CA2509082C - Rotary pump stabilizer - Google Patents

Abstract

A stabilizer is provided for stabilizing a rotary or progressive cavity pump suspended from production tubing in well casing. The stabilizer is connected between the production tubing and the pump. The stabilizer has a tubular body having a cylindrical wall and a longitudinal bore contiguous with the production tubing. A releasable sliding dog is disposed on the exterior of the tubular body and is operatively connected by a link to one or more pistons. Each piston is disposed in a piston housing that is in fluid communication with the bore of the tubular body. Circumferentially spaced-apart feet extend radially outwardly from the tubular body. In operation, actuating fluid pressure advances the pistons uphole, driving the sliding dog up one or more longitudinal outwardly extending ramps to brace against the casing, with the feet contacting the casing and bearing opposing reactive force. Preferably, the sliding dog and the feet form a three-point contact with the casing that arrests lateral movement in any direction. Under non-actuating pressure, upward drag on the sliding dog compresses the pistons, retracting the dog, and permitting removal of the stabilizer and pump.

Description

1 "ROTARY PUMP STABILIZER"

2

3 FIELD OF THE INVENTION

4 The invention relates to a dynamic pressure-responsive apparatus used for the stabilization of tools suspended from production tubing, said tools 6 being subject to undesirable lateral movement, and particularly tools subject to 7 vibration in operation such as progressive cavity pumps.

Apparatus are known for stabilizing various well tools which are 11 suspended at the bottom of a production tubing string. An example of a tool 12 which would benefit from stabilization is a rotary or progressive cavity pump ("PC
13 pump"). A PC pump is located within an oil well, positioned at the bottom end of 14 a production tubing string which extends down the casing of the well. The pump pressurizes well fluids and drives them up the bore of the production tubing 16 string to the surface. The pump comprises a pump stator coupled to the 17 production tubing string, and a rotor which is both suspended and rotationally 18 driven by a sucker rod string extending through the production tubing string bore.
19 The stator is held from reactive rotation by a tool anchored against the casing.
Usually this anti-rotation tool or torque anchor is located at the base of the stator 21 and typically applies serrated slips to grip against the casing.
22 The rotor is a helical element which rotates within a corresponding 23 helical passage in the stator. Characteristically, the rotor does not rotate 24 concentrically within the stator but instead scribes a circular or elliptical path.

1 This causes vibration and oscillation of the sucker rod, the pump's stator and the 2 tubing attached thereto.
3 The greater the pump flow, the greater is the vibration. This can 4 lead to loosening of the slips and functional failure of the no-turn tool.
Other problems include fatigue failure of the connection of the stator to the tubing or 6 nearby tubing-to-tubing connections.
7 In the prior art, bow springs have typically been used to centralize 8 and stabilize the stator and the supporting tubing. By design, the bow springs 9 are radially flexible, in part to permit installation and removal through casing.
Unfortunately, the spring's flexibility permits cyclic movement, resulting in fatigue 11 and eventual failure of the springs.
12 Unitary tubing string centralizers generally position the tool in a 13 concentric or central position in the welt. While these centralizers may provide a 14 positioning function, they are not effective as a tool-stabilizing means.
The known centralizers are passive devices and do not actively contact the casing.
16 More sophisticated apparatus are known which more positively 17 secure and position tools within a well. For example, in U.S. Patent 2,490,350 to 18 Grable, a centralizer is provided using mechanical linkages which lock radially 19 outwardly to engage the casing. Each of a plurality of two-bar linkages is held tight to the outside of the tubing string with a retaining bolt. A
longitudinal spring 21 and longitudinal ratchet are arranged external to the tubing for pre-loading of one 22 link with the potential to jack-knife the linkage outwardly, except for the 23 restraining action of the retaining bolt. A radial plunger extends through the 24 tubing wall to contact the linkage. The plunger has limited stroke. When the tubing string bore is pressurized, the plunger urges the linkage sufficiently 1 outwardly to break the retaining bolt, permitting the spring to drive the linkage 2 radially outwardly. The driven link engages the ratchet, ensuring the linkage 3 movement is uni-directional.
4 In U.S. Patent 4,960,173 to Cognevich, a tubular housing is also disclosed having mechanical linkages which are held tight to the housing during 6 installation. The linkages are irreversibly deployed upon melting of a fusible link 7 at downhole conditions. An annular compression spring actuates a telescoping 8 sleeve which deploys a four-bar linkage and forcibly holds the linkage against 9 the casing wall. Rollers on the ends of two of the linkages contact the casing wall for aiding in limited longitudinal movement of the tubular housing once the 11 linkages are deployed. Gradual radial adjustment of the linkage is permitted by 12 a fluid bleed to permit the telescoping sleeve to slowly retract during this 13 movement. If the bleed fails and additional radial movement continues, a pin will 14 shear, fully releasing the telescoping sleeve and linkage from the compression spring.
16 In summary, both Grable and Cognevitch disclose apparatus 17 which: rely upon compression spring force alone to drive and hold the linkages 18 radially outwardly; do not deploy or extend the linkage until after installation on 19 the casing; result in an irreversible deployment; and in the case of Grable, do not permit movement or removal without damage to the linkage, and in the case of 21 Cognevitch, limited movement is permitted but if the linkage cannot accept the 22 movement required, a jarring action will shear a pin and irreversibly separate the 23 compression spring from the linkage.
24 In Canadian Patent Application 2,296,867 to Tessier, a tubular stabilizing apparatus is disclosed having a sliding dog disposed in a longitudinal 1 pocket formed in the exterior of the tubular body. The sliding dog is activated by 2 pistons pivotally connected to the sliding dog whereby fluid pressure within the 3 piston bore dynamically drives the pistons to move the sliding dog along a ramp 4 formed within the pocket. The tip of the sliding dog is thereby driven upwardly and outwardly to contact and brace against the casing, with the opposite side of 6 the tubular body contacting the casing.
7 While the stabilizing apparatus of Tessier provides several 8 advantages over the prior art, under some circumstances, the two-point contact 9 of the tip of the sliding dog and the opposing tubular body with the casing may not provide sufficient stabilization against movement transverse to the plane of 11 contact.
12 There is, therefore, a need for an improved stabilizing apparatus.

