Abstract:
A tandem progressive cavity pump system lifts well fluids from a production zone to a well surface. The system provides a first pump and a second pump. The system positions the first pump at the production elevation within the well, and the second pump at an intermediate elevation within the well. The system then connects a discharge of the first pump to an intake of the second pump. The system is then operated so that the first pump lifts well fluids from the production zone to the intermediate zone, depositing the well fluids in the intake of the second pump. The second pump then lifts the well fluids from the intermediate zone to the surface of the well.

Description:
BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     This invention relates in general to fluid production systems and, in particular, to fluid production systems using tandem progressive cavity pumps. 
     2. Brief Description of Related Art 
     In some well completions, use of progressive cavity pumps, or progressing cavity pumps (PCPs), is preferred to produce well fluids from the completed well to the surface. The PCPs are suspended within a production zone on a string of tubing and operated to lift well fluid to the surface. PCPs may be preferred in part because they operate at lower speeds. Lower speed operation provides a costs savings due to the ability of the PCP to operate with standard equipment rather than heavily overbuilt equipment. Lower operating speeds also allow the PCPs to operate for longer periods of time without repairs or replacement. Still further, the lower operating speeds allow PCPs to handle well fluids with suspended solid matter better than other pumping systems. This is also a result of the PCP pumping mechanism which moves the fluid through the pump without flinging it against the pump stator. This decreases the stress on the pump during operation. In addition, it prevents damage to the pump caused by the impact of suspended solids on the pump housing that may cause pitting and eventual pump leakage. 
     Unfortunately, PCPs are unable to overcome as much head as other pump types, such as electric submersible pumps (ESPs). ESPs are typically centrifugal type pumps. Because of this, PCPs may not be used in well completions where the production zone is beyond 5,000 to 7,000 feet from the well surface. In those instances, other pump types capable of producing the well fluid to the surface, beyond the 5,000 to 7,000 feet range, must be used. This can lead to problems when the pumped fluid has a high suspended fluid content. While it is possible to use non-PCPs in wells having a high content of suspended solid matter in the well fluids, the pumps are likely to need repair and replacement at more frequent intervals. This is a result of the higher operating speeds and pumping mechanisms that may fling the suspended solids against the pump housing. More frequent repair and replacement increases the costs of production. As the time costs and production costs to continually repair or replace the downhole pump increase, the areas in which hydrocarbons may be feasibly developed are diminished due to decreased profitability margins for the well. Therefore, there is a need for a PCP that can lift well fluids beyond the standard 5,000 to 7,000 feet, thus avoiding use of ESPs. 
     SUMMARY OF THE INVENTION 
     These and other problems are generally solved or circumvented, and technical advantages are generally achieved, by preferred embodiments of the present invention that provide a tandem progressive cavity pumping system. 
     In accordance with an embodiment of the present invention, a method for producing hydrocarbons from a well is disclosed. The method provides a first pump and a second pump. The method then positions the first pump at a first elevation within the well, and the second pump at a second elevation within the well. The method then connects a discharge of the first pump to an intake of the second pump and operates the first and second pumps so that hydrocarbons may be produced to a surface of the well. 
     In accordance with another embodiment of the present invention, a fluid production system for a well is disclosed. The system includes an upper string of conduit leading from a wellhead to a first pump. The first pump is at a first elevation within a wellbore at a lower end of the upper string of conduit. The first pump has a first pump intake and a first pump discharge so that fluid flows from the first pump discharge through the upper string of conduit when the first pump operates. The system also includes a second pump at a second and lower elevation within the wellbore. The second pump has a second pump intake and a second pump discharge. A lower string of conduit leads from the intake of the first pump at the first elevation to the discharge of the second pump at the second elevation. This allows fluid to flow from the second pump discharge to the first pump intake through the lower string when the second pump operates. 
