Abstract:
The invention relates to a method of positioning a pump in a well in order to create artificial lift. The method involves frictionally engaging a portion of the pump with a portion of the well, such that the pump is retained in a starting position. In order to progress the pump into the well, the pressure differential across the pump is increased, and then, when the pump is in a finishing position, the pressure differential across the pump is reduced such that the pump is once again retained in the finishing position by the frictional engagement between the pump and the well. A pump for use in the above method of deployment is also provided.

Description:
BACKGROUND OF THE INVENTION 
       [0001]    The present invention relates to a method of positioning a pump in a downhole environment, particularly, but not exclusively, a method of positioning a pump in a hydrocarbon producing well in order to provide artificial lift. 
         [0002]    In wells that have insufficient natural lift (pressure) to bring production fluid to the surface, electric or hydraulic “submersible pumps” are often lowered into the well. In order to position such pumps at the appropriate location within the well, these pumps are typically deployed on tubing strings. However, this method of installation has many drawbacks; for example it can be expensive and time-consuming. 
       SUMMARY OF THE INVENTION 
       [0003]    According to a first aspect of the present invention, there is provided a method of positioning a pump in a well, the method comprising frictionally engaging a portion of the pump with a portion of the well, such that the pump is retained in a starting position by said frictional engagement, and then, when it is desired to progress the pump into the well, selectively increasing a pressure differential across the pump in order to progress the pump into the well, and then, when the pump is in a finishing position, reducing the pressure differential across the pump such that the pump is retained in said finishing position by said frictional engagement between the pump and the well. 
         [0004]    According to a second aspect of the present invention, there is provided a pump comprising frictional engagement means adapted to provide a coefficient of friction between the pump and a portion of the well in order to prevent movement of the pump in the well when a pressure differential across the pump is below a predetermined threshold, and which allows movement of the pump into the well when the pressure differential across the pump is above said predetermined threshold such that the pump may be pumped from a starting position to a finishing position within the well by selectively increasing the pressure differential across the pump to above the predetermined threshold. 
         [0005]    According to a third aspect of the present invention, there is provided a submersible pump for providing artificial lift in a well, the submersible pump comprising a turbine arrangement, a pump arrangement driven by the turbine arrangement and a drive shaft connecting the turbine arrangement to the pump arrangement, wherein at least a portion of the drive shaft is hollow in order to provide a fluid flow passage along which comingled power and production fluids may pass. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0006]    Embodiments of the present invention will now be described by way of example only, with reference to the following diagrams, in which: 
           [0007]      FIG. 1  is a perspective cut-away illustration of a pump-in module of a pump in accordance with the present invention; 
           [0008]      FIG. 2  is a transverse cross-sectional view of the pump-in module of  FIG. 1  attached to the pump in position within existing production tubing running through existing wellbore casing;  FIG. 2  is a schematic illustration that has been shortened from true length at splits S 1 , S 2  in order to improve clarity; 
           [0009]      FIG. 3  is a further schematic transverse illustration of the pump in position within production tubing; 
           [0010]      FIG. 4  is a perspective transverse illustration of the apparatus of  FIG. 3 ; 
           [0011]      FIG. 5  is a more detailed illustration of the area referenced “A” in  FIG. 4  showing the turbine and pump stages, drive shaft arrangement and a mixing chamber; 
           [0012]      FIG. 6  is an illustration of the flow patterns within and around the in use; 
           [0013]      FIG. 7  is a more detailed illustration of the impeller and stator stages of the pump portion of  FIG. 6 ; 
           [0014]      FIG. 8  is a more detailed illustration of the turbine rotors and stators of  FIG. 6 ; 
           [0015]      FIG. 9  is an illustration of a pump according to an alternative embodiment of the invention; 
           [0016]      FIG. 10  is an illustration of pre-prepared tubing and casing ready to accept the pump of  FIG. 9  therein; 
           [0017]      FIG. 11  is an illustration of the pump installed within the existing production tubing and casing where the flow patterns around and within the pump are shown; 
           [0018]      FIG. 12  is a perspective illustration of an annular pump according to a further embodiment of the invention; and 
           [0019]      FIG. 13  is a transverse cross section of the annular pump of  FIG. 12 . 
