US20180347337A1

US20180347337A1 - Progressive Cavity Pump Tubing Tester

Info

Publication number: US20180347337A1
Application number: US15/995,288
Authority: US
Inventors: Michael C. Romer; Bill B. Blatnick
Original assignee: Individual
Current assignee: Individual
Priority date: 2017-06-01
Filing date: 2018-06-01
Publication date: 2018-12-06

Abstract

A down-hole tool and method for pressure testing production tubing within a borehole of a well returning the well to production, including a valve having a first valve member positioned within the tool housing and a second valve member moveable between a closed position and an open position; and a valve catcher engaged with a distal end of a rotor of the progressive cavity pump, the valve catcher for securing the second valve member in the open position with the valve catcher during rotational operation of the rotor and securing the second valve member with the valve catcher during removal of the second valve member from within the progressive cavity pump when the rotor is removed through the progressive cavity pump stator; wherein the production tubing may be pressure tested when the second valve member is in the closed position with respect to the first valve member.

Description

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application No. 62/513,708, filed Jun. 1, 2017, the contents of which is hereby incorporated by reference in its' entirety.

FIELD

The present disclosure relates to an apparatus for and a method of pressure testing production tubing within a borehole of a well including a progressive cavity pump (PCP) and returning the well to production.

BACKGROUND

A PCP is an artificial lift system commonly used for producing fluid from wellbores, such as water, oil, heavy crudes, and such fluids laden with abrasive sand and solids. A PCP system typically includes has a helical stator run into a wellbore on a production tubing string or within a tubing string, and a corresponding helical rotor that is rotated within the stator via a rod string positioned within the tubing. A drive system located at the surface applies torque to the rod string which in turn rotates the rotor within the stator. The meshing helical rod and stator create a progressively moving cavity that actually pumps the fluid, applying lift pressure to move the produced fluid up the tubing string and to the surface. Two problems with PCP's are that 1) they can create wear on production tubing, which necessitates pressure tests; and 2) they can cause lower joints of tubing to become loosened or disconnected. Pulling rod strings and the rotor is relatively inexpensive and not overly time consuming. However, most problems occur with the tubing and pulling tubing is substantially more expensive and time consuming than merely pulling the rods.
PCP rotor rods routinely cause significant wear on the inner diameter of the production tubing string, potentially leading to tubing leaks at wear points. If the rod has eccentricity, it can rub against the inside of the production tubing and create wear spots, especially at rod joint connections.
Fluid pressure tests of the production tubing are required routinely during the life of a PCP pumped well to ensure the integrity of the production tubing for efficient operation thereof. One current method of practice is to run the production tubing in hole with a bull plug, conduct a pressure test, pull the tubing out of hole, replace the bull plug with the stator, run in hole with the tubing for a second time, and then run in hole with the rotor. Every time that the tubing is re-tested, the rods, rotor and tubing all have to be pulled out of hole and the operation is repeated with this current practice until the tubing passes the pressure tests.
When a progressive cavity pump is operating, significant rotations of torsional strain torque may be built up in the rod string between the surface and the pump several thousand feet downhole. When operation of the pump stops, as routinely occurs during pump usage, such as for normal operating practice or for service, two forces combine to create a “backspin” force at the pump. One is the rod torque trying to release its rotation, however, that force is amplified by the hydrostatic column of fluid above the pump now trying to backflow through the pump as the fluid drains back out of the production tubing into the wellbore. Uncontrolled backspin may reach velocities from a few hundred RPM to a few thousand RPM. The backspin force that can be quite damaging as the force could lead to surface unit destruction, rod connections unscrewing and damage to the rotor and/or stator parts of the pump itself. As may be appreciated, when the rod connections are loosened or disconnected, well operations compromise are compromised, potentially leading to well failure, unplanned operational interruption, and required well service work. Surface power units are often provided with braking systems or backspin control units that either prevent backspin or ensure that it is dissipated in a controlled fashion. Commonly, reverse rotation is expended or controlled prior to restarting a PCP, which can result in significant restart delays.
One method to prevent backspin in event of pump stoppage is placing a standing valve below the pump intake. Standing valves are typically ball and seat type arrangements, similar to standing valves commonly used with cyclic rod pumps. However, as with using bullplugs for testing tubing pressure integrity, standing valves typically require pulling the tubing string for retrieval.
However, if the tubing string using a standing valve needs repair, to avoid pulling a “wet string” full of produced fluid, common practice is to first perforate a hole in the production tubing or rupture a pressure relief port a joint or two above the pump, subsequent to removal of the rotor and rod string, and then wait for the tubing to drain through the perforations, which again, may result in a significant delay in operations. The perforated joint or joints of tubing also must be replaced prior to returning the well to operation. For these and related reasons, it is often preferred not to use a standing valve in many installations.
While there exists certain existing technology to address the above backspin and pressure testing needs, what is still needed is improved ability to utilize a standing valve for pressure testing but not have the standing valve present during normal pumping operation.

