GB2361017A

GB2361017A - Dual pump system

Info

Publication number: GB2361017A
Application number: GB0105974A
Authority: GB
Inventors: Paul Shotter
Original assignee: Pump Tools Ltd
Current assignee: Pump Tools Ltd
Priority date: 2000-03-10
Filing date: 2001-03-12
Publication date: 2001-10-10
Anticipated expiration: 2021-03-12
Also published as: GB2361017B; GB0105974D0; GB0005640D0

Abstract

A pump system for use downhole in an oil or gas well in pumping production fluid to surface, wherein the pump system comprises at least two pumps 2, 7 each pump having a fluid inlet selectively communicable with the production fluid and a fluid outlet or discharge selectively communicable with the production tubing. Each pump has its own drive motor, 3, 6, and there is valving 13, 15 to control the flow path of the production fluid. With the upper pump operative, flow is out of valve 13, up through annulus 14, into pump 2 and then up the production tube 1. When the lower pump is operated, the valve 13 is closed so that flow is into pump 7, from this pump into the annulus, and then through valve 15 into the production tube 1.

Description

2361017 1 1 "Dual Pump System" 2 3

This invention is in the field of oil production and relates particularly to apparatus and methodology for downhole use in an oil well.

4 5 6 7 In oil production, the crude oil is generally lifted 8 to the surface by means of a downhole pump driven by an electric motor. Such pumps are commonly referred to as Electrical Submersible Pumps or ESPs.

11 12 13 14 15 16 17 18 19 20 21 22 As is common to mechanical and electrical apparatus, these pumps, in time, can develop faults that render them inefficient or inoperable, necessitating their repair. In such cases the pump and its associated equipment require to be raised to the surface for maintenance or replacement. It will be appreciated that this leads to expensive discontinuation of the oil recovery, while also potentially requiring the withdrawal from the drill hole of substantial lengths of equipment.

2 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 According to a first aspect of the present invention there is provided a pump system for use downhole in an oil or gas well in pumping production fluid such as crude oil to surface typically via production tubing, wherein the pump system comprises at least two pumps, each pump having a fluid inlet selectively communicable with the production fluid and a fluid outlet or discharge selectively communicable with the production tubing.

Preferably, the two or more pumps are electrical submersible pumps, and each pump is associated with a respective motor. Electrical power may be fed to each motor via dedicated power cables suspended from surface.

Preferably also, the pump system further comprises an upper isolation means and a lower isolation means, wherein the upper and lower isolation means define an annular space therebetween and isolate said space from well bore fluids above the upper isolation means while also enabling fluid pressure in said space to be distinguished from production fluid below the lower isolation means.

The upper isolation means may be a retrievable packer and it may also be adapted to support weight associated with the pump system and production tubing. Typically the upper isolation means will have a plurality of mandrels for enabling through passage of production tubing and said power cables.

3 1 2 3 4 5 6 7 8 9 10 12 13 14 is 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 The lower isolation means may be a sump packer.

Also according to the present invention there is provided a pump system for use downhole in an oil or gas well in pumping production fluid such as crude oil to surface typically via production tubing, wherein the system comprises an upper and lower pump each having respective fluid intakes, wherein the system further comprises pump selection means for switching between a first flow path and a second flow path for said production fluid, wherein one of said first and second flow paths directs production fluid through one of said upper and lower pumps and the other of said flow paths directs the production fluid through the other of said upper and lower PUMPS - The pump selection means may include an upper valve associated with an inlet on the upper pump for selectively obturating fluid flow to said inlet of the upper pump, and a lower valve associated with an inlet on the lower pump for selectively obturating fluid flow to said inlet of the lower pump.

Also according to the present invention there is provided a pump system for use downhole in an oil or gas well, the pump system comprising at least two independent pumping units, each having an electrical submersible pump and motor, characterised in that either pumping unit may be individually and solely operated to pump production fluid in the well to surface.

4 1 2 3 4 6 7 8 9 11 12 13 14 16 17 18 19 21 22 23 24 26 27 28 29 31 To assist in understanding, Figs. 1 and 2 have been 32 included merely to demonstrate the prior art.