       
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
       [0020]    With reference to  FIG. 1 , a pump-in module  10  comprises fishing neck attachment  13  for attachment to a fishing neck  12 , resilient elastomer inserts  14  and a nozzle arrangement  16  which leads on to a threaded connector  18 . 
         [0021]    The elastomer inserts  14  are received within pressure sensitive pockets  15  of the module  10 . The pockets  15  and the flexibility of the elastomer inserts  14  provides the elastomer inserts  14  with the ability to swell in response to an increase in pressure within the pump module  10 . An upper inlet aperture (which also provides an exit aperture for flow M 2  as described subsequently) is also provided in the pump module  10  which provides fluid communication between the upper production tubing  28  and the interior of the pump module  10 . The restricted bore provided by the nozzle section  16  therefore helps to increase the pressure acting upon the inserts  14  by increasing the pressure there-against for any given pressure of power/pump fluid entering the interior of the pump module  10 . This therefore effectively allows the outer circumference (or at least the outer extremities of the outer circumference i.e. the outer edges of elastomer inserts  14 ) of the pump module  10  to be actively adjusted in order to control the rate of descent of the pump module  10  within the well. Furthermore, the elastomer inserts  14  around the module  10  provide a partial seal or obstruction in the annulus between the outer circumference of the pump module and the inner diameter of the surrounding production tubing. The dimensions and or number of inserts  14  can be selected to provide more or less of an obstruction as required. In an alternative embodiment (not shown), a similar effect may be provided with retractable rollers, contact pads or similar frictional engagement surfaces. In another alternative embodiment (not shown) the required friction may be provided by way of a worm formation on the outer diameter of the module which allows the module to be “screwed” into place. The worm formation may be provided with resin to improve the frictional characteristics. In this alternative, the worm may be driven using a gear between the turbine casing and worm internal diameter. 
         [0022]    Referring to  FIG. 2 , the pump module  10  is attached to a pump unit  20  having a turbine arrangement  22 , corresponding impeller arrangement  24  and connecting central drive shaft  26 . The pump module  10  and pump unit  20  are located in existing production tubing  28  which is situated within existing well casing  30 . 
         [0023]    As is best illustrated in  FIG. 5 , the turbine arrangement  22  comprises a series of axially arranged turbine rotors  32  which are alternately arranged with a series of axially arranged turbine stators  34  around the central drive shaft  26 . The impeller arrangement  24  comprises a series of axially arranged impeller blades  36  which are alternately arranged with a series of axially arranged impeller stators  38 . The turbine arrangement  22  comprises aerofoil blade profiles on both the rotors and stators. The pump arrangement design can be altered depending upon the well in which the arrangement is to be deployed to take account of e.g. fluid viscosity, gas fraction, depth etc. and can include e.g. radial flow, mixed flow, axial type and alternate stage geometry. 
         [0024]    The central drive shaft  26  has a solid section  26 A around which the impeller blades  36  are arranged and a hollow section  26 B around which the turbine rotors  32  are arranged. The internal diameter of the hollow section  26 B also acts as a flow channel for produced/co-mingled power fluid as will be described subsequently. A drive shaft bearing  27  is also provided to provide bearing support for the central drive shaft  26 ; additional support bearings may be provided along the central drive shaft  26  as required. Furthermore, pressurised power fluid can also be used to provide bearing life support. 
         [0025]    At zone A ( FIGS. 4 and 5 ), a mixing chamber  40  is provided between the turbine and impeller arrangements. The wall of the central drive shaft  26  has an open aperture  42  along the length of the mixing chamber  40  and an associated lower aperture through the casing of the turbine arrangement surrounding the mixing chamber. This provides a fluid flow path between the internal diameter of the hollow drive shaft  26 B, the mixing chamber  40  and the annulus between the outer diameter of the turbine casing and the inner diameter of the production tubing  28  by way of the lower aperture adjacent the mixing chamber  40 . 
