Abstract:
A protection system for an artificial lift device including but not limited to electrical submersible pump (ESP) and an electrical submersible progressing cavity pup (ESPCP). The artificial lift device is suspended on a tubing string into a wellbore where the artificial lift device contacts well fluids. The artificial lift device is provided with a barrier such as an intake barrier or output barrier that deters an ingress of well fluids into the artificial lift device. As a result, the artificial lift device may remain idle and submerged within well fluids for an extended period of time without experiencing degradation of the artificial lift device internals. The intake barrier may include a plug, burst disk, dissolvable material, a selectively openable barrier such as a sleeve or a spring biased member or other member that is capable of providing a suitable barrier. The barrier may be removed once the artificial lift device is ready for operation. The artificial lift device may be filled with a protective fluid. An optional pressure sensor may be provided that is in communication with the interior of the backup unit for communicating with a compressor that may be activated to maintain a positive pressure within the artificial lift device to prevent well fluids from entering the unit. The protection system of the invention is desirable for protecting an idle artificial lift device, including when the artificial lift device is a backup unit in a multi-artificial lift device deployment.

Description:
BACKGROUND OF THE INVENTION  
       [0001]     1. Field of the Invention  
         [0002]     This invention relates generally to submersible artificial lift devices, and in particular to a single or multi-device system provided with a barrier to deter an ingress of well fluids into the device to reduce or prevent development of corrosion, formation of scale or asphaltenes or other problems in an idle device within a wellbore.  
         [0003]     2. Background  
         [0004]     Submersible artificial lift devices are widely used to pump fluid from a wellbore, particularly for purposes of hydrocarbon recovery. Examples of submersible artificial lift devices include an electrical submersible well pump (ESP) and an electrical submersible progressing cavity pump (ESPCP). Typically, an artificial lift device is suspended within a well from a flow conduit. The artificial lift device is submerged in well fluids. Prolonged inactivity and exposure to well fluids may damage motor and pump components of a typical artificial lift device. Therefore, it is desirable to protect the internals of an inactive artificial lift device when the device is submerged in wellbore fluids.  
         [0005]     For example, U.S. Pat. No. 2,783,400 to Arutunoff teaches a protecting unit for an oil field submergible electrical motor. The protective unit provides a pathway for a lubricating and protecting fluid to expand or contract as a result of heating or cooling due to the electric motor. Additionally, the protecting unit essentially doubles the length of a path traveled by moisture or any contaminating fluid before such fluid can reach the pumping unit. One potential drawback of the protecting unit of Arutunoff is that the lengthened moisture path delays rather than prevents moisture migration to the pumping unit.  
         [0006]     In some cases, it has been desirable to deploy multiple pumping units within a wellbore. Examples of multiple pumping units include the following:  
         [0007]     U.S. Pat. No. 3,741,298 to Canton teaches a multiple well pump assembly wherein upper and lower pumps are both housed in a single wellbore hole and the pumps are connected in parallel so as to supplement each other&#39;s output. The pumps may be provided with different flow capacities and may couple with power means for running each pump individually or both simultaneously to provide a well pump system capable of selectively delivering three different effective flow rates from a single wellbore hole to satisfy varying flow demands.  
         [0008]     U.S. Pat. Nos. 4,934,458 and 5,099,920 to Warburton et al. teach a small diameter dual pump pollutant recovery system. The system includes a water pump assembly and a pollutant pump assembly mounted at the lower end of piping, which serves to suspend the pumps in a well and also as an exhaust conduit for transporting pump water to the surface. The pollutant pump is used to recover lower density immiscible pollutants from the surface of the underground water table using the cone of the pressure method. The water pump may be raised and lowered to the position at the pollutant/water interface. A method of relocating the pollution intake and resetting the height of the cone of depression when conditions vary the height of the pollutant/water interface is also disclosed.  
