Pump isolation apparatus and method for use in tubing string pressure testing

Abstract

An apparatus and method for pressure testing a tubing string of a fluid production well, the tubing string being provided with a progressing cavity pump at a downhole end, which apparatus and method can be used to help determine whether the tubing string has failed or the pump has failed. The apparatus comprises a plug member connected to the rod string assembly that includes the pump rotor, such that the rod string assembly can be lowered to seat the plug member in a seat member within the tubing string above the pump, thus sealing off and isolating the pump from the rest of the tubing string, allowing pressure testing of the tubing string above the pump.

Claims

1. A method for pressure testing a tubing string in a fluid production well having a downhole progressing cavity pump comprising a rotor and a stator, the tubing string having a longitudinal axis, a rod string and the rotor of the pump being part of a rod string assembly axially moveable within the tubing string along the longitudinal axis of the tubing string, the method comprising the steps of: a. providing a seat member operably disposed within the tubing string at a point above the stator, the seat member comprising a surface disposed above the stator that defines a centrally-disposed aperture; b. providing a plug member operably disposed on the rod string assembly at a point above the rotor, the plug member comprising a surface disposed above the rotor that is configured for mating with the surface of the seat member and sealing the aperture, the plug member moveable between a raised position in which the aperture is unobstructed by the plug member to fluidly couple the tubing string and the pump, and a lowered position in which the plug member seals and fully obstructs the aperture to fluidly isolate the tubing string from the pump; c. positioning the plug member in the raised position and operating the pump to produce a production fluid through the aperture and up the tubing string; d. ceasing operation of the pump; e. with the plug member in the raised position, injecting a well pressure testing fluid from surface down the tubing string to the pump; f. measuring pressurization of the well pressure testing fluid; g. lowering the rod string assembly to position the plug member in the lowered position such that the plug member engages and seals the aperture, thus fully obstructing flow downwardly through the aperture and fluidly isolating the tubing string from the pump; h. with the plug member in the lowered position, injecting a tubing string pressure testing fluid from surface down the tubing string; i. allowing pressurization of the tubing string pressure testing fluid within the tubing string; and j. measuring the pressurization.

2. The method of claim 1 further comprising the following step between steps b. and c.: lowering the rod string assembly to position the plug member in the lowered position in order to locate the rotor at a desired location within the pump.

3. The method of claim 1 wherein measuring the pressurization comprises measuring the quantum of the pressurization of the tubing string pressure testing fluid and/or measuring the period and rate over which the pressurization releases.

4. A method for isolating a downhole progressing cavity pump for a tubing string pressure test, the tubing string having a longitudinal axis, the pump comprising a rotor and a stator, a rod string and the rotor of the pump being part of a rod string assembly that is axially moveable within the tubing string along the longitudinal axis of the tubing string, the method comprising the steps of: a. providing a seat member operably disposed within the tubing string at a point above the stator, the seat member comprising a surface disposed above the stator that defines a centrally-disposed aperture; b. providing a plug member operably disposed on the rod string assembly at a point above the rotor, the plug member comprising a surface disposed above the rotor that is configured for mating with the surface of the seat member and sealing the aperture, the plug member moveable between a raised position in which the aperture is unobstructed by the plug member to fluidly couple the tubing string and the pump, and a lowered position in which the plug member seals and fully obstructs the aperture to fluidly isolate the tubing string from the pump; c. positioning the plug member in the raised position and operating the pump to produce a production fluid through the aperture and up the tubing string; d. ceasing operation of the pump; e. with the plug member in the raised position, injecting a well pressure testing fluid from surface down the tubing string to the pump; f. measuring allowing pressurization of the well pressure testing fluid; g. lowering the rod string assembly to position the plug member in the lowered position such that the plug member engages and seals the aperture, thus fully obstructing flow of fluid downwardly through the aperture and fluidly isolating the tubing string from the pump; h. with the plug member in the lowered position, injecting a tubing string pressure testing fluid from surface down the tubing string; i. allowing pressurization of the tubing string pressure testing fluid within the tubing string above the plug member; and j. measuring the pressurization.

5. The method of claim 4 further comprising the following step between steps b. and c.: lowering the rod string assembly to position the plug member in the lowered position in order to locate the rotor at a desired location within the pump.