In order to provide a better understanding of the invention, an embodiment will now be described by way of example only, with reference to the accompanying figures, in which:- Fig. 1 illustrates a conventional electrical submersible pump installation forming part of the prior art;

Fig. 2 illustrates further prior art comprising coil tubing supporting an inverted electrical submersible pump installation;

Fig. 3 illustrates in elevation an example embodiment of a pump system; Fig. 4 shows the fluid flow path of the pump system of Fig. 3 in one mode of operating; Fig. 5 shows the fluid flow path of the pump system of Fig. 3 in an alternative mode of operation; Fig. 6 illustrates an alternative embodiment of a pump system; Fig. 7 shows an exemplary upper valve; and Fig. 8 shows an exemplary lower valve.

1 2 3 4 5 6 7 8 9 10 11 12 13 14 is 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 In Fig. 1 there is shown a pump unit comprising a pump A, seal section B and motor C. The pump unit is suspended in well bore casing D on production tubing E. The motor C is typically an electrical motor which is supplied with electrical power from surface by electrical cabling F. The pump A has a pump intake or inlet G adapted to receive production fluid being typically crude oil that enters the well bore casing D (or casing liner) through the perforations H. Fluid received into the pump A via the inlet G is then pumped to surface up the production tubing E.

Fig. 2 illustrates an alternative arrangement wherein the pump unit is inverted; that is to say, the motor J is positioned above the pump K. This type of arrangement is more suitable for use with coiled tubing L which isolates the power cable M from the production fluid flowing up the annulus between the coiled tubing L and casing N. With this system it will be seen therefore that the pump K discharges the pumped production fluid into the annulus and not directly into an inner string or production tubing. For this reason a seal or packer P is employed to divide the annulus between the pump inlet Q and pump discharge R.

It will be appreciated that with the pump systems known to the art and illustrated in Figs. 1 and 2, the production of oil from the well is entirely dependent upon the performance of the pump unit. if the pump fails to operate there is no other facility 6 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 readily available for pumping the production fluid to surface.

In Figs. 3 to 6 like parts or components are designated with the same reference numerals for ease of understanding and simplicity.

Referring firstly to Fig. 3, a pump system for use downhole in an oil well in pumping production fluid such as crude oil to surface via production tubing 1 comprises an upper pump unit and a lower pump unit. The upper pump unit is made up of a conventional electrical submersible pump 2 and motor 3. The pump 2 is positioned above the motor 3 and suspended from the production tubing 1. Electrical power is fed to the motor 3 via a dedicated power cable (not shown) reaching from the surface of the well to the submerged motor 3.

A retrievable packer 4 is set above the upper pump unit.

Suspended from the underside of the motor 3 and securely connected to the underside of the motor is a connection sub 5. The connection sub may be of any desired length and is adapted to connect the abovementioned upper pump unit with a lower pump unit. More specifically, the connection sub 5 securely connects the motor 3 (being part of the upper pump unit) and a second motor 6 (being part of the lower pump unit).

7 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 In the example embodiment illustrated in Fig. 3, the connection sub 5 incorporates an optional electrical conductor feedthrough, to enable power connections to the lower motor 6 via cable conductors fed from outside of the connection sub 5. In this respect the connection sub 5 also becomes a cable isolation sub. The cable isolation feature is utilised when the lower motor 6 is fed electrically via electrical connections at the top and centre of the lower motor 6, inside of the connection sub 5.

The second or lower pump unit comprises a lower pump 7 in combination with the abovementioned lower motor 6. The pump 7 and motor 6 are configured in an inverted manner.

In respect of both the upper pump unit and lower pump unit, respective seal sections 8 are provided between the pumps 2, 7 and motors 3, 6.

Both the upper pump 2 and lower pump 7 are provided with intakes, referenced 9 and 10 respectively in Fig. 3. In respect of the second pump 7 the pump intake 10 communicates with a tubular extension or stinger which protrudes from the bottom of the pump 7. The intake of the tubular extension 11 is inserted into a permanent sump packer 12 with a polished bore receptacle, which accepts the intake of the tubular extension 11 and thereby permits production fluid to enter the pump intake 10 from under the packer 12. Furthermore, the tubular 8 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 extension 11 prevents passage of fluid into the pump intake 10 from above the packer 12.