2 A stabilizer is provided for securely and releasably stabilizing 3 downhole tools suspended from a production tubing string containing fluid under 4 varying pressure. Such a tool is associated with or is the source of lateral movement within the casing.
6 In a broad aspect of the invention, the stabilizer is positioned 7 between a well tool, such as a PC pump, and the production tubing string.
The 8 stabilizer comprises a tubular body having a cylindrical wall and a longitudinal 9 bore contiguous with that of the production tubing string. A releasable stabilizing means or assembly is disposed on the exterior of the tubular body that extends 11 radialiy outward to contact the casing when actuated. At least two 12 circumferentially spaced-apart feet extend radially outward from the tubular body 13 to contact the casing when the stabilizer is actuated. More particularly, the angle 14 between the stabilizer and the feet adjacent to the stabilizing means is greater than ninety degrees, preferably in the range of about 110 degrees to about 160 16 degrees, and most preferably about 120 degrees, such that the feet bear 17 reactive force against the stabilizing means to substantially arrest lateral 18 movement in any direction. Preferably, there are two feet equidistant from the 19 stabilizing means and at an angle of about 120 degrees forming a three-point contact of the feet and the stabilizer with the casing.
21 In one embodiment, the stabilizer utilizes fluid pressure to actively 22 and forcefully stabilize the tool against lateral movement in any direction.
23 Further, when the fluid pressure diminishes, such as when no fluid is being 24 produced, the apparatus may be readily repositioned, repeatedly installed or removed without irreversible alteration of the apparatus or peripheral damage.

5 1 The apparatus is dynamically responsive so as to provide greater stabilizing 2 force at higher fluid pressures, for instance, in the case of a PC pump tool, when 3 the pump is pumping more vigorously.
4 Preferably, the stabilizing means comprises a radially outwardly extendable sliding dog operably connected to a fluid pressure-driven actuating

6 means or actuator comprising one or more pistons, housed and moveable within

7 piston bores formed in a piston housing. The piston bore is in communication

8 with the bore of the tubular body so that it is pressurized dynamically with fluid.

9 Fluid pressure causes the pistons to advance uphole, driving the sliding dog upward to be driven up at feast one ramp, so as to move radially outwardly to 11 contact and brace against the casing, with the radial force being proportional 12 with the fluid pressure. Preferably, there are two longitudinally spaced-apart 13 ramps and the sliding dog and the pistons are connected by a pivotable fink such 14 that the sliding dog is substantially parallel with the casing when actuated.
The stabilizer can also include a shear pin extending thought the 16 wall of the tubular body and the stabilizing means to prevent pre-actuation of the 17 stabilizer, such as when the stabilizer is being installed within the well.
Further, 18 stops can be provided that limit longitudinal movement of the stabilizing means 19 or actuating means to obviate a possible jamming of the stabilizer in the well.

