Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
CA 02292867 1999-12-22
1 "ROTARY PUMP STABILIZER"
2
3 FIELD OF THE INVENTION
4 The invention relates to a dynamic pressure-responsive tool used for
the stabilization tools suspended from production tubing, said tools being
subject to
6 undesirable lateral movement, more particularly tools subject to vibration
in
7 operation such as progressive cavity pumps.
8
9 BACKGROUND OF THE INVENTION
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
which
12 would benefit from stabilization is a rotary or progressive cavity pump
("PC pump").
13 A PC pump is located within an oil well, positioned at the bottom end of a
production
14 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 string to the
surface.
16 The pump comprises a pump stator coupled to the production tubing string,
and a
17 rotor which is both suspended and rotationally driven by a sucker rod
string
18 extending through the production tubing string bore. The stator is held
from reactive
19 rotation by a tool anchored against the casing. Usually this anti-reactive,
or no-turn
tool is located at the base of the stator. Typically a no-turn tool applies
serrated
21 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
CA 02292867 1999-12-22
1 concentrically within the stator but instead scribes a circular or
elliptical path. This
2 causes vibration and oscillation of the sucker rod, the pump's stator and
the tubing
3 attached thereto.
4 The greater the pump flow, the greater is the vibration. This can lead
to loosening of the slips and functional failure of the no-turn tool. Other
problems
6 include fatigue failure of the connection of the stator to the tubing or
nearby tubing-
7 to-tubing connections.
8 In the prior art, bow springs have typically been used to centralize and
9 stabilize the stator and the supporting tubing. By design, the bow springs
are
radially flexible, in part to permit installation and removal through casing.
11 Unfortunately, the spring's flexibility permits cyclic movement, resulting
in fatigue
12 and eventual failure of the springs.
13 Unitary tubing string centralizers generally position the tool in a
14 concentric or central position in the well. While these centralizers may
provide a
positioning function, they are not effective as a tool-stabilizing means. The
known
16 centralizers are passive devices and do not actively contact the casing.
17 More sophisticated apparatus are known which more positively secure
18 and position tools within a well. For example, in U.S. Patent 2,490,350 to
Grable, a
19 centralizer is provided using mechanical linkages which lock radially
outwardly to
engage the casing. Each of a plurality of two-bar linkages is held tight to
the
21 outside of the tubing string with a retaining bolt. A longitudinal spring
and
22 longitudinal ratchet are arranged external to the tubing for pre-loading of
one link
23 with the potential to jack-knife the linkage outwardly, except for the
restraining
2
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1 action of the retaining bolt. A radial plunger extends through the tubing
wall to
2 contact the linkage. The plunger has limited stroke. When the tubing string
bore is
3 pressurized, the plunger urges the linkage sufficiently outwardly to break
the
4 retaining bolt, permitting the spring to drive the linkage radially
outwardly. The
driven link engages the ratchet, ensuring the linkage movement is uni-
directional.
6 In U.S. Patent 4,960,173 to Cognevich, a tubular housing is also
7 disclosed having mechanical linkages which are held tight to the housing
during
8 installation. The linkages are irreversibly deployed upon melting of a
fusible link at
9 downhole conditions. An annular compression spring actuates a telescoping
sleeve
which deploys a four-bar linkage and forcibly holds the linkage against the
casing
11 wall. Rollers on the ends of two of the linkages contact the casing wall
for aiding in
12 limited longitudinal movement of the tubular housing once the linkages are
13 deployed. Gradual radial adjustment of the linkage is permitted by a fluid
bleed to
14 permit the telescoping sleeve to slowly retract during this movement. If
the bleed
fails and additional radial movement is continues, a pin will shear, fully
releasing the
16 telescoping sleeve and linkage from the compression spring.
17 In summary, both Grable and Cognevitch disclose apparatus which:
18 - rely upon compression spring force alone to drive and hold the
19 linkages radially outwardly;
- do not deploy or extend the linkage until after installation on the
21 casing;
22 - result in an irreversible deployment; and
3
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1 - in the case of Grable, do not permit movement or removal
2 without damage to the linkage, and in the case of Cognevitch,
3 limited movement is permitted but if the linkage cannot accept
4 the movement required, a jarring action will shear a pin and
irreversibly separate the compression spring from the linkage.
6 Therefore, for well tools which require secure stabilization within the
7 casing, there is a demonstrated need for a device which is capable of
providing a
8 stabilizing force which is greater than that provided by spring force alone,
yet is still
9 capable of being moved within or removed from the casing without
irreversible
damage to the apparatus.
11
4
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1 SUMMARY OF THE INVENTION
2 Stabilizing apparatus is provided for securely stabilizing downhole
3 tools suspended from a production tubing string containing fluid under
varying
4 pressure. Such a tool is associated with or is the source of lateral
movement within
the casing.
6 The novel apparatus utilizes fluid pressure to actively and forcefully
7 stabilize the tool. No springs are required for its actuation or release.