Fitted into the tubular extension 11 is a valve having a side door arrangement 13. The valve may a simple form be a side door in the tubular. The valve 13 is located above the packer 12 and below the pump 7.

The purpose of the valve 13 in the tubular extension 11 is to direct production fluid from under the packer 12 which travels up through the tubular extension 11 into two possible routes, firstly, directly into the pump intake 10 of the lower pump 7 or, secondly, to divert the production fluid rising up the tubular extension 11 into the well bore annulus 14 above the packer 12.

Seals may be provided to prevent fluid leakage into a destination not selected.

Means, known to those skilled in the art, may be employed to automatically activate the valve 13. For example, an operator may "pressure up" a mechanical spring mechanism or hydraulic means, or alternatively there may be a separate control line provided for this purpose. Using such means, an operator may select which of the above two routes or flow paths to be taken by the production fluid.

Towards the upper end of the pump system is provided an additional valve 15. The upper valve 15 is 9 1 2 3 4 6 7 8 9 10 11 12 13 14 is 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 located between the upper retrievable packer 4 and the upper pump 2. The upper valve 15 can also provide for two settings:

1. To provide communication of well fluid from the annulus 14 between the upper packer 4 and sump packer 12 into the production tubing 1 to allow communication of the production fluid via the production tubing 1 to surface; 2. To provide communication from the discharge 16 of the upper pump 2 up the production tubing 1 to surface.

Typically when the upper valve 15 is in the first of the aforementioned settings, fluid entering the production tubing 1 through the side door 15 is prohibited from passing back down the production tubing and into the discharge 16 of the upper pump 2.

The operation of the pump system has two modes, depending on whether the upper pump 2 or lower pump 7 is utilised. Fig. 4 demonstrates operation of the pump system using the upper pumping unit. In this case, the upper valve 15 is closed to prevent passage of fluid from the annulus 14 into the production tubing 1. This allows fluid flow through the upper pump discharge 16 into the production tubing 1 to surface.

1 2 3 4 6 7 8 9 10 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 The lower valve 12 is opened to the annulus 14 thereby allowing fluids entering the tubular extension 11 from under the sump packer 12 to pass into the annulus 14 between the casing and the pumping units above the sump packer 12 and then to flow upward and around the lower pump unit 7 and into the intake 9 of the upper pump 2. In this setting the lower valve 13 prevents fluid communication between the intake 10 of the lower pump unit 7, and the tubing below the valve 13.

The fluid in the annulus between the two packers 4, 12 is at reservoir pressure, and the upper pump unit 2 can operate normally.

Operation of the lower pump unit is illustrated in Fig. 5. The lower valve 13 is set closed in the opposite attitude to that described above and therefore will direct fluid entering the tubular extension 11 into the intake 10 of the lower pump 7 rather than into the annulus 14. The upper valve 15 is set open in the opposite attitude to that required for operating the upper pump and therefore will allow passage of fluid from outside the pumping system, that is the from the annulus 14, into the production tubing 1 and on to surface. Fluid is prevented from passing up the annulus 14 to surface by the retrievable packer 4. The packer 4 can be set in the main casing or in a casing liner. Communication between the production tubing 1 and the upper pump 2 is shut off by the upper valve 15.

1 2 3 4 6 7 8 11 12 13 14 is 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 During the operation fluid is directed into the intake 10 of the lower pump 7 and discharged through its outlet 7o at pump pressure into the annulus 14. The fluid in the annulus 14 is able to enter the production tubing 1 via the upper valve 15. No communication is allowed back down through the upper pump 2 and re-circulation is therefore avoided.

In Fig. 6 an alternative embodiment of the pump system is illustrated in which power cables 20, 21 are depicted. The power cables 20, 21 supply power to the upper motor 22 and lower motor 23 respectively.