SUMMARY

In one aspect, provided is a down-hole tool for pressure testing production tubing within a borehole of a well and returning the well to production. The down-hole tool includes a production tubing string supporting a progressive cavity pump within a wellbore, the downhole tool comprising: (a) a tool housing engaged with the production tubing and positioned downhole with respect to a fluid intake end of a stator for the progressive cavity pump; (b) a valve for controlling the flow of down-hole fluids within the production tubing, the valve comprising a first valve member fixedly positioned within the tool housing and a second valve member positionable between a closed position with respect to the first valve member and an open position with respect to the first valve member; and (c) a valve catcher engaged with a distal end of a rotor of the progressive cavity pump, the valve catcher for securing the second valve member with the valve catcher when the second valve member is positioned in an open position and for retaining the second valve member with the valve catcher during rotational operation of the rotor and during removal of the second valve member from within the progressive cavity pump when the rotor is removed through the progressive cavity pump stator; wherein the production tubing may be pressure tested when the second valve member is in the closed position with respect to the first valve member.
In some embodiments, the down-hole tool is engaged with a stator of a progressive cavity pump.
In some embodiments, the down-hole tool is engaged with a downhole end of a non-perforated tubular extension engaged on an uphole end with a downhole end of the stator of a progressive cavity pump.
In some embodiments, the second valve member comprises a ball and the first valve member comprises a seat for the ball.
In some embodiments, the second valve member comprises a poppet type valve and the first valve member comprises a seat for the poppet type valve.
In some embodiments, the valve catcher comprises a magnet and the second valve member comprises a ferromagnetic material.
In some embodiments, the valve catcher comprises at least one of a finger type catcher and a cup type catcher.
In some embodiments, the valve catcher and the second valve member are able to pass through a progressive cavity pump stator with the second valve member engaged with the valve catcher.
In some embodiments, the valve catcher covers at least a portion of the second valve member so as to shield the second valve member from a produced fluid in the production tubing from washing the second valve member out of engagement with the valve catcher when the pump is stopped and the produced fluid flows backward through the progressive cavity pump and through the housing.
In some embodiments, the valve catcher is engaged with the progressive cavity pump rotor.
In some embodiments, the valve catcher is threadably engaged with the progressive cavity pump rotor.
In some embodiments, the tool further comprises a rotational retaining tool including an anchor to engage an interior surface of the well to prevent rotation of the progressive cavity pump stator.
In some embodiments, the second valve member is changed from the close position to the open position and into engagement with the valve catcher by produced fluid moving through the first valve member and into the fluid intake end of the progressive cavity pump.
In some embodiments, at least a portion of the valve catcher comprises an integral part of the rotor.
In some embodiments, the valve catcher comprises a magnet positioned within the fluid intake end of the rotor and the rotor further comprises a concave end-face for receiving at least a portion of the second valve member therein.
In some embodiments, the second valve member is retrieved with the rotor, through the stator, when the rotor is retrieved to the surface.
In some embodiments, the stator includes at least a portion of the tool housing.
In some embodiments, the valve comprises a standing valve.
In some aspects, included are methods for pressure testing a production tubing string supporting a progressive cavity pump within a wellbore, the method comprising: positioning the production tubing string and a progressive cavity pump stator within a wellbore, the progressive cavity pump stator positioned on a downhole end of the production tubing string; providing a tool housing engaged with the production tubing and downhole with respect to a fluid intake end of the progressive cavity pump; providing a valve for controlling the flow of down-hole fluids within the production tubing for purposes of pressure testing the production tubing for leaks, the valve comprising a first valve member fixedly engaged with the tool housing and a second valve member positionable between a closed position with respect to the first valve member and an open position with respect to the first valve member; deploying the second valve member into the production tubing string for the second valve member to engage the first valve member in a closed position; providing a valve catcher engaged at a distal end of the progressive cavity pump rotor, the valve catcher for securing the second valve member with the valve catcher when the second valve member is positioned in an open position and for retaining the second valve member with the valve catcher during rotational operation of the rotor and during removal of the second valve member from within the progressive cavity pump when the rotor is removed from within the progressive cavity pump; subsequent to deploying the second valve member into the production tubing, running the rotor into the production tubing and into the stator; pressure testing the production tubing string and stator against the valve in the closed position; thereafter, rotationally operating the progressive cavity pump, causing the second valve member to move to the open position with respect to the first valve member and into capture by the valve capture.
In some embodiments, included are the steps of thereafter pulling the rotor, valve catcher, and the captured second valve member through the stator, through the production tubing string, and retrieving the second valve member at the surface.
In some embodiments, the method further comprises pulling the tubing string and stator from the wellbore without having to drain produced fluid from within the production tubing.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 presents a diagrammatic view of an illustrative example of a down-hole tool for pressure testing production tubing within a borehole of a well, shown with a commercial anti-rotation tool, in combination with a progressive cavity pump and production tubing and rotor rods, according to the present disclosure.

