PROTECTION OF ELECTRIC SUBMERSIBLE PUMP WHILE RUNNING AND RETRIEVING

Abstract

A method for use with a subterranean well can include connecting a tool in a tubing string uphole of an electric submersible pump, the tool including a frangible barrier and a valve, and installing the tubing string in the well, the frangible barrier preventing flow through a central flow passage of the tubing string, and the valve preventing fluid communication between the central flow passage and an annulus external to the tubing string. A system for use with a subterranean well can include an electric submersible pump, a valve connected uphole of the electric submersible pump, the valve selectively preventing and permitting fluid communication between a central flow passage extending through the valve and an annulus external to the valve, and a frangible barrier connected uphole of the electric submersible pump, the frangible barrier preventing fluid flow through the central flow passage.

Description

BACKGROUND

This disclosure relates generally to equipment utilized and operations performed in conjunction with a subterranean well and, in an example described below, more particularly provides for protection of an electric submersible pump while running and retrieving a tubing string.

An electric submersible pump is used in a well to lift produced fluids to surface. A pump and an electric motor of an electric submersible pump are typically connected at or near a downhole end of a production tubing string that extends to the surface. Produced fluids are received into an inlet of the pump, and the motor drives the pump, so that the fluids are flowed through an interior of the production tubing string to the surface.

It is time-consuming and expensive to install or retrieve a production tubing string into or out of a well. For at least this reason, it is important that the electric submersible pump is capable of surviving installation in the well, and is capable of operation for long periods of time thereafter.

It will, therefore, be readily appreciated that improvements are continually needed in the art of designing, constructing and utilizing systems and methods for pumping produced fluids from subterranean wells. The present disclosure provides such improvements, which may be used in a wide variety of different well configurations.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a representative partially cross-sectional view of an example of a well system and associated method which can embody principles of this disclosure.

FIG. 2 is a representative side view of an example of a pump and motor protection tool that may be used with the FIG. 1 system and method.

FIG. 3 is a representative cross-sectional view of the pump and motor protection tool, taken along line 3-3 of FIG. 2.

FIG. 4 is a representative cross-sectional view of a frangible barrier housing portion of the pump and motor protection tool.

FIG. 5 is a representative cross-sectional view of an example of a surge valve that may be used with the pump and motor protection tool in an open configuration.

FIG. 6 is a representative cross-sectional view of the surge valve in a closed configuration.

FIG. 7 is a representative cross-sectional view of the surge valve in a pumped open configuration.

FIG. 8 is a representative cross-sectional view of an example of a sliding sleeve valve portion of the pump and motor protection tool in an open configuration of the valve.

DETAILED DESCRIPTION

Representatively illustrated in FIG. 1 is a system 10 and associated method which can embody principles of this disclosure. However, it should be clearly understood that the system 10 and method are merely one example of an application of the principles of this disclosure in practice, and a wide variety of other examples are possible. Therefore, the scope of this disclosure is not limited at all to the details of the system 10 and method described herein and/or depicted in the drawings.

The system 10 can in some examples be used to eliminate the installation of blanking plugs while running an electric submersible pump (ESP, for example, including a permanent magnet motor), and eliminate a slickline trip to recover the plug. The system 10 can provide at least two safety barriers for protection of the permanent magnet motor. However, the scope of this disclosure is not limited to only this use of the system 10, since the system can be used with other types of ESP's for other purposes.

It is desired to prevent fluid flow through the pump when the pump and motor are installed with production tubing in a well. This will help to mitigate any damage to the pump and motor due to such fluid flow.

While running the production tubing string, including the pump and the electric motor, the frangible barrier (such as, a ceramic or glass disk or dome) will act as a plug to prevent fluid flow through the production tubing above the pump. For example, the frangible barrier may have a rating of 10,000 psi differential pressure from the pump uphole, and 1,000 psi differential pressure to rupture it from uphole to downhole of the frangible barrier.

If it is desired to test the production tubing, a dissolvable or stainless steel ball can be deployed into the production tubing to check integrity, or a double disk can be implemented to accomplish this. When it is desired to produce fluids from the well, the frangible barrier can be broken hydraulically by applying pressure to the production tubing from the surface to burst or break the frangible barrier, or by dropping an object from surface. However, the scope of this disclosure is not limited to any particular method or means used to open or breach the frangible barrier.