In an embodiment where the lower motor has its electrical connection around the diameter of the motor and not at the top end and therefore outside of the connection sub, the connection sub need not incorporate the cable isolation sub feature as previously described herein.

Referring now to the Figs. 7 and 8, an upper valve assembly comprises a body having upper and lower subs 30 and 31 connected together by box and pin joints as is known in the art. The upper sub 30 houses a shuttle 32 that slides axially within the upper sub 30 between a first position shown on the left hand side of Fig. 7 and a second position shown on the right hand side of Fig. 7. The shuttle 32 is sealed to the upper sub 30 by 0-rings 33a, b, and c, and at its lower end has a further set of 0- rings 34 for sealing to a narrowed portion of the lower sub 12 1 2 3 4 6 7 8 11 12 13 14 is 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 31. The shuttle 32 has an axial bore closed off at the lower end but with an internal flow port 35 adjacent the lower end above the 0-ring seal 34 which communicates with the axial bore of the shuttle 32. When the shuttle 32 is in the first position, the 0-rings 34 are clear of the lower sub 31 and fluid flowing through the lower sub 31 flows into the annulus between the shuttle 34 and the upper sub 30 and through the internal flow port 35 in the shuttle. From there the fluid can flow through the shuttle 32 and upward to the production tubing (not shown) to which the upper sub 30 is connected.

The shuttle 32 has a second flow port 36 which is sealed off against the upper sub 30 by 0-rings 33b and c when the shuttle 32 is in the upper first position. A shear pin S maintains the shuttle 32 in the upper position as shown on the left-hand side of Fig. 7.

A hydraulic pressure line 37 from surface communicates with a signal port 38 through the upper sub 30, and pressuring up on the hydraulic line 37 increases the pressure within an annular chamber between the shuttle 32 and the upper sub 30 so as to break the shear pin S and drive the shuttle 32 into the second position. In the second position, which is shown on the right hand side of Fig. 7, the lower 0-rings 34 engage with a neck region of the lower sub 31 thereby denying access of fluid from below through the internal flow port 35. However, as the 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 1 shuttle 32 moves down within the subs, the 0-rings 2 sealing off the second flow port 36 move down to permit communication of the through port 36 with an external port 39 in the upper sub 30, thereby permitting fluid from the annulus between the subs 30, 31 and the casing to flow through the ports 37 and 36 into the bore of the shuttle 32 and upwards into the production tubing (not shown) above. Fluid flow downward through the shuttle 32 is prevented by the blind end adjacent to the 0-rings 34.

It will be appreciated that the 0-ring seals can be substituted for Chevron or lip-type seals as required.

The lower valve assembly is similar in nature and is shown in Fig. 8. The lower valve assembly also has an upper sub 40 and a lower sub 41, a shuttle 42 that is sealed at 43a, b, c and d to the upper sub 40. The orientation of the shuttle 42 is inverted as compared to the shuttle 32, with a blind upper end adjacent the 0-rings 43a, which engage with a narrow neck portion of the upper sub 40. There is an axial bore in the shuttle 42, which can also move from a first position shown in the left hand side of Fig. 8 to a second (lower) position shown on the right hand side of Fig. 8 when actuated by a hydraulic control line 38 supplying pressure to an annular chamber as described above.

When in the first upper position, a shear pin S' holds the shuttle 42 up so that the top of the 14 2 3 4 5 6 7 8 11 12 13 14 is 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 1 shuttle 42 engages in the narrow neck region of the upper sub 40 and the 0-ring seal 43a and blind ending of the shuttle 42 prevents fluid flow through the bore of the sub 40. Fluid can flow through the lower sub 41 into the open lower end of the shuttle 42 and out through a shuttle flow port 46 and external port 47 into the annulus between the upper sub 40 and the casing (not shown). When pressure is applied through the hydraulic line 38, sufficient to shear the pin S' and drive the shuttle 42 downwards, the seals 43c and d blank off the flow port 47 through the upper sub 40 and deny passage of fluid from the bore of the shuttle 42 into the annulus. Instead, the fluid flows straight up through the bore of the shuttle 42 and into the annulus between the shuttle 42 and the upper sub 40. As the upper 0-ring seal 43a has now been disengaged from the narrow neck region of the sub 40, the fluid can flow upwards through the bore of the sub 40 without restriction.