Further,
8 when the fluid pressure diminishes, such as when no fluid is being produced,
the
9 apparatus may be readily repositioned, repeatably installed or removed
without
irreversible alteration of the apparatus or peripheral damage. The apparatus
is
11 dynamically responsive so as to provide greater stabilizing force at higher
fluid
12 pressures, for instance, in the case of a PC pump tool, when the pump is
pumping
13 more vigorously.
14 In a broad aspect of the invention, stabilizing apparatus is connected
to a well tool, such as a PC pump, suspended from the bottom of a production
16 tubing. The apparatus comprises a tubular body having an enclosing wall and
a
17 longitudinal bore contiguous with that of the production tubing string. A
sliding dog
18 is recessed within the tubular body. The sliding dog is attached pivotally
to one or
19 more pistons, housed and moveable within piston bores formed in the
cylindrical
wall of the tubular body. When actuated longitudinally, the pistons drive the
sliding
21 dog upward to contact and be driven up a ramp so as move radially so as to
contact
22 and brace against the casing. The piston's bore is connected to the
longitudinal
23 bore so that it is pressurized dynamically with fluid. As the fluid
pressure actuates
5
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1 the sliding dog radially outwards, the radial force is proportional with the
fluid
2 pressure.
3
4 BRIEF DESCRIPTION OF THE DRAWINGS
Figure 1 is cross-sectional view of the lower end of a well casing with
6 the stator of a PC pump suspended from production tubing and anchored to the
7 casing, the pump having a stabilizer of the present invention connected
thereabove
8 for stabilizing the pump and tubing within the casing;
9 Figure 2 is a partially exploded perspective view of an embodiment of
the stabilizer. A portion of the stabilizer is cut-away to illustrate the
sliding dog;
11 Figure 3 is a cross-section side view of the stabilizer of Fig. 2, showing
12 the sliding dog in the non-actuated position; and
13 Figure 4 is a cross-sectional side view of the stabilizer of Fig. 2
14 showing the sliding dog in the actuated position.
6
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1 DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT
2 Having reference to Fig. 1, a stabilizer 1 is located within the bore of
3 the casing 2 of a completed oil well 3. The stabilizer 1 is connected to a
downhole
4 well tool such as a rotary pump. Shown in this embodiment, the stabilizer 1
is
connected co-axially and in-line to the stator 4 of a progressive cavity pump
("PC
6 pump") 5. The PC pump is located within the well casing 2. The PC pump is
7 suspended from a production tubing string (not shown) by connection through
the
8 stabilizer 1. In operation, the PC pump 5 pressurizes well fluids and
directs them up
9 the bore of the production tubing string to the surface.
In the context of a PC pump, its stator 4 is secured against reactive
11 torque rotation in the casing 2. While not shown, it is understood that the
stator 4 is
12 secured using a no-turn tool usually positioned at the lower end of the PC
pump.
13 The rotor of the PC pump 5, which is not shown would be typically suspended
and
14 rotationally driven from a sucker rod, also not shown.
Referring also to Fig. 2, the stabilizer 1 comprises a tubular body 7, a
16 sliding dog 8 and fluid-pressure actuating means 9. The tubular body 7 has
a
17 longitudinal bore 10 extending therethrough for passing pressurized well
fluids
18 pumped from the PC pump 5, through bore 10 and up the production tubing
string
19 to the surface. The longitudinal bore 10 through the body 7 forms a
contiguous wall
annular wall 11 for separating the bore 10 from the casing 2. In Figs. 2 - 4
the bore
21 10 is eccentric within the tubular body 7 for providing a thickened wall
portion 11 b in
22 which the pocket 12 is formed.
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1 The sliding dog 8 is radially extendible to engage the casing 2 (Figs. 1
2 and 4). Fluid pressure PB in the bore 10, being greater that the pressure PA
3 existing outside the stabilier 1, forcibly actuates and braces the sliding
dog against
4 the casing 2 and substantially arrest oscillatory movement of the PC pump
stator 4.
The bracing of the dog 8 against the casing 2 thereby jams the tubular body 7
6 against the opposing side of the well casing 2.
7 In greater detail and having reference to Figs. 2, 3, and 4, the
8 stabilizer 1 comprises the tubular body 7 having a sliding dog 8. As shown
in Fig. 3
9 and 4, the sliding dog 8 is operable between a retracted position (Fig. 3)
within the
body 7 and a radially extended position (Figs. 1,4) for engaging the casing 2.
11 A single, longitudinally extending pocket 12 is formed in cylindrical
12 wall 11, extending radially inwardly or recessed from the outer surface 13
of the
13 body 7. The pocket 12 has a first and second end 14,15. The first, downhole
end
14 14 has a radial, closed face and the second uphole surface end 15 is
sloped. The
pocket has a floor 16. An inclined ramp 17 is formed at the pocket's second
end 15,
16 rising from the floor 16 up to the outer surface 13 of the body 7. One or
more
17 longitudinally extending stops 21 are formed on the pocket's floor 16
preceding the
18 ramp 17. Grooves 22 are formed in the base of the sliding dog 8 and size
19 correspondingly for enabling sliding passage over the stops 21.
A pivot point 18 pivotally connects the sliding dog 8 to a linear
21 actuating member 20.
