Patent Abstract:
A system for producing fluids from a subterranean zone comprises a tubing string disposed in a well bore, the tubing string adapted to communicate fluids from the subterranean zone to a ground surface. A downhole fluid lift system is operable to lift fluids towards the ground surface. A downhole fluid heater is disposed in the well bore and is operable to vaporize a liquid in the well bore. A seal between the downhole fluid lift system and the downhole fluid heater is operable to isolate a portion of the well bore containing the downhole fluid lift system from a portion of the well bore containing the downhole fluid heater. A method comprises: disposing a tubing string in a well bore; generating vapor in the well bore; and lifting fluids from the subterranean zone to a ground surface through the tubing string.

Full Description:
TECHNICAL FIELD 
     This invention relates to resource production, and more particularly to resource production using heated fluid injection into a subterranean zone. 
     BACKGROUND 
     Fluids in hydrocarbon formations may be accessed via well bores that extend down into the ground toward the targeted formations. In some cases, fluids in the hydrocarbon formations may have a low enough viscosity that crude oil flows from the formation, through production tubing, and toward the production equipment at the ground surface. Some hydrocarbon formations comprise fluids having a higher viscosity, which may not freely flow from the formation and through the production tubing. These high viscosity fluids in the hydrocarbon formations are occasionally referred to as “heavy oil deposits.” In the past, the high viscosity fluids in the hydrocarbon formations remained untapped due to an inability to economically recover them. More recently, as the demand for crude oil has increased, commercial operations have expanded to the recovery of such is 5 heavy oil deposits. 
     In some circumstances, the application of heated fluids (e.g., steam) and/or solvents to the hydrocarbon formation may reduce the viscosity of the fluids in the formation so as to permit the extraction of crude oil and other liquids from the formation. The design of systems to deliver the steam to the hydrocarbon formations may be affected by a number of factors. 
     In some cyclical steam injection and producing operations, a dedicated steam injection string is installed in a well bore and used for injecting heated fluid into a target formation during a steam injection cycle to reduce the viscosity of oil in the target formation. Once a steam injection cycle is completed, the injection assembly is removed from the well bore and a production string including an artificial lift assembly is installed on the well bore to produce the well. At some point, the reservoir temperature cools to a point at which increasing viscosity of the oil significantly inhibits reservoir fluid recovery using artificial lift means. Once this happens, the production string is removed from the well bore and the steam injection string is reinstalled to begin next steam injection cycle. 
     SUMMARY 
     Systems and methods of producing fluids from a subterranean zone can include downhole fluid heaters (including steam generators) in conjunction with artificial lift systems such as pumps (e.g., electric submersible, progressive cavity, and others), gas lift systems, and other devices. Supplying heated fluid from the downhole fluid heater(s) to a target subterranean zone such as a hydrocarbon-bearing formation or reservoir can reduce the viscosity of oil and/or other fluids in the target formation. To enhance this process of combining artificial lift systems with downhole fluid heaters, a downhole cooling system can be deployed for cooling the artificial lift system and other components of a completion system. 
     In one aspect, systems for producing fluids from a subterranean zone include: a downhole fluid lift system adapted to be at least partially disposed in the well bore, the downhole fluid lift system operable to lift fluids towards a ground surface; a downhole fluid heater adapted to be disposed in the well bore, the downhole fluid heater operable to vaporize a liquid in the well bore; and a seal between the downhole fluid lift system and the downhole fluid heater, the seal operable to selectively seal with the well bore and isolate a portion of the well bore containing the downhole fluid lift system from a portion of the well bore containing the downhole fluid heater. 
     In another aspect, systems include: a pump with a pump inlet, the pump inlet disposed in the well bore, the pump operable to lift fluids towards the ground surface; and a downhole fluid heater disposed in the well bore, the downhole fluid heater operable to vaporize a liquid in the well bore. 
     In one aspect, a method includes: with an artificial lift system in a well bore, introducing heated fluid into a subterranean zone about the well bore; and artificially lifting fluids from the subterranean zone to a ground surface using the artificial lift system. 
     In one aspect, a method includes artificially lifting fluids from a subterranean zone through a well bore while a downhole heated fluid generator resides in the well bore. 
     Such systems can include one or more of the following features. 
     In some embodiments, the downhole fluid lift system includes a gas lift system. 
     In some embodiments, the downhole fluid lift system includes a pump (e.g., an electric submersible pump). In some cases, the pump is adapted to circulate fluids. In some embodiments, systems also include a surface pump. 