     In accordance with yet another embodiment of the present invention, a well fluid production system is disclosed. The well fluid production system includes a rod driven progressive cavity pump (RDPCP) at a first elevation, and a progressive cavity pump with a downhole electric motor (ESPCP) at a second elevation that is lower than the first elevation. An intake of the RDPCP connects to a discharge of the ESPCP so that the RDPCP is in the flow line of the ESPCP. This causes well fluids lifted by the ESPCP to discharge at the intake to the RDPCP, and the RDPCP to lift the well fluid from the discharge of the ESPCP to the surface. 
     An advantage of a preferred embodiment is that it provides a pumping system utilizing progressive cavity pumps. The disclosed progressive cavity pumping system is capable of pump lift greater than the standard pump lift of prior art progressive cavity pumps. This allows the progressive cavity pumping system to be disposed at greater wellbore depths than previous progressive cavity pumping systems. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       So that the manner in which the features, advantages and objects of the invention, as well as others which will become apparent, are attained, and can be understood in more detail, more particular description of the invention briefly summarized above may be had by reference to the embodiments thereof which are illustrated in the appended drawings that form a part of this specification. It is to be noted, however, that the drawings illustrate only a preferred embodiment of the invention and are therefore not to be considered limiting of its scope as the invention may admit to other equally effective embodiments. 
         FIG. 1  is schematic representation of a portion of a fluid production system in accordance with an embodiment of the present invention. 
         FIG. 2  is a schematic representation of additional components of the fluid production system of  FIG. 1 . 
     
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT 
     The present invention will now be described more fully hereinafter with reference to the accompanying drawings which illustrate embodiments of the invention. This invention may, however, be embodied 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 the scope of the invention to those skilled in the art. Like numbers refer to like elements throughout, and the prime notation, if used, indicates similar elements in alternative embodiments. 
     In the following discussion, numerous specific details are set forth to provide a thorough understanding of the present invention. However, it will be obvious to those skilled in the art that the present invention may be practiced without such specific details. Additionally, for the most part, details concerning well drilling, drilling rig operation, well completion, and the like have been omitted inasmuch as such details are not considered necessary to obtain a complete understanding of the present invention, and are considered to be within the skills of persons skilled in the relevant art. 
     Referring to  FIG. 1 , a well having a casing string  11  disposed within the well is shown. Casing  11  may be perforated at a lower end for allowing well fluid to enter. An electric submersible progressive cavity pump or progressing cavity pump assembly (ESPCP)  13  is disposed within casing  11  at the end of a first tubing string  15 . ESPCP  13  may include an electric motor  17 , a seal section  19 , a gear box  21 , and a pump  23 . A flexshaft  25  may extend from motor  17  through seal section  19  and gear box  21  to pump  23 . There flexshaft  25  may couple to an ESPCP rotor  29  positioned within ESPCP stator  31 . ESPCP rotor  29  may rotate in response to rotation of flexshaft  25  causing fluid to enter pump  23  and be moved downstream through tubing string  15 . A power cable  18  may run from the surface of the well to electric motor  17  to provide voltage to motor  17  for operation of ESPCP  13 . Power cable  18  runs alongside tubing string  15 . 
     First tubing string  15  may extend from a discharge of ESPCP  13  to an intake of a rod driven progressive cavity pump or progressing cavity pump assembly (RDPCP)  33 . RDPCP  33  may include an RDPCP stator  35  and an RDPCP rotor  37 . RDPCP stator  35  may couple to an upper end of first tubing string  15  such that fluid flow downstream through first tubing string  15  may flow into the intake of RDPCP  33 . RDPCP stator  35  may have a lower end that is open to first tubing string  15  so that RDPCP stator  35  is in the flow line of ESPCP  13 , i.e. fluid in first tubing string  15  may flow directly into RDPCP stator  35 . A person skilled in the art may understand that tubing string  15  may be quite long, upwards of several thousand feet. In the illustrated embodiment, first tubing string  15  may be as long as 7,000 feet. A second string of tubing  39  may couple to the discharge of RDPCP  33  and extend to a surface. Well fluids may flow from RDPCP  33  to the surface through second string of tubing  39 . RDPCP  33  may include RDPCP rotor  37  positioned within and configured to rotate within RDPCP stator  35  to move fluids through RDPCP  33 . A drive rod  41  may couple to RDPCP rotor  37  and extend to the surface of the well. There, drive rod  41  may further couple to a motor, such as an electric engine or combustion engine, adapted to rotate drive rod  41 . 