FIG. 2 presents an exploded diagrammatic view of an illustrative, non-exclusive example of a down-hole tool for pressure testing production tubing within a borehole of a well according to the present disclosure.

DETAILED DESCRIPTION

FIGS. 1 and 2 provide illustrative, non-exclusive examples of a down-hole tool for pressure testing production tubing, according to the present disclosure and/or of systems, apparatus, and/or assemblies that may include, be associated with, be operatively attached to, and/or utilize such systems. In FIGS. 1-2, like numerals denote like, or similar, structures and/or features; and each of the illustrated structures and/or features may not be discussed in detail herein with reference to each of FIGS. 1-2. Similarly, each structure and/or feature may not be explicitly labeled in each of FIGS. 1-2; and any structure and/or feature that is discussed herein with reference to any one of FIGS. 1-2 may be utilized with any other of FIGS. 1-2 without departing from the scope of the present disclosure.
In general, structures and/or features that are, or are likely to be, included in a given embodiment are indicated in solid lines in FIGS. 1-2, while optional structures and/or features are indicated in broken lines. However, a given embodiment is not required to include all structures and/or features that are illustrated in solid lines therein, and any suitable number of such structures and/or features may be omitted from a given embodiment without departing from the scope of the present disclosure.
Referring now to FIG. 1, a simplified plan view of an illustrative example of a down-hole tool for pressure testing production tubing 10 is presented and shown in a post-pressure test mode. The down-hole tool 20 for pressure testing production tubing 10 includes an anti-rotational device 30, including anti-rotation wing or slip elements 32 to engage an inner surface of the borehole to anchor the production tubing thereto. Rod string 12 rotates to drive rotor 16, positioned within stator 14.
The downhole tool 20 of FIG. 1 illustrates a tool housing 23 supporting a first valve member 26, illustrated as valve seat 26 and enclosing a second valve member 28, which in the illustrated embodiment is a ball that can form a hydraulic seal when engaged with seat 26. Ball 28 is illustrated retained within valve catcher 24. It will be readily recognized that housing 23 may be a dedicated component for supporting the first valve member 26 therein, or that housing 23 may be a tubing collar, a pup joint, a joint of tubing, or a component related to or part of the stator 14 or PCP pump housing. The illustration in FIG. 1 is merely exemplary and illustrative.
Similarly, the axial spacing between first valve member 26 and valve catcher 24 may be relatively close, as illustrated in FIG. 1, or may be separated by substantial distance, such as a several feet or by a joint of production tubing. In some embodiments, vanes or guides may be provided to assist with directing the second valve member 28 into proper alignment with valve catcher 24 for valve catcher 24 to catch and retain second valve member 28 therein.
Valve catcher 24 may include a magnet 22 for securing ball 28 within valve catcher 24 and may include a cup and/or finger type catcher for grappling and securing ball 28 therewith. In the illustrated embodiment, valve catcher 24 is secured to the distal end 18 (downhole, with respect to from the surface) of rotor 16 via a threaded connection 21 with mated female 21 a and male 21 b components. However, connection or engagement of the valve catcher 24 with rotor 16 may be provided by welding, adhesion, or any other suitable means for securing the valve catcher 24 to rotor 16. As discussed above, valve catcher 24 may be partially or fully configured as an integral portion of the distal end 18 of rotor 16. FIG. 2 provides an exploded, simplified view of various embodiments for components of the downhole tool assembly illustrated in FIG. 1.
Note that the disclosed technology may be incorporated into an existing PCP installation utilizing traditional PCP components such as tag bar 29 positioned below the pump, used for spacing out the rotor 16 within stator 14. The rotor may be spaced out in a traditional measurement and adjustment process, whereby the valve catcher 24 actually tags upon the second valve member 28 which is seated upon first valve member 26. Because the production tubing is full of fluid, the valve catcher 24 will not retain or dislodge second valve member 26 off of the seat upon the first valve member 26 due to the substantial hydraulic pressure differential across the second valve member 28. After tagging the valve catcher 24 upon the second valve member 28, the rotor 16 may be pulled up a measured amount and into operational position. Only after the PCP pump is spaced out, started, and rotating at speed will the hydraulic fluid load within the production tubing 10 be lifted so as to remove the substantial hydraulic differential from the second valve member 28 such that the second valve member 28 may unseat and move up into engagement and retention with valve catcher 24.
