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BACKGROUND 
       [0001]    Embodiments of the invention generally relate to the field of submersible pumping systems, and more particularly, but not by way of limitation, to a system designed to produce fluids with a high gas fraction from subterranean wells that may also include significant volumes of liquid. 
         [0002]    Submersible pumping systems are often deployed into wells to recover petroleum fluids from subterranean reservoirs. Typically, the submersible pumping system includes a number of components, including one or more fluid filled electric motors coupled to one or more high performance pumps located above the motor. When energized, the motor provides torque to the pump, which pushes wellbore fluids to the surface through production tubing. Each of the components in a submersible pumping system must be engineered to withstand the inhospitable downhole environment. 
         [0003]    Some reservoirs contain a higher volume of gaseous hydrocarbons than liquid hydrocarbons. In these reservoirs, it is desirable to install recovery systems that are designed to handle fluids with higher gas fractions. Prior art gas handling systems are generally effective at producing gaseous fluids, but tend to fail or perform poorly when the exposed to significant volumes of liquid. Many wells initially produce a higher volume of liquid or produce higher volumes of liquid on an intermittent basis. The sensitivity of prior art gas handling systems to liquids presents a significant problem in wells that produce predominantly gaseous hydrocarbons but that nonetheless produce liquids at start-up or on an intermittent basis. It is to these and other deficiencies in the prior art that the embodiments of present invention are directed. 
       BRIEF DESCRIPTION 
       [0004]    In some embodiments, the present invention includes a fluid processor for use in a downhole pumping operation. The fluid processor includes a fluid processing stage, a nozzle stage and a gas compressor stage. The fluid processing stage may include an impeller and a diffuser. The nozzle stage may include a nozzle chamber and a variable metering member. The nozzle chamber is configured as a convergent-divergent nozzle and the variable metering member is configured for axial displacement within the convergent section to adjust the open cross-sectional area of the nozzle. The gas compressor stage includes one or more gas compressor turbines. 
         [0005]    In another aspect, some embodiments include a method for producing fluid hydrocarbons from a subterranean wellbore, where the fluid hydrocarbons have a variable gas-to-liquid ratio. The includes the steps of measuring a first gas-to-liquid ratio of the fluid hydrocarbons with the sensor module; outputting a signal representative of the first gas-to-liquid ratio of the fluid hydrocarbons to a variable speed drive; and applying an electric current from the variable speed drive to the motor to cause the motor to operate at a first rotational speed. The method continues with the steps of measuring a second gas-to-liquid ration of the fluid hydrocarbons with the sensor module, where the second gas-to-liquid ratio is greater than the first gas-to-liquid ratio; outputting a signal representative of the second gas-to-liquid ratio of the fluid hydrocarbons to the variable speed drive; and applying an electric current from the variable speed drive to the motor to cause the motor to operate at a second rotational speed that is faster than the first rotational speed. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0006]      FIG. 1  depicts a submersible pumping system constructed in accordance with an embodiment of the present invention. 
           [0007]      FIG. 2  provides an elevational view of the fluid processor of the pumping system of  FIG. 1 . 
           [0008]      FIG. 3  provides a partial cut-away view of the fluid processor of  FIG. 2 . 
           [0009]      FIG. 4  provides an elevational view of a helical axial pump of the fluid processor of  FIG. 3 . 
           [0010]      FIG. 5  presents a cross-sectional view of a diffuser of the fluid processor of  FIG. 3 . 
           [0011]      FIG. 6  presents a cross-sectional view of the nozzle chamber of the fluid processor of  FIG. 3 . 
           [0012]      FIG. 7  presents a perspective view of the metering member of the fluid processor of  FIG. 3 . 
           [0013]      FIG. 8  presents a perspective view of a compressor stage of the fluid processor of  FIG. 3 . 
       
    
    
     DETAILED DESCRIPTION 
       [0014]    In accordance with an embodiment,  FIG. 1  shows an elevational view of a pumping system  100  attached to production tubing  102 . The pumping system  100  and production tubing  102  are disposed in a wellbore  104 , which is drilled for the production of a fluid such as water or petroleum. The production tubing  102  connects the pumping system  100  to a wellhead  106  located on the surface. As used herein, the term “petroleum” refers broadly to all mineral hydrocarbons, such as crude oil, gas and combinations of oil and gas. 
