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BACKGROUND 
   In a variety of subterranean environments, submersible pumping systems are used in the production of hydrocarbon based fluids or other types of fluids. A relatively narrow wellbore is drilled, and the pumping system is deployed into the wellbore via, for example, a suspension cable or deployment tubing. Depending on well parameters, the production of fluid, e.g. oil, can be limited by the available horsepower from a given submersible motor or motors used to drive a submersible centrifugal pump. Available horsepower is limited because horsepower generated by the system is transferred through a single shaft to the pump. Due to diameter restrictions, use of a larger shaft to accommodate greater horsepower would require space needed by the centrifugal pump to maintain pumping efficiency. 
   Sometimes, tandem installations are deployed downhole to increase the production rate. For example, a Y-tool can be used to suspend two electric submersible pumping systems that are offset from each other. However, the offset equipment limits the size of the systems that can be placed into a particular wellbore. 
   SUMMARY 
   In general, the present invention provides a submersible pumping system for use in movement of a fluid from one location to another. For example, the fluid may be moved from a wellbore to a collection point. The submersible system utilizes at least a pair of electric submersible pumping systems in a space efficient package that enables substantially increased, e.g. doubled, power output within a wellbore of a given size. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
     Certain embodiments of the invention will hereafter be described with reference to the accompanying drawings, wherein like reference numerals denote like elements, and; 
       FIG. 1  is a front elevational view of a submersible pumping system, according to an embodiment of the present invention; 
       FIG. 2  is a schematic illustration of one embodiment for coupling the upper electric submersible pumping system to the lower electric submersible pumping system illustrated in  FIG. 1 ; 
       FIG. 3  is another embodiment of the submersible pumping system illustrated in  FIG. 1 ; and 
       FIG. 4  is another embodiment of the submersible pumping system illustrated in  FIG. 1 . 
   

   DETAILED DESCRIPTION 
   In the following description, numerous details are set forth to provide an understanding of the present invention. However, it will be understood by those of ordinary skill in the art that the present invention may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible. 
   The present invention generally relates to fluid production equipment and related methods. The equipment and methods are useful in, for example, the production of hydrocarbon based fluids, such as oil, from subterranean locations. However, the equipment and methods of the present invention are not limited to those fluids and locations. For example, the system can be used in non-oilfield applications, such as mine dewatering, supplying potable water, water injection, waste fluid disposal and other applications. 
   The embodiments described are amenable, for example, to use in a high horsepower system. As the power is increased in an electric submersible pumping system, the horsepower capacity of the shaft that runs through the system becomes inadequate. In the following embodiments, multiple systems are used in tandem while remaining mechanically independent, i.e. the drive shafts of the multiple systems are not coupled to each other. Thus, the benefit of greater system horsepower is achieved without the problems associated with a single drive shaft. 
   Referring generally to  FIG. 1 , a submersible pumping system  10  is illustrated, according to an embodiment of the present invention. The overall system  10  may be deployed in a wellbore  12  extending to a given subterranean formation  14 . Subterranean formation  14  typically contains a desired fluid  16 , such as oil, that flows into wellbore  12  for production to a desired location, e.g. the surface of the Earth, via pumping system  10 . In many applications, wellbore  12  is lined with a liner or casing  18  and perforations  20  are formed through the casing to enable the flow of fluid from subterranean formation  14  into wellbore  12 . 
   In the embodiment illustrated, pumping system  10  comprises a plurality of electric submersible pumping systems, such as a first electric submersible pumping system  22  and a second electric submersible pumping system  24 . In this embodiment, the first electric submersible pumping system  22  is a downstream system, e.g. an upper system, and the second electric submersible pumping system  24  is an upstream system, e.g. a lower system in the application illustrated. It should be noted that additional electric submersible pumping systems can be added, but a pair of systems  22 ,  24  is illustrated to facilitate explanation of system operation. 
   Although each electric submersible pumping system may comprise a variety of components depending on the specific application, the embodiments illustrated show basic components that are utilized in typical electric submersible pumping systems. In the embodiment of  FIG. 1 , first electric submersible pumping system  22  is an inverted system, sometimes referred to as a bottom intake electric submersible pumping system. In this type of system, a submersible motor or motors  26  drive a submersible pump  28  located upstream, e.g. below, motors  26 . A motor protector  30  may be positioned between motors  26  and pump  28 . By way of example, one, two or three motors  26  can be used to run one, two or three connected pumps  28 . 
   On the other hand, electric submersible pumping system  24  is a conventional system, i.e. not an inverted system. The example illustrated comprises a submersible motor  32  that powers a submersible pump  34  disposed downstream, e.g. above, motor  32 . As with pumping system  22 , power may be provided by a plurality of motors  32 , such as the tandem motors  32  illustrated. Also, one, two or three connected motors  32  can be used to run one, two or three connected pumps  34 . A motor protector  36  is deployed between motors  32  and pump  34 . In some applications, the systems can be run with a gas handler (compressor) or a gas separator if there is sufficient gas in the downhole formation. 
   Upper system  22  and lower system  24  are powered independently by power cables  38  and  39  connected to drives  40  and  41 , respectively, e.g. surface drives. In the embodiment illustrated, the two systems are electrically independent. The total power available to pumping system  10  is shared between the two electric submersible pumping systems. However, both electric submersible pumping systems may be powered simultaneously by a single cable  38  extending from a single drive, such as drive  40 . Alternatively, a single drive, such as drive  40 , can run power through a split cable extending into the well to a motor of each system. In this latter configuration, a switch (not shown) can be placed in each line after the split from drive  40 . Each switch may contain a motor controller that allows the electric submersible pumping systems to be started and shutdown individually. Thus, the switches are able to provide independent motor protection to each electric submersible pumping system even though the systems are powered by the same drive. 