         [0009]     U.S. Pat. No. 5,404,943 to Strawn teaches a multiple pump assembly for wells. Strawn teaches a design to allow multiple submersible pumps in a single borehole. The multiple pump assembly provides flexibility in use of multiple pumps by allowing the user to avoid multiple well requirements through the use of standby or peak loading pumps.  
         [0010]     U.S. Pat. No. 6,119,780 to Christmas teaches a wellbore fluid recovery system and method for recovering fluid from a wellbore that has at least one lateral wellbore extending out therefrom. The system includes a first electrical submergible pumping system for recovering fluids from a first zone of a wellbore and a second electrical submergible pumping system for recovering fluids from a second zone of a wellbore, such as a from a lateral wellbore. The fluid recovery system allows fluid recovery from each lateral wellbore to be independently controlled and also to provide adequate draw down pressure for each lateral wellbore.  
         [0011]     U.S. Pat. No. 6,250,390 to Narvaez et al. teaches a dual electric submergible pumping system for producing fluids from separate reservoirs. A first submergible pumping system is suspended from deployment tubing and a second submergible pumping system is suspended from deployment tubing. The first submergible pumping system is connected to a fluid transport such that fluid may be discharged into the first fluid flow path, and a second submergible pumping system is connected to the fluid transport such that the fluid may be discharged into the second fluid flow path.  
         [0012]     Typically, once an ESP is located below the static fluid level during deployment of the ESP into the well, wellbore fluid is free to enter into and fill the pump. If a blanking plug is installed, e.g. in a Y-Tool crossover, wellbore fluid is free to fill the open path in the pump and compress the air cap in the pump having a blanking plug in place. Depending on submergence pressure, the wellbore fluid may partially or substantially fully fill the pump.  
         [0013]     A difficulty with having an idle unit that is at least partially filled with well fluid is that the idle unit is subject to the possibility of degradation of internal components including scale or asphaltenes precipitating out in the unit, which can cause either plugging of flow passageways and/or interference or locking of rotating components. Therefore, it is desirable to provide a protective environment for internals of the pump(s) that are held in backup or that have a delayed start-up. A protective environment increases the reliability of starting and running the pumps.  
       SUMMARY OF THE INVENTION  
       [0014]     The present invention features an artificial lift device that is suspended on a flow conduit within a well. The artificial lift device is submerged in well fluids. A barrier is provided to prevent ingress of well fluids into the artificial lift device.  
         [0015]     In many instances it is desirable to use multiple artificial lift devices in a single borehole. One advantage is that one device may be used as a primary pump and a second device may be used as a backup pump. One difficulty is that the static, or backup, unit sits idle and soaks in the wellbore environment, where the backup unit may be exposed to pressure cycles and possibly small temperature cycles. Possibilities exist for scale or asphaltenes to precipitate out in the unit. This can cause plugging of flow passageways and/or interference or locking of rotating components. By providing a barrier to protect the internal components of a backup unit or units from well fluid, the probability of damage to internal components is reduced.  
         [0016]     In one embodiment, a multi-unit system of the invention is suspended on a tubing string into the wellbore. The multi-unit system has a junction, such as a Y-tool, T-connector or other type of junction having an upper end that communicates with production tubing and has a lower end having an operating unit port and a backup unit port. An operating unit communicates with the junction via the operating unit port and a backup unit communicates with the junction via the backup unit port. A barrier, such as a valve, blanking plug or other type of barrier is provided in the junction for selectively blocking off either the operating unit port or the backup unit port, thereby blocking fluid communication with either the operating unit or the backup unit. The backup unit is also provided with an intake barrier that deters ingress of well fluids into the backup unit. Therefore, the backup unit may remain submerged within well fluids for an extended period of time without experiencing degradation of the backup unit internals. The intake barrier may include a plug, burst disk, soluble material, a selectively openable intake barrier such as a sleeve or a spring biased member or other member that is capable of providing a suitable barrier.  