After the frangible barrier is opened, the motor can be activated (such as, via electrical power conducted through an umbilical extending from the motor to the surface) to thereby operate the pump. Well fluids will then enter an intake and be pumped by the pump into the production tubing and to the surface.

When it is desired to retrieve the pump and motor with the production tubing, a dart or other plugging device can be deployed into the production tubing from the surface. The plugging device will seat in a sleeve of a sliding sleeve valve. Pressure can be applied to the production tubing at the surface to thereby shear pins or other retainers (such as, a shear ring, collets, detents, etc.) and shift the sleeve downward.

When the sleeve is shifted, so that the valve is opened, the plugging device still blocks fluid flow axially through the sleeve. Thus, fluid in the production tubing is allowed to drain from the tubing while it is retrieved from the well, but fluid flow through the pump below the sleeve is blocked. In this manner, the pump and motor are not damaged by fluid flow as the production tubing is retrieved from the well. The system thereby provides a fluid path of least resistance to prevent the motor from spinning during its retrieval.

The sleeve is preferably pressure balanced axially, until the plugging device is installed. This eliminates premature shearing of the pins or release of another retainer.

In the FIG. 1 example, a pump and motor protection tool 12 is connected as part of a production tubing string 14. The tubing string 14 is installed in a well, so that an annulus 16 is formed between the tubing string and a wellbore 18.

In this example, the wellbore 18 is lined with casing 20 and cement 22, but in other examples, the tubing string 14 could extend into an uncased or open hole section of the wellbore. Perforations 24 are formed through the casing 20 and cement 22 to permit fluids 26 to flow into the wellbore 18.

As depicted in FIG. 1, an electric submersible pump 28 is connected at a downhole end of the tubing string 14. The ESP 28 includes an intake 30 to receive the fluids 26 therein, a motor 32 and a pump 34. An electric umbilical 36 extends to the surface for supplying electrical power to the motor 32 to drive the pump 34.

When the pump 34 is operated, the fluids 26 are discharged from the pump into the tubing string 14 uphole of the pump, and the fluids flow to the surface through a central flow passage of the tubing string. However, before the ESP 28 is used to produce the fluids 26 to the surface, it is advantageous to prevent the pump 34 from spinning due to fluid flow through the pump (for example, during installation of the tubing string 14). The tool 12 is used in the system 10 to prevent such undesirable spinning of the pump 34, or for safety in case a well kicks while running the tubing string 14 and pump.

Additional tools connected in the tubing string 14 in the FIG. 1 example can include a surge valve 38 and a sand lift tool 40 connected between the ESP 28 and the tool 12. The sand lift tool 40 may be the same as or similar to the sand lift tool described in U.S. Pat. No. 11,434,723. Different tools and other combinations or configurations of tools may be connected in the tubing string 14 in other examples.

Referring additionally now to FIG. 2, a representative side view of an example of the pump and motor protection tool 12 is depicted. For convenience, the tool 12 is described below as it may be used with the FIG. 1 system 10 and method, but the tool 12 may be used with other systems and methods in other examples.

As depicted in FIG. 2, the tool 12 includes a frangible barrier sub 42 connected uphole of a sliding sleeve-type valve 44. In other examples, the valve 44 could be connected uphole of the frangible barrier sub 42.

As described more fully below, the frangible barrier sub 42 prevents fluid flow through the central flow passage of the tubing string 14, until the frangible barrier is opened (such as, by breaking or rupturing the frangible barrier). The valve 44 prevents fluid communication between the central flow passage and the annulus 16 external to the tubing string 14, until the valve is opened. When the valve 44 is opened, fluid flow is permitted between the central flow passage and the annulus 16 via openings 46 formed through an outer housing 48 of the valve.

Referring additionally now to FIG. 3, a representative cross-sectional view of the pump and motor protection tool 12, taken along line 3-3 of FIG. 2, is depicted. In this view, the tool 12 is in a run-in configuration in which the tool is installed in a well with the rest of the tubing string 14.

In the FIG. 3 example, the frangible barrier sub 42 includes a frangible barrier 50 sealingly mounted in an outer housing assembly 52. In the run-in configuration of FIG. 3, the frangible barrier 50 prevents fluid flow through the central flow passage 54 in the outer housing assembly 52.