In some embodiments, valve catcher 24 may be provided as a concave feature milled into the end of rotor 16 for securing at least a portion of the conforming ball or second valve member 28 therewith. In such embodiments, a magnet 22 may also be provided within the distal end 18 of rotor 16, in back of the concave cavity of valve catcher 24. In still other embodiments, the distal end 18 of the rotor may be fitted or provided with a dimensionally conforming shape 24 that corresponds with receiving at least a portion of a second valve member 28 therewith. For example, in some embodiments, the second valve member 28 may be a poppet type valve that seats on the first valve member 26 and the poppet valve includes a stem or guide that extends axially up into a bore within at least a portion of the distal end 18 of the rotor 16. These illustrated embodiments are merely exemplary embodiments of a two-part valve assembly for downhole tool 20, whereby one of the two valve members is captured by the valve catcher and rotor for retrieval out of the tubing string with the rotor and rods, such that the remaining first valve member remains within the tubing in the wellbore until such time as the tubing is retrieved from the wellbore. In other embodiments, the valve assembly and related components may be provided as an integral part of the PCP pump or stator assembly.
It is desirable that valve catcher 24 and second valve member 28 are dimensionally sized such that when the rotor 16 is withdrawn from the stator 14, valve catcher 24 and second valve member 28 may also slide through stator 14 without releasing or losing the second valve member from the valve catcher. A benefit of the presently disclosed technology is the ability to retrieve the standing valve ball, dart, popett, or component thereof to prevent the first valve member from block the backflow of fluids from within the production tubing 10 backward through the PCP after pressure testing of the production tubing 10 is complete.
An exemplary method for using the presently disclosed technology may include providing the downhole tool 20 on or near a distal or downhole end of a tubing string 10. The tool may include both the first and second valve members 26, 28 in the tubing string, such as in a seating nipple or other seat for supporting the standing valve seat thereon. The PCP stator 14 may be provided immediately above the seat 26 or a joint or other spacing may be provided between the seat 26 and the stator 14. After the tubing string 10 is run into the wellbore, the second valve member 28 may be dropped from the surface or otherwise deployed into the tubing for engagement upon the first valve member seat 26. Thereafter, the production tubing string may be filled with fluid and hydrostatically tested for pressure loss or leaks. If leaking, the tubing may be pulled and repaired, and the process repeated until the tubing passes the pressure test.
After passing the pressure test, the rotor 16 may be run into the tubing string 10 and spaced out through stator 14 while the second valve member 24 is engaged upon the first valve member 28 seat. The PCP system is then operated to pump fluid from the wellbore, through the production tubing 10. As production fluid is drawn from the wellbore annulus and into an open lower end of the tubing string and through an aperture in the seat of the first valve member 26, the second valve member 28 is lifted off of the sealing seat and due to viscous fluid drag is moved up the wellbore toward the valve catcher 24, and into engagement therewith, capturing the second valve member 28 in the valve catcher 24. For embodiments where the second valve member 24 is a metal or otherwise ferromagnetic ball or valve member, a strong magnet 22 may be provided within the valve catcher at distal end 18 of the rotor 16, to assist with retaining the second valve member therein, such as illustrated in FIG. 1. As the rotor rotates, valve catcher 24 and second valve member 28 will merely rotate with the rotor.
When the PCP pump is subsequently operationally stopped, because the second valve member 28 is captured and engaged with the valve catcher 24 and no longer positioned upon first valve member seat 26, production fluid within the production tubing 10 will backflow through the helical annulus in the PCP pump between the stator and rotor, past the captured second valve member 28, back through the open first valve member 26, and into the wellbore. To prevent the second valve member from being washed out of engagement with the valve catcher 24 during such event, it may be preferable for the valve catcher 24 to cover or conceal sufficient surface area on the second valve member 28 such that the backflowing fluid does not cause disengagement of the second valve member 28 from the valve catcher 24. Thereby, many embodiments may utilize a valve catcher 24 that provides surface area concealment protection such as a hemispherical cup, recess, or tubular cylinder, or otherwise confing shape for protecting the second valve member 28 contained therein, protected from exposure to the hydraulic forces of the backflowing production fluid.