2 In drawings which are intended to illustrate embodiments of the 3 invention and which are not intended to limit the scope of the invention:
4 Figure 1 is a cross-sectional view of the lower end of a well casing with the stator of a PC pump located therein, the pump having an embodiment of 6 the stabilizer of the present invention connected thereabove for stabilizing the 7 pump and tubing within the casing, and with the cross-section of the stabilizer 8 taken along line i-I of Fig. 3B;
9 Figure 2 is a partially exploded perspective view the stabilizer according to Fig. 1;
11 Figure 3A and 3B are top end views of the stabilizer taken along 12 the lines III-III of Figs. 4A and 4B, respectively, with the stabilizer installed in a 13 well casing and shown in the non-actuated condition (Fig 3A) and actuated 14 condition (Fig. 3B);
Figures 4A and 4B are elevational views of the stabilizer according 16 to Fig. 1, with part of the piston housing cut away and shown in the non-actuated 17 condition (Fig. 4A) and actuated condition (Fig. 4B); and 18 Figures 5A and 5B are cross-sectional views taken along lines V-V
19 of Figs. 4A and 4B, respectively, with the stabilizer installed in a well casing.
Figure 6 is a cross-sectional view of an alternative embodiment of 21 a stabilizer according to the present invention with the stabilizer installed in a 22 well casing and in the actuated condition.

2 Having reference to Fig. 1, one embodiment of a stabilizer 2 is 3 located within the bore 3 of the casing 4 of a completed oil well 6. The stabilizer 4 2 is suspended from a production tubing string 7 and connected to a downhole well tool such as a rotary pump. Shown in this embodiment, the stabilizer 2 is 6 connected co-axially via a pup joint 8 to the stator 10 of a progressive cavity 7 pump ("PC pump") 12 located within the well casing 4. The PC pump 12 is 8 therefore suspended from the production tubing string 7 by connection through 9 the stabilizer 2. In operation, the PC pump 12 pressurizes well fluids and directs them up the bore 13 of the production tubing string 7 to the surface.
11 In the context of a PC pump 12, its stator 10 is secured against 12 reactive torque rotation in the casing 4. While not shown, it is understood that 13 the stator 10 is secured using an anti-rotation tool or a torque anchor usually 14 positioned at the lower end of the PC pump 12. The rotor of the PC pump 12, which is not shown for clarity of the other components, would be typically 16 suspended and rotationally driven from a sucker rod, also not shown.
17 Referring also to Figs. 2, 3A and 3B, the stabilizer 2 comprises a 18 tubular body 14 and a releasable stabilizing means or assembly 16 disposed on 19 the exterior 17 of the tubular body 14. The tubular body 14 has a contiguous annular wall 18 forming a longitudinal bore 20 extending therethrough for 21 passing pressurized well fluids pumped from the PC pump 12, through the 22 tubular body bore 20 and up the production tubing string bore 13 to the surface.
23 An annular space 22 is formed between the tubular body 14 and the casing 4.
24 The releasable stabilizing means 16 is radially outwardly extendible to engage the casing 4. Actuation such as by fluid pressure in the tubular body 1 bore 20 (PB), which is greater than the pressure in the annulus 22 (PA), forcibly 2 actuates and braces the stabilizing means 16 against the casing 4 and thereby 3 jams the tubular body 14 against the opposing side of the well casing 4 to 4 substantially arrest oscillatory movement of the PC pump stator 10. The stabilizing means 16 is dynamically actuated by fluid pressure which makes the 6 stabilizing capability stronger as the fluid pressure PB increases.
7 In greater detail, the tubular body 14 is profiled to provide at least 8 two longitudinally extending and circumferentially spaced-apart protrusions or 9 feet 24. The effective diameter of the stabilizer 2 before actuation is less than the diameter of the casing bore 3 to permit installation of the stabilizer 2 therein.
11 The angle A between the stabilizing means 16 and each of the feet 24 adjacent 12 to the stabilizing means 16 is greater than 90 degrees, preferably in the range of 13 about 110 degrees to about 160 degrees, such that when the stabilizing means 14 16 is actuated, the stabilizing means 16 and the feet 24 contact the casing. In other words, each of the feet 24 need to bear opposing reactive force against the 16 stabilizing means 16 when actuated. Preferably, there are two feet 24 17 equidistant from the stabilizing means 16 and the angle is about 120 degrees, 18 thereby forming a three point contact of the stabilizing means 16 and the feet 24 19 with the casing 4 to substantially arrest lateral movement of the PC pump