     In some embodiments, the downhole fluid lift systems are adapted to circulate fluids in the portion of the well bore containing the downhole fluid lift system while isolated from the portion of the well bore containing the downhole fluid heater. In some embodiments, systems can also include a surface pump adapted to circulate fluids in the portion of the well bore containing the downhole fluid lift system while isolated from the portion of the well bore containing the downhole fluid heater. 
     In some embodiments, the downhole fluid heater includes a steam generator. 
     In some embodiments, systems also include a tubing string disposed in a well bore, the tubing string adapted to communicate fluids from the subterranean zone to a ground surface. 
     In some embodiments, systems also include a seal between the pump inlet and the downhole fluid heater such that fluid flow between a portion of the well bore containing the pump inlet and a portion of the well bore containing the downhole fluid heater is limited by the seal. 
     In some embodiments, methods also include isolating a portion of the well bore containing the artificial lift system from a portion where the heated fluid is being introduced into the subterranean zone. 
     In some embodiments, methods also include circulating fluid in the portion of the well bore containing the artificial lift system while introducing heated fluid into the subterranean zone. In some instances, circulating fluid comprises circulating fluid using the artificial lift system. In some instances, circulating fluid comprises circulating fluid using a surface pump. 
     In some embodiments, methods also include cooling a downhole pump present in the well bore while vapor is being generated. 
     In some embodiments, methods also include heating the fluid in the well bore. 
     Systems and methods based on downhole fluid heating can improve the efficiencies of heavy oil recovery relative to conventional, surface based, fluid heating by reducing the energy or heat loss during transit of the heated fluid to the target subterranean zones. Some instances, this can reduce the fuel consumption required for heated fluid generation. 
     In addition, by heating fluid downhole, the injection assembly between the surface and the downhole fluid heating device is no longer used as a conduit for the conveyance of heated fluid into the subterranean zone. Thus, a multipurpose completion assembly can be deployed which provides heated fluid injection into the subterranean zone and a producing conduit to the surface which includes an artificial lift system. Heating the fluids downhole reduces collateral heating of the uphole well bore, thereby reducing heat effects and possible damage on the artificial lift production system and other equipment therein. In addition, multipurpose completion assemblies including cooling mechanisms for downhole artificial lift systems and other devices can further reduce the possibility that heat associated with heating the fluid will damage artificial lift systems or other devices present in the well bore. 
     Use of multipurpose completion assemblies can also increase operational efficiencies. Such multipurpose completion assemblies can be installed in a well bore and remain in place during both injection and production phases of a cyclic production process. This reduces the number of trips in and out of the well bore that would otherwise be required for systems and methods based on the use of separate injection and production assemblies. 
     The details of one or more embodiments of the invention are set forth in the accompanying drawings and the description below. Other features, objects, and advantages of the invention will be apparent from the description and drawings, and from the claims. 
    
    
     
       DESCRIPTION OF DRAWINGS 
         FIGS. 1A-1C  are schematic views of an embodiment of a system for producing fluids from a subterranean zone. 
         FIG. 2  is a schematic view of another embodiment of a system for producing fluids from a subterranean zone. 
         FIG. 3  is a schematic view of another embodiment of a system for producing fluids from a subterranean zone. 
         FIG. 4  is a schematic view of another embodiment of a system for producing fluids from a subterranean zone. 
         FIG. 5  is a schematic view of another embodiment of a system for producing fluids from a subterranean zone. 
     
    
    
     Like reference symbols in the various drawings indicate like elements. 
     DETAILED DESCRIPTION 
     Systems and methods of producing fluids from a subterranean zone can include downhole fluid heaters in conjunction with artificial lift systems. One type of downhole fluid heater is a downhole steam generator that generates heated steam or steam and heated liquid. Although “steam” typically refers to vaporized water, a downhole steam generator can operate to heat and/or vaporize other liquids in addition to, or as an alternative to, water. Some examples of artificial lift systems include pumps, such as electric submersible, progressive cavity, and others, gas lift systems, and other devices that operate to move fluids. Supplying heated fluid from the downhole fluid heater(s) to a target formation such as, a hydrocarbon-bearing formation or reservoir can reduce the viscosity of oil and/or other fluids in the target formation. To accomplish this process of combining artificial lift systems with downhole fluid heaters, a downhole cooling system can be deployed for cooling the artificial lift system and other components of a completion system. In some instances, use of a single multipurpose completion assembly allows for cyclical steam injection and production without disturbing or removing the well bore completion assembly. Such multipurpose completion assemblies can include a downhole heated fluid generator, an artificial lift system, and a production assembly cooling system that circulates surface cooled well bore water during the steam injection process. 
