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[0001]    This application claims the priority date of provisional application Ser. No. 60/234,057, filed Sep. 20, 2000. 
     
    
     
       TECHNICAL FIELD  
         [0002]    This invention relates in general to electrical submersible pumps and in particular to a restrictor for reducing downward flowing casing annulus well fluid during the initial start-up.  
         BACKGROUND  
         [0003]    In a well, a static fluid level is established while the well is not being produced. This level is a function of the reservoir pressure at the well bore perforations. If this level is above the wellhead (ground level), it is a flowing well. If the level is below the wellhead, it is a dead well and requires artificial lift to flow.  
           [0004]    [0004]FIG. 8 represents an example of an inflow performance relationship. It plots pressure at the perforations versus flow from the well. The pressure at the perforations could also be plotted as a fluid level (or fluid over the perforations ratio), as shown on the right scale of FIG. 8.  
           [0005]    When an artificial lift system, such as an electrical submersible pump (ESP) is started, it adds pressure to the fluid so that it flows to the surface at a predicted flow rate. Before start-up of the ESP, the well bore is at a static condition with the well bore fluids stabilized in the well bore at a static fluid level. After the ESP is started and it has reached its design point, the well bore fluids are stabilized at a flowing fluid level. This drawdown follows the IPR curve in FIG. 8.  
           [0006]    Between start and well bore stabilization, the fluid level is moving form the static level to the flowing level. This is called “annulus drawdown”. Therefore, the annulus volume has to be reduced or pulled down to its flowing fluid level. On start-up, almost all of the fluid being pumped is from the annulus above the pump intake, with only a small amount coming through the well bore perforations. As the annulus is drawn down, the flow from the annular volume decreases and the flow from the well bore perforations increases. The rate of this transfer is dependent upon the well annular volume (casing ID to tubing and equipment OD and the annular drawdown length) and the pumping flow rate.  
           [0007]    At startup, the flow from the perforations upward past the motor to the pump intake will be zero or very low. The motor depends upon fluid flow by its skin to carry heat away. If this flow is too low, for too long a period, excessive heat can build up internally in the motor, causing damage or failure. This is especially true in wells which produce heavy, or viscous oil.  
           [0008]    [0008]FIG. 9 shows graphically the heat rise in the motor, flow from perforations (flow by the motor), and annular flow to the surface versus time. In this example, the reduced cooling flow by the motor causes the motor to reach 480+ degrees F. in about 33 minutes. The drawdown to well bore stabilization takes over 583 minutes. In some wells, the transition time from start-up to steady state conditions may be as long as two days. 
       
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0009]    [0009]FIG. 1 is a schematic side view of an electrical submersible pump assembly, showing a tubing annulus flow restrictor in accordance with this invention.  
         [0010]    [0010]FIG. 2 is a view of an upper portion of the pump assembly of FIG. 1, showing a first alternate embodiment of a restrictor.  
         [0011]    [0011]FIG. 3 is a schematic view of an upper portion of the pump assembly of FIG. 1, showing a second alternate embodiment of a restrictor.  
         [0012]    [0012]FIG. 4 is sectional view of an upper portion of the pump assembly of FIG. 1, showing a third alternate embodiment of a restrictor.  
         [0013]    [0013]FIG. 5 is a sectional view of an upper portion of the pump assembly of FIG. 1, showing a fourth alternate embodiment of a restrictor.  
         [0014]    [0014]FIG. 6 is a sectional view of an upper portion of the pump assembly of FIG. 1, showing a fifth alternate embodiment of a restrictor.  
         [0015]    [0015]FIG. 7 is a sectional view of an upper portion of the pump assembly of FIG. 1, showing a fifth alternate embodiment of a restrictor.  
         [0016]    [0016]FIG. 8 is a graph of pressure of a typical well at the perforations versus flow from the pump.  
         [0017]    [0017]FIG. 9 is a graph of a typical rise in temperature of an electrical motor of an electrical submersible pump of a prior art assembly and installation. 
     
