Patent Publication Number: US-11661828-B2

Title: Charging pump for electrical submersible pump gas separator

Description:
CROSS REFERENCE TO RELATED APPLICATION 
     This application claims priority to provisional application Ser. No. 63/001,908, filed Mar. 30, 2020. 
    
    
     FIELD OF THE DISCLOSURE 
     This disclosure relates in general to electrical submersible pump (ESP) assemblies, and in particular to an ESP assembly with a gas separator located between a charge pump and a production pump. 
     BACKGROUND 
     A variety of pumps are used in oil producing wells to pump well fluid to a wellhead assembly at an upper end of the well. The well fluid often comprises water, oil and gas. A typical pump is a centrifugal pump having a large number of stages, each stage having an impeller and a diffuser. Centrifugal pumps have difficulty in pumping well fluids containing a large amount of gas. Gassy well ESP installations often employ a gas separator upstream from the production pump. The gas separator separates some of the gas from the liquid and discharges it into an annulus, typically outside of the production tubing. 
     While these systems work well, in some instances, the intake and discharge flow paths of the gas separator can become inverted, causing the gas separator to cease separating gas from liquid. This may occur due to low pressure of the well fluid flowing into the gas separator. 
     SUMMARY 
     An apparatus for pumping well fluid from a well comprises an electrical submersible pump assembly (ESP) having an electrical motor. A centrifugal production pump driven by the motor has a plurality of production pump stages. The motor also drives a gas separator upstream from the production pump and a centrifugal charge pump upstream from the gas separator. The charge pump has a plurality of charge pump stages and a discharge that leads to an intake of the gas separator. 
     Each of the production pump stages has a higher lifting capacity than each of the charge pump stages. More specifically, each of the production pump stages has an impeller with a vane exit angle relative to a longitudinal axis of the production pump. Each of the charge pump stages has an impeller with a vane exit angle relative to the longitudinal axis of the production pump that is less than the vane exit angle of the impeller of each of the production pump stages. 
     In one embodiment, the assembly includes a string of production tubing with a power cable wet mate device secured to the tubing. A power cable extends alongside an exterior of the tubing and down to the power cable wet mate device. An adapter on an upper end of the assembly couples to a wireline for lowering the assembly into the tubing. An annular seal arrangement seals between the production pump and the tubing. A motor wet mate device on the motor engages the power cable wet mate device. The gas separator secures to a lower end of the production pump, the charge pump secures to a lower end of the gas separator, and the motor is below the charge pump. A first port in the tubing below the wet mate devices directs upward flowing well fluid in the tubing outward into a tubing annulus surrounding the tubing. A second port in the tubing above the wet mate devices directs upward flowing well fluid in the tubing annulus into the tubing and to an intake of the charge pump. A third port in the tubing above the second port and below the annular seal arrangement directs separated gas from the gas separator outward into the tubing annulus. First, second and third sleeve valves may be employed to selectively open and close the first, second and third ports, respectively. 
     In another embodiment, a string of production tubing extends into the well. A power cable coiled tubing adapter on an upper end of the motor connects the assembly to a string of coiled tubing. The production pump is below the motor and has a production pump discharge for discharging well fluid into an assembly annulus in the tubing surrounding the assembly. The gas separator secures to a lower end of the production pump and has a gas separator discharge for discharging separated gas into the assembly annulus. The charge pump secures to a lower end of the gas separator. A seal arrangement seals between the tubing and the production pump below the production pump discharge and above the gas separator discharge. A port in the tubing below the seal arrangement directs separated gas from the gas separator discharge into a tubing annulus surrounding the tubing. Optionally, a sleeve valve may selectively opens and closes the port. 
     In a third embodiment, an outer conduit into which well fluid flows contains the assembly. The production pump has a production pump discharge for discharging well fluid into a string of tubing within the outer conduit. The gas separator has a separated liquid discharge coupled to an intake of the production pump and a separated gas discharge for discharging separated gas into the outer conduit. The charge pump has a charge pump discharge connected to an intake of the gas separator. The motor is within the outer conduit upstream from the charge pump. Optionally, a well fluid gravity separator may be at an upstream end of the charge pump for gravity separating gas from liquid in the well fluid flowing to the charge pump. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIGS.  1 A and  1 B  comprise a schematic side view of a thru-tubing wireline installed ESP installation in accordance with this disclosure. 