         [0026]    In order to deploy the system from surface to the required pumping position downhole, the pump module  10  is first attached to the pumping unit  20  and then inserted into a small tail section of the existing production tubing  28  at the surface. At this point, in order to facilitate insertion of the pump module  10  in the production tubing  28 , the elastomer inserts  14  may be locked in a retracted position. A manual or automatically operated lock-off feature, where the inserts  14  are fully inward, may be provided. During this procedure, the pump module  10  and attached pump unit  20  may be suspended from a rig, wireline or other appropriate arrangement. 
         [0027]    Once fully inserted into the small tail section of the production tubing  28  the inserts  14  are pushed outwards until they frictionally engage with the inner diameter of the production tubing  28  as shown in  FIG. 2 . A manual or automatically operated lock-on feature, where the inserts  14  are fully outward, may be provided to facilitate this while no fluid pressure has yet been applied. 
         [0028]    The frictional abutment between the outer surface of the inserts  14  and the inner diameter of the production tubing  28  is now sufficient to hold the weight of the pump module  10  and associated pump unit  20  such that any wireline, rig or other suspension arrangement can be disconnected. 
         [0029]    In order to deploy the pump module into its final position within the well, suitable pumping apparatus is firstly attached to the production tubing  28  at the well head. Pump-in fluid (i.e. existing available power fluid) is then pressured-up above the partial seal created by the inserts  14 . In this regard, the greater the seal created by the inserts  14 , the greater the pressure build-up will be above the module  10 . 
         [0030]    Furthermore, during pressure-up, fluid will start to flow through the upper aperture of the pump module  10 , through the restriction of the nozzle section  16 , along the hollow drive shaft  26 B, out of the mixing aperture  26 , into the mixing chamber  40 , out of the lower aperture and into the annulus between the outer diameter of the turbine casing and the inner diameter of the production tubing  28  for subsequent recirculation to the surface (via an aperture provided in the production tubing or by any other appropriate return route). 
         [0031]    Once the pressure of the pump-in fluid above the module  10  is sufficiently high the frictional engagement of the inserts  14  on the inner wall of the production tubing  28  will no longer be sufficient to hold the pump module  10  in position. The pump module  10  and connected pump unit  20  will therefore begin to progress down into the well. If desired, the pressure of the pump-in fluid can be “pulsed” in order to incrementally progress the pump module  10  into the well. Furthermore, the rate of deployment may be controlled by increasing or decreasing the pressure of the pump-in pressure. An increase in pressure will result in an increased rate of deployment and a decrease in pressure will result in a decreased rate of deployment; however, the degree of change in rate of deployment in response to a change in pressure (and the point at which the pressure will overcome the frictional engagement) can also be controlled and adjusted by appropriate calibration of the dimensions, material etc. of the inserts  14 . This can also be tuned by appropriate calibration of the sensitivity and response of the pressure sensitive pockets  15 . 
         [0032]    Wireless or other technology may be utilised in order to monitor the depth of the pump module during deployment. Alternatively or additionally, depth verification may be achieved using a small diameter wire. Furthermore, backup batteries may be used if required in order to power the turbine of the unit initially until sufficient fluid flow to power the turbine arrangement  22  has been established. 
         [0033]    Once the pump module  10  and associated pump unit  20  are in the desired location within the well, the pressure of the pump-in fluid is reduced such that the frictional engagement of the inserts  14  with the inner surface of the production tubing  28  is once again sufficient to retain the pump module  10  in a fixed position within the well. With particular reference to  FIGS. 6 to 8 , operation of the pump unit  20  once in position in the well will now be described. 