     Referring to  FIGS. 1A-1C , a system  100  for producing fluids from a reservoir or subterranean zone  110  includes a tubing string  112  disposed in a well bore  114 . The tubing string  112  is adapted to communicate fluids from the subterranean zone to a ground surface  116 . A downhole fluid lift system  118 , operable to lift fluids towards the ground surface  116 , is at least partially disposed in the well bore  114  and may be integrated into, coupled to or otherwise associated with the tubing string  112 . A downhole fluid heater  120 , operable to vaporize a liquid in the well bore  114 , is also disposed in the well bore  114  and may be carried by the tubing string  112 . As used herein, “downhole” devices are devices that are adapted to be located and operate in a well bore. A seal  122  (e.g., a packer seal) is disposed between the downhole fluid lift system  118  and the downhole fluid heater  120 . The seal  122  may be carried by the tubing string  112 . The seal  122  may be selectively actuable to substantially seal the annulus between the well bore  114  and the tubing string  112 , thus hydraulically isolating a portion of the well bore  114  uphole of the seal  122  from a portion of the well bore  114  downhole of the seal  122 . As will be explained in more detail below, the seal  122  limits the flow of heated fluid (e.g., steam) upwards along the well bore  114 . 
     A well head  117  may be disposed proximal to a ground surface  116 . The well head  117  may be coupled to a casing  115  that extends a substantial portion of the length of the well bore  114  from about the ground surface  116  towards the subterranean zone  110  (e.g., hydrocarbon-containing reservoir). The subterranean zone  110  can include part of a formation, a formation, or multiple formations. In some instances, the casing  115  may terminate at or above the subterranean zone  110  leaving the well bore  114  un-cased through the subterranean zone  110  (i.e., open hole). In other instances, the casing  115  may extend through the subterranean zone and may include apertures formed prior to installation of the casing  115  or by downhole perforating to allow fluid communication between the interior of the well bore  114  and the subterranean zone. Some, all or none of the casing  115  may be affixed to the adjacent ground material with a cement jacket or the like. In some instances, the seal  122  or an associated device can grip and operate in supporting the downhole fluid heater  120 . In other instances, an additional locating or pack-off device such as a liner hanger (not shown) can be provided to support the downhole fluid heater  120 . In each instance, the downhole fluid heater  120  outputs heated fluid into the subterranean zone  110 . 
     In the illustrated embodiment, well bore  114  is a substantially vertical well bore extending from ground surface  116  to subterranean zone  110 . However, the systems and methods described herein can also be used with other well bore configurations (e.g., slanted well bores, horizontal well bores, multilateral well bores and other configurations). 
     The tubing string  112  can be an appropriate tubular completion member configured for transporting fluids. The tubing string  112  can be jointed tubing or coiled tubing or include portions of both. The tubing string  112  carries the seal  122  and includes at least two valves  125 ,  126  bracketing the packer seal (e.g., valve  125  provided on one side of seal  122  and valve  126  provided on the other side of seal). Valves  125 ,  126  provide and control fluid communication between a well bore annulus  128  and an interior region  130  of the tubing string  112 . When open, valves  125 ,  126  allow communication of fluid between the annulus  128  and tubing string interior  130 , and when closed valves  125 ,  126  substantially block communication of fluid between the annulus  128  and tubing string interior  130 . In this embodiment, the valves  125 ,  126  are electrically operated valves controlled from the surface  116 . In other embodiments, valves  125 ,  126  can include other types of closure mechanisms (e.g., apertures in the tubing string  112  opened/closed by sliding sleeves and other types of closure mechanisms). Additionally, in other embodiments, the valves  125 ,  126  can be controlled in a number of other different manners (e.g., as check valves, thermostatically, mechanically via linkage or manipulation of the string  112 , hydraulically, and/or in another manner). 
     The downhole fluid lift system  118  is operable to lift fluids towards the ground surface  116 . In the illustrated embodiment, the downhole fluid lift system is an electric submersible pump  118  mounted on the tubing string  112 . The electric submersible pump  118  has a pump inlet  132  which draws fluids from the well bore annulus  128  uphole of the packer seal  120  and a pump outlet  134  which discharges fluids into the interior region  130  of the tubing string  112 . Power and control lines associated with electric submersible pump  118  can be attached to an exterior surface of tubing string  112 , communicated through the tubing string  112 , or communicated in another manner. In some embodiments, downhole fluid lift systems are implemented using other mechanisms such as, for example, progressive cavity pumps and gas lift systems as described in more detail below. 