         [0017]     In one embodiment, a pressure sensor is provided in communication with the interior of the backup unit. The pressure sensor communicates with a pressure producing device, such as a compressor, pump, or other device that may be activated to maintain a positive pressure within the backup unit to assist in preventing well fluids from entering the backup unit. A pressure sensor may also be provided in communication with the interior of the primary unit to detect a failure of the primary unit and to send a signal to an automated system to auto-activate the back-up unit. Alternatively, the pressure sensor may be used to send a warning to the surface, e.g., to a workstation, so that an operator may intervene to take appropriate action, such as starting the back-up unit in the event of primary unit failure.  
         [0018]     The invention further includes a method of preserving pump integrity of an idle unit in a well, e.g., as a backup unit in a multiple unit system in a common wellbore. The method includes locating a multi-unit system in a wellbore wherein the multi-unit system includes an operating unit in communication with a junction and the backup unit in communication with a junction. A fluid barrier is provided in an output port output passageway, the junction, an intake port, or both ports or other combination of locations to deter ingress of well fluids into the backup unit. The backup unit is preferably filled with a protective fluid. The backup unit may be filled with protective fluid prior to deploying the multiple unit system within the wellbore or the backup unit may be filled, e.g., via a hydraulic communication line after the multiple unit system is deployed within the wellbore.  
         [0019]     In one embodiment, a bubbler gage system may be used to deliver a fluid, such as an inert gas, to the backup unit. Typically, a bubbler gage system includes a fluid line extending from the surface to a location below the fluid level in a well, in this case to a submerged artificial lift unit. Fluid is then continuously delivered to the interior of the unit to maintain a positive pressure therein, which deters ingress of fluids into the unit. The bubbler gage also provides an additional benefit in that the well fluid level may be determined by noting when the pressure required to deliver additional fluid into the fluid line ceases to increase as a function of volume of fluid delivered.  
         [0020]     To facilitate operation of the idle unit, the barrier is removed. The barrier may be removed by the application of additional pressure in the backup unit to push out a barrier or to burst a burst disk type barrier or by activating the unit to “pump out” a barrier. Additionally, if the barrier is comprised of a soluble material, then a solvent may be delivered to the backup unit to dissolve the fluid barrier. A selectively openable member may also be activated to open a flapper type valve, to slide a sliding sleeve, or to manipulate other types of selectively openable members. Examples of activators include, but are not limited to, a hydraulic line, an electric line in communication with a servo or an electric line to deliver a one time electrical pulse to activate a charge, a pneumatic line, or other means. Further, the barrier may be a spring-biased member that opens automatically by activation of the backup unit. Additionally, the barrier may be activated to open by rotation of the shaft in the unit. The barriers may also be opened to allow the fluid barrier to drain or flow out of the unit. Other types of barriers may also be used. Although the invention is described primarily as it relates to a protection scheme for a backup unit, it should be understood that the invention is also applicable to a single ESP unit that is to remain idle for a period of time while submerged in well fluids.  
         [0021]     A better understanding of the present invention, its several aspects, and its advantages will become apparent to those skilled in the art from the following detailed description, taken in conjunction with the attached drawings, wherein there is shown and described the preferred embodiment of the invention, simply by way of illustration of the best mode contemplated for carrying out the invention. 
     
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0022]      FIG. 1  is a schematic view of a multiple unit artificial lift system deployed in a wellbore.  
         [0023]      FIG. 2  is a cross-sectional view of a Y-Tool having a blanking plug installed therein.  
         [0024]      FIG. 3  is a cross-sectional view of a Y-Tool having a flapper valve installed therein.  
         [0025]      FIG. 4  is a perspective view of a barrier plug obstructing a pump intake port.  
         [0026]      FIG. 5  is a perspective view of a burst disk obstructing a pump intake port.  
         [0027]      FIG. 6  is a perspective view of a soluble plug obstructing a pump intake port.  
         [0028]      FIG. 7  is a perspective view of a spring-biased member obstructing a pump intake port.  
         [0029]      FIG. 8  is a perspective view of a sliding sleeve obstructing a pump intake port.  