         FIG.  2    is an enlarged, partly sectional view of a production pump of the ESP installation of  FIG.  1   . 
         FIG.  3    is an enlarged, partly sectional view of a gas separator of the ESP installation of  FIG.  1   . 
         FIG.  4    is a schematic view of a gas separator charge pump for the ESP installation of  FIG.  1   . 
         FIGS.  5 A and  5 B  comprise a schematic side view of a coiled tubing installed ESP installation in accordance with this disclosure. 
         FIGS.  6 A and  6 B  comprise a schematic side view of an ESP installation for a horizontal well section in accordance with this disclosure 
     
    
    
     DETAILED DESCRIPTION OF THE DISCLOSURE 
     The method and system of the present disclosure will now be described more fully hereinafter with reference to the accompanying drawings in which embodiments are shown. The method and system of the present disclosure may be in many different forms and should not be construed as limited to the illustrated embodiments set forth herein; rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey its scope to those skilled in the art. Like numbers refer to like elements throughout. In an embodiment, usage of the term “about” includes +/−5% of the cited magnitude. In an embodiment, usage of the term “substantially” includes +/−5% of the cited magnitude. The terms “upper” and “lower” and the like bare used only for convenience as the well pump may operate in positions other than vertical, including in horizontal sections of a well. 
     It is to be further understood that the scope of the present disclosure is not limited to the exact details of construction, operation, exact materials, or embodiments shown and described, as modifications and equivalents will be apparent to one skilled in the art. In the drawings and specification, there have been disclosed illustrative embodiments and, although specific terms are employed, they are used in a generic and descriptive sense only and not for the purpose of limitation. 
     Referring to  FIG.  1 A , a well has a conduit  11 , typically casing cemented in place. A wellhead (not shown) supports a string of production tubing  13  in conduit  11 . In this example, a lower portion of tubing  13  has three ports  15 ,  17 , and  19  in its sidewall, spaced axially from each other. Each port  15 ,  17 , and  19  may optionally have a sliding sleeve valve  21  to selectively open and close the port. Sliding sleeve valves  21  may be controlled from the surface, such as by hydraulic lines (not shown). 
     Referring to  FIG.  1 B , a packer  23  seals between tubing  13  and conduit  11  near the lower end of tubing  13 , which is open to receive well fluid. Tubing  13  may have a conventional safety valve  25  and back up valve  27  above the open lower end. Safety valve  25  typically remains open in response to hydraulic fluid pressure in a line (not shown) leading to the wellhead. Back up valve  27  may also be hydraulically actuated. 
     Referring again to  FIG.  1 A , ESP assembly  29  has a production pump  31  with an adapter  33  on its upper end that includes a wireline fishing tool neck. Production pump discharges through adapter  33 . A conventional wireline tool (not shown) on a string of wireline is employed to run and retrieve ESP assembly  29 . The wireline tool releasably engages and disengages from adapter  33 . 
     An annular seal member  35 , which may be of various types, seals between production pump  31  and tubing  13 . Seal member  35  is located above third port  19  in tubing  13 . Seal member  35  may be a type that is lowered through tubing  13  along with ESP assembly  29 , then set, such as by swelling. 
     A gas separator  37  for separating gas or lighter components from liquid or heavier components in the well fluid connects to the lower end of production pump  31 . Gas separator  37  has a separated gas discharge  39  that discharges into an assembly annulus  41  between ESP assembly  29  and tubing  13 . The separated gas is free to flow out third port  19  into a tubing annulus  43  between tubing  13  and conduit  11 . 
     A charge pump  45  has its discharge connected to the intake of gas separator  37 . Charge pump  45  has an intake  47  that receives well fluid flowing up ESP assembly annulus  41 . Charge pump  45  increases the flowing pressure of the well fluid and discharges the well fluid into gas separator  37 . Charge pump  45  is of a type that can more easily handle large amounts of gas than production pump  31 . However, charge pump  45  will have less lifting capacity than production pump  31  for lifting a column of well fluid up tubing  13 . 
     A seal section  49  has an upper end that secures to the lower end of charge pump  45  and a lower end that secures to the upper end of an electrical motor  51 . Motor  51  is typically a three-phase electrical motor filled with a dielectric lubricant. A pressure equalizer, which may be in seal section  49 , reduces a pressure differential between the dielectric lubricant and well fluid on the exterior of motor  51 . Seal section  49  also seals around a drive shaft driven by motor  51  for driving charge pump  45 , gas separator  37  and production pump  31 . 