     The downhole fluid heater  120  is disposed in the well bore  114  below the seal  122 . The downhole fluid heater  120  may be a device adapted to receive and heat a recovery fluid. In one instance, the recovery fluid includes water and may be heated to generate steam. The recovery fluid can include other different fluids, in addition to or in lieu of water, and the recovery fluid need not be heated to a vapor state (e.g. steam) of 100% quality, or even to produce vapor. The downhole fluid heater  120  includes inputs to receive the recovery fluid and other fluids (e.g., air, fuel such as natural gas, or both) and may have one of a number of configurations to deliver heated recovery fluids to the subterranean zone  110 . The downhole fluid heater  120  may use fluids, such as air and natural gas, in a combustion or catalyzing process to heat the recovery fluid (e.g., heat water into steam) that is applied to the subterranean zone  110 . In some circumstances, the subterranean zone  110  may include high viscosity fluids, such as, for example, heavy oil deposits. The downhole fluid heater  120  may supply steam or another heated recovery fluid to the subterranean zone  110 , which may penetrate into the subterranean zone  110 , for example, through fractures and/or other porosity in the subterranean zone  110 . The application of a heated recovery fluid to the subterranean zone  110  tends to reduce the viscosity of the fluids in the subterranean zone  110  and facilitate recovery to the ground surface  116 . 
     In this embodiment, the downhole fluid heater is a steam generator  120 . Gas, water, and air lines  136 ,  138 ,  140  convey gas, water, and air to the steam generator  120 . In certain embodiments, the supply lines  136 ,  138 ,  140  extend through seal  122 . In the embodiment of  FIG. 1A , a surface based pump  142  pumps water from a supply such as supply tank  144  to piping  146  connected to wellhead  148  and water line  140 . Various implementations of supply lines  136 ,  138 ,  140  are possible. For example, gas, water, and air lines  136 ,  138 ,  140  can be integral parts of the tubing string  112 , can be attached to the tubing string, or can be separate lines run through well bore annulus  128 . One exemplary tube system for use in delivery of fluids to a downhole heated fluid generator device includes concentric tubes defining at least two annular passages that cooperate with the interior bore of a tube to communicate air, fuel and recovery fluid to the downhole heated fluid generator. 
     In operation, well bore  114  is drilled into subterranean zone  110 , and well bore  114  can be cased as appropriate. After drilling is completed, tubing string  112 , downhole fluid heater  120 , downhole fluid lift system  118 , and seal  122  can be installed in the well bore  114 . The seal  122  is then actuated to extend radially to press against and substantially seal with the casing  115 . The valves  126 ,  125  are initially closed. 
     Referring to  FIG. 1A , cooling fluid (e.g., water) can be supplied to uphole well bore annulus  128  at wellhead  148 . The downhole fluid lift system  118  can be activated to circulate the cooling water downward through uphole well bore annulus  128  and upwards to the interior region  130  of tubing string  112 . The combined effect of the isolation of uphole well bore annulus  128  from downhole well bore annulus  129  and the circulation of cooling fluid can reduce temperatures in the uphole well bore annulus  128 . The reduced temperatures reduce the likelihood of heat damage to the downhole fluid lift system  118  and other devices in the uphole portion of the well bore  114  (e.g., the deterioration and premature failure of heat sensitive components such as rubber gaskets, electronics, and others). Of note, although additional steps are not required to actively cool the cooling fluid, in some instances, the cooling fluid may be cooled by exposure to atmosphere, using a refrigeration system (not shown), or in another manner. 
     The downhole fluid heater  120  can be activated, thus heating recovery fluid (e.g., steam) in the well bore. Because the apertures  126  in the downhole production sleeve are closed, the heated fluid passes into the target subterranean zone  110 . The heated fluid can reduce the viscosity of fluids already present in the target subterranean zone  110  by increasing the temperature of such fluids and/or by acting as a solvent. 
     Referring to  FIG. 1B , after a sufficient reduction in viscosity has been achieved, fluids (e.g., oil) are produced from the subterranean zone  110  to the ground surface  116  through the tubing string  112 . Both the downhole fluid heater  120  and the downhole fluid lift system  118  can be turned off and the downhole valve  125  opened. Flow of cooling water into the uphole annulus  128  of the well bore  114  can be stopped. For some period of time after injection is completed, pressures in the subterranean zone  110  can be high enough to cause a natural flow of fluids from the reservoir to the ground surface  116  through the tubing string  112 . During this period of time, the uphole valve  126  remains closed. 