A single pressure source can optionally supply the lines to activate both of the shuttles to their second positions, and as they are inverted in relation to one another this simultaneously opens one and closes the other, in this embodiment.

Certain embodiments of the invention permit the installation of a dualpump system in a fairly narrow bore e.g. 7" or 5 5/8n casing. This is achieved by virtue of the fact that the annulus between the pumps and the casing can be used as a is 2 3 4 5 6 7 8 9 11 flowpath. This also permits larger diameter pumps to be installed. Certain embodiments of the invention permit operation of the pumps without wireline intervention. Certain other embodiments also shut off the inoperative valve from the fluid pathway, thereby reducing pump wear through idling while inoperative.

As with the upper valve, the 0-ring seals can be substituted for other types without departing from the scope of the invention.

16

Claims

1 Claims:

2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 191 20 21 22 23 24 25 26 27 28 29 30 31 32 A pump system for use downhole in an oil or gas well in pumping production fluid to surface, wherein the pump system comprises at least two pumps, each pump having a fluid inlet selectively communicable with the production fluid and a fluid outlet or discharge selectively communicable with the production tubing.

2.

3.

4.

A pump system as claimed in claim 1, wherein each pump is associated with a respective motor.

A pump system as claimed in claim 1 or claim 2, wherein each pump is electrically powered.

A pump system as claimed in any preceding claim, having an upper isolation means and a lower isolation means, wherein the upper and lower isolation means define an annular space therebetween.

5. A pump system as claimed in claim 4, wherein the isolating means isolates the annular space from well bore fluids above and/or below the isolation means.

A pump system as claimed in claim 4 or claim 5, wherein the isolating means enables fluid pressure in the annular space to be 1 distinguished from fluid pressure above and/or 2 below the lower isolation means.

3 4 7. A pump system as claimed in any one of claims

6

7

8 8.

9 11 12 13 9.

14 is 16 17 18 19 21 22 23 24 26 27 28 29 31 32 4, 5 or 6, wherein the upper isolation means comprises a packer.

A pump system as claimed in any one of claims 4-7, wherein the isolation means is adapted to support weight associated with the pump system and production tubing.

A pump system as claimed in any one of claims 4-8, wherein the isolation means has one or more channels for through passage of power, signal and fluid conduits.

10. A pump system as claimed in any one of claims 4-9, wherein the lower isolation means comprises a sump packer.

11. A pump system as claimed in any preceding claim, having selection means to control the fluid flow through the pumps.

12. A pump system as claimed in any preceding claim, wherein at least one of the pumps is controlled by pressure supplied through a hydraulic control line.

13. A pump system as claimed in any preceding claim, wherein at least one of the pumps is 18 1 2 3 4 5 6 7 8 9 10 11 12 13 14 is 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 controlled by electrical and/or electronic signals.

14. A pump system for use downhole in an oil or gas well in pumping production fluid to surface, wherein the system comprises an upper and lower pump each having respective fluid intakes; and pump selection means for switching between a first flow path and a second flow path for said production fluid; wherein one of said first and second flow paths directs production fluid through one of said upper and lower pumps and the other of said flow paths directs the production fluid through the other of said upper and lower pumps.

15. A pump system as claimed in claim 14, wherein the pump selection means has an upper valve associated with an inlet on the upper pump for selectively obturating fluid flow to said inlet of the upper pump, and a lower valve associated with an inlet on the lower pump for selectively obturating fluid flow to said inlet of the lower pump.

16. A pump system for use downhole in an oil or gas well, the pump system comprising at least two independent pumping units, each having an electrical submersible pump and motor, characterised in that either pumping unit may be individually and solely operated to pump production fluid in the well to surface.

19 1 2 3 4 5 6 7

17. A pump system according to any preceding claim, having a fluid flowpath comprising an annulus between at least one of the pumps and a tubular.

18. A pump system as hereinbefore described with reference to any one of Figs. 3 to 8.