         [0030]      FIG. 9  is a perspective view of a hydraulically actuated flapper valve obstructing a pump intake port.  
         [0031]      FIG. 10  is a cross-sectional view of a multi-unit in-line artificial lift system deployed in a wellbore.  
     
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT  
       [0032]     Before explaining the present invention in detail, it is important to understand that the invention is not limited in its application to the details of the embodiments and steps described herein. The invention is capable of other embodiments and of being practiced or carried out in a variety of ways. It is to be understood that the phraseology and terminology employed herein is for the purpose of description and not of limitation.  
         [0033]     Referring now to  FIG. 1 , shown is a multiple unit system designated generally  10 . The multi-unit system  10  is deployed within wellbore  12 . Wellbore  12  is lined with casing  14 . A tubing string  16  carries the multiple unit system  10 . Typically, the multiple unit system  10  is utilized to lift wellbore fluids  18  that enter the wellbore  12  through perforations  20 . Wellbore fluids  18  are directed upward through tubing string  16 , through wellhead  22 , and to a production line  24 . A junction, designated generally  23 , such as Y-Tool crossover  26 , is affixed to the lower end of the tubing string  16 . As can be seen in greater detail in  FIGS. 2 and 3 , Y-Tool crossover  26  has an upper end  28  and a lower end  30 , which is provided with a first unit port  32  and a second unit port  34 . Typically, a junction  23 , such as the Y-Tool crossover  26 , is provided with an output barrier  35  in either the first unit port  32  or second unit port  34 . Examples of output barriers  35  include a blanking plug  36  ( FIG. 2 ) and a flapper valve  38  ( FIG. 3 ). Flapper valve  38  is preferably capable of 180 ° rotation to selectively seal either the first unit port  32  or the second unit port  34 . Further examples include a traveling ball used to selectively close a selected side. Although blanking plug  36  and flapper valve  38  are specifically shown in  FIGS. 2 and 3 , it should be understood that other types of output barriers may be suitable for use to selectively seal off either the first unit port  32  or the second unit port  34 . Additionally, in some cases it may be desirable to directly seal off a discharge port  39  ( FIG. 1 ) of the unit  42 , or to locate a barrier in a first unit passageway  40 , which extends upwards from the unit  42 .  
         [0034]     Referring back to  FIG. 1 , first unit passageway  40  communicates with first unit port  32  of Y-Tool  26 . First unit passageway  40  delivers output from first unit  42  through Y-Tool  26  and up tubing string  16  to the surface. As shown, first unit  42  is an ESP having a centrifugal pump  44 , a rotary gas separator  46 , a seal section  48 , and an electric motor  50 . Typically, rotary gas separator  46  is provided with pump intakes  52 . The electric motor  50  receives power from a cable, which transmits electric power to electric motor  50  from the surface.  
         [0035]     The multiple unit system  10  of the invention is provided with a second unit  60 , which may be used as a primary unit or as a back-up unit as desired. Second unit  60  communicates with the second unit port  34  of Y-Tool  26  via a second unit passageway  62 . Second unit passageway  62  communicates with discharge port  61  of second unit  60 . The second unit  60  and the second unit passageway  62  are preferably affixed to the first unit  42  via a series of clamps  64 . As shown, second unit  60  is an ESPCP having a progressing cavity pump  66 , a flex shaft section  68 , a seal section  70 , a gear reducer  71  and an electric motor  72 . The electric motor  72  receives power from the surface via a cable. Second unit  60  is also provided with a fluid intake  74 .  