6. The method of claim 4 wherein measuring the pressurization comprises measuring the quantum of the pressurization of the tubing string pressure testing fluid and/or measuring the period and rate over which the pressurization releases.

7. The method of claim 4 wherein, when the tubing string is fluid isolated from the pump, the tubing string pressure testing fluid does not impinge on the pump.

8. A method for failure testing of a progressive cavity pump comprising a rotor and stator, the stator being located at a downhole end of a tubing string within a fluid production well, the tubing string having a longitudinal axis, a rod string and the rotor of the pump being part of a rod string assembly that is axially moveable within the tubing string along the longitudinal axis of the tubing string, the method comprising the steps of: a. providing a seat member operably disposed on the tubing string at a point above the stator, the seat member comprising a surface disposed above the stator that defines a centrally-disposed aperture; b. providing a plug member operably disposed on the rod string assembly at a point above the rotor, the plug member comprising a surface disposed above the rotor that is configured for mating with the surface of the seat member and sealing the aperture, the plug member moveable between a raised position in which the aperture is unobstructed by the plug member to fluidly couple the tubing string and the pump, and a lowered position in which the plug member seals and fully obstructs the aperture to fluidly isolate the tubing string from the pump; c. operating the pump to produce a production fluid; d. detecting a deficient fluid production from the well indicative of a potential downhole equipment failure; e. ceasing operation of the pump; f. with the plug member in the raised position, injecting a well pressure testing fluid from surface down the tubing string to the pump; g. measuring pressurization of the well pressure testing fluid; h. lowering the rod string assembly to position the plug member in the lowered position such that the plug member engages and seals the aperture, thus fully obstructing flow of fluid downwardly through the aperture and fluidly isolating the tubing string from the pump; i. with the plug member in the lowered position, injecting a tubing string pressure testing fluid from surface down the tubing string; j. allowing pressurization of the tubing string pressure testing fluid within the tubing string above the plug member; k. measuring the pressurization; and l. determining whether the pressurization indicates a potential tubing string failure or a potential pump failure.

9. The method of claim 8 further comprising the following step between steps b. and c.: lowering the rod string assembly to position the plug member in the lowered position in order to locate the rotor at a desired location within the pump; and raising the rod string assembly to position the plug member in the raised position.

10. The method of claim 8 wherein measuring the pressurization comprises measuring the quantum of the pressurization of the tubing string pressure testing fluid and/or measuring the period and rate over which the pressurization releases.

11. The method of claim 8 wherein, when the tubing string is fluid isolated from the pump, the tubing string pressure testing fluid does not impinge on the pump.

12. The method of claim 8 wherein the step of determining whether the pressurization indicates a potential tubing string failure or a potential pump failure comprises determining whether the pressurization is within normal parameters, pressurization within normal parameters indicating a potential failure of the pump that was isolated during pressurization.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) In the accompanying drawings, which illustrate exemplary embodiments of the present invention:

(2) FIG. 1 is a perspective view of a tubing string with stator and a rod string with rotor, in accordance with an embodiment of the present invention;

(3) FIG. 2 is a sectional view of the rod string and tubing string of FIG. 1, with the rotor positioned in the stator and the assembly in the pump operating position;

(4) FIG. 3 is a detailed section view showing the plug member and the seat member;

(5) FIG. 4a is a detailed section view of the plug member and the seat member, in the pump operating position;

(6) FIG. 4b is a detailed section view of the plug member and the seat member, in the pressure testing position;

(7) FIG. 5a is a detailed section view of the plug member and the seat member, in the pump operating position, with the tubing string environment;

(8) FIG. 5b is a detailed section view of the plug member and the seat member, in the pressure testing position, with the tubing string environment;

(9) FIGS. 6a to 6e are various views illustrating an embodiment comprising a plug member and seat member having a tapered interface;

(10) FIGS. 7a to 7d are various views illustrating an embodiment comprising a plug member and seat member having a rounded interface;

(11) FIGS. 8a to 8d are various views illustrating an embodiment comprising a plug member and seat member having an overlapping shoulder interface;

(12) FIGS. 9a to 9e are various views illustrating an embodiment comprising a plug member and seat member having a vertical interface;

(13) FIG. 10 is a flowchart illustrating an exemplary method in accordance with an embodiment of the present invention; and

(14) FIG. 11 is a flowchart illustrating an exemplary method in accordance with an embodiment of the present invention.

