  301  has an electrode that can be configured to inject electrical current into the target interval  305  for heating kerogen in the pay interval  307 . The electrode is electrically coupled to one or more electrical conductors  309  that extend through the first wellbore  303  to the surface. For the case where an open hole completion completes the target interval, the electrode can be configured to contact mudcake lining the wall of the first wellbore  303 . An insulating pad can surround the electrode and electrically insulate the electrode from direct electrical contact with other parts of the formation (other than the mudcake). The mudcake can provide a flow barrier that inhibits the flow of flow of fluid between the first wellbore  303  and the target interval. 
     An exemplary embodiment of the downhole tool located in the first wellbore  301  is shown in  FIG. 4A . The downhole tool  301 ′ includes an elongate conveyance member  351  that is adapted to be moved through the wellbore  303 . The upper end of member  351  is connected by conveyance means (such as a wireline cable or coiled tubing or drill pipe) to suitable apparatus at the surface for moving (raising and lowering) the conveyance member  351  within the wellbore  303 . The downhole tool  301 ′ further includes a tool body  353  supported below the member  351 . A pad member  355  is adapted to be pushed outwardly and away from the tool body  353  toward the wall of the wellbore  303 . To accomplish this, support arms  357 ,  359 ,  361  are pivotably coupled to the pad member  355  by suitable hinge means. The lower support arm  361  is pivotably coupled to a slidable collar member  363 . Suitable actuating means is contained within the tool body  353  to urge the support members outward to thereby urge the pad member  355  against the wellbore wall, and to reverse this deployment process. The pad member  355  is made of a suitable wear resistance and electrically insulating material. An electrode  365  is secured to a central portion of the pad member  355  and faces outward away from the tool body  353  such that when the pad member  355  contacts the wall of the wellbore  303 , the electrode  365  makes physical contact with the wall of the wellbore  303 . The electrode  365  can include an element, such as knife edge or plow, that cuts through mudcake lining the wellbore  303  toward the uninvaded zone of the target interval. An insulated electrical conductor extends through (or along) one of the support arms (for example, support arm  357 ) and terminates at the electrode  365 . Such conductor is electrically connected to the conductor  309  that extends to the surface-located electrical energy source  317  to provide for an electrical conductive path therebetween. 
     In an alternative embodiment as shown in  FIG. 4B , the electrode  365 ′ of the downhole tool located in the first wellbore  301  can extend away from the pad member  355 ′ into and preferably through the mudcake into the invaded zone and possibly further into and through the transition zone and into the uninvaded zone as shown. The terminal end of the electrode  365 ′ can be configured with a drill bit to assist in advancement of the terminal end into the formation. This configuration can be useful for wells that were drilled with non-conductive oil-based mud. 
     In yet other alternate embodiments, the electrode of the downhole tool located in the first wellbore  301  can be positioned inside the first wellbore  301  at the level of the target interval where fluid such as drilling mud fills the wellbore  301 . 
     Referring back to  FIG. 3 , a second downhole tool  311  is positioned in the second wellbore  313 . The second downhole tool  311  has an electrode that can be configured to inject electrical current into the target interval  305  for heating kerogen in the pay interval  307 . The electrode is electrically coupled to one or more electrical conductors  315  that extend through the second wellbore  313  to the surface. For the case where an open hole completion completes the target interval, the electrode can be configured to contact mudcake lining the wall of the second wellbore  313 . An insulating pad can surround the electrode and electrically insulate the electrode from direct electrical contact with other parts of the formation (other than the mudcake). The mudcake can provide a flow barrier that inhibits the flow of fluid between the second wellbore  313  and the target interval. 
     Exemplary embodiments of the downhole tool located in the second wellbore  313  are shown in  FIGS. 4A and 4B . In yet other alternate embodiments, the electrode of the downhole tool located in the second wellbore  313  can be positioned inside the second wellbore  313  at the level of the target interval where connate water of the target interval fills the wellbore  313 . This configuration can be useful for wellbores completed with liners, perforated casings or other suitable completions that allow for the connate water to flow from the target interval and fill the inside of the wellbore adjacent the target interval. 
     The conductors  309 ,  315  for the two electrodes of the first and second downhole tools  301 ,  311  are electrically connected to an electrical energy source  317 . The electrical energy source  317  is configured to supply an AC electrical signal to the two electrodes of the first and second borehole tools  301 ,  311  via the conductors  309 ,  315  that extend through the respective boreholes. The AC electrical signal has a frequency preferably in a frequency range less than 100 HZ (more preferably in the range of 50 Hz to 60 Hz typical of mains electrical power). The AC electrical signal supplied to the two electrodes induces an AC current flow (depicted by arrow  319 ) that flows between the two electrodes into and at least partially through the target interval  305 . 
     A large part of the AC current flowing between the two electrodes of the first and second borehole tools  301 ,  311  travels along the path of least resistance through the formation. It is contemplated that some AC current flow can travel along other higher resistance path(s) through the formation. In one embodiment, the path of least resistance through the formation involves a path solely through the target interval  305  without passing through other parts of the formation. In this case, the AC current flow that travels along this path through the target interval  305  heats the target interval  305 , and such heat transfers through the formation by conduction (depicted by arrows  321 ) to heat the pay interval  307 . For the case where the target interval  305  holds connate water, the electrical current flow heats the target interval  205  primarily by ohmic heating of the conductive connate water. 
     The AC electrical supply signal can be generated and supplied by the electrical energy source  317  in a continuous manner (or near continuous manner) to the two electrodes of the first and second downhole tools  301 ,  311  for an extended period of time in order to heat kerogen of the pay interval  307  to a sufficient temperature to convert the kerogen into shale oil (a synthetic crude oil) and gas phase hydrocarbons. For example, the pay interval  307  can be heated to about 350° C. at which point the kerogen of the pay interval  307  is converted to shale oil and gas phase hydrocarbons. The shale oil and gas phase hydrocarbons can be produced from the formation employing a suitable production methodology. The production methodology can employ one or more vertical (and/or horizontal) production wells that allow for production of the shale oil and gas phase hydrocarbons from the formation. Alternatively, the wellbore(s) that contain the current injection tools can be configured to provide for production of the shale oil and gas phase hydrocarbons from the formation. 
     In alternate embodiments, it is contemplated that electrical energy source can generate and supply pulsed-mode DC signals in a continuous manner (or near continuous manner) to the two electrodes of the first and second downhole tools  301 ,  311  for an extended period of time in order to inject pulsed-mode DC current into the target interval  305  that produces heat that diffuses and heats the kerogen of the pay interval  307  to a sufficient temperature to convert the kerogen into shale oil (a synthetic crude oil) and gas phase hydrocarbons. 
     The heat introduced into the target interval  305  spreads across the formation according to the well-known diffusion equation [see e.g., Lienhard and Lienhard, A Heat Transfer Textbook, 3rd ed., Phlogiston Press, 2008, chap. 4] as follows: 
     