   As explained more fully below, upper system  22  and lower system  24  also are mechanically independent. In other words, although the two systems may be physically connected, the operation of one electric submersible pumping system is not tied to operation of the other by, for example, a common shaft. The two systems are, however, hydraulically connected in the sense that submersible pump  34  of system  24  delivers fluid to submersible pump  28  of system  22 . 
   In one mode of operation, second electric submersible pumping system  24  is initially started, and first electric submersible pumping system  22  is started thereafter. Pumping system  24  draws fluid  16  along wellbore  12  to a pump intake  42  of submersible pump  34 . By way of example, submersible pump  34  may comprise a centrifugal style pump. Regardless of pump type, fluid  16  is moved through submersible pump  34  and discharged through a pump discharge  44 . The discharged fluid is directed to a pump intake  46  of submersible pump  28 , e.g. a centrifugal pump. Because the illustrated pumping system  22  is a bottom intake electric submersible pumping system, fluid  16  is discharged from pump  28  through a fluid discharge end  48  for routing around, e.g. along, motor protector  30  and motors  26 . (It should be noted that when the motors are sequentially started, the non-operating system may turn as fluid is forced through the system by the operating pump. Therefore, it may be beneficial if the motor controller associated with the drive of the non-operating system has the capability of “catching a spinning motor” to facilitate starting of the motor. This functionality is present in a variety of available motor controllers.) 
   In the embodiment illustrated, fluid  16  moves from fluid discharge  48  into a shroud  50  which, in turn, guides the fluid along the exterior of pumping system  22  to a fluid inlet  52  disposed in a tubing  54 . Tubing  54  may comprise production tubing, coiled tubing or other types of tubing for conducting fluid  16  to a desired location, such as a collection point. Tubing  54  also can be used to suspend electric submersible pumping systems  22 , 24  within, for example, a wellbore. Fluid inlet  52  is disposed at a downstream location with respect to first electric submersible pumping system  22 . Shroud  50  may be sealed around tubing  54  to ensure fluid  16  is forced into fluid inlet  52  and through the interior of tubing  54 . 
   Operationally, the electric submersible pumping systems are mechanically independent. However, the first electric submersible pumping system  22  may be physically connected to second electric submersible pumping system  24  in the sense they are affixed to each other. For example, a coupling  56  may be used to connect the two systems and to conduct the flow of fluid  16  from submersible pump  34  directly to submersible pump  28 . 
   As illustrated best in  FIG. 2 , first electric submersible pumping system  22  comprises a first drive shaft  58  by which the motor or motors  26  drive submersible pump  28 . Similarly, second electric submersible pumping system  24  comprises a second drive shaft  60  by which motor or motors  32  drive submersible pump  34 . However, first drive shaft  58  is not linked to second drive shaft  60 , thereby enabling independent operation of each electric submersible pumping system. 
   Referring to both  FIG. 1  and  FIG. 2 , first electric submersible pumping system  22  has an axis or centerline  62 . Similarly, second electric submersible pumping system  24  has an axis or centerline  64 . Efficient use of space may be achieved by aligning centerline  62  and centerline  64  to create a common centerline for both electric submersible pumping systems. With little or no offset, the power of each electric submersible pumping system is more readily maximized. The result is a system that can deliver twice the lift when compared to an individual system. However, because the systems are mechanically independent, the drive shaft  58 ,  60  of each system must only carry the horsepower associated with that individual system. 
   Referring generally to  FIG. 3 , another embodiment of system  10  is illustrated. In this embodiment, a packer  68  is deployed about an extended coupling  56  to separate wellbore  12  into an upper wellbore section  70  and a lower wellbore section  72 . The packer  68  is deployed between the downstream electric submersible pumping system  22  and the upstream electric submersible pumping system  24 . 
   As illustrated, fluid  16  is drawn into pump intake  42  and pumped through packer  68  via extended coupling  56  to pump intake  46  of submersible pump  28 . The fluid  16  is discharged from pump  28  at fluid discharge end  48  and into an annulus  74  surrounding electric submersible pumping system  22 . The fluid is then moved upwardly along annulus  74  to a desired collection point. In the embodiment illustrated, annulus  74  is formed by upper wellbore section  70  such that the fluid  16  is contained by wellbore casing  18  as it progresses upwardly to a collection point. 
   In another embodiment illustrated in  FIG. 4 , packer  68  again separates the downstream electric submersible pumping system  22  from the upstream electric submersible pumping system  24 . However, in this embodiment, system  22  comprises a conventional electric submersible pumping system. 
   As described with reference to  FIG. 3 , upstream electric submersible pumping system  24  discharges fluid through packer  68  via coupling  56 . The fluid is then discharged into upper wellbore section  70  through one or more discharge openings  76  formed in coupling  56  (see  FIG. 4 ). The fluid  16  is forced along the annulus  74  surrounding, for example, one or more motors  78  and a motor protector  80 . Subsequently, fluid is drawn into a pump intake  82  on a submersible pump  84 , such as a centrifugal pump. Pump  84  moves fluid  16  to a desired collection point through, for example, the interior of tubing  54 . It should be noted that in the embodiments illustrated in  FIGS. 3 and 4 , annulus  74  can be formed by casing  18  or by other walls, such as a wall of a surrounding shroud. 
   Although only a few embodiments of the present invention have been described in detail above, those of ordinary skill in the art will readily appreciate that modifications are possible without materially departing from the teachings of this invention. Accordingly, such modifications are intended to be included within the scope of this invention as defined in the claims.

Summary:
A submersible pumping system is provided for the movement of fluids. The system utilizes a first electric submersible pumping system that cooperates with a second electric submersible pumping system. The arrangement enables increased horsepower in a space efficient package.