(15) Exemplary embodiments of the present invention will now be described with reference to the accompanying drawings.

DETAILED DESCRIPTION OF EXEMPLARY EMBODIMENTS

(16) Throughout the following description specific details are set forth in order to provide a more thorough understanding to persons skilled in the art. However, well known elements may not have been shown or described in detail to avoid unnecessarily obscuring the disclosure. The following description of examples of the technology is not intended to be exhaustive or to limit the invention to the precise forms of any exemplary embodiment. Accordingly, the description and drawings are to be regarded in an illustrative, rather than a restrictive, sense.

(17) The present invention relates to techniques and apparatuses for pressure testing a tubing string of a fluid production well, the tubing string being provided with a progressing cavity pump at a downhole end, to help determine whether the tubing string has failed or the pump has failed. Apparatuses according to the present invention comprise a plug member connected to the rod string assembly that comprises the pump rotor, such that the rod string assembly can be lowered to seat the plug member in a seat member within the tubing string above the pump, thus sealing off and isolating the pump from the rest of the tubing string, allowing pressure testing of the tubing string above the pump.

(18) Turning to FIGS. 1 to 3, an exemplary embodiment of the present invention is illustrated. The exemplary embodiment comprises a tubing string 10 and a rod string 16, the rod string 16 configured for axial and rotational movement within the tubing string 10 in a manner familiar to those skilled in the art. The tubing string 10 is connected at its downhole end 12 to a stator 14 of a progressing cavity pump 36. The stator 14 comprises an inner double helix cavity for receiving a single helix rotor 24, in a conventional manner. The rod string 16 may be primarily made up of sucker rods or continuous rod. The rotor 24 is connected to the rod string 16, which rod string 16 is driven at surface by drive means known to those skilled in the art, rotating to impart rotation to the rotor 24 to pump fluids upwardly through the pump 36. The operation of a progressing cavity pump is well known to those skilled in the art and will thus not be described in any further detail.

(19) A plug member 18 is connected to the rod string 16 at a location upwardly spaced from the rotor 24. The rod string 16 connects to a top end of the plug member 18, while a connector rod 20 connects to a bottom end of the plug member 18. As the central axis of the rotor 24 is eccentric or offset from the central axis of the stator 14, the connector rod 20 may be required in the view of a skilled person to provide a flexible connection to ensure that the seal between the plug member 18 and the seat member 26 is possible. The connector rod 20 in turn connects to a rod box connection 22 which connects to the rotor 24 to impart the rotation from the rod string 16.

(20) Note that while the plug member 18 is shown as connected to the rod string 16 in the illustrated embodiment, it could be connected to another component of the rod string assembly where appropriate and desirable. For example, the rod string assembly may comprise a rod box connection (for connecting rods and the rotor or other components together), a sucker rod (a single segment of a rod string), a connector rod (a shorter version of a sucker rod), a rod shear (a component designed to break under a certain defined tension), a rod centralizer (which centralizes a rod string within a tubing string), and a rotor, and the plug member can be connected or integral to any of these where determined to be appropriate and desirable by a person skilled in the art having reference to the within teaching.

(21) FIGS. 2 and 3 illustrate sectional views of the exemplary embodiment. In these Figures a seat member 26 is shown, which seat member 26 connects to the inner wall 28 of the tubing string 10 in any appropriate conventional manner, including without limitation welding, threading, integral manufacturing or a custom component. While shown as connected to a larger-diameter tubing component allowing coilability, the present invention is not to be construed as being limited to this embodiment. The seat member 26 comprises a peripheral protuberance 30, which in the illustrated embodiment is a ring-shaped insert having a wedge-shaped cross-section, the wedge widening in a downhole direction to receive and retain the plug member 18, as described below.

(22) Note that while the seat member 26 is shown as connected to the inner wall 28 of the tubing string 10 in the illustrated embodiment, it could be connected to another component of the tubing string where appropriate and desirable. For example, the seat member could be connected to a joint of tubing, a tubing pup joint (a shorter version of a standard tubing joint), a tubing drain (a component designed to burst open when enough hydraulic pressure is applied to allow fluid to drain from the tubing above the pump), or the stator itself, where determined to be appropriate and desirable by a person skilled in the art having reference to the within teaching.