         [0034]    The lower aperture adjacent the mixing chamber  40  is first closed by e.g. a sliding sleeve arrangement. Power fluid is then pumped into the annulus between the existing casing  30  and the existing production tubing  28  illustrated as flow F 1 . The power fluid then enters the turbine as flow F 2  via a port or other aperture in the wall of the production tubing  28 . The power fluid then progresses through the turbine stages as F 3  at which point its energy is transferred into the turbine arrangement  22  in order to drive the pump unit  24  via the central drive shaft  26 . This causes the pump impellers  36  to rotate thereby facilitating the flow of production fluid P 4  into the pump  24 . Production fluid then flows up through the stages of the impeller arrangement  24  as flow P 5 . 
         [0035]    Power fluid exhausted from the turbine arrangement  22  mixes with the produced fluid from the pump arrangement  24  in the mixing chamber  40 . The resulting co-mingled fluid (power fluid combined with produced fluid) then enters the hollow portion  26 B of the central drive shaft  26  via aperture  42  (best illustrated in  FIG. 5 ) and passes therealong until it exits the upper end of the hollow drive shaft  26 B as co-mingled flow M 1 . The co-mingled flow is then exhausted out of the pump module  10  via an exit aperture (not shown) as M 2  before passing up the inner diameter of the production tubing  28  as co-mingled flow M 3  for separation/further processing. 
         [0036]    Although not shown, depending upon the well conditions and set-up it may be desirable to pump a hydraulic submersible pump into the well using the described method and pass power fluid through the production tubing such that return flow is returned through the annulus. 
         [0037]    Referring now to  FIGS. 9 ,  10  and  11 , an alternative embodiment of the invention will now be described where a pump module  110  comprises a series of seals  114  in place of the elastomer inserts of the previous embodiment. In this embodiment, the turbine is retained within turbine section  122  which is provided with a no-go collar  123  at the upper end thereof and a pack-off seal  125  provided adjacent its join with a pump section  124 . 
         [0038]    As shown in  FIG. 10 , the well is pre-prepared with existing casing  130  and tubing  128  having a no-go shoulder  129 , corresponding to the position of the no-go collar  123  of the turbine section  122 . A communication port (such as a sliding sleeve)  131  is provided through the wall of the tubing  128  below the no-go shoulder  129 . A packer  133  is also provided to create a sealed-off annulus  139  between the outer diameter of the tubing  138  and the inner diameter of the casing  130 . 
         [0039]    The process of deploying the pump module  110  and attached pump unit of the present embodiment is substantially similar to that previously described for the first embodiment. With the pump module  110  of the second embodiment in position, the abutment between the no-go collar  123  of the turbine section  122  and the no-go shoulder  129  on the inner diameter of the tubing  128  prevents the pump from progressing further into the tubing  128 . This also ensures that the communication port  131  of the turbine section  122  aligns with corresponding flow inlets  137  provided through the wall of the turbine section  122 . In order to create a flow path into the turbine section  122  from the annulus  139 , a sliding sleeve in the completion can be actuated or guns can be run on a previous trip in order to perforate the production tubing. Alternatively, a suitable mechanism may be used on the downhole assembly in order to cut holes following setting of the tool in the production tubing at the required depth. 
         [0040]    With particular reference to  FIG. 11 , operation of the pump unit once in position in the well will now be described. Power fluid (i.e. liquid or gas) is pumped into the annulus  139  as flow 
         [0041]    Fl. The power fluid then enters the turbine as flows F 2  via the communication port  131  and flow inlets  137 . The power fluid then progresses through the turbine stages (not shown in  FIG. 11 ) at which point its energy is transferred into the turbine arrangement  122  in order to drive the pump unit  124 . This helps to progress the flow of production fluid P 4  into the pump  124 . Production fluid will then flow up through the progressive stages of the impeller arrangement (not shown). 
         [0042]    The power fluid exhausted from the turbine arrangement  122  mixes with the produced fluid from the pump arrangement  124 . This co-mingled fluid then exits as co-mingled flow M 1  before being passed up the inner diameter of the tubing  128  to the surface/separator equipment for further processing. 