     A conventional electrical wet mate device (schematically illustrated) has an outer portion  53   a  mounted to tubing  13  and an inner portion  53   b  mounted to motor  51 . An electrical power cable  55  extends from the wellhead alongside tubing  13  down to outer portion  53   a . When running ESP assembly  29 , inner portion  53   b  will slide into electrical engagement with outer portion  53   a , establishing electrical continuity between power cable  55  and the windings of motor  51 . Wet mate portions  53   a ,  53   b  are located above tubing first ports  15  and below tubing second ports  17 . When engaged, wet mate portions  53   a ,  53   b  will restrict or block well fluid from flowing up tubing  13  to charge pump intake  47 . 
     During operation, motor  51  will drive charge pump  45 , gas separator  37  and production pump  31 . As indicated by the solid arrows, well fluid containing gas and liquid flows up the lower end of tubing  13  and out first ports  15  into tubing annulus  43 . The well fluid flows from tubing annulus  43  through tubing second ports  17  into assembly annulus  41 . The well fluid flows from assembly annulus  41  into charge pump intake  47 . Charge pump  45  increases the flowing pressure and discharges all of the well fluid into gas separator  37 . 
     Gas separator  37  separates some of the lighter components, or gas, in the well fluid from liquid or heavier components. Gas separator  37  discharges the gas out separated gas discharge  39  into assembly annulus  41 , as indicated by the dotted arrows. The gas flows from assembly annulus  41  through tubing third ports  19  into tubing annulus  43 . The gas in tubing annulus  43  will migrate upward to the wellhead. Gas separator  37  discharges the heavier components of well fluid into production pump  31 , which pumps that portion out the discharge in adapter  33  into tubing  13  above annular seal  35 , as indicated by the dashed arrow. 
       FIG.  2    illustrates one example of production pump  31  removed from ESP assembly  29 . Production pump  31  has a pump housing  57  containing a rotatable shaft  59  that extends along a longitudinal axis  61  of pump housing  57 . Upper and lower bearings  63  radially support shaft  59 . Production pump  31  is a conventional centrifugal pump with a large number of stages, each stage having an impeller  65  and a diffuser  67 . Impellers  65  and diffusers  67  may be of a variety of types, including mixed flow types, as shown, radial flow types or even axial flow types. The mixed flow type shown has an impeller vane exit angle  69  relative to longitudinal axis  61  that is less than 90 degrees. 
     Production pump  31  has a base or intake  70  at its lower end that directs all of the liquid portions of the well fluid flowing from gas separator  37  ( FIG.  3   ) into pump housing  57 . A splined coupling  71  in base  70  connects production pump shaft  59  to drive shaft  72  of gas separator  37 . 
     Referring to  FIG.  3   , gas separator  37  may be conventional, having a housing  73  in which shaft  72  rotates. Upper and lower bearings  77  provide radial support for gas separator shaft  72 . Gas separator  37  has features to separate gas from liquid in the well fluid. In this example, the separation features include a set of vanes  79  keyed to shaft  72  for rotation in unison. Vanes  79  impart a swirling action to the well fluid, which results in the heavier, more liquefied portions of the well fluid moving outward relative to the axis of shaft  72 . The lighter, more gaseous portions of the well fluid tend to remain more centered, closer to shaft  72 . 
     An optional inducer  81  may be located below vanes  79 . Inducer  81  is a screw pump having a helical flight, similar to an auger, for homogenizing the flow of well fluid toward vanes  79 . Gas separator  37  has an intake or base  83  at its lower end that directs all of the well fluid flowing from charge pump  45  ( FIG.  4   ) into the interior of gas separator housing  73 . Gas separator  37  has a head  85  on its upper end that directs all of the separated liquid portion of the well fluid into production pump base  70  ( FIG.  2   ). 
     A crossover  87  mounted in head  85  directs the lighter or more gaseous components of the well fluid out gas discharge  39 . The heavier or more liquid components flow up head  85  into pump base  70  ( FIG.  2   ). A coupling  89  on the lower end of gas separator shaft  72  connects to a driven shaft (not shown) of charge pump  45  ( FIG.  4   ). 