(23) The peripheral protuberance 30 defines an internally disposed aperture 32, through which fluids may pass when unobstructed. FIGS. 4a through 5b illustrate these and other features in greater detail.

(24) FIGS. 4a and 4b illustrate certain details of the first embodiment without the tubing string 10 environment. The plug member 18 receives a downstream end of the rod string 16 and an upstream end of the connector rod 20 (which connector rod 20 may not be required in all embodiments of the present invention). The plug member 18 also comprises a sealing surface 38 which is configured to seal against a corresponding sealing surface 40 of the seat member 26, as described below. The seat member 26 comprises the peripheral protuberance 30 and the aperture 32, and the peripheral protuberance 30 is provided with the sealing surface 40 of the seat member 26.

(25) FIG. 4a illustrates the exemplary embodiment in the raised or pump operation position, in which the plug member 18 is disengaged from the seat member 26, thus keeping the aperture 32 open and unobstructed to allow fluid flow through the aperture 32 during operation of the pump 36. FIG. 4b illustrates the exemplary embodiment in the lowered or pressure testing position, in which the plug member 18 engages the seat member 26, the sealing surfaces 38, 40 pressed together to seal the aperture 32, as will be described in detail below.

(26) FIGS. 5a and 5b illustrate the same features as in FIGS. 4a and 4b, but with the tubing string 10 environment. FIG. 5a illustrates the flow path 34 for the produced fluid, as the produced fluid can move upwardly through the aperture 32, around the plug member 18 and upwardly in the tubing string 10. This is the position of the plug member 18 when an operator desires to use the pump 36 to move fluid to surface through the tubing string 10. When an operator wishes to isolate the tubing string 10 from the pump 36 for a pressure test, pump 36 operation is ceased and the rod string 16 is lowered to seat the plug member 18 in the seat member 26, as shown in FIG. 5b, thus blocking the flow path for produced fluid that was open in FIG. 5a.

(27) The sealing interface between the plug member 18 and the seat member 26 can take various forms. For the purposes of illustration, four alternative embodiments are shown and described below. Note that the illustrated plug member designs incorporate an uphole tapered surface, which is intended for ease of rod string retrieval. Also, plug members according to the present invention could incorporate a combination of the sealing interfaces described below and illustrated herein.

(28) Turning now to FIGS. 6a to 6e, a first sealing interface arrangement is illustrated. In these Figures, a tapered sealing interface is shown. The plug member 18 comprises a conically tapered sealing surface 42 which tapers inwardly in a downhole direction. This sealing surface 42 is configured to mate with a corresponding tapered sealing surface 44 on the peripheral protuberance 30, which sealing surface 44 can be seen in dashed lines in FIG. 6a, which illustrates this embodiment in the raised or pump operating position with the plug member 18 disengaged from the seat member 26.

(29) FIGS. 6b and 6c illustrate this embodiment of the plug member 18 in detail. The plug member 18 comprises the tapered sealing surface 42, and also an inner bore 46 for receiving the rod string 16 in an upper end and the connector rod 20 in a lower end. Again, the present invention is not limited to a threaded connection of a plug member to a rod string.

(30) FIGS. 6d and 6e illustrate the plug member 18 and the seat member 26 in accordance with this embodiment, with the plug member 18 comprising the sealing surface 42 and the seat member 26 comprising the corresponding sealing surface 44. FIG. 6d illustrates the plug member 18 disengaged from the seat member 26, while FIG. 6e illustrates the plug member 18 engaged with the seat member 26. As can be seen in FIG. 6e, a portion of the sealing surface 42 seals against a portion of the sealing surface 44 when the plug member 18 is fully inserted within the seat member 26, creating a sealed interface 48. While this may be a metal on metal seal, it is also obviously possible to provide one or more gaskets or sealing rings to enhance the seal, or make either or both of the plug member 18 and the seat member 26 out of an elastomeric or composite material or coat same with an elastomeric or composite material. By thus sealing the components and obstructing the aperture 32, a pressure test can be run on the tubing string 10, as described below.