         [0015]    The pumping system  100  may include a fluid processor  108 , a motor  110 , a seal section  112 , a sensor module  114 , an electrical cable  116  and a variable speed drive  118 . Although the pumping system  100  is primarily designed to pump petroleum products, it will be understood that embodiments of the present invention can also be used to move other fluids. It will also be understood that, although each of the components of the pumping system are primarily disclosed in a submersible application, some or all of these components can also be used in surface pumping operations. 
         [0016]    The motor  110  may be an electric submersible motor that is provided power from the variable speed drive  118  on the surface by the electrical cable  114 . When selectively energized, the motor  110  is configured to drive the fluid processor  108 . The variable speed drive  118  controls the characteristics of the electricity supplied to the motor  110 . In an embodiment, the motor  110  is a three-phase electric motor and the variable speed drive  118  controls the rotational speed of the motor by adjusting the frequency of the electric current supplied to the motor  110 . Torque is transferred from the motor  110  to the fluid processor  108  through one or more shafts  120  (not shown in  FIG. 1 ). 
         [0017]    In some embodiments, the seal section  112  is positioned above the motor  110  and below the fluid processor  108 . In some embodiments, the seal section  112  isolates the motor  110  from wellbore fluids in the fluid processor  108 . The seal section  112  also accommodates the expansion of liquid lubricant from the motor  110  resulting from thermal cycling. 
         [0018]    The sensor module  114  is configured to measure a range of operational and environmental conditions and output signals representative of the measured conditions. In an embodiment, the sensor module  114  is configured to measure at least the following external parameters: wellbore temperature, wellbore pressure and the ratio of gas to liquid in the wellbore fluids (gas fraction). The sensor module  114  can be configured to measure at least the following internal parameters: motor temperature, pump intake pressure, pump discharge pressure, vibration, pump and motor rotational speed, and pump and motor torque. The sensor module  114  may be positioned within the pumping system  100  at a location that permits the measurement of upstream conditions, i.e., the measurement of fluid conditions approaching the pumping system  100 . In the embodiment depicted in  FIG. 1 , the sensor module  114  is attached to the upstream side of the motor  110 . It will be appreciated, however, that the sensor module  114  can also be deployed with a tether in a remote position from the balance of the components in the pumping system  100 . 
         [0019]    In some embodiments, the fluid processor  108  is connected between the seal section  112  and the production tubing  102 . The fluid processor  108  may include an intake  122  and a discharge  124 . The fluid processor  108  is generally designed to produce wellbore fluids that have a predominately high gas fraction but that present significant volumes of liquid at start-up or on an intermittent basis. The fluid processor  108  includes turbomachinery components that are configured to increase the pressure of gas and liquid by converting mechanical energy into pressure head. When driven by the motor  110 , the fluid processor  108  draws wellbore fluids into the intake  122 , increases the pressure of the fluid and pushes the fluid through the discharge  124  into the production tubing  102 . 
         [0020]    Although only one of each component is of the pumping system  100  shown in  FIG. 1 , it will be understood that more can be connected when appropriate, that other arrangements of the components are desirable and that these additional configurations are encompassed within the scope of some embodiments. For example, in many applications, it is desirable to use tandem-motor combinations, gas separators, multiple seal sections, multiple pumps, and other downhole components. 
         [0021]    It will be noted that although the pumping system  100  is depicted in a vertical deployment in  FIG. 1 , the pumping system  100  can also be used in non-vertical applications, including in horizontal and non-vertical wellbores  104 . Accordingly, references to “upper” and “lower” within this disclosure are merely used to describe the relative positions of components within the pumping system  100  and should not be construed as an indication that the pumping system  100  must be deployed in a vertical orientation. 