     Referring to  FIG.  4   , charge pump  45  may be a conventional centrifugal pump with a housing  91  containing a number of centrifugal pump stages. The number of pump stages in charge pump  45  may be the same or less than the number of pump stages in production pump  31  ( FIG.  2   ). Each charge pump stage has an impeller  93  and a diffuser  95 . Impellers  93  have exit angles  97  that are smaller than production pump impeller exit angles  69  ( FIG.  2   ), thus charge pump  45  is more of an axial-flow type pump than production pump  31  ( FIG.  2   ). The flow path in an axial flow pump is more axially directed than a radial flow pump, which directs the flow radially outward with each impeller and radially inward with each diffuser. The flow path is also more axially directed than in a mixed flow pump, which directs the flow outward and upward with each impeller and upward and inward with each diffuser. 
     Referring again to  FIG.  2   , production pump  31  may be a radial type, a mixed flow type as shown, or an axial flow type. A radial type (not shown) discharges well fluid from each impeller  65  approximately radially relative to axis  61 . Thus a radial type has an impeller vane exit angle  69  relative to axis  61  that is near or at 90 degrees, greater than a mixed flow type. An axial flow type, such as illustrated by charge pump  45  ( FIG.  4   ), has even a smaller exit angle  97  relative to axis  61  than exit angle  69  ( FIG.  2   ) of a mixed flow type impeller. The greater radial exit angle  69  creates more lifting capacity than the smaller exit angle  97  to lift a column of well fluid. On the other hand, the smaller impeller exit angles  97  of charge pump  45  allows it to better pass through large volumes of gas than production pump  31 . 
     Charge pump  45  can thus more efficiently pump well fluid containing a high gas percentage than production pump  31 . However, each stage in charge pump  45  creates less pressure or lifting capability than each stage of production pump  31 . As an example only, each stage of production pump  31  may have 1.5 to 2.0 times the lifting capability of each stage of charge pump  45 . Stated another way, each stage of charge pump  45  may be capable of lifting 20-30 feet of a column of water, while each stage of production pump  31  may be capable of lifting 40-60 feet of a column of water. Correspondingly, and as an example only, charge pump  45  may be capable of efficiently pumping well fluid containing up to 60% of gas while production pump  31  may be capable of efficiently pumping well fluid containing only up to about 40% of gas. The flow pressure applied by charge pump  45  makes gas separator  37  more efficient in separating gas from liquid. 
       FIGS.  5 A and  5 B  show a first alternate embodiment. The well has a string of outer conduit or casing  99 , which may be cemented in the well. A wellhead (not shown) suspends a string of production tubing  101  within casing  99 . Tubing  101  creates a tubing annulus  103  between tubing  101  and outer conduit  99 . Tubing  101  has a tubing port  105  in its sidewall communicating its interior with tubing annulus  103 . A sliding sleeve valve  107  may be mounted to tubing  101  for opening and closing tubing port  105 . Sliding sleeve valve  107  may have a hydraulic line (not shown) leading down from the wellhead to actuate sliding sleeve valve  107 . The lower end of tubing  101  stabs into a packer  109  that seals tubing  101  to outer conduit  99 . Well fluid flows into the open lower end of tubing  101 , as indicated by the solid arrow. 
     An ESP assembly  111  within tubing  101  has an electrical motor  113  with an adapter  115  on its upper end that connects to a string of power cable coiled tubing  117 . Power cable coiled tubing  117  is a conventional type comprising flexible steel tubing containing an electrical power cable with power conductors for each phase of the three phases of motor  113 . 
     A seal section  119  connects to the lower end of motor  113  for sealing around a drive shaft rotated by motor  113 . Seal section  119  also reduces a pressure difference between dielectric lubricant in motor  113  and well fluid on its exterior. 
     A production pump  121  has an upper end that connects to the lower end of seal section  119 . Production pump  121  may be the same as production pump  31  ( FIG.  2   ), except that it has a well fluid discharge  123  that discharges outward into an assembly annulus  125  located between ESP assembly  111  and tubing  101 . 
     Production pump  121  has a tubular seal member  127  on its lower end that has an exterior surface configured to slide into and seal with an upper polished bore receptacle  129  mounted in tubing  101 . The drive shaft assembly extending from motor  113  through seal section  119  and production pump  121  also extends through seal member  127 . Seal member  127  could be an integral portion of the housing of production pump  121 . 