10 in any direction.
21 It is to be noted that while Fig. 3A shows the feet 24 contacting the 22 casing 4 in the non-actuated position, this is only to more clearly show the radial 23 movement of the stabilizing means 16 within the annular space 22 upon 24 actuation. In fact, the stabilizer 2 is loosely and randomly fit within the casing bore 3 until it is actuated.

1 The stabilizing means 16 comprises a sliding dog 26 and a fluid 2 pressure-driven actuating means or actuator 28. Having further reference to 3 Figs. 4A, 4B, 5A and 5B, the sliding dog 26 is operable between a retracted 4 position (Figs. 4A, 5A) and a radially outwardly extended position (Figs.
4B, 5B) for engagement of the sliding dog 26 with the casing 4.
6 The sliding dog 26 and actuating means 28 are positioned in a 7 longitudinally extending pocket 34 formed in a thickened portion 36 of the 8 annular wall 18. The pocket 34 extends radially inwardly or is recessed from an 9 outer surface 38 of the tubular body 14. More particularly and as best seen in Fig. 2, the pocket 34 has an uphole portion 44 into which the sliding dog 26 is

11 disposed and a downhole portion 46 into which the actuating means 28 is

12 disposed. The sliding dog 26 and actuating means 28 are operatively connected

13 by one or more links 48 positioned therebetween and pivotally attached thereto

14 with pins 49, such as a roll pins. Each link 48 is a double link having first and second ends 48a, 48b to enable both axial and radial displacement of the sliding 16 dog 26.
17 The uphole portion 44 includes a first, uphole ramp 50 and a 18 parallel second, downhole ramp 52 longitudinally spaced by a land 54 from the 19 first ramp 50. The ramps 50, 52 extend longitudinally and outwardly from the floor 56 of the pocket 34. In operation, as shown in Figs. 4B and 5B, when the 21 tubular body bore 20 is pressurized for actuation (PB»PA), the actuating means 22 28 is advanced longitudinally uphole for driving the sliding dog 26 against the 23 first and second ramps 50, 52. The ramps 50, 52 deflect the sliding dog 26 24 radially outward, similar to the action of a parallelogram linkage, as the links 48 pivot relative to the actuating means 28 and the sliding dog 26. Eventually, as 1 the actuating means 28 advances, the sliding dog 26 radially contacts and 2 braces against the casing 4, with the sliding dog 26 being substantially parallel to 3 the casing 4.
4 To prevent the sliding dog 26 from failing out of the pocket 34 during handling outside of the casing 4, while also subsequently permitting 6 movement of the sliding dog 26 as required, a shoulder screw 40 is affixed to the 7 tubular body 14 and set within a longitudinally elongated screw hole 42.
8 In an aitemative embodiment, as shown in Fig. 6, there is a single 9 ramp 53. Further, the sliding dog 26 can be pivotally connected to the actuating means 28 by a hinge 57, in which case the sliding dog will pivot outwardly for 11 contact of a tip 59 of the sliding dog 26 with the casing 4. Such an apparatus is 12 described in Canadian Patent Application No. 2,292,867 to Tessier.
13 The actuating means 28 is an arrangement of one or more 14 longitudinally-extending pistons 60 and piston bores 62, and ports 64 extending between each piston bore 62 and the bore 20 of the tubular body 14.
16 In detail, each piston bore 62 is drilled in a piston housing 66 that is 17 fit within the downhole portion 46 of the pocket 34. The piston housing 66 is 18 secured to the tubular body 14 by screws 68 or other suitable means. Each 19 piston bore 62 has a first, uphole end 70 that opens into the pocket's uphole portion 44 and a second, downhole end 72 that communicates with the tubular 21 body bore 20 through the ports 64. The ports 64 are drilled through the piston 22 housing 66 and the annular wail 18 to form a contiguous port 64 when the 23 housing 66 is fit within the pocket 34. An O-ring 74 is fit between the piston 24 housing 66 and the annular wall 18 to form a fluid seal through the ports 64.