(31) Turning now to FIGS. 7a to 7d, a second sealing interface arrangement is illustrated. In this embodiment, a rounded sealing interface is shown. The plug member 18 comprises a convex rounded sealing surface 50 which is disposed in a downhole direction. This sealing surface 50 is configured to mate with a corresponding concave rounded sealing surface 52 on the peripheral protuberance 30, which sealing surface 52 can be seen in dashed lines in FIG. 7a, which illustrates this embodiment in the raised or pump operating position with the plug member 18 disengaged from the seat member 26.

(32) The plug member 18 comprises the rounded sealing surface 50, and also an inner bore 54 for receiving the rod string 16 in an upper end and the connector rod 20 in a lower end.

(33) FIGS. 7b to 7d illustrate the plug member 18 and the seat member 26 in accordance with this embodiment, with the plug member 18 comprising the sealing surface 50 and the seat member 26 comprising the corresponding sealing surface 52. FIGS. 7b and 7c illustrate the plug member 18 disengaged from the seat member 26, while FIG. 7d illustrates the plug member 18 engaged with the seat member 26. As can be seen in FIG. 7d, a portion of the sealing surface 50 seals against a portion of the sealing surface 52 when the plug member 18 is fully inserted within the seat member 26, creating a sealed interface 56.

(34) Turning now to FIGS. 8a to 8d, a third sealing interface arrangement is illustrated. In this embodiment, a horizontal shoulder sealing interface is shown. The plug member 18 comprises a horizontal shoulder as sealing surface 58 which faces in a downhole direction. This sealing surface 58 is configured to mate with a corresponding upwardly facing shoulder as sealing surface 60 on the peripheral protuberance 30, which sealing surface 60 can be seen in dashed lines in FIG. 8a, which illustrates this embodiment in the raised or pump operating position with the plug member 18 disengaged from the seat member 26.

(35) The plug member 18 comprises the downwardly facing sealing surface 58, and also an inner bore 62 as can be seen in FIG. 8b for receiving the rod string 16 in an upper end and the connector rod 20 in a lower end.

(36) FIGS. 8b to 8d illustrate the plug member 18 and the seat member 26 in accordance with this embodiment, with the plug member 18 comprising the sealing surface 58 and the seat member 26 comprising the corresponding sealing surface 60. FIGS. 8b and 8c illustrate the plug member 18 disengaged from the seat member 26, while FIG. 8d illustrates the plug member 18 engaged with the seat member 26. As can be seen in FIG. 8d, a portion of the sealing surface 58 seals against a portion of the sealing surface 60 when the plug member 18 is fully inserted within the seat member 26, creating a sealed interface 64.

(37) Turning now to FIGS. 9a to 9e, a fourth sealing interface arrangement is illustrated. In this embodiment, a vertical sealing interface is shown. The plug member 18 comprises a vertical sealing surface 66. This sealing surface 66 is configured to mate with a corresponding vertical sealing surface 68 on the peripheral protuberance 30, which sealing surface 68 can be seen in dashed lines in FIGS. 9a and 9b, which illustrates this embodiment in the raised or pump operating position with the plug member 18 disengaged from the seat member 26.

(38) The plug member 18 comprises the sealing surface 66, and also an inner bore 70 as can be seen in FIGS. 9c and 9d for receiving the rod string 16 in an upper end and the connector rod 20 in a lower end.

(39) FIGS. 9c to 9e illustrate the plug member 18 and the seat member 26 in accordance with this embodiment, with the plug member 18 comprising the sealing surface 66 and the seat member 26 comprising the corresponding sealing surface 68. FIGS. 9c and 9d illustrate the plug member 18 disengaged from the seat member 26, while FIG. 9e illustrates the plug member 18 engaged with the seat member 26. As can be seen in FIG. 9e, a portion of the sealing surface 66 seals against a portion of the sealing surface 68 when the plug member 18 is fully inserted within the seat member 26, creating a sealed interface 72, and an engagement edge 74 of the plug member 18 contacts the seat member 26, thus restricting further downward movement of the plug member 18. While not shown, it will be obvious that additional sealing components such as gaskets, hold down or seating rings can be employed to enhance the seal.

(40) While the illustrated embodiments show the plug member receiving the rod string and connector rod within bores in the plug member, other connection means can be used and would be clear to those skilled in the art having recourse to the within teaching. Also, the plug member may be positioned at other points on the rod string, for example connecting two rod ends. In further examples, the plug member could connect the rod string to a shear coupling or could be integral to the shear coupling in the rod string. The plug member integral to any appropriate rod component including centralizers, and it could even be integral to the rotor in appropriate designs.