     A rotary driven gas separator  131  secures to the lower end of seal member  127 . Gas separator  131  may be the same as gas separator  31  of  FIG.  2   . Gas separator  131  has a gas discharge  133  that directs separated gas into assembly annulus  125 . Tubing ports  105  are located below polished bore receptacle  129  and either above or aligned with gas discharge  133 . Thus, separated gas flowing out of gas discharge  133  flows out tubing ports  105  into tubing annulus  103 , indicated by the dotted arrows. 
     A charge pump  135 , which may be the same as charge pump  45  ( FIG.  4   ), connects to the intake of gas separator  133 . Referring to  FIG.  5 B , a seal member or stack  137  on the lower end of charge pump  135  slides into and seals within a lower polished bore receptacle  139 , which may be a part of packer  109 . Seal stack  137  is a tubular member with an open lower end for flowing well fluid into charge pump  135 , as indicated by the solid arrow. 
     During installation of ESP assembly  111 , power cable coiled tubing  117  will be deployed by a coiled tubing injector (not shown) at the wellhead. Seal member  127  slides into sealing engagement with upper polished bore receptacle  129 . Seal stack  137  slides into sealing engagement with lower polished bore receptacle  139 . 
     When power is supplied to the conductors in power cable coiled tubing  117 , motor  113  will drive production pump  121 , gas separator  131  and charge pump  135 . Charge pump  135  draws in a well fluid mixture of liquid and gas, as indicated by the solid arrow, and discharges the mixed phase well fluid at an increased flowing pressure into gas separator  131 . Gas separator  131  separates lighter components from heavier and discharges the lighter components out gas discharge  133 , as indicated by the dotted arrows. The gaseous components flow through tubing ports  105  and up tubing annulus  103  to the wellhead. Gas separator  131  discharges the heavier components into production pump  121 , which increases the flowing pressure and discharges the heavier components out discharge  123  into ESP assembly annulus  125 , as indicated by the dashed arrows. 
       FIGS.  6 A and  6 B  illustrate a third embodiment, which particularly applies to SAGD (steam assisted gravity drainage) wells. Outer conduit  141  is a casing or the like tubular that has a generally horizontal section containing apertures in its sidewall for steam to be injected into outer conduit  141  to reduce the viscosity of the hydrocarbon flowing into it. A production pump  143  has a discharge  145  connected to a string of production tubing (not shown). A gas separator  147  connects to the intake of production pump  143  for delivering liquid well fluid. Gas separator  147 , which may be the same as gas separator  37  ( FIG.  3   ), has a gas discharge  149  that discharges more gaseous components into outer conduit  141 . 
     A charge pump  151 , which may be the same as charge pump  45  ( FIG.  4   ), pressurizes and discharges well fluid into the intake of gas separator  147 . An optional gravity type of separator  153  may be connected to the intake of charge pump  151 . Gravity separator  153  is a conventional device used in SAGD installations. It includes a tubular member with slots  154  and an internal blocking member (not shown). The internal blocking member has an counterweight that causes it to block slots  154  located on the lower side of gravity separator  153  and open those on the upper side. Well fluid containing gas and liquid flows into gravity separator  153 , as indicated by the solid arrow. Gas that separates by gravity from the well fluid flowing into gravity separator  153  can flow out the open outlet slots  154  on the upper side, as indicated by the dotted arrow. Liquid flows from gravity separator  153  into the intake of charge pump  151 . 
     A seal section  155  connects to the intake end of gravity separator  153 . In this example, a second seal section  157  is connected in tandem with seal section  155 . An electric motor  159  connects to the upstream seal section  157 . Seal sections  155 ,  157  reduce a pressure differential between dielectric lubricant in motor  159  and well fluid on the exterior of motor  159 . The power cable (not shown) extends alongside the production tubing to motor  159 . Centralizers  161  may be at the upstream end of motor  159  and along the length of the ESP assembly. 
     Charge pump  151  operates in the same manner as in the other embodiments by applying a charging pressure to the intake of gas separator  147 . Gas separator  147  operates more efficiently as a result in supplying separated liquid to production pump  143 . Charging pump  151  reduces the tendency for well fluid flowing along outer conduit  141  around motor  159  to enter into gas separator discharge  149  instead of the intake of gas separator  147 . 
     While only three embodiments of the disclosure have been given for purposes of disclosure, numerous changes exist in the details of procedures for accomplishing the desired results. These and other similar modifications will readily suggest themselves to those skilled in the art, and are intended to be encompassed within the scope of the appended claims.