       
         
           
             
               
                 
                   
                     
                       ∂ 
                       T 
                     
                     
                       ∂ 
                       t 
                     
                   
                   = 
                   
                     
                       ∇ 
                       
                         · 
                         
                           ( 
                           
                             κ 
                             ⁢ 
                             
                               ∇ 
                               T 
                             
                           
                           ) 
                         
                       
                     
                     + 
                     Θ 
                   
                 
               
               
                 
                   ( 
                   1 
                   ) 
                 
               
             
           
         
       
         
         
           
             where T is the temperature of a body and K is the thermal diffusivity given by 
           
         
       
    
     
       
         
           
             
               
                 
                   κ 
                   = 
                   
                     k 
                     
                       ρ 
                       ⁢ 
                       
                           
                       
                       ⁢ 
                       C 
                     
                   
                 
               
               
                 
                   ( 
                   2 
                   ) 
                 
               
             
           
         
       
         
         
           
             where k is the thermal conductivity, ρ is the mass density and C is the heat capacity per unit mass.
 
The heat generation term Θ of Eqn. (1) is given by:
 
           
         
       
    
     
       
         
           
             
               
                 
                   Θ 
                   = 
                   
                     
                       Q 
                       . 
                     
                     
                       ρ 
                       ⁢ 
                       
                           
                       
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                       C 
                     
                   
                 
               
               
                 
                   ( 
                   3 
                   ) 
                 
               
             
           
         
       
         
         
           
             where {dot over (Q)} is the power transferred to the earth per unit volume.
 
In the case of ohmic heating, {dot over (Q)} is given by:
 
           
         
       
    
     
       
         
           
             
               
                 
                   
                     Q 
                     . 
                   
                   = 
                   
                     
                       
                         J 
                         2 
                       
                       σ 
                     
                     = 
                     
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                         E 
                         2 
                       
                     
                   
                 
               
               
                 
                   ( 
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             where J is the electrical current density, E is the electric field, and σ is the electrical conductivity of the medium. 
           
