Abstract:
A centrifugal pump assembly for a well is lowered into the well on a string of tubing. A packer mounts to the pump assembly below an intake of the pump and is lowered in with the pump assembly. The packer is radially expansible to seal against the casing in the well. A conduit leads from the pump assembly to the packer for diverting a portion of the well fluid being pumped through the pump assembly. This pressurized fluid causes the packer to expand and seal against casing.

Description:
FIELD OF THE INVENTION 
   This invention relates in general to well pumps, and in particular to an electrical submersible pump assembly with a packer that actuates in response to pump pressure. 
   BACKGROUND OF THE INVENTION 
   One type of electrical submersible pump assembly for oil wells includes a centrifugal pump that is coupled to an electrical motor. The pump has a large number of stages of impellers and diffusers. Normally, the pump assembly is lowered into the well on a string of tubing and, during operation, discharges the well fluid up through the tubing to the surface. The well fluid flows through perforations, past the electrical motor for cooling, and then enters the intake of the pump. 
   Often the well fluid is made up of water, oil and gas. Gas entrained in the well fluid may have a damaging effect on the ability of the pump to pump the well fluid. Significant amounts of gas or a gas slug can cause the pump to gas lock. A number of methods have been developed to re-route the gas so that it passes the pump intake. In one technique, a gas separator is installed in the pump assembly below the intake and above the motor for separating gas before entering the pump. A common type of gas separator has a rotating vane that separates gas from liquid by centrifugal force. Normally the gas flows to the annulus in the casing, and the remaining liquid portion of the well fluid flows up into the intake of the pump. 
   A number of other systems have been proposed to reroute the well fluid so that the gas passes the pump intake. In some techniques, a packer is set in the casing to isolate the separated gas from the well fluid being drawn into the intake. Usually, the packer is set in advance by a conventional method, then the pump assembly is lowered into the well, and a stinger on the lower end stabs into the packer. 
   SUMMARY OF THE INVENTION 
   In this invention, a packer is mounted to and lowered into the well with the pump assembly. The packer is radially expansible from a retracted position to an expanded position. A conduit leads from the pump assembly to the packer for delivering a portion of the well fluid flowing through the submersible pump assembly while the pump is operating. This diverted portion of the well fluid flows to the packer and causes the packer to move to the expanded position. Shutting off the pump causes the packer to return to the retracted position. 
   Preferably, the packer is located below an intake of the pump assembly. A bypass passage extends through the packer. A riser extends upward from the bypass passage and has an upper end above an intake of the pump assembly. The well fluid flowing from the perforations flows up the bypass passage and the riser tube, then down to the intake of the pump. As the well fluid turns from the upward flowing direction to the downward flowing direction, gas separates from the liquid by gravity separation. 

   
     BRIEF DESCRIPTION OF DRAWINGS 
       FIG. 1  is an elevational view of a submersible pump assembly having a packer constructed in accordance with the invention. 
       FIG. 2  is an enlarged elevational view of the packer of  FIG. 1 , shown in a retracted position. 
       FIG. 3  is an enlarged elevational view of the packer of  FIG. 1 , shown in an expanded position. 
       FIG. 4  is a partial sectional view of an alternate embodiment of a packer in accordance with this invention. 
   