     Referring to  FIG. 2 , drive rod  41  may extend to the surface of the well where drive rod  41  may be coupled to a drive head  43 . A person skilled in the art may understand that drive rod  41  may comprises multiple shafts coupled together so that each shaft may rotate in response to rotation of the previous shaft. Drive head  43  may include a bearing box and an electric motor. Drive head  43  may be positioned in any suitable manner such that operation of the electric motor within drive head  43  may cause rotation of drive rod  41 . Drive head  43  may include any suitable motor, such as a gas powered or electric motor. As drive head  43  causes rotation of drive rod  41 , drive rod  41  may, in turn, rotate RDPCP rotor  37  within RDPCP stator  35 . 
     As well operations move from completion to production, ESPCP  13  may be lowered into casing  13  to a production zone  45 . Production zone  45  may be at a significant depth within the well, perhaps up to 14,000 feet. ESPCP  13  may not have sufficient pumping head to produce fluids from production zone  45  to the surface of the well. As ESPCP  13  is lowered into the well, first tubing string  15  may be coupled to and run into the well so that ESPCP  13  may move well fluids downstream through first tubing string  15 . After running first tubing string  15  in for a sufficient length, such as 5,000 to 7,000 feet, RDPCP stator  35  may be coupled to a downstream end of first tubing string  15  opposite ESPCP  13 . Second tubing string  39  may then be coupled to RDPCP stator  35  opposite ESPCP  13 . Second tubing string  39  may be run into casing  11  until ESPCP  13  is at production zone  45 , and RDPCP  33  is at an intermediate zone  47  within the well. Second string of tubing  39  may be hung from a tubing hanger so that RDPCP  33  and ESPCP  13  are suspended within casing  11 . Following landing and setting of second string of tubing  39 , RDPCP rotor  37  may be run into the well on drive rod  41  and landed on a tag bar  36 . Tag bar  36  may be mounted to RDPCP stator  35  or first string of tubing  15  so that when RDPCP rotor  37  lands on tag bar  36 , RDPCP rotor  37  may be positioned within RDPCP stator  35 . Drive rod  41  may then be coupled to drive head  43 . 
     In operation, ESPCP  13  may operate through electrical power to lift well fluids from production zone  45  to intermediate zone  47 . There, the well fluids lifted by ESPCP  13  may discharge into the intake of RDPCP  33 . RDPCP  33  may then operate to lift the well fluids from intermediate zone  47  to the surface of the well. In this manner, well fluids may be lifted from the well from depths greater than the maximum pumping lift of the progressive cavity pump (PCP) located in the production zone at the bottom of the well. A person skilled in the art may understand that the present invention may be modified to utilize alternative pump types in the positions of ESPCP  13  and RDPCP  33 . The disclosed embodiments contemplate and include such modifications. 
     Accordingly, the disclosed embodiments provide numerous advantages. For example, the disclosed embodiments provide a pumping system that allows for use of PCP pumps at depths greater than the maximum pumping head of modern PCP pumps. This is advantageous because the PCP pumps are more forgiving and can produce fluids with suspended solid matter with less wear and tear to the pump. In turn, this allows for longer life of the PCP and, consequently, longer and lower-cost production periods from the well. 
     It is understood that the present invention may take many forms and embodiments. Accordingly, several variations may be made in the foregoing without departing from the spirit or scope of the invention. Having thus described the present invention by reference to certain of its preferred embodiments, it is noted that the embodiments disclosed are illustrative rather than limiting in nature and that a wide range of variations, modifications, changes, and substitutions are contemplated in the foregoing disclosure and, in some instances, some features of the present invention may be employed without a corresponding use of the other features. Many such variations and modifications may be considered obvious and desirable by those skilled in the art based upon a review of the foregoing description of preferred embodiments. Accordingly, it is appropriate that the appended claims be construed broadly and in a manner consistent with the scope of the invention.