     Referring to  FIG. 1C , as the pressure in the subterranean zone  110  is depleted or as the subterranean zone  110  cools and fluid viscosity in the reservoir increases, production due to reservoir pressure can slow and even stop. As this occurs, the uphole valve  126  is opened and the downhole fluid lift system  118  is activated. The downhole fluid lift system  118  pumps fluids through downhole valve  125 , out of uphole valve  126  and from uphole annulus  128  to the ground surface  116  through the interior region  130  of tubing string  112 . In some instances, tubing string  112  can include additional flow control mechanisms. For example, tubing string can include check valves and/or other arrangements to direct the travel of fluids transferred into the interior region  130  of the tubing string  112  from fluid lift system  118  uphole in the tubing string  11 . 
     As the subterranean zone  110  further cools and fluid viscosity in the reservoir further increases, production, even using the downhole fluid lift system, can slow. At this point, system  100  can be reconfigured for injection by closing valves  125 ,  126 , and by activating the downhole fluid lift system  118  (to circulate cooling water) and the downhole fluid heater  120  to repeat the cycle described above. Such systems and methods can increase operational efficiencies because a single completion assembly can be installed in a well bore and remain in place during both injection and production phases of a cyclic production process. This reduces the number of trips in and out of the whole that would otherwise be required for systems and methods based on the use of separate injection and production assemblies. 
     The concepts described above can be implemented in a variety of systems and/or system configurations. For example, other approaches can be used to cool the downhole fluid lift system. Similarly, other downhole fluid lift systems can be used. 
       FIG. 2  depicts an alternate approach to cooling the downhole fluid lift system and other components in the uphole portion of the well bore  114 . A system  200  can be arranged in substantially the same configuration as system  100 . However, system  200  can use the surface pump to circulate cooling water through the uphole annulus  128  of the well bore  114  during the heated fluid injection phase. This can reduce the overall use of downhole fluid lift system  118  and, thus, can reduce the likelihood of wear related damage to the downhole fluid lift system. The surface pump can be the pump  142  used to supply water to the downhole fluid heater  120  or a separate pump can be used. 
       FIG. 3  depicts yet another alternate approach to cooling the downhole fluid lift system and other components in the uphole portion of the well bore  114 . Like system  200 , system  300  can reduce the overall use of downhole fluid lift system  118  and, thus, can reduce the likelihood of wear related damage to the downhole fluid lift system. System  300  is also arranged in substantially the same configuration as system  100  and system  200 . However, system  300  includes an alternate mechanism for cooling the downhole fluid lift system  118  during the injection phase. The water line  140  that feeds the downhole fluid heater  120  is connected to a shroud  310  disposed around exterior portions of the downhole fluid lift system  118 . During the injection phase, water flowing to the downhole fluid heater  120  passes through the shroud  310  providing both insulation and cooling for the downhole fluid lift system  118 . Other components in the uphole portion of the well bore  114  can be similarly cooled using the water line  140 . 
     Referring to  FIG. 4 , systems can also be implemented using alternate downhole fluid lift systems. For example, system  400  is implemented using a progressive cavity pump  418  disposed in line with the tubing string  112  as the downhole fluid lift system. The progressive cavity pump  418  is driven by a drive shaft  420  extending downward to the progressive cavity pump through the interior region  130  of tubing string  112 . System  400  is also arranged in substantially the same configuration as the previously described systems  100 ,  200 ,  300 . However, because the progressive cavity pump  418  is arranged in line with the tubing string  112 , the uphole valve can be omitted. In some embodiments, system  400  includes the shroud  310  described above as arranged above for cooling the progressive cavity pump  418 . 
     Referring to  FIG. 5 , systems can also be implemented using a gas lift system as the downhole fluid lift system. For example, system  500  is implemented using a gas lift production assembly rather than pumps as the downhole fluid lift system. System  500  is also arranged in substantially the same configuration as the previously described system  400 . However, a gas lift production assembly  518  which includes at least one gas lift production liner  520  with gas lift mandrels  522 . The gas lift mandrels  522  each include one or more gas lift valves  524 . Dummies can be placed in the gaslift mandrels  522  during the injection phase so that the uphole well bore annulus  128  does not need to be cooled. After the injection phase is completed, the dummies are removed and gas lift valves installed (e.g., by using a wireline system). The reservoir fluid is then lifted to the ground surface  116  using artificial lift provided by the gas lift system  518 . 
     A number of embodiments of the invention have been described. Nevertheless, it will be understood that various modifications may be made without departing from the spirit and scope of the invention. Accordingly, other embodiments are within the scope of the following claims.

Technology Classification (CPC): 4