The frangible barrier 50 may be made of a ceramic or another breakable or dissolvable material. In other examples, a burst disc or other openable barrier may be used.

The frangible barrier 50 may be configured to withstand a pressure differential from downhole to uphole in the central flow passage 54 that is greater than a pressure differential level from uphole to downhole at which the frangible barrier will open. For example, if hydrostatic pressure at the tool 12 is expected to be about 7,000 psi, the frangible barrier 50 may be designed to withstand 10,000 psi from downhole to uphole, so that the tubing string 14 uphole of the frangible barrier can remain completely or partially empty while the tubing string is installed.

After installation of the tubing string 14, the tubing string can be filled to the surface above the frangible barrier 50. Then, a suitable increase of pressure (such as, about 1,000 psi) can be applied to the tubing string 14 uphole of the frangible barrier 50 to thereby open the frangible barrier when desired.

In this manner, the ESP 28 is protected from being caused to spin while the tubing string 14 is installed in the well. After installation of the tubing string 14, the frangible barrier 50 can be conveniently opened, thereby allowing the ESP 28 to pump the fluids 26 to the surface via the central flow passage 54.

As depicted in FIG. 3, the valve 44 includes a sliding sleeve 56 sealingly received in the outer housing 48. The sleeve 56 is retained in position by shear screws 58 (or other suitable retaining members, such as, a shear ring, collets, a snap ring, etc.).

In the FIG. 3 run-in configuration, the sleeve 56 prevents fluid flow through the openings 46 (see FIG. 2) in the outer housing 48. Thus, fluid communication between the central flow passage 54 and the annulus 16 external to the valve 44 is prevented.

Referring additionally now to FIG. 4, a representative cross-sectional view of the frangible barrier housing assembly 52 portion of the pump and motor protection tool 12 is depicted. In this view, the frangible barrier 50 (see FIG. 3) has been opened, thereby permitting the pump 34 to flow the fluids 26 to the surface via the flow passage 54.

In the FIG. 4 example, the frangible barrier 50 can be opened by increasing pressure in the tubing string 14 uphole of the frangible barrier (e.g., by applying pressure to the tubing string at the surface). When a predetermined pressure differential from uphole to downhole of the frangible barrier 50 is achieved, the frangible barrier opens. The ESP 28 can then be operated to pump the fluids 26 through the flow passage 54 to the surface.

Referring additionally now to FIG. 5, a representative cross-sectional view of an example of the surge valve 38 in an open configuration is depicted. In this configuration, the surge valve 38 permits fluid flow in an uphole direction through the flow passage 54, for example, from the pump 34 to the surface.

As depicted in FIG. 5, the surge valve 38 includes a closure member 60 (such as, a ball, a flapper, etc.) and an annular seat 62 contained in an outer housing 64. The seat 62 is biased upward (as viewed in FIG. 5) by a biasing device 66 (such as, one or more springs, compressed gas or fluid, an elastomeric material, etc.). against a shoulder 68 formed in the outer housing 64.

An inner tubular support 70 is secured in the outer housing 64, so that its upper end is below or downhole of a seal surface 72 of the seat 62 configured to sealingly engage the closure member 60. Vanes or another suitable structure 74 is positioned in the outer housing 64 to prevent the closure member 60 from being displaced uphole and out of the housing by the fluid flow in the uphole direction.

As mentioned above, the surge valve 38 permits fluid flow in the uphole direction when the pump 34 flows the fluids 26 to the surface via the tubing string 14. In addition, the surge valve 38 permits the tubing string 14 downhole of the frangible barrier 50 to fill while the tubing string is being installed in the well.

Referring additionally now to FIG. 6, a representative cross-sectional view of the surge valve 38 in a closed configuration is depicted. In the closed configuration, the surge valve 38 prevents fluid flow in a downhole direction through the flow passage 54. This prevents inadvertent back-flow of fluid through the tubing string 14 to the pump 34 after the frangible barrier 50 has been opened.

Referring additionally now to FIG. 7, a representative cross-sectional view of the surge valve 38 in a pumped open configuration is depicted. In this configuration, fluid 74 can be flowed in a downhole direction through the surge valve 38 when desired, for example, to flush debris out of the ESP 28.

