WO2013011307A2

WO2013011307A2 - A pump and a method of positioning a pump

Info

Publication number: WO2013011307A2
Application number: PCT/GB2012/051712
Authority: WO
Inventors: Jamie LINDSAY
Original assignee: Downhole Energy Ltd
Priority date: 2011-07-20
Filing date: 2012-07-18
Publication date: 2013-01-24
Also published as: US20140205469A1; WO2013011307A3; GB201112460D0

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

A Pump and a Method of Positioning a Pump

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.

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.

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.

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. 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. Further features and advantages of the first, second and third aspects of the present invention will become apparent from the attached claims and the following description.

Embodiments of the present invention will now be described by way of example only, with reference to the following diagrams, in which:-

Fig. 1 is a perspective cut-away illustration of a pump-in module of a pump in accordance with the present invention;

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 S1 , S2 in order to improve clarity;

Fig. 3 is a further schematic transverse illustration of the pump in position within production tubing;

Fig. 4 is a perspective transverse illustration of the apparatus of Fig. 3;

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;

Fig. 6 is an illustration of the flow patterns within and around the in use; Fig. 7 is a more detailed illustration of the impeller and stator stages of the pump portion of Fig. 6; Fig. 8 is a more detailed illustration of the turbine rotors and stators of Fig. 6;

Fig. 9 is an illustration of a pump according to an alternative embodiment of the invention;

Fig. 10 is an illustration of pre-prepared tubing and casing ready to accept the pump of Fig. 9 therein;

Fig. 1 1 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;

Fig. 12 is a perspective illustration of an annular pump according to a further embodiment of the invention; and

Fig. 13 is a transverse cross section of the annular pump of Fig. 12.

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.

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. The restricted bore provided by the nozzle section 16 helps to increase the pressure acting upon the inserts 14 by increasing the pressure there-against for any given pressure of power / pump fluid. 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.

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.

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.

The central drive shaft 26 has a solid section 26A around which the impeller blades 36 are arranged and a hollow section 26B around which the turbine rotors 32 are arranged. The internal diameter of the hollow section 26B 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. At zone A (Fig. 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. This provides a fluid flow path between the mixing chamber 40 and the internal diameter of the hollow drive shaft 26B.

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.

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.

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.

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 (which could be exiting 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. 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.

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.

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 Fig. 6 to 8, operation of the pump unit 20 once in position in the well will now be described. Power fluid is pumped into the annulus between the existing casing 30 and the existing production tubing 28 illustrated as flow F1 . The power fluid then enters the turbine as flow F2 via a port or other aperture in the wall of the production tubing 28. The power fluid then progresses through the turbine stages as F3 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 P4 into the pump 24. Production fluid then flows up through the stages of the impeller arrangement 24 as flow P5.

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 26B 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 26B as co-mingled flow M1 . The co-mingled flow is then exhausted out of the pump module 10 via an exit aperture (not shown) as M2 before passing up the inner diameter of the production tubing 28 as co-mingled flow M3 for separation / further processing.

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.

Referring now to Figs. 9, 10 and 1 1 , an alternative embodiment of the invention will now be described where a pump module 1 10 comprises a series of seals 1 14 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. 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.

The process of deploying the pump module 1 10 and attached pump unit of the present embodiment is substantially similar to that previously described for the first embodiment.

With the pump module 1 10 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.

With particular reference to Fig. 1 1 , operation of the pump unit once in position in the well will now be described. Power fluid (which may be liquid or gas) is pumped into the annulus 139 as flow F1 . The power fluid then enters the turbine as flows F2 via the communication port 131 and flow inlets 137. The power fluid then progresses through the turbine stages (not shown in Fig. 1 1 ) 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 P4 into the pump 124. Production fluid will then flow up through the progressive stages of the impeller arrangement (not shown). 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 M1 before being passed up the inner diameter of the tubing 128 to the surface / separator equipment for further processing.

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;-

No expensive power cable is required; therefore costs are reduced since the unit is powered by pumping fluid from the surface.

No tubing string is required to run the pump into the well; costs are reduced.

No rig or wireline unit required; costs are reduced. The unit is deployed from a small truck and surface pump; costs are reduced.

The unit can be deployed quickly subsea from a vessel with potential to use existing seawater injection pumps to boost production.

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.

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.

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.

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.

High speed operation enables head gains.

- Seal-less technology; therefore, no pressure balance is required. 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 .

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.

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 appended claims.

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 as defined by the claims. Examples of these include the following :-

The technology described above could also be applied to other submersible application (such as gas dewatering) and geothermal applications.

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. Although the pump module 10, 1 10 of the above described embodiments is connected to a hydraulic pump unit powered by the power fluid, the pump module 10, 1 10 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.

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. 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.

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.

Claims

1 . 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.

2. A method according to claim 1 , wherein the step of increasing and removing the pressure differential across the pump comprises a cycle of consecutive increases and decreases in order to progressively pulse the pump into the well.

3. A method according to either of claim 1 or 2, wherein the method comprises pumping a centrifugal pump into the well.

4. A method according to any preceding claim, wherein the step of increasing the pressure differential across the pump comprises increasing the pressure of power liquid within an annulus between production tubing and the well casing.

5. A method according to any of claims 1 to 3, wherein the step of increasing the pressure differential across the pump comprises increasing the pressure of a gas within an annulus between production tubing and the well casing.

6. 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.

7. A pump according to claim 6, wherein the pump is adapted to be pumped within production tubing of the well.

8. A pump according to claim 6, wherein the pump is adapted to be pumped within an annulus between production tubing and inner casing of the well.

9. A pump according to any of claims 6 to 8, wherein the pump comprises a hydraulic submersible pump..

10. A pump according to any of claims 6 to 8, wherein the pump comprises a centrifugal pump.

1 1 . A pump according to any of claims 6 to 10, wherein the pump comprises a turbine arrangement connected to a pumping unit by way of a drive shaft.

12. A pump according to claim 1 1 , wherein the drive shaft has at least a hollow portion and an aperture therein to allow comingled power fluid and production fluid to flow along the interior of the drive shaft.

13. A pump according to any of claims 6 to 12, wherein the frictional engagement means comprise at least a resilient insert.

14. A pump according to claim 13, wherein the resilient insert comprises a series of tapered members provided around the outer surface of a portion of the pump.

15. A pump according to claim 14, wherein the or each resilient insert comprises pressure sensitive pockets in order to control the magnitude of frictional

engagement with the well and hence the rate of movement of the pump within the well.

16. 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.

17. A submersible pump according to claim 16, wherein the drive shaft is provided with at least a fluid flow inlet at one end of the fluid flow passage and at least a fluid flow outlet at the other end of the fluid flow passage.

18. A submersible pump according to claim 17, wherein the fluid flow inlet comprises an aperture through the wall of the hollow portion of the drive shaft between the turbine arrangement and pump arrangement.