The rod string 12 and rotor 16 may be pulled through the stator 14 and out of the production tubing string, thereby facilitating retrieval of the second valve member 28 at the surface of the wellbore. When appropriate to pressure test the tubing again, the second valve member 28 is merely re-deployed back down the tubing string 10, such as by dropping the second valve member 28 back down the tubing string, and into engagement with the first valve member seat 26. Such operation may save significant time and costs for tripping tubing out of and back into the wellbore for retrieving bull plugs after each test.
As used herein, the term “and/or” placed between a first entity and a second entity means one of (1) the first entity, (2) the second entity, and (3) the first entity and the second entity. Multiple entities listed with “and/or” should be construed in the same manner, i.e., “one or more” of the entities so conjoined. Other entities may optionally be present other than the entities specifically identified by the “and/or” clause, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, a reference to “A and/or B,” when used in conjunction with open-ended language such as “comprising” may refer, in one embodiment, to A only (optionally including entities other than B); in another embodiment, to B only (optionally including entities other than A); in yet another embodiment, to both A and B (optionally including other entities). These entities may refer to elements, actions, structures, steps, operations, values, and the like.
As used herein, the phrase “at least one,” in reference to a list of one or more entities should be understood to mean at least one entity selected from any one or more of the entity in the list of entities, but not necessarily including at least one of each and every entity specifically listed within the list of entities and not excluding any combinations of entities in the list of entities. This definition also allows that entities may optionally be present other than the entities specifically identified within the list of entities to which the phrase “at least one” refers, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, “at least one of A and B” (or, equivalently, “at least one of A or B,” or, equivalently “at least one of A and/or B”) may refer, in one embodiment, to at least one, optionally including more than one, A, with no B present (and optionally including entities other than B); in another embodiment, to at least one, optionally including more than one, B, with no A present (and optionally including entities other than A); in yet another embodiment, to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other entities). In other words, the phrases “at least one,” “one or more,” and “and/or” are open-ended expressions that are both conjunctive and disjunctive in operation. For example, each of the expressions “at least one of A, B and C,” “at least one of A, B, or C,” “one or more of A, B, and C,” “one or more of A, B, or C” and “A, B, and/or C” may mean A alone, B alone, C alone, A and B together, A and C together, B and C together, A, B and C together, and optionally any of the above in combination with at least one other entity.
In the event that any patents, patent applications, or other references are incorporated by reference herein and define a term in a manner or are otherwise inconsistent with either the non-incorporated portion of the present disclosure or with any of the other incorporated references, the non-incorporated portion of the present disclosure shall control, and the term or incorporated disclosure therein shall only control with respect to the reference in which the term is defined and/or the incorporated disclosure was originally present.
As used herein the terms “adapted” and “configured” mean that the element, component, or other subject matter is designed and/or intended to perform a given function. Thus, the use of the terms “adapted” and “configured” should not be construed to mean that a given element, component, or other subject matter is simply “capable of” performing a given function but that the element, component, and/or other subject matter is specifically selected, created, implemented, utilized, programmed, and/or designed for the purpose of performing the function. It is also within the scope of the present disclosure that elements, components, and/or other recited subject matter that is recited as being adapted to perform a particular function may additionally or alternatively be described as being configured to perform that function, and vice versa.