    
     DETAILED DESCRIPTION OF THE INVENTION  
       [0018]    Referring to FIG. 1, the well has a casing  11  containing perforations  13 . Well fluid flows in through perforations  13 , and if not pumped, will reach a static level  15  below the top of the well. Static level  15  could be only a short distance above perforations  13 , or it could be thousands of feet above perforations  13 .  
         [0019]    An electrical submersible pump assembly (“ESP”)  17  is installed in casing  11 . ESP  17  includes a centrifugal pump  19 . Pump  19  is made up of a large number of impellers and diffusers in a conventional manner. Pump  19  has an intake  21  at its base. An electrical motor  23  is part of ESP  17  and drives pump  19 . Motor  23  is normally a three-phase induction electrical motor that drives a shaft in pump  19 . A seal section  25  locates between pump  19  and motor  23  for equalizing the hydrostatic pressure of the well fluid with internal lubricant located in the motor. ESP  17  may also have a gas separator (not shown) that separates gas from well fluid and discharges it into casing  11 .  
         [0020]    ESP  17  is suspended on tubing  27  that secures to the upper end of pump  19 . Tubing  27  is normally production tubing, made up of sections of steel pipe screwed together. A power cable  29  extends from the surface to motor  23  for supplying power. Power cable  29  will extend alongside and be strapped to tubing  27 . A tubing annulus  30  is located around tubing  27  within casing  11 . Similarly, a pump annulus  32  surrounds pump  19  within casing  11 . Normally, pump  19  is of larger diameter than tubing  27 , thus pump annulus  32  will be smaller in cross-sectional flow area than tubing annulus  30 . Pump annulus  32  and tubing annulus  30  maybe considered to be separate parts of a well annulus.  
         [0021]    A flow restrictor  31  is placed in tubing annulus  30  for restricting flow of well fluid down pump annulus  32  into intake  21  during start-up. Restrictor  31  is a blocking member sized so that the suction created by the start-up of pump  19  will draw more well fluid from perforations  13  than from the well fluid in tubing annulus  30 . In the embodiments of FIGS.  1 - 3  and  5 - 7 , the restrictor is placed about 50 to 100 feet above pump  19 . Restrictor  31 , as well as those in the other embodiments, provides a downward flow area that is less than the minimum flow area in pump annulus  32 . The minimum flow area in pump annulus  32  is normally around motor  23 , which is typically larger in diameter than pump  19 . The maximum downward flow rate through restrictor  31 , as well as the restrictors of the other embodiments, is a fraction of the discharge flow rate of pump  19 , preferably about 5% to 50%.  
         [0022]    In the embodiment of FIG. 1, restrictor  31  is similar to a swab cup, having an elastomeric portion that slidingly engages the inner wall of casing  11  while ESP  17  is being lowered into the well. The orientation of restrictor  31  allows upward flow past the sealing surfaces as it is being lowered, but not downward flow. However, it has a plurality of orifices or passages  33  that extend through it for allowing a maximum flowrate of downflow from tubing annulus  30 . The flowrate is selected to be small enough such that most of the well fluid flowing into pump intake  21  will be from perforations  13 . Additionally, passages  33  allow any gas that is discharged by a gas separator (not shown in FIG. 1) into casing  11  to flow up past restrictor  31 . There are no check valves in passages  33 , allowing fluid flow in both upward and downward directions.  
         [0023]    In operation, there will be a static fluid level  15  when pump  19  is not operating. Static fluid level  15  will normally be above restrictor  31 . Once pump  19  begins operating, formation fluid from perforations  13  will begin flowing into pump intake  21 . At the same time, static fluid level  15  will begin dropping. Well fluid in tubing annulus  15  will flow downward through passages  33  toward intake  21 , but at a lower flow rate than would exist if no restriction were present. The restriction provided by restrictor  31  enhances flow out of perforations  13  over the prior art, which has no type of restrictor  31 . The decreased downward flow rate increases the drawdown period before the well fluid in tubing annulus  30  reaches a constant fluid level with pump  19  operating, but increases cooling flow by motor  23  during the initial starting period. Eventually, static fluid level  15  will drop to a constant level even though pump  19  is operating, with downward flow from tubing annulus  30  ceasing. This constant level while pump  19  is operating may be either above restrictor  31  or below.  
         [0024]    Rather than a swab cup type restrictor  31 , various other blocking members could be utilized. For example, the diameter of tubing  27  between the discharge of pump  19  and the static fluid level could be increased. This decreases the cross-sectional flow area of tubing annulus  30  in that area, reducing the downward flow during start-up. Also, as shown in FIG. 2, an inflatable packer  35  could be utilized having orifices  37  for upward and downward flow. Packer  35  would be inflated in a conventional manner during installation of ESP  17 .  