As depicted in FIG. 7, pressure has been applied in the tubing string 14 uphole of the surge valve 38 (e.g., pressure applied to the flow passage 54 at the surface), so that a predetermined pressure differential is created from uphole to downhole of the closure member 60 and the seat 62. This pressure differential overcomes the biasing force exerted by the biasing device 66, thereby causing the seat 62 to displace downward and out of sealing engagement with the closure member 60.

The closure member 60 is prevented from displacing downward with the seat 62 by the support 70. Recesses 78 formed in an upper end of the support 70 permit the fluid 76 to flow past the closure member 60 into the flow passage 54 downhole of the closure member.

When it is no longer desired to flow the fluid 76 downhole through the surge valve 38, the pressure differential across the closure member 60 and seat 62 is relieved. The biasing device 66 will then return the seat 62 to its FIG. 6 position abutting the shoulder 68. When the pump 34 is again operated, the surge valve 38 will permit flow of the fluids 26 in the uphole direction (see FIG. 5).

Referring additionally now to FIG. 8, a representative cross-sectional view of the sliding sleeve valve 44 is depicted in an open configuration. The valve 44 is preferably opened prior to removing the tubing string 14 from the well.

As depicted in FIG. 4, a dart or other type of plug 80 (such as, a ball, etc.) has been deployed into the tubing string 14, until the plug is sealingly engaged in the sleeve 56. Increased pressure is applied to the tubing string 14 uphole of the plug 80, so that a predetermined pressure differential is achieved across the plug and the sleeve 56.

The shear screws 58 shear when the predetermined pressure differential is applied, and the sleeve 56 is displaced downward to the FIG. 8 open position. In the open position, fluid communication is permitted between the flow passage 54 and the annulus 16 external to the valve 44 via the openings 46. In this manner, the tubing string 14 can drain while it is being removed from the well.

Note that the plug 80 remains sealingly engaged in the sleeve 56, thereby continually preventing fluid flow to the pump 34 via the flow passage 54 while the tubing string 14 is removed from the well. The plug 80 may be provided with collets, a latch, resilient members or other devices (not shown) to retain the plug in the sleeve 56 while the tubing string 14 is being removed.

As an additional barrier to fluid flow to the pump 34 through the flow passage 54 while the tubing string 14 is being removed from the well, the surge valve 38 will be in the FIG. 6 closed configuration. Thus, both of the plug 80 and the closure member 60 will block fluid flow in a downhole direction through the flow passage 54 to the pump 34 during retrieval of the tubing string 14.

However, note that use of the surge valve 38 is not necessary for protection of the ESP 28 during installation and removal of the tubing string 14. The pump and motor protection tool 12 can be used in some examples, without the surge valve 38 also being used.

It may now be fully appreciated that the above disclosure provides significant benefits to the art of designing, constructing and utilizing systems and methods for pumping produced fluids from subterranean wells. In examples described above, the tool 12 can prevent the pump 34 from spinning during installation and removal of the tubing string 14. The surge valve 38 provides for flushing the ESP 28, and also provides an additional barrier to flow through the flow passage 54 while the tubing string 14 is being removed from the well.

A system 10 and method are described above, in which a frangible barrier 50 blocks axial fluid flow between the surface and an electric submersible pump 28 when a production tubing string 14 is installed in a well. A valve 44 blocks fluid flow between an interior of the production tubing string 14 and an annulus 16 external to the valve 44 when the production tubing string 14 is installed in the well.

The frangible barrier 50 may be opened to thereby permit fluid flow from the pump 34 to the surface. The valve 44 may be opened to thereby permit fluid flow from the interior of the production tubing string 14 to the annulus 16 when the pump 34 is retrieved to the surface.

A plug 80 is installed in the valve 44, in order to open the valve 44. The plug 80 permits the fluid flow from the interior of the production tubing string 14 to the annulus 16 when the valve 44 is open, but the plug 80 blocks fluid flow to the pump 34 via the interior of the production tubing string 14. Pressure is applied to the interior of the production tubing string 14 to thereby shift the plug 80 and sleeve 56 to an open position, in order to open the valve 44.

The frangible barrier 50 may be opened by dropping an object into the production tubing string 14 to thereby impact the frangible barrier 50. Alternatively, pressure can be applied to the production tubing string 14 to thereby open the frangible barrier 50.