         
       
    
     Note that the thermal diffusion across the formation can be anistropic in nature. For example, the thermal diffusivity of the Green River oil shale formation has been measured as a function of kerogen content and temperature [Wang et al., 1979] as depicted in  FIGS. 5A and 5B .  FIG. 5A  illustrates the thermal diffusivity of Green River oil shale perpendicular to the bedding planes, while  FIG. 5B  illustrates the thermal diffusivity of Green River oil shale parallel to the bedding planes. Note that the thermal diffusion is anisotropic across the Green River oil shale formation where heat travels more readily along bedding planes than across them. Also note that thermal conductivity is highest in the leanest formations. 
     To illustrate the efficacy of the methodology and system of the present application, several deployment schemes have been modeled. In the models, layers with contrasting electrical resistivities have thicknesses of 1 meter each and approximate an oil shale formation with dips of 0°. The electrodes are placed adjacent a formation layer in two wells 10 m apart. For the models, a temperature-independent thermal diffusivity κ of 5×10 −7  m 2 /s has been assumed for all layers. The vadose zone is above the water table. For the Green River oil shale formations, some of the richest pay intervals lie in the vadose zone. To model the vadose zone, the layers are assigned alternating resistivities of 100 ohm-m and 1000 ohm-m. The former are lean zones, having relatively low kerogen content, while the latter are rich zones having relatively high kerogen content. It is especially desirable to heat the rich zones. 
       FIG. 6A  shows a case where the two electrodes are placed adjacent a rich layer with a high resistivity of 1000 ohm-m in order to inject current flow into and through the rich layer.  FIG. 6A  shows that the current paths between the two electrodes are largely deflected into adjacent lean conductive beds above and below the rich layer and heating is localized near the two electrodes. 
       FIG. 6B  shows a case where the two electrodes are placed adjacent a lean layer with a low resistivity of 100 ohm-m in order to inject current flow into and through the lean layer.  FIG. 6B  shows that the current paths between the two electrodes are more focused into the lean layer, and the heating is less localized. Thus, the heat deposition zone has larger extent, from which heat diffuses vertically into neighboring rich beds. 
       FIG. 7A  shows a temperature profile over time through the center of the rich layer heated by the electrode configuration of  FIG. 6A . Each line shows the effect of an additional day of heating. Similarly,  FIG. 7B  shows a temperature profile over time through the center of the rich layer heated by the electrode configuration of  FIG. 6B . Each line shows the effect of an additional day of heating.  FIGS. 7A and 7B  shows that the heat is better distributed through the rich layer when the electrodes inject current into the adjacent lean layer ( FIGS. 6B and 7B ) as compared to the configuration when the electrodes inject current into the resistive bed itself ( FIGS. 6A and 7A ). 
       FIG. 8  shows a case where the two electrodes are placed adjacent two different lean layers with a low resistivity of 100 ohm-m that straddle a rich layer of high resistivity of 1000 ohm-m. This electrode configuration is slightly different than the electrode configuration of  FIGS. 3 and 6A and 7A . In this configuration, the path of least resistance through the formation (and thus the path for the large part of current flow through the formation between the two electrodes) involves a path generally parallel to bedding through the two adjacent lean layers and crossing the rich layer perpendicular to bedding in such rich layer.  FIG. 9  shows a temperature profile over time through the center of the rich layer heated by the electrode configuration of  FIG. 8 . The distribution of heat in the rich layer is satisfactory as evident from  FIG. 9 . 
       FIGS. 10, 11 and 12  depict the results of heating a saline zone modeled by 1 meter thick layers of alternating resistivities of 10 ohm-m (lean layer) and 50 ohm-m (rich layer). The same electrode configurations were modeled as for the vadose zone cases of  FIGS. 6A, 6B and 8 . For each figure, the respective lines show the effect of an additional day of heating. Again, heating of the rich layer is more uniform when current is injected into adjacent lean layers, either flowing parallel to the rich layer ( FIG. 11 ) or forced to cross it ( FIG. 12 ). 
     In order to further understand the electrical heating methods utilized in conjunction with connate water, it is necessary to understand how the electrical resistivity of water changes as a function of temperature and pressure. More specifically, increases in temperature to connate water increases the electrically conductivity of the connate water up to a critical point where the water vaporizes in a gaseous phases. Water in the gaseous phase is an electrical insulator. The boiling temperature of the connate water is a function of formation pressure.  FIG. 13  shows the boiling point of pure water as a function of pressure as provided by Steam Tables in the CRC Handbook of Chemistry and Physics. The lithostatic pressure gradient in many oil shale and heavy oil formations is approximately 1 psi/ft, and reservoir depths commonly range from a few hundred feet to 3000 ft. At any pressure, salinity of the connate water raises the boiling point. Therefore for the deeper reservoir sections, most, if not all, heating to 350° C. will occur in the presence of liquid water and will not vaporize the connate water. In other embodiments, the AC electrical signal flowing between the two electrodes and the resulting heating temperature of the target interval can be controlled according to the formation pressure of the target interval such that the connate water does not vaporize. As part of such control, one or more downhole pressure sensors can be utilized to characterize formation pressure, and one or more downhole temperature sensors can be utilized to monitor the heating temperature of the target interval. The temperature across the target interval can also be measured by cross-well acoustic measurements. There is rich literature on the temperature dependence of sound propagation in reservoirs, see e.g., B. Gurevich et al., “Modeling elastic wave velocities and attenuation in rocks saturated with heavy oil,” Geophysics, 72, E115-E122 (2008), herein incorporated by reference in its entirety. Characteristics of the AC electrical signal flowing between the two electrodes (such as the AC voltage) can be controlled over time such that heating temperature of the target interval remains in a desired range such that the connate water does not vaporize. The control scheme can also monitor the heating temperature of the pay interval to ensure it is within the desired range. For example, the heating temperature across the pay interval can possibly be measured by cross-well acoustic measurements as described above. 