INDUSTRIAL APPLICABILITY

The systems and methods disclosed herein are applicable to the oil and gas industry.
It is believed that the disclosure set forth above encompasses multiple distinct inventions with independent utility. While each of these inventions has been disclosed in its preferred form, the specific embodiments thereof as disclosed and illustrated herein are not to be considered in a limiting sense as numerous variations are possible. The subject matter of the inventions includes all novel and non-obvious combinations and subcombinations of the various elements, features, functions and/or properties disclosed herein. Similarly, where the claims recite “a” or “a first” element or the equivalent thereof, such claims should be understood to include incorporation of one or more such elements, neither requiring nor excluding two or more such elements.
It is believed that the following claims particularly point out certain combinations and subcombinations that are directed to one of the disclosed inventions and are novel and non-obvious. Inventions embodied in other combinations and subcombinations of features, functions, elements and/or properties may be claimed through amendment of the present claims or presentation of new claims in this or a related application. Such amended or new claims, whether they are directed to a different invention or directed to the same invention, whether different, broader, narrower, or equal in scope to the original claims, are also regarded as included within the subject matter of the inventions of the present disclosure.

Claims

1. A down-hole tool for pressure testing a production tubing string supporting a progressive cavity pump within a wellbore, the downhole tool comprising:

(a) a tool housing engaged with the production tubing and positioned downhole with respect to a fluid intake end of a stator for the progressive cavity pump;

(b) a valve for controlling the flow of down-hole fluids within the production tubing, the valve comprising a first valve member fixedly positioned within the tool housing and a second valve member positionable between a closed position with respect to the first valve member and an open position with respect to the first valve member; and

(c) a valve catcher engaged with a distal end of a rotor of the progressive cavity pump, the valve catcher for securing the second valve member with the valve catcher when the second valve member is positioned in an open position and for retaining the second valve member with the valve catcher during rotational operation of the rotor and during removal of the second valve member from within the progressive cavity pump when the rotor is removed through the progressive cavity pump stator;

wherein the production tubing may be pressure tested when the second valve member is in the closed position with respect to the first valve member.