         [0036]     It should be understood that although  FIG. 1  shows first unit  42  as an ESP and second unit  60  as an ESPCP, this arrangement is shown for example purposes only. Other combinations are possible and fall within the scope of the invention. For example, first unit  42  and second unit  60  may both be an ESP unit or may both be an ESPCP unit. First unit  42  may be an ESPCP unit and second unit  60  may be an ESP unit. Additionally, other types of artificial lift devices may be substituted for either or both the first unit  42  and second unit  60 . Moreover, additional units  42 ,  60  may be provided in combination with additional junctions  23  so that three or more artificial lift devices may be provided in any combination of ESPs, ESPCPs, or other artificial lift devices. Finally, as shown in  FIG. 1 , the terms “first unit” and “second unit” are used for convenience only and it should be understood that either or both of the units may be operated or held as a backup as required. Still referring to  FIG. 1 , wherein first unit  42  is shown as an ESP and second unit  60  is shown as an ESPCP, it may be desirable to operate one or the other of units  42  and  60  depending upon well conditions or process preferences.  
         [0037]     Referring now to  FIGS. 4-9 , in the preferred embodiment, first unit  42  and second unit  60  are provided with an intake barrier designated generally  100 , which may be located in the pump intake  52  of the first unit  42  and in pump intake  74  of second unit  60  or intakes  208  and  238  ( FIG. 10 ), discussed below, to prevent wellbore fluids  18  from entering the units  42 ,  60  when units  42 ,  60  are not in use. Although units  42 ,  60  are specifically referenced, it should be understood that  FIGS. 4-9  are equally applicable to a stand-alone artificial lift unit or to an artificial lift unit in any multi-unit system configuration. A pressure sensor  101  may be provided to sense pressure within a unit  42 ,  60 . Pressure information is communicated to the surface where a pressure producing device, such as compressor or pump  104  ( FIG. 1 ), may be selectively operated to maintain pressure within the unit  42 ,  60  at a pressure above that of the wellbore fluids  18 . The pressure producing device, such as compressor  104 , communicates with the unit  42 ,  60  via a communication line, such as hydraulic line  106 . Hydraulic line  106  is connected to the multiple unit system  10  at a location below the junction  23 .  
         [0038]     Examples of intake barrier  100  include plug  108  ( FIG. 4 ), burst disk  110  ( FIG. 5 ), soluble plug  114  ( FIG. 6 ), and a selectively openable member designated generally  116  ( FIGS. 7-9 ). Selectively openable member  116  includes a spring biased member  118  as shown in  FIG. 7 , a sliding sleeve  120 , actuated by a hydraulic system and hydraulic piston  121 , as shown in  FIG. 8 , or flapper valve  122  actuated by hydraulic piston  123 , as shown in  FIG. 9 . Other selectively openable members may also be used as required.  
         [0039]     In practice, a method of preserving pump integrity of an idle unit, such as second unit  60  of a multiple unit system  10  is as follows. It should be understood that the method of preserving pump integrity is equally applicable to first pump  42  or to a stand alone artificial lift device, secondary back-up unit or other artificial lift device and that second unit  60  is used herein for purposes of example only. An intake barrier  100  is provided in pump intake  74  of the second unit  60  to deter ingress of well fluids  18  into the second unit  60 . The second unit  60  is filled with a protective fluid to inhibit contamination of the second unit  60  within the wellbore  12 . Examples of suitable protective fluids include but are not limited to a range of fluids having a generally lighter specific gravity, e.g. diesel, to protective fluids that have a generally heavy specific gravity, e.g. “Beaver Lube”. Preferably, the protection fluids are inert with respect to component materials of the unit. Second unit  60  may be filled with protective fluid prior to deployment of multi-unit system  10  within the wellbore  12  or may be filled with protective fluid via hydraulic communication line  106  after multiple unit system  10  reaches setting depth. In one embodiment, pressure within the second unit  60  is at least periodically maintained at a level that is equal to pressure external of the second unit  60  in the wellbore. Pressure within the second unit  60  may be maintained via hydraulic communication line  106 , which is operatively connected to a pressure producing device, such as compressor  104 . Additionally, periodic flushing of the second unit  60  may be undertaken to assure continued protection over the time.  