     Note that the temperature increases to the connate water due to the heating of the target interval increases the electrical conductivity (decreases the electrical resistance) of the target interval and thus increases the current flow through the target interval and thus further aids in the heating of the target interval.  FIG. 14  is a graph that illustrates temperature dependence of the electrical resistance of 30 ppt sodium chloride in water solution as provided by a Schlumberger Log Interpretation Chart Gen-9. The salinity of the 30 ppt sodium chloride and water solution approximates that of sea water and can be analogous to connate water. It should be noted that the salinities of Green River Formation connate waters are highly variable in both composition and concentration, due to the presence of soluble minerals. 
     For many applications, the electrode configurations can be configured to inject current into one or more lower resistive target intervals that are in closed proximity to the rich pay interval that is desired to be heated. In some applications, computational modeling of the injected current can be utilized. The computational modeling can be used to optimize electrode placement as well as the voltage level (and possibly other properties) of the electrical supply signal generated and supplied by the electrical energy source to the downhole electrodes over time for the desired heating. Specifically, according to Joule&#39;s law, the heat injected into the respective target interval is proportional to the square of current flowing through the target interval as well as the electrical resistance of the target interval. The current flowing through the target interval is dependent upon the voltage level of the electrical supply signal and the electrical resistance of the target interval. The electrical resistance of the target interval is dependent upon the conductivity of the target interval and its length, which is dictated by the distance between electrodes. Furthermore, the diffusion of heat from the target interval(s) to the pay interval is dependent upon the thermal conductivity of the formation between the target interval(s) and the pay interval. These properties can be embodied in a computational model for the specific formation of interest along with appropriate boundary conditions. The computation model for the specific formation of interest can be analyzed to optimize the electrode placement and the voltage levels (and possibly other properties) of the electrical supply signal generated and supplied by the electrical energy source to the downhole electrodes over time for the desired heating of the specific formation of interest. The boundary conditions can represent limitations of available power, constraints on the heating process (such as constraints that limit the borehole temperature in order to avoid borehole over-heating), desirable heating profiles over time as well as other suitable process conditions. 
     In alternate embodiments, different electrode configurations can be used. For example, one of the electrodes can be realized by a casing string or insulated section of a casing string. In another example, the two electrodes can be spaced apart in a single wellbore (such as a u-shaped wellbore). In yet another example, more than two wellbores and downhole tools with associated current injection electrodes can be arranged in an array over the formation to provide a desired heating pattern. 
     Advantageously, the method and system of the present application provides for efficient and effective in-situ conversion of kerogen into shale oil and gas phase hydrocarbons suitable for production. These products can be a good quality refinery feedstock requiring no further upgrading. Moreover, waste products remain underground, minimizing environmental impacts. 
     In another aspect of the invention, the system and methodology as described above can be adapted to provide for in-situ heating of heavy oil of a subterranean formation through heating of at least one adjacent lower resistance zone of the formation. The heating is accomplished by AC current injection into and through the adjacent lower resistance zone(s). The heat deposited into the adjacent lower resistance zone(s) is transferred by conduction (also referred to as “diffusion”) to the heavy oil zone in order to heat the heavy oil and reduce its viscosity to aid in production. For these applications, the target interval(s) for the heating would be an interval of relatively high water saturation (and low heavy oil saturation) that is adjacent or otherwise proximate to the heavy oil pay interval. Advantageously, these operations can be effectively and efficiently carried out in deepwater heavy oil plays where traditional steam-assisted heavy oil recovery is infeasible. The reduced viscosity oil can be produced from the formation employing a suitable production methodology. The production methodology can employ one or more horizontal production wells that allow for production of the reduced viscosity oil from the formation. Alternatively, the wellbore(s) that contain the current injection tools can be configured to provide for production of the reduced viscosity oil from the formation. 
     There have been described and illustrated herein several embodiments of a method and system for electrical heating of oil shale and heavy oil formations. While particular embodiments of the invention have been described, it is not intended that the disclosure be limited thereto, as it is intended that it be as broad in scope as the art will allow and that the specification be read likewise. It will therefore be appreciated by those skilled in the art that modifications could be made. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses, if any, are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. §112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.