2. The down-hole tool of claim 1, wherein the down-hole tool is engaged with a stator of a progressive cavity pump.

3. The down-hole tool of claim 1, wherein the down-hole tool is engaged with a downhole end of a non-perforated tubular extension engaged on an uphole end with a downhole end of the stator of a progressive cavity pump.

4. The down-hole tool of claim 1, wherein the second valve member comprises a ball and the first valve member comprises a seat for the ball.

5. The downhole tool of claim 1, wherein the second valve member comprises a poppet type valve and the first valve member comprises a seat for the poppet type valve.

6. The downhole tool of claim 1, wherein the valve catcher comprises a magnet and the second valve member comprises a ferromagnetic material.

7. The downhole tool of claim 1, wherein the valve catcher comprises at least one of a finger type catcher and a cup type catcher.

8. The downhole tool of claim 1, wherein the valve catcher and the second valve member are able to pass through a progressive cavity pump stator with the second valve member engaged with the valve catcher.

9. The downhole tool of claim 7, wherein the valve catcher covers at least a portion of the second valve member so as to shield the second valve member from a produced fluid in the production tubing from washing the second valve member out of engagement with the valve catcher when the pump is stopped and the produced fluid flows backward through the progressive cavity pump and through the housing.

10. The downhole tool of claim 1, wherein the valve catcher is engaged with the progressive cavity pump rotor.

11. The downhole tool of claim 10, wherein the valve catcher is threadably engaged with the progressive cavity pump rotor.

12. The downhole tool of claim 1, further comprising a rotational retaining tool including an anchor to engage an interior surface of the well to prevent rotation of the progressive cavity pump stator.

13. The downhole tool of claim 1, wherein the second valve member is changed from the close position to the open position and into engagement with the valve catcher by produced fluid moving through the first valve member and into the fluid intake end of the progressive cavity pump.

14. The downhole tool of claim 1, wherein at least a portion of the valve catcher comprises an integral part of the rotor.

15. The downhole tool of claim 1, wherein the valve catcher comprises a magnet positioned within the fluid intake end of the rotor and the rotor further comprises a concave end-face for receiving at least a portion of the second valve member therein.

16. The downhole tool of claim 15, wherein the second valve member is retrieved with the rotor, through the stator, when the rotor is retrieved to the surface.

17. The downhole tool of claim 1, wherein the stator includes at least a portion of the tool housing.

18. The downhole tool of claim 1, wherein the valve comprises a standing valve.

19. A method for pressure testing a production tubing string supporting a progressive cavity pump within a wellbore, the method comprising:

positioning the production tubing string and a progressive cavity pump stator within a wellbore, the progressive cavity pump stator positioned on a downhole end of the production tubing string;

providing a tool housing engaged with the production tubing and downhole with respect to a fluid intake end of the progressive cavity pump;

providing a valve for controlling the flow of down-hole fluids within the production tubing for purposes of pressure testing the production tubing for leaks, the valve comprising a first valve member fixedly engaged with the tool housing and a second valve member positionable between a closed position with respect to the first valve member and an open position with respect to the first valve member;

deploying the second valve member into the production tubing string for the second valve member to engage the first valve member in a closed position;

providing a valve catcher engaged at a distal end of the progressive cavity pump rotor, the valve catcher for securing the second valve member with the valve catcher when the second valve member is positioned in an open position and for retaining the second valve member with the valve catcher during rotational operation of the rotor and during removal of the second valve member from within the progressive cavity pump when the rotor is removed from within the progressive cavity pump;

subsequent to deploying the second valve member into the production tubing, running the rotor into the production tubing and into the stator;

pressure testing the production tubing string and stator against the valve in the closed position;

thereafter, rotationally operating the progressive cavity pump, causing the second valve member to move to the open position with respect to the first valve member and into capture by the valve capture.

20. The method of claim 19, further comprising:

thereafter pulling the rotor, valve catcher, and the captured second valve member through the stator, through the production tubing string, and retrieving the second valve member at the surface.

21. The method of claim 19, further comprising pulling the tubing string and stator from the wellbore.