         [0025]    In the embodiment of FIG. 3, a rigid plate  39  is mounted to tubing  27  above pump  19  (FIG. 1) and below static fluid level  15 . An annular clearance  41  is located between plate  39  and the inner diameter of casing  11 . Annular clearance  41  allows some downward flow of fluid from tubing annulus  30 . Furthermore, plate  39  has orifices  43  sized for allowing only a selected rate of downward flow during start-up. Orifices  43  also allow upward flow.  
         [0026]    In the embodiment of FIG. 4, the restriction comprises aggregate  45  placed in tubing annulus  30 . Aggregate  45 , basically gravel, could also be placed around pump  19  in pump annulus  32 . Aggregate  45  reduces the flow rate of well fluid in tubing annulus  30 .  
         [0027]    The embodiment of FIG. 5 is particularly useful for wells that produce significant amounts of gas. Blocking member  47  may be either a packer such as packer  35  of FIG. 2, or it may be a swab cup type elastomer such as elastomer  31  of FIG. 1. Blocking member  47  has at least two passages, with passage  46  being primarily for upward gas flow and passage  48  being for downward liquid flow of well fluid in the tubing annulus. Gas flow passage  46  is connected to a tube  49  that extends upward, and well fluid passage  48  is connected to a tube  51  that extends downward. Preferably, tube  49  extends above the static fluid level  15  (FIG. 1), although this is not necessary. Tube  51  extends downward far enough to be below any gas cap  52  that may form below the lower end of blocking member  47 . Tube  51  serves to bleed off gas in gas cap  52  to prevent it from growing to a size large enough to affect the intake of liquid into the pump intake  21  (FIG. 1). Locating the upper end of tube  49  above restrictor  47  reduces the amount of liquid flowing downward in tube  49 , which might otherwise impede the upward flow of gas. Similarly, tube  51  reduces downward flowing liquid in the vicinity of the inlet to gas flow passage  46 , which might otherwise obstruct the flow of gas. There are no valves in either passage  46 ,  48  that would prevent upward or downward flow of fluid.  
         [0028]    [0028]FIG. 6 also discloses an embodiment for facilitating the upward flow of gas while restricting the downward flow of liquid. Blocking member  53  is an annular member mounted to tubing  27  so as to provide a lower end that is configured to create a gas pocket  57  along one side. In this embodiment, gas pocket  57  is created by tilting blocking member  53  so that portion of the lower end is higher than another portion. A gas flow passage  55  extends upward through blocking member  53  from the portion above gas pocket  57 . A well fluid passage  59  extends through a lower portion of blocking member  53  for the downward flow of well fluid. Both passages  55  and  59  are capable of two-way flow, however gas will tend to flow through gas flow passage  55  because of its location over gas pocket  57 .  
         [0029]    [0029]FIG. 7 shows another embodiment for restricting downward flow. Blocking member  61  may be either a packer such as in FIG. 2 or an elastomer as in FIG. 1. Blocking member  61  has one or more passages  63  that allow downward flow of well fluid as well as upward flow. A pressure responsive variable orifice valve  65  is in each passage  63 . Each valve  65  will reduce the flow area through passage  63  in response to an increase in differential pressure across blocking member  61 . Valve  65  constricts the flow rate of downward flowing well fluid in proportion to the extent of draw down due to the initial operation of pump  19  (FIG. 1). If there is a fairly high static fluid level, when pump  27  starts to operate, a fairly large pressure differential across blocking member  61  may occur. If so, valves  65  will reduce the flow area accordingly to prevent a high flow rate of well annulus fluid from flowing downward. Valve  65  preferably is not electrically actuated. Rather it preferably has a resilient portion within its passage that deforms in response to pressure differential to reduce and increase the passage.  
         [0030]    The invention has significant advantages. Restricting downward flow of well annulus fluid allows more flow through the perforations. The increased flow through the perforations flows past the motor, cooling it.  
         [0031]    While the invention has been shown in several of its forms, it should be apparent that the invention is not so limited, but is susceptible to various changes without departing from the scope of the invention.

Summary:
A method of pumping well fluid from a well having casing with perforations includes connecting an electrical motor to a lower end of a pump and securing the pump to tubing. A restrictor is mounted to the tubing above the pump, the restrictor having a restrictor passage. The well annulus contains a well fluid with a static level under static conditions. When the motor is started to cause the pump to operate, downward flow of well fluid contained in the well annulus flows through the restrictor passage. This reduces the amount of downward flow to increase well fluid flow through the perforations.