         [0022]    Turning to  FIGS. 2 and 3 , shown therein are elevational and partial cut-away views, respectively, of the fluid processor  108 . In some embodiments, the fluid processor  108  includes three sections: a fluid processing stage  126 , an intermediate nozzle stage  128  and a compressor stage  130 . Generally, the fluid processing stage  126  includes one or more impellers  132  and diffusers  134 . The fluid processing stage  126  is used to pressurize fluids with a high liquid fraction. The intermediate nozzle stage  128  is designed to process fluids with a lower liquid fraction by reducing and dispersing liquid droplets in the fluid stream. The intermediate nozzle stage  128  may include a nozzle chamber  136  and a variable metering member  138 . The gas compressor stage  130  is primarily intended to pressurize fluid streams with a high gas fraction. The compressor stage  130  may include one or more gas turbines  140 . 
         [0023]    Turning to  FIG. 4 , shown therein is an elevational view of the impeller  132  constructed in accordance with an embodiment. The impeller  132  is connected to the shaft  120  and configured for rotation within the diffuser  134 . The impeller  132  includes an upstream series of helical vanes  142  and a downstream series of axial vanes  144 . The helical vanes  142  are designed to induce into the fluid processor  108  the flow of fluids with a significant liquid fraction. The axial vanes  144  accelerate the fluid in a substantially axial direction. 
         [0024]    Turning to  FIG. 5 , shown therein is a cross-sectional view of the diffuser  134 . The diffuser  134  may include a diffuser shroud  146  and a series of diffuser vanes  148 . The diffuser maintains a stationary position within the fluid processor  108 . The diffuser  134  captures the fluid expelled by the impeller  132  and the diffuser vanes  148  reduce the axial velocity of the fluid, thereby converting a portion of the kinetic energy imparted by the impeller  132  into pressure head. Although a single impeller  132  and diffuser  134  are depicted in  FIG. 3 , the use of multiple pairs of impellers  132  and diffusers  134  is contemplated within the scope of additional embodiments. 
         [0025]    Turning to  FIGS. 6 and 7 , shown therein are perspective and cross-sectional views of the nozzle chamber  136  and variable metering member  138 , respectively. The nozzle chamber  136  may be configured as a convergent-divergent novel that includes a convergent section  150 , a throat  152  and a divergent section  154 . In some embodiments, the nozzle chamber  136  is configured as a de Laval nozzle that includes an asymmetric hourglass-shape. In an embodiment, the nozzle chamber  136  is configured as a reverse-flow de Laval nozzle in which fluids accelerate from the convergent section  150  through the throat  152  and then decelerate in the divergent section  154 . The acceleration and deceleration of the fluid passing through the nozzle chamber  136  causes entrained liquid droplets to disperse and homogenize with smaller droplet diameter. 
         [0026]    The variable metering member  138  shown in  FIG. 7A  may include a frustoconical outer surface  156  and an interior bowl  158  that permits the passage of the shaft  120 . The exterior conical surface  156  fits within the convergent section  150  of the nozzle chamber  136 . The interior bowl  158  is positioned upstream toward the diffuser  134 . 
         [0027]    As shown in  FIGS. 7A and 7B , The variable metering member  138  is configured to be axially displaced along the shaft  120 . In some embodiments, the variable metering member  138  includes a spring  139  and a spring retainer clip  141 . The spring retainer clip  141  is fixed at a stationary position on the shaft  120  and biases the variable metering member  138  in an open position adjacent the diffuser  134 . As higher volumes of liquid pass from the diffuser  134 , pressure exerted on the interior bowl  158  increases and the variable metering member  138  shifts downstream along the shaft  120  (as shown in  FIG. 7C ), thereby reducing the open cross-sectional area of the convergent section  150  of the nozzle chamber  136 . Closing a portion of the nozzle chamber  136  under conditions of higher liquid loading creates a Venturi effect that compresses gas bubbles within the fluid stream and prevents damage to the downstream compressor stage  130 . When the fluid discharged from the diffuser  134  includes a low liquid fraction, the force exerted by the spring  139  overcomes the hydraulic force exerted on the variable metering member  138  and the variable metering member  138  returns to a position adjacent the diffuser  134  (as shown in  FIG. 7B ) to permit the high-volume flow of high gas fraction fluid through the nozzle stage  128 . 