   DETAILED DESCRIPTION OF THE INVENTION 
   Referring to  FIG. 1 , well  11  has a casing  13  that is cemented in place. Perforations  15  in casing  13  admit well fluid into casing  13 . A string of production tubing  17  is lowered into casing  13 . Tubing  17  may be made up of individual sections of pipe screwed together, or it may comprise continuous coiled tubing. 
   An electrical submersible pump assembly  19  is suspended on the lower end of tubing  17 . Pump assembly  19  in this embodiment includes an upper pump  21 . Upper pump  21  is preferably a conventional centrifugal pump having a number of pump stages  23 , shown schematically by the dotted lines. Each pump stage  23  comprises an impeller and a diffuser (not shown). Alternately, upper pump  21  could comprise a different type of pump, such as a progressing cavity pump. 
   A lower pump  25  is mounted below upper pump  21 . Lower pump  25  is also conventional, and has at least one stage  27  having an impeller and a diffuser. Upper pump  21  preferably has many more stages  23  than the stages  27  of lower pump  25 . Lower pump  25  has an intake  29  to admit well fluid. A tandem connector  31  connects the discharge of lower pump  25  to the intake of upper pump  21 . Well fluid flowing into lower pump intake  29  will thus pass through lower pump  25  and into upper pump  21 . 
   Lower pump  25  and upper pump  21  could alternately be a single integral pump, with lower pump  25  merely comprising a lower portion of upper pump  21 . Furthermore, lower pump  25  could be a rotary gas separator with an inducer stage. An inducer stage of a rotary gas separator is actually a pump stage, thus this type of gas separator, if used, would not only separate liquid and gas by centrifugal force, but would also increase pressure due to the inducer stage. 
   A packer  33  is mounted to pump assembly  19  below intake  29 . Packer  33  in one embodiment has a packer body  35  as shown in  FIG. 2 . Packer body  35  could be an integral portion of the lower end of lower pump  25 . An elastomeric hose  37  is wrapped with multiple turns around body  35 . Hose  37  is inflatable and is shown in the contracted position in  FIG. 2 . The lower end of hose  37  is sealed, and the upper end connects to a conduit  39 . Conduit  39  leads to a portion of pump assembly  19  for supplying well fluid under an increased pressure over the hydrostatic pressure surrounding hose  37 . 
   In the preferred embodiment, as shown in  FIG. 1 , conduit  39  taps into the uppermost stage  27  of lower pump  25 . The uppermost stage  27  is actually an intermediate stage between the lowest stage  27  in lower pump  25  and the highest stage  23  in upper pump  21 . The pressure of the well fluid flowing through lower pump  25  and upper pump  21  increases with each stage  27  and  23 . Consequently, the pressure at the uppermost stage  27  of pump  25  will be elevated above the intake  29  pressure, which is approximately the hydrostatic pressure at packer  33 , and be below the discharge pressure of upper pump  21 . This increased pressure causes hose  37  to inflate and seal against casing  13  as shown in  FIG. 3 . 
   Packer body  35  preferably has a bypass passage  41  that extends through it from its lower end to its upper end. Bypass passage  41  is preferably located in a laterally protruding portion of packer body  35 , thus in this example, packer body  35  is eccentric. This laterally protruding portion extends farther outward from the outer diameter of the lower end of pump  25 . A riser tube  43  extends into bypass passage  41  for allowing well fluid from perforations  15  ( FIG. 1 ) to flow up riser tube  43 . 
   As shown in  FIG. 1 , the upper end of riser tube  43  is spaced a considerable distance above pump intake  29 . In the embodiment shown, the upper end of riser tube  43  is located above the upper end of upper pump  21 . With packer  33  in the sealed position of  FIG. 3 , all of the well fluid flowing into intake  29  ( FIG. 1 ) must first flow along the communication path of bypass passage  41  and riser tube  43 , then back downward to intake  29 , as indicated by the solid arrows. The dotted arrows indicate that a significant portion of the gas will separate from the liquid at the upper end of riser tube  43  and continue up casing  13 . 
   Referring again to  FIG. 1 , pump assembly  19  has a conventional seal section  45  and an electrical motor  47 . The upper end of seal section  45  connects to the lower end of packer body  35 , and packer body  35  could be integrally formed on seal section  45 . Motor  47  has a rotating shaft (not shown) that is coupled to a shaft in seal section  45 . The shaft in seal section  45  extends through packer body  35  and couples to a shaft in lower pump  25  for driving lower pump  25 . The shaft in lower pump  25  is coupled to a shaft in upper pump  21  for driving upper pump  21 . Motor  47  and seal section  45  are filled with a dielectric lubricant. Seal section  45  has a movable barrier for communicating hydrostatic pressure to the lubricant. Having the lubricant at approximately hydrostatic pressure reduces pressure differential across the seal around the shaft of seal section  45 . A power cable  49  extends alongside production tubing  17  to motor  47 . 
   In the operation of the first embodiment, packer  33  is assembled with pump assembly  19  and lowered into the well on tubing  17 . The operator supplies power to motor  47  to drive pumps  25  and  21 . Well fluid flows into intake  29 . For a short duration upon start up, some of the well fluid may be drawn upward from perforations  15  and some from the annulus surrounding pumping assembly  19  above packer  33 . Pump stages  27  and  23  increase the pressure of the well fluid as it flows up pumps  25 ,  21  into tubing  17 . A portion of the well fluid is diverted into conduit  39 , which causes hose  37  to inflate, as shown in  FIG. 3 , and seal against casing  13 . Once inflated, all of the well fluid from perforations  13  must flow up riser tube  43 . Packer  33  will remain in the expanded position as long as pump assembly  19  is operating. 
   Most of the gas contained in the well fluid is separated by gravity at the upper end of riser tube  43 . This reduces the quantity of gas flowing into intake  29 , and particularly avoids large quantities of gas or gas slugs from entering intake  29 . For a well producing moderate quantities of gas, it would not be necessary to employ a rotary gas separator. 
     FIG. 4  illustrates an alternate embodiment. Packer  51  has a body  52 . An annular bladder  53  surrounds body  52 . Conduit  55 , which leads from lower pump  25  ( FIG. 1 ), communicates with the interior of bladder  53 . In the example shown, a passage  57  leads through body  52  from conduit  55  to the interior of bladder  53 . The fluid pressure causes bladder  53  to expand to the sealing position shown. 
   Packer  51  also has a bypass passage  59 . A riser tube  61  extends upward from passage  59  for delivering well fluid. Although not shown, packer  51  also has a central passage through which a shaft from seal section  45  extends, as in the first embodiment. Packer  51  operates in the same manner as first embodiment packer  33 . 
   The invention has significant advantages. The packer is set without requiring any additional trips into the well. The packer is run on the same trip as the pump assembly. The packer seals to the casing only when required, which is when the pump assembly is operating. The packer releases each time the pump ceases to operate, thus requires no special tools or manipulation when pulling the pump for maintenance. The packer facilitates gas separation by using a riser tube to gravity separate the gas from the liquid at a point above the intake to the pump. 
   While the invention has been shown in only two of its forms, it should be apparent to those skilled in the art that it is not so limited but is susceptible to various changes without it departing from the scope of the invention.