22 Having reference to Fig. 3, before actuation, in the non-pressurized,
23 rest position shown in Fig. 3, the sliding dog 8 resides within the pocket
12.
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1 As shown in Figs. 1 and 4, when the bore 10 is pressurized for
2 actuation (PB>>PA), the actuating member 20 is advanced longitudinally along
3 pocket 12 for driving the sliding dog 8 against ramp 17. The ramp 17
deflects the
4 dog 8 radially outward as it pivots relative to the actuating member 20.
Eventually,
as the actuating member 20 extends, the sliding dog 8 radially contacts and
braces
6 against the casing 2.
7 If the casing 2 is damaged or too large for the stabilizer 1 used, the
8 dog 8 may not engage the casing and risk over extension of the actuating
member
9 20. In such cases, the stops 21 block the actuation member from further
extension.
The actuation of the sliding dog 8 is performed with pressure-actuating
11 means 9. The actuating member 20 is an arrangement of one or more pistons
and
12 piston bores. More particularly, longitudinally-extending piston bores 25
are formed
13 within the cylindrical wall 11.
14 Each piston bore 25 has a first end 26 opening into the pocket's first
end 14. The piston bore 25 is blocked at its second end 27. A piston 28 is
16 disposed in each piston bore 25 and is longitudinally movable between the
bore's
17 first and second ends 26, 27. The stops 21 in the pocket 12 act to arrest
the pistons'
18 outward movement.
19 A double 0-ring seal 29 is fitted to the pressure end 30 of the piston
28. The piston 28 extends from the first end 26 of the piston bore 25 and into
the
21 pocket. The pocket end of the piston 28 is fitted with a pivot point 32 for
connection
22 with the dog's pivot point 18 using pin 33. The pin 33 may be designed to
shear at
23 emergency retrieval forces, far above that experienced during service.
9
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1 The second end of the piston bore 27 is closed with cylindrical plugs
2 34. Each plug is fitted with double 0-ring seals 35 for forming a pressure
chamber
3 36 within the piston bore 25, located between the plug 34 and the pressure
end of
4 the piston 28. The pressure chamber 36 communicates with the longitudinal
bore
10 through ports 35 drilled through cylindrical wall 11.
6 Preferably the tubular body 7 is cast in one piece. The pocket is
7 recessed into wall 11, such as being cast in place or formed through a
process such
8 as milling. The piston bores 25 are drilled into the cylindrical wall of the
stabilizer
9 from the downhole end of the stabilizer through to the first end 14 of the
pocket 12.
Ports 35 are drilled through the cylindrical wall 11 and into the longitudinal
bore 10.
11 The unused portion of ports 35, extending from the wall's outer surface 13
into the
12 piston bore 25 is subsequently sealed off, retaining the port between the
piston bore
13 25 and the longitudinal bore 10. The pistons 28 are placed into their bores
25 with
14 the double 0-ring seal 29 slightly uphole of ports 35. The plugs 34 block
the piston
bore 25 from the annulus between the well casing 2 and the stabilizer 1. The
plugs
16 34 form the pressure chambers and are held in place with a stop pin 37.
17 The pressure actuating means 9 is provided as dynamic means which
18 makes the stabilizing capability stronger as the fluid pressure PB in the
longitudinal
19 bore 10 increases.
The pressure actuating means 9 comprises the piston 28, the piston
21 bore 25, and the port 35 between the piston and longitudinal bores 25,10.
As
22 shown in Fig. 3, when the PC pump operates, the resulting fluid pressure PB
within
23 the longitudinal bore 10 is raised above the pressure PA outside the
stabilizer 1, the
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1 differential pressure (PB-PA) causing the piston 28 to advance towards the
first end
2 26, actuating the sliding dog 8.
3 The greater is the fluid pressure PB in the bore 10, the greater is the
4 differential pressure (PB-PA), the greater is the force applied to the
pistons 28 and
the greater is the force applied by the sliding dog against the casing 2.
6 Serendipitously, as the PC pump works harder and results in greater
vibration, the
7 bore pressure PB also increases and the sliding dog 8 provides even greater
8 stabilizing force.
9 In an example case where each piston 28 and piston bore 25 are 1
inch in diameter, differential fluid pressures (PB-PA) of 2000 psi(g) result
in
11 actuating forces of 1500 pounds, and radial forces of 7500 pounds being
applied
12 against the casing wall.
13 When it is necessary to move or remove the downhole tool or
14 stabilizer 1 from the casing 2, the pressure is reduced in the longitudinal
bore 10. In
the case of a PC pump 5, pumping is stopped and the pressure differential
between
16 the bore and the casing annulus falls (PB substantially equals PA). The
actuating
17 means 9 goes slack and the force of the sliding dog 8 against the casing 2
drops,
18 releasing the dog and enabling movement of the stabilizer 1. When the
stabilizer is
19 being removed from the casing, upward movement drags the dog against the
casing, forcing the dog 8 back into the pocket 12 (Fig. 4), forcing the
pistons 28
21 back in their bores 25, and ensuring a snag-free profile or line for ease
of removal.
11