         [0040]     If a protective fluid is used that has a heavier specific gravity than well fluids, then the unit  60  may be sealed with an intake barrier  100  since the protective fluid will tend to settle to the lower portions of the unit. Conversely, if a protective fluid is used that has a lighter specific gravity than well fluids, then a barrier may located in the junction  23 , as shown in  FIGS. 2 and 3 , in passageway  40 ,  62 , in output ports  39 ,  60  or at another location in the upper regions of units  42 ,  60 . Such a barrier shall be referred to herein as an “output barrier”. The lighter protective fluid will float on any well fluid present in the unit and, when held in place with an output barrier, will serve to prevent ingress of well fluids into the unit. Therefore, it can be seen that a protective fluid may prevent ingress of well fluids when used in conjunction with one of an intake barrier and an output barrier. Of course, barriers may be provided at both the intake and output regions and used with or without a protective fluid.  
         [0041]     In operation, if an operating unit, e.g. first unit  42 , fails or if it is desired to run first unit  42  and second unit  60  simultaneously, an intake barrier  100  and/or output barrier  35  must be removed from the pump intake  74  and/or the output region of the second unit  60 . Similarly, if unit  60  is a stand alone unit in a well, e.g., if for some reason it is desirable to install the unit  60  and leave the unit idle for some period of time, then intake barrier  100  and/or output barrier  35  will be removed from pump intake  74  before operating unit  60 .  
         [0042]     One method of removing an intake barrier is to apply additional pressure within the backup unit  60  via hydraulic line  106  to push out the intake barrier  100 , such as plug  108  (FIG.  4 ). Additionally, pressure may be delivered to the second unit  60  via hydraulic line  106  to burst a burst disk  110  ( FIG. 5 ).  
         [0043]     Further, in one embodiment, intake barrier  100  and/or output barrier  35  may be a soluble plug  114  ( FIGS. 2 and 6 ). To remove soluble plug  114 , a solvent is introduced through a passageway such as hydraulic line  106  into the unit  42 ,  60 . Examples of suitable materials for a soluble plug include gels, solids, or other suitable materials. The solvent acts to dissolve soluble plug  114 , thereby opening the pump intake  74  or pump output. Examples of suitable solvents include acids, e.g. hydrochloric acid, hydrofluoric acid, or other fluid treatments that are preferably not damaging to the unit or to the reservoir and which are preferably not soluble to well fluids. Hydraulic line  106  may be used to selectively activate a selectively openable member  116  ( FIGS. 7-9 ). For example, pressure may be delivered to move a sliding sleeve  120  to expose the pump intake  74  ( FIG. 8 ) or hydraulic pressure may be applied to open flapper valve  122  ( FIG. 9 ), thereby opening pump intake  74 . A pressure differential across pump intake  74  when the pump is running may be sufficient to open a spring biased member  118  to open pump intake  74  ( FIG. 7 ). Additionally, sliding sleeve  120  ( FIG. 8 ) and flapper valve  122  ( FIG. 9 ) may be opened by internal pump pressure rather than by pressure via hydraulic line  106 .  
         [0044]     Although, second pump  60  has been shown as part of a multi-unit artificial lift system  10 , the protection schemes of the invention could be utilized on multi-unit artificial lift systems having multiple backup pumps or the protection schemes of the invention could be utilized on a single artificial lift device deployed downhole, particularly where the single artificial lift device may not be started immediately.  
         [0045]     Referring now to  FIG. 10 , an additional embodiment of a multi-unit system is shown. In particular, an in line POD system  200  is suspended from tubing  202  within a wellbore  204 . An upper artificial lift device  206  has an intake port  208  and an output port  210 . Upper artificial lift device  206  may be an ESP or an ESPCP or other types of submersible artificial lift devices. A passageway  212  communicates the output port  210  with the tubing  202 . Passageway  212  has an upper selectively openable member  214  thereon. In one embodiment, the selectively openable member is a sliding sleeve  216  that may be positioned to selectively block fluid flow. Other types of selectively openable members may be used to allow selective flow from an outside to an inside passageway  212 . Additional selectively openable members may include but are not limited to spring biased members similar to spring biased member  118  shown in  FIG. 7  or may employ a hydraulic system and hydraulic piston similar to the hydraulic system and piston shown in  FIG. 8 , a flapper valve similar to the flapper valve  122  shown in  FIG. 9 , or other types of selectively openable member.  