The above disclosure provides to the art a method for use with a subterranean well. In one example, the method can include: connecting a tool 12 in a tubing string 14 uphole of an electric submersible pump 28, the tool 12 comprising a frangible barrier 50 and a first valve 44; and installing the tubing string 14 in the well, the frangible barrier 50 preventing flow through a central flow passage 54 of the tubing string 14, and the first valve 44 preventing fluid communication between the central flow passage 54 and an annulus 16 external to the tubing string 14.

In the installing step, the frangible barrier 50 may be positioned uphole of the first valve 44.

The method may include opening the frangible barrier 50, thereby permitting fluid flow from the electric submersible pump 28 through the tubing string 14. The frangible barrier 50 opening step may include breaking the frangible barrier 50. The frangible barrier 50 opening step may include increasing pressure in the central flow passage 54 uphole of the frangible barrier 50.

The method may include, after the frangible barrier 50 opening step, opening the first valve 44, thereby permitting fluid communication between the central flow passage 54 and the annulus 16. The first valve 44 may be opened prior to withdrawing the tubing string 14 from the well. The first valve 44 opening step may include preventing fluid flow through the central flow passage 54 in the first valve 44.

The connecting step may include connecting a second valve 38 between the electric submersible pump 28 and the first valve 44. The second valve 38 may be configured to permit fluid flow through the central flow passage 54 from the electric submersible pump 28, and to prevent fluid flow through the central flow passage 54 to the electric submersible pump 28.

The method may include increasing pressure in the central flow passage 54 uphole of the second valve 38 to a predetermined pressure level, thereby permitting fluid flow through the second valve 38 to the electric submersible pump 28.

The above disclosure also provides to the art a system 10 for use with a subterranean well. In one example, the system 10 can include: an electric submersible pump 28; a first valve 44 connected uphole of the electric submersible pump 28, the first valve 44 selectively preventing and permitting fluid communication between a central flow passage 54 extending through the first valve 44 and an annulus 16 external to the first valve 44; and a frangible barrier 50 connected uphole of the electric submersible pump 28, the frangible barrier 50 preventing fluid flow through the central flow passage 54.

The frangible barrier 50 may be connected uphole of the first valve 44. The frangible barrier 50 may be configured to break and/or open in response to a predetermined pressure differential across the frangible barrier 50.

The system 10 may include a plug 80 disposed in the first valve 44, the plug 80 preventing fluid flow through the central flow passage 54.

The system 10 may include a second valve 38 connected between the frangible barrier 50 and the electric submersible pump 28. The second valve 38 may permit fluid flow through the central flow passage 54 from the electric submersible pump 28 and prevent fluid flow through the central flow passage 54 to the electric submersible pump 28.

The second valve 38 may include a closure member 60 and a seat 62. The closure member 60 and seat 62 may be configured to prevent fluid flow through the central flow passage 54 to the electric submersible pump 28 when the closure member 60 is engaged with the seat 62. The closure member 60 and seat 62 may be configured to permit fluid flow through the central flow passage 54 to the electric submersible pump 28 when the closure member 60 is disengaged from the seat 62.

The seat 62 may be configured to disengage from the closure member 60 in response to a predetermined pressure differential applied from an uphole side to a downhole side of the seat 62. The system 10 may include a biasing device 66 that biases the seat 62 in an uphole direction.

Although various examples have been described above, with each example having certain features, it should be understood that it is not necessary for a particular feature of one example to be used exclusively with that example. Instead, any of the features described above and/or depicted in the drawings can be combined with any of the examples, in addition to or in substitution for any of the other features of those examples. One example's features are not mutually exclusive to another example's features. Instead, the scope of this disclosure encompasses any combination of any of the features.

Although each example described above includes a certain combination of features, it should be understood that it is not necessary for all features of an example to be used. Instead, any of the features described above can be used, without any other particular feature or features also being used.

It should be understood that the various embodiments described herein may be utilized in various orientations, such as inclined, inverted, horizontal, vertical, etc., and in various configurations, without departing from the principles of this disclosure. The embodiments are described merely as examples of useful applications of the principles of the disclosure, which is not limited to any specific details of these embodiments.