         [0043]    It can therefore be seen that the method and apparatus of the present invention provides a novel way of providing artificial lift in a well. Advantages of the method and apparatus of the invention include, but are not limited to the following; 
         [0044]    No expensive power cable is required; therefore costs are reduced since the unit is powered by pumping fluid from the surface. 
         [0045]    No tubing string is required to run the pump into the well; costs are reduced. 
         [0046]    No rig or wireline unit required; costs are reduced. The unit is deployed from a small truck and surface pump; costs are reduced. 
         [0047]    The unit can be deployed quickly subsea from a vessel with potential to use existing seawater injection pumps to boost production. 
         [0048]    The unit provides a very reliable pumping function. Work-over frequency is therefore reduced and, in the event that work-over is required, the pump can be quickly pumped out and replaced. 
         [0049]    There are no temperature limitations in the hydraulic embodiment of the invention since no electric motor is required; the unit therefore has geothermal boosting potential. 
         [0050]    Once the unit is no longer required in the hole, it can be reverse pumped out of the hole or alternatively may be simply pulled out of the hole by a wireline fishing tool that can be latched to the top of the pump/fishing neck. 
         [0051]    The downhole pump of the present invention is “cable-less” i.e. it does not require a tubing string or wireline/electric-line to be deployed. 
         [0052]    High speed operation enables head gains. 
         [0053]    Seal-less technology; therefore, no pressure balance is required. 
         [0054]    With reference to  FIGS. 12 and 13 , in a further alternative embodiment of the invention an annular pump  210  comprises a rotating annular drive shaft  226  having a turbine arrangement  222  and a pump arrangement  224  mounted there-around. The turbine arrangement  222  is provided with turbine rotors  232  interspersed with turbine stators  233  within inner casing  239 . The pump arrangement comprises pump impellers  235 . A production tubing packer  237  seals the end of small diameter production tubing  238  and an outer casing packer  233  seals the annulus between the inner casing  239  and the outer casing  230  to form a casing annulus  241 . 
         [0055]    In use, the annular pump  210  is pumped down the casing annulus  241  in a similar pumping cycle as previously described for the previous embodiments. 
         [0056]    Although particular embodiments of the invention have been disclosed herein in detail, this has been done by way of example and for the purposes of illustration only. The aforementioned embodiments are not intended to be limiting with respect to the scope of the invention. 
         [0057]    It is contemplated by the inventor that various substitutions, alterations, and modifications may be made to the invention without departing from the spirit and scope of the invention. Examples of these include the following: 
         [0058]    The technology described above could also be applied to other submersible application (such as gas dewatering) and geothermal applications. 
         [0059]    The turbine arrangement in each described embodiment drives a corresponding “wet end” pump arrangement. In the embodiments described, the wet end comprises an axial flow pump; however, this could alternatively comprise any other type of suitable pump such as a centrifugal (radial) or mixed flow pump. 
         [0060]    Although the pump module  10 ,  110  of the above described embodiments is connected to a hydraulic pump unit powered by the power fluid, the pump module  10 ,  110  could alternatively be used with an Electric Submersible Pump (ESP). In this regard, the hollow central drive shaft  26  may also be used in ESP application whereby the production fluid is able to flow through the inner diameter of the shaft and other components of the electrical submersible pump, such as the motor. This provides a cooling effect which can help increase the lifetime of the ESP. 
         [0061]    The method described in the above embodiments utilises high pressure power fluid (liquid) in order to progress the unit into the well; however, high pressure gas could be used instead. In such a method, a gas powered turbine may be attached to the pump module. This application may be particularly suitable where excess gas is available at surface. 
         [0062]    The pump module may be attached to other downhole tools, such as logging equipment, in order to deploy those to an appropriate depth in a similar fashion. 
         [0063]    Another method of utilising the pump module of the invention may be to deploy several small dimension pumps directly into the well perforations/surrounding formation. This enables as much energy as possible to remain inside the reservoir and therefore improve well recovery rates.