(41) Further, while the illustrated embodiments show the seat member connected to an inner surface of the tubing string at a point above the pump, the seat member can be connected to or integral with a tubing joint, a tubing collar, a drain or the stator.

(42) Having described exemplary embodiments of an apparatus, assembly and system in accordance with the present invention, exemplary embodiments of methods according to the present invention will now be described with reference to the accompanying drawings.

(43) Turning now to FIG. 10, an exemplary method 200 is illustrated. This method 200 allows for both pressure testing of a tubing string and for isolating a downhole PCP. The method 200 commences with the provision of a seat member on the tubing string inner surface at step 202 and the provision of a plug member on the rod string above the seat member at step 204, as described above. After the tubing string has been lowered into the well with the PCP stator at its lower end, the rod string is lowered within the tubing string at step 206 to position the rotor within the stator cavity. The location of the seat member may optionally be determined such that once the plug member fully engages the seat member the rod string is blocked from further downward movement and the rotor is placed thereby in a desired location within the stator cavity; the rod string would then be pulled up some set distance (a “space out”) to ensure a desired rod string tension. At step 208 the rod string is pulled upwardly to lift the plug member into the raised or pump operation position, disengaged from the seat member. The PCP can then be operated at step 210 and fluid can be produced at step 212.

(44) When it is desired to pressure test the tubing string or isolate the pump for any reason, the method 200 continues by ceasing operation of the pump and flushing the pump (pulling the rotor from the stator and allowing fluid to drain through the stator) at step 214, and running an initial pressurization test using a flush-by unit in an effort to pressurize the system. This initial pressurization test involves injecting a pressure testing fluid down the tubing string to the pump at step 216, and allowing pressurization within the tubing string and pump at step 218. Note that at this stage the pump has not been isolated. The quantum of pressurization can be measured, as can the time it takes for the pressurization to decline after injection ceases. If the pressurization is measured to be less than should be expected under normal circumstances with the downhole equipment in good operating condition, or the pressurization declines more rapidly than should be the case, this indicates a potential failure somewhere in the tubing string or the pump.

(45) At step 220, isolation of the pump is undertaken as a way to clarify the location of the potential failure. The rod string is lowered to the pressure testing position such that the plug member engages and seals the aperture, thus fully obstructing flow downwardly through the aperture. To lower the rod string, it first needs to be released at surface, where a clamp conventionally secures the topmost section called the polished rod. At this point the pump is isolated from the test environment. Once again, at step 222, a pressure testing fluid is injected from surface down the tubing string, and at step 224 pressurization of the tubing string commences, with measurement of the pressurization as described above. Identification of the failed component can then be undertaken based on the two pressure tests.

(46) Turning now to FIG. 11, a second but similar method 300 is illustrated, including two determination points relating to use of the exemplary method where deficient fluid production has been detected. It should be noted that low fluid production as such is not necessarily the result of downhole equipment failure—for example, deficient fluid production levels could be caused by plugging of reservoir porosity by sand—but the method 300 can be used to provide an indication of a potential equipment failure. The method 300 commences with the provision of a seat member on the tubing string inner surface at step 302 and the provision of a plug member on the rod string above the seat member at step 304, as described above. After the tubing string has been lowered into the well with the PCP stator at its lower end, the rod string is lowered within the tubing string at step 306 to position the rotor within the stator cavity. As indicated above, this step 306 can optionally incorporate a top tag, such that once the plug member fully engages the seat member the rod string is blocked from further downward movement and the rotor is thus placed in a desired location within the stator cavity, and the rod string would be spaced out to ensure a desired rod string tension. Whether or not a top tag action is used with the method 300, at step 308 the rod string is pulled upwardly to lift the plug member into the raised or pump operation position, disengaged from the seat member. The PCP can then be operated at step 310 and fluid can be produced.

(47) At this point in the method 300, a determination point is reached. A determination is made as to whether fluid production is at anticipated levels, which determination can be made using any number of methods and techniques known to those skilled in the art. If fluid production is at anticipated or acceptable levels, pump operation and fluid production can continue at step 310. If, however, it is determined that the fluid production is deficient, pump operation is halted and the pump is flushed (pulling the rotor from the stator and allowing fluid to drain through the stator) at step 314, and a pressure test then commences.