         [0028]    Turning to  FIG. 8 , shown therein is a perspective view of the gas compressor turbine  140  of the gas compressor stage  130 . The gas compression turbine  140  may include a series of upstream compressor vanes  160 , a hub  162 , a series of ports  164  passing from the upstream side of the hub  162  to the downstream side of the hub  162  and a series of downstream compressor vanes  166 . The upstream compressor vanes  160  are configured to induce the flow of fluid through the gas compressor stage  130 . Fluid passes through the hub  162  through the ports  164  and into the downstream compressor vanes  166 . The downstream compressor vanes  166  are designed to increase the pressure of the fluid. In some embodiments, the gas compressor stage  130  includes a series of multi-axial and radial centrifugal gas compressor stages. 
         [0029]    The operation of the fluid processor  108  is adjusted based on the condition of the fluid in the wellbore  104 . Based on information provided by the sensor module  114  about the gas-to-liquid ration in the wellbore fluid, the variable speed drive  118  adjusts the electric current provided to the motor  110 , which in turn, adjusts the rotational speed of the rotary components of the fluid processor  108 . When the wellbore fluid exhibits a high liquid-to-gas ratio (above about 5% LVF), the motor  110  operates at a relatively low speed. At lower speeds, the fluid processing stage  126  is effective and pumps the high liquid-fraction fluid through the fluid processor  108 . At these lower rotational speeds, the compressor stage  130  does not significantly increase or impede the flow of fluid through the fluid processor  108 . 
         [0030]    When the sensor module  114  detects the presence of wellbore fluids with a higher gas-to-liquid ratio, the variable speed drive  118  increases the rotational speed of the motor  110 , which in turn, increases the rotational speed of the rotary components in the fluid processor  108 . The higher rotational speed allows the compressor stage  130  to increase the pressure of the high gas fraction fluid. During operation, the nozzle stage  136  meters the flow of fluid into the compressor stage  130  and reduces the size of liquid droplets entrained in the fluid stream. 
         [0031]    In some embodiments, the fluid processor  108  is operated in a low speed “pump” mode when the liquid fraction is above about 8%. When the liquid fraction is below about 8%, the speed of the fluid processor  108  can be increased to optimize the operation of the compressor stage  130 . Thus, in some embodiments, the operation of the fluid processor  108  is adjusted automatically to optimize the movement of fluids depending on the gas-to-liquid ratio of the fluids. Although the sensor module  114  can be used to provide the gas and liquid composition information to control the operation of the fluid processor  108 , it may also be desirable to control the operation of the fluid processor  108  based on the torque requirements of the motor  110 . An increase in torque demands may signal the processing of fluids with higher liquid-to-gas ratios. 
         [0032]    It is to be understood that even though numerous characteristics and advantages of various embodiments of the present invention have been set forth in the foregoing description, together with details of the structure and functions of various embodiments of the invention, this disclosure is illustrative only, and changes may be made in detail, especially in matters of structure and arrangement of parts within the principles of the present invention to the full extent indicated by the broad general meaning of the terms in which the appended claims are expressed. It will be appreciated by those skilled in the art that the teachings of the present invention can be applied to other systems without departing from the scope and spirit of the present invention.

Summary:
A fluid processor for use in a downhole pumping operation includes a fluid processing stag, a nozzle stage and a gas compressor stage. The nozzle chamber is configured as a convergent-divergent nozzle and the variable metering member is configured for axial displacement within the convergent section to adjust the open cross-sectional area of the nozzle. A method for producing fluid hydrocarbons from a subterranean wellbore with a pumping system includes the steps of measuring a first gas-to-liquid ratio of the fluid hydrocarbons and operating a motor within the pumping system to operate at a first rotational speed. The method continues with the steps of measuring a second gas-to-liquid ration of the fluid hydrocarbons with the sensor module, where the second gas-to-liquid ratio is greater than the first gas-to-liquid ratio, and operating the motor at a second rotational speed that is faster than the first rotational speed.