         [0046]     A shroud  218  surrounds the upper artificial lift device  206 . Shroud  218  defines an annulus  220  between the upper artificial lift device  206  and the shroud  218 . An upper closure member  222  is positioned on an upper end of shroud  218 . The upper closure member  222  preferably has a first electric cable aperture  224  and a second electric cable aperture  226 . A first cable  228  extends down through wellbore  204  through the first electric cable aperture  224  and provides power to the upper artificial lift device  206 . A lower closure member  230  is provided on the lower end of shroud  218 . The lower closure member  230  preferably has an aperture  232  located therein. The upper closure member  222  and the lower closure member  230  seal off ends of annulus  222  and define a sealed annular space  234 .  
         [0047]     A lower artificial lift device  236  is located below the upper artificial lift device  206 . Lower artificial lift device  236  has an input port  238  that it is in communication with wellbore fluids in wellbore  204 . Lower artificial device  236  additionally has an output port  240 . The output port  240  is in communication with the aperture  232  and the lower closure member  230 . Preferably, a passageway  242  communicates the output port  240  of the lower artificial lift device  236  with the annular space  234  by passing through aperture  232  in the lower closure member  230 . Passageway  242  is additionally provided with a lower selectively openable member  246 , which may be of the type described above with respect to upper selectively openable member  214 . A second electric cable  250  extends through the second electric cable aperture  226  in the upper closure member  222 . The second electric cable extends within annular space  234  and provides power to the lower artificial lift device  236 . Second electric cable  250  may also extend through an aperture in lower closure member  230  similar to second electric cable aperture  226  in upper closure member  222 , as required.  
         [0048]     In operation, lower artificial lift device  236  may be provided with intake barriers  100  ( FIGS. 4-9 ) to prevent well fluid from entering into the lower artificial lift device  236 . The intake barriers may be of the type described above in reference to  FIGS. 4-9 . When lower artificial lift device  236  is used as a backup unit, intake ports  238  are provided with intake barriers  100 . Lower selectively openable member  246  is opened to allow output fluid from lower artificial lift device  236  to pass through passageway  242  and into sealed annular space  234 . Upper artificial lift device  206  then is able to draw wellbore fluids in through lower selectively openable member  246  through passageway  242  and into the annular space  234  where the fluids pass into intake port  208  of the upper artificial lift device  206 . The upper artificial lift device  206  then forces wellbore fluids to the surface through passageway  212 .  
         [0049]     If upper artificial lift device  206  fails, or if it is desirable to run lower artificial lift device  236  while using upper artificial lift device  206  as a backup, then upper selectively openable member  214  is opened to allow wellbore fluids to pass therethrough. In this mode of operation, lower artificial lift device  236  intakes wellbore fluids through input ports  238 . The wellbore fluid is driven out of output port  240  and through passageway  242  into the annular space  234  between the shroud  218  and upper artificial lift device  206 . The wellbore fluid then flows past the upper artificial lift device  206  and through the open selectively openable member  214  and through passageway  212  and into tubing  202  where it can pass through the surface. Advantages of the POD system  200  include the ability to install dual or multi-unit systems in well casing having a smaller diameter as compared to multi-unit systems utilizing a junction, as shown in  FIG. 1 . The in-line POD system  200  permits multi-unit installation having larger pumps than does a Y-type multi-unit system in the same diameter of well casing. Additionally, a larger motor may be used for the lower artificial lift device  222  than is used for the upper artificial lift device  206  due to the pressure containment shroud  218 , which surrounds the upper artificial lift device  206 .  
         [0050]     While the invention has been described with a certain degree of particularity, it is understood that the invention is not limited to the embodiment(s) set for herein for purposes of exemplification, but is to be limited only by the scope of the attached claim or claims, including the full range of equivalency to which each element thereof is entitled.