1 A piston 60 is disposed in each piston bore 62 and is longitudinally 2 movable between the bore's first and second ends 70, 72. Each piston 60 has 3 an uphole, pocket end 76 and a downhole, pressure end 78. A double O-ring 4 seal 80 is fit to the downhole end 78 of each piston 60 to prevent pressurizing fluid from flowing out of the piston bore 62, thereby forming a pressure chamber 6 82 at the second end 72 of the piston bore 62. The uphole end 76 of each piston 7 60 is pivotally connected to the first end 48a the link 48, with the second end 48b 8 of the link 48 being pivotally connected to a downhole end 84 of the sliding dog 9 26.
When fluid pressure PB within the tubular body bore 20 is raised 11 above the pressure PA outside the stabilizer 2, such as when a PC pump 12 operates, the differential pressure (PB-PA) causes each piston 60 to advance in 13 the uphole direction, actuating the sliding dog 26.
14 The greater is the fluid pressure PB in the bore 20, the greater is the differential pressure (PB-PA), the greater is the force applied to each piston 16 60 and the greater is the force applied by the sliding dog 26 against the casing 4.
17 Serendipitously, as the downhole tool, such as a PC pump, works harder and 18 results in greater vibration, the bore pressure PB also increases and the sliding 19 dog 26 provides even greater stabilizing force. At the same time, an extension stop 86 is positioned to contact the uphole end 76 of each piston 60 to limit the 21 piston 60 from over-stroking and thereby obviating a possible jamming of the 22 stabilizer 2 in the casing 4.
23 In an example case where each of two pistons 60 and piston bores 24 62 are 3/4 inch in diameter, differential fluid pressures (PB-PA) of 2000 psi(g) 1 result in actuating forces of 1770 pounds, and radial forces of 8850 pounds 2 being applied against the casing wall.
3 As best seen in Figs. 2, 4A and 4B, a shear pin 88 extending 4 through at least one of the pins 49 and the annular wall 18 prevents premature actuation of the stabilizer 2 as it is inserted into the casing 4. The shear pin 88 is 6 constructed of material that is capable of supporting sufficient load to prevent 7 premature actuation, but which will shear at actuating forces, as shown in Figs.
8 4A and 4B. In the above example case, the shear pin 88 can be a nylon shear 9 pin capable of supporting a load of 400 Ibs.
When it is necessary to move or remove the downhole tool or 11 stabilizer 2 from the casing 4, the pressure is reduced in the tubular body bore 12 20. In the case of a PC pump, pumping is stopped and the pressure differential 13 between the tubular body bore 20 and the annulus 22 falls to reach equilibrium 14 (PB substantially equals PA). The actuating means 28 goes slack and the force of the sliding dog 26 against the casing 4 drops, releasing the dog 26 and 16 enabling movement of the stabilizer 2. Further, when the stabilizer 2 is being 17 removed from the casing 4, upward movement drags the dog 26 against the 18 casing 4 also forces the dog 26 back into the pocket 34 and the pistons 60 back 19 in their bores 62.
To ensure a snag-free profile or line for ease of removal, uphole 21 and downhole retraction stops 90, 92 are provided that limit the downhole 22 movement of the sliding dog 26, as particularly seen in Figs. 2, 4A and 4B.
The 23 uphole retraction stop 90 is formed by the uphole end 94 of the land 54 between 24 first and second ramps 50, 52. The uphole retraction stop 90 has an upwardly facing radial surface 96 extending to the pocket floor 56 that contacts a 1 downwardly facing radial surface 98 of the sliding dog 26. The downhole 2 retraction stop 92 projects outwardly from the pocket floor 56 and is positioned to 3 contact the downhole end 84 of the sliding dog 26. Conveniently, the downhole 4 stop 92 can correspond to the extension stop 86.
Preferably the tubular body 14 is cast or machined in one piece.
6 The pocket 34 is recessed into wall 18, such as being cast in place or formed 7 through a process such as milling. The following are examples of materials 8 suitable for use for the various stabilizer components.