(48) An initial pressurization test occurs at steps 316 and 318, comprising injecting a pressure testing fluid down the tubing string to the pump at step 316, and allowing pressurization within the tubing string and pump at step 318. Again, at this stage the pump has not been isolated. The quantum of pressurization can be measured, as can the time it takes for the pressurization to decline after injection ceases. If the pressurization is measured to be less than should be expected under normal circumstances with the downhole equipment in good operating condition, or the pressurization declines more rapidly than should be the case, this indicates a potential failure somewhere in the tubing string or the pump.

(49) At step 320, isolation of the pump is undertaken as a way to clarify the location of the potential failure. The rod string is lowered to the pressure testing position such that the plug member engages and seals the aperture, thus fully obstructing flow downwardly through the aperture. At this point the pump is isolated from the test environment. Once again, at step 322, a pressure testing fluid is injected from surface down the tubing string, and at step 324 pressurization of the tubing string commences, with measurement of the pressurization as described above. At this point a second determination is made, namely whether the measured pressurization with the pump isolated is within a normal or expected range. If it is determined that the measured pressurization is within a normal or expected range, this indicates that the potential failure occurred in the pump, which had been isolated for the pressure test. If it is determined that the measured pressurization is not within a normal or expected range, this indicates that the potential failure occurred in the tubing string (although it is conceivable but unlikely that a potential failure has also occurred in the pump at the same time). This allows for corrective measures to be undertaken.

(50) As can be seen by those skilled in the art, embodiments of the present invention can provide significant advantages over the prior art, including differentiating between tubing string and pump failures without requiring undesirable equipment expense and while reducing well down-time. Unnecessary rotor pulls and swaps can be avoided, as can expensive tubing scans.

(51) Unless the context clearly requires otherwise, throughout the description and the claims: “comprise”, “comprising”, and the like are to be construed in an inclusive sense, as opposed to an exclusive or exhaustive sense; that is to say, in the sense of “including, but not limited to”. “connected”, “coupled”, or any variant thereof, means any connection or coupling, either direct or indirect, between two or more elements; the coupling or connection between the elements can be physical, logical, or a combination thereof. “herein”, “above”, “below”, and words of similar import, when used to describe this specification shall refer to this specification as a whole and not to any particular portions of this specification. “or”, in reference to a list of two or more items, covers all of the following interpretations of the word: any of the items in the list, all of the items in the list, and any combination of the items in the list. the singular forms “a”, “an” and “the” also include the meaning of any appropriate plural forms.

(52) Words that indicate directions such as “vertical”, “transverse”, “horizontal”, “upward”, “downward”, “forward”, “backward”, “inward”, “outward”, “vertical”, “transverse”, “left”, “right”, “front”, “back”, “top”, “bottom”, “below”, “above”, “under”, and the like, used in this description and any accompanying claims (where present) depend on the specific orientation of the apparatus described and illustrated. The subject matter described herein may assume various alternative orientations. Accordingly, these directional terms are not strictly defined and should not be interpreted narrowly.

(53) Where a component (e.g. a circuit, module, assembly, device, drill string component, drill rig system etc.) is referred to herein, unless otherwise indicated, reference to that component (including a reference to a “means”) should be interpreted as including as equivalents of that component any component which performs the function of the described component (i.e., that is functionally equivalent), including components which are not structurally equivalent to the disclosed structure which performs the function in the illustrated exemplary embodiments of the invention.

(54) Specific examples of methods and apparatus have been described herein for purposes of illustration. These are only examples. The technology provided herein can be applied to contexts other than the exemplary contexts described above. Many alterations, modifications, additions, omissions and permutations are possible within the practice of this invention. This invention includes variations on described embodiments that would be apparent to the skilled person, including variations obtained by: replacing features, elements and/or acts with equivalent features, elements and/or acts; mixing and matching of features, elements and/or acts from different embodiments; combining features, elements and/or acts from embodiments as described herein with features, elements and/or acts of other technology; and/or omitting combining features, elements and/or acts from described embodiments.

(55) The foregoing is considered as illustrative only of the principles of the invention. The scope of the claims should not be limited by the exemplary embodiments set forth in the foregoing, but should be given the broadest interpretation consistent with the specification as a whole.