In the above description of the representative examples, directional terms (such as “above,” “below,” “upper,” “lower,” “upward,” “downward,” etc.) are used for convenience in referring to the accompanying drawings. However, it should be clearly understood that the scope of this disclosure is not limited to any particular directions described herein.

The terms “including,” “includes,” “comprising,” “comprises,” and similar terms are used in a non-limiting sense in this specification. For example, if a system, method, apparatus, device, etc., is described as “including” a certain feature or element, the system, method, apparatus, device, etc., can include that feature or element, and can also include other features or elements. Similarly, the term “comprises” is considered to mean “comprises, but is not limited to.”

Of course, a person skilled in the art would, upon a careful consideration of the above description of representative embodiments of the disclosure, readily appreciate that many modifications, additions, substitutions, deletions, and other changes may be made to the specific embodiments, and such changes are contemplated by the principles of this disclosure. For example, structures disclosed as being separately formed can, in other examples, be integrally formed and vice versa. Accordingly, the foregoing detailed description is to be clearly understood as being given by way of illustration and example only, the spirit and scope of the invention being limited solely by the appended claims and their equivalents.

Claims

1. A method for use with a subterranean well, the method comprising: connecting a tool in a tubing string uphole of an electric submersible pump, the tool comprising a frangible barrier and a first valve; andinstalling the tubing string in the well, the frangible barrier preventing flow through a central flow passage of the tubing string, and the first valve preventing fluid communication between the central flow passage and an annulus external to the tubing string.

2. The method of claim 1, in which, in the installing, the frangible barrier is positioned uphole of the first valve.

3. The method of claim 1, further comprising opening the frangible barrier, thereby permitting fluid flow from the electric submersible pump through the tubing string.

4. The method of claim 3, in which the frangible barrier opening comprises breaking the frangible barrier.

5. The method of claim 3, in which the frangible barrier opening comprises increasing pressure in the central flow passage uphole of the frangible barrier.

6. The method of claim 3, further comprising, after the frangible barrier opening, opening the first valve, thereby permitting fluid communication between the central flow passage and the annulus.

7. The method of claim 6, in which the first valve is opened prior to withdrawing the tubing string from the well.

8. The method of claim 6, in which the first valve opening comprises preventing fluid flow through the central flow passage in the first valve.

9. The method of claim 1, in which the connecting comprises connecting a second valve between the electric submersible pump and the first valve, the second valve configured to permit fluid flow through the central flow passage from the electric submersible pump and prevent fluid flow through the central flow passage to the electric submersible pump.

10. The method of claim 9, further comprising increasing pressure in the central flow passage uphole of the second valve to a predetermined pressure level, thereby permitting fluid flow through the second valve to the electric submersible pump.

11. A system for use with a subterranean well, the system comprising: an electric submersible pump;a first valve connected uphole of the electric submersible pump, the first valve selectively preventing and permitting fluid communication between a central flow passage extending through the first valve and an annulus external to the first valve; anda frangible barrier connected uphole of the electric submersible pump, the frangible barrier preventing fluid flow through the central flow passage.

12. The system of claim 11, in which the frangible barrier is connected uphole of the first valve.

13. The system of claim 11, in which the frangible barrier is configured to open in response to a predetermined pressure differential across the frangible barrier.

14. The system of claim 11, in which the frangible barrier is configured to break in response to a predetermined pressure differential across the frangible barrier.

15. The system of claim 11, further comprising a plug disposed in the first valve, the plug preventing fluid flow through the central flow passage.

16. The system of claim 11, further comprising a second valve connected between the frangible barrier and the electric submersible pump.

17. The system of claim 16, in which the second valve permits fluid flow through the central flow passage from the electric submersible pump and prevents fluid flow through the central flow passage to the electric submersible pump.

18. The system of claim 16, in which the second valve comprises a closure member and a seat, the closure member and seat being configured to prevent fluid flow through the central flow passage to the electric submersible pump when the closure member is engaged with the seat, and the closure member and seat being configured to permit fluid flow through the central flow passage to the electric submersible pump when the closure member is disengaged from the seat.

19. The system of claim 18, in which the seat is configured to disengage from the closure member in response to a predetermined pressure differential applied from an uphole side to a downhole side of the seat.

20. The system of claim 18, further comprising a biasing device that biases the seat in an uphole direction.