Component material Tubular body 14 Carbon steel Piston housing 302 stainless steel Sliding dog 26 HTSR

Piston 60 17-4 stainless PH, grade HL50 Links 48 HTSR

Pins 49 stainless steel O-rings 74, 80 Viton 90

Claims (16)

THE EMBODIMENTS OF THE INVENTION IN WHICH AN
EXCLUSIVE PROPERTY OR PRIVILEGE IS CLAIMED ARE DEFINED AS
FOLLOWS:

1. A stabilizer for stabilizing a well tool within a subterranean casing, the well tool being suspended from a production tubing and having a longitudinal bore for containing pressurized well fluid therein, the stabilizer comprising:

a tubular body having a cylindrical wall and a longitudinal bore extending therethrough, the tubular body positioned within the casing between the well tool and the production tubing, the bore of the tubular body in communication with the longitudinal bore of the production tubing;

a releasable stabilizing means disposed on the tubular body, the stabilizing means being actuatable to extend radially outward for contacting the casing, the stabilizing means comprising:

a recessed pocket formed in the wall, the pocket having an uphole portion forming at least one radially outwardly extending ramp, and a downhole portion;

a radially outwardly extendable sliding dog disposed within the uphole portion, the sliding dog having a first position wherein the sliding dog is retracted within the pocket and a second position wherein the sliding dog is radially outwardly extended;

a downhole retraction stop positioned between the sliding dog and the actuating means, the downhole retraction stop limiting the downhole movement of the sliding dog; and actuating means positioned within the downhole portion and operatively connected to the sliding dog, the actuating means in fluid communication with the longitudinal bore of the tubular body whereby the fluid pressure causes the actuating means to advance uphole, driving the sliding dog longitudinally along the at least one ramp to move the sliding dog from the first position to the second position to contact the casing and stabilize the well tool, the force of contact being substantially proportional to the fluid pressure, and at least two circumferentially spaced-apart feet extending radially outward from the tubular body, an angle between the stabilizing means and each of the feet adjacent to the stabilizing means being greater than 90 degrees, wherein the feet and the stabilizing means contact the casing when the stabilizing means is actuated.

2. The stabilizer of claim 1 wherein the angle is in the range of about 110 degrees to 160 degrees.

3. The stabilizer of claim 1 wherein the angle is about 120 degrees.

4. The stabilizer of claim 1 wherein there are two feet equidistant from the stabilizing means, wherein the angle is about 120 degrees, and wherein the feet and the stabilizing means form a three-point contact with the casing when the stabilizing means is actuated.

5. The stabilizer of any one of claims 1 to 4 wherein the actuating means is connected to the sliding dog by a link, and wherein the sliding dog is substantially parallel with the casing when actuated.

6. The stabilizer of any one of claims 1 to 5 wherein the uphole portion of the pocket forms two longitudinally spaced and parallel ramps.

7. The stabilizer of claim 6 further comprising an uphole retraction stop between the two ramps, the uphole retraction stop having an upwardly facing surface for contacting a downwardly facing surface of the sliding dog when in the first position.

8. The stabilizer of any one of claims 1 to 7 further comprising:
an extension stop positioned between the sliding dog and the actuating means, the extension stop limiting the uphole movement of the actuating means.

9. The stabilizer of any one of claims 1 to 7 further comprising:
an extension stop positioned between the sliding dog and the actuating means, the extension stop limiting the uphole movement of the actuating means, wherein the downhole retraction stop and the extension stop are the same.

10. The stabilizer of any one of claims 1 to 9 wherein the actuating means comprises:

one or more piston bores formed in a piston housing, the piston housing securely fit within the downhole portion of the pocket, each piston bore having a first downhole end in communication with the longitudinal bore of the tubular body and a second end open to the one or more pockets; and a piston longitudinally moveable within each piston bore and having an uphole end operatively connected to the sliding dog, the fluid pressure within the longitudinal bore of the tubular body pressurizing each piston bore causing each piston to advance uphole to drive the sliding dog.

11. The stabilizer of claim 10 wherein there are two piston bores, wherein the pistons are connected to the sliding dog by a link having a first end pivotally connected to the piston and a second end pivotally connected to the sliding dog, and wherein the uphole portion forms two longitudinally spaced and parallel ramps.

12. The stabilizer of any one of claims 1 to 11 further comprising a shear pin extending through the wall and the stabilizing means to prevent actuation of the apparatus in the absence of actuating fluid pressure.

13. The stabilizer of any one of claims 1 to 12 wherein the well tool being stabilized is a fluid pump that pressurizes fluid within the bore of the tubular body.

14. The stabilizer of claim 13 wherein the pump is a rotary pump.

15. The stabilizer of claim 13 wherein the pump is a progressive cavity pump.

16. The stabilizer of any one of claims 1 to 15 wherein the stabilizing means is a stabilizing assembly and the actuating means is an actuator.