Note: Descriptions are shown in the official language in which they were submitted.
STUFFING BOX EMPLOYING TAPERED SURFACE FOR A DYNAMIC SEAL
TECHNICAL FIELD
[0001] This document relates to stuffing boxes for wellheads.
BACKGROUND
[0002] Stuffing boxes are used in the oilfield to form a seal between the
wellhead
and a well tubular passing through the wellhead, in order to prevent leakage
of wellbore
fluids between the wellhead and the piping. Stuffing boxes may be used in a
variety of
applications, for example production with pump-jacks, and inserting or
removing coiled
tubing. Stuffing boxes exist that incorporate a tubular shaft mounted for
rotation in the
housing for forming a stationary seal with the piping in order to rotate with
the piping. The
tubular shaft in turn dynamically seals with the stuffing box housing. Designs
of this type of
stuffing box can be seen in US 7,044,217 and CA 2,350,047.
[0003] Leakage of crude oil from a stuffing box is common in some
applications, due
to a variety of reasons including abrasive particles present in crude oil and
poor alignment
between the wellhead and stuffing box. Leakage costs oil companies money in
service time,
down-time and environmental clean-up. It is especially a problem in heavy
crude oil wells in
which oil may be produced from semi-consolidated sand formations where loose
sand is
readily transported to the stuffing box by the viscosity of the crude oil.
Costs associated with
stuffing box failures are some of the highest maintenance costs on many wells.
SUMMARY
[0004] A stuffing box for a wellhead, the stuffing box comprising: a
stationary
housing defining a passage for receiving a well tubular; a tubular shaft
mounted on the
stationary housing for rotation within the passage and defining an inner axial
bore adapted to
form a static seal around a well tubular in use; and a dynamic pressure seal
mounted within
an annular cavity defined by respective cylindrical surfaces of the stationary
housing and
tubular shaft, in which one or both of the respective cylindrical surfaces are
tapered to
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decrease the radial cross sectional area of a seal travel portion of the
annular cavity in an
axial direction downstream from a well end of the stuffing box.
[0005] In various embodiments, there may be included any one or more of the
following features: The respective cylindrical surface of the tubular shaft is
outward facing
and the respective cylindrical surface of the stationary housing is inward
facing. The
respective cylindrical surface of the tubular shaft is tapered outwardly in an
axial direction
downstream from the well end. The respective cylindrical surface of the
tubular shaft is
inward facing and the respective cylindrical surface of the stationary housing
is outward
facing. The stuffing box comprises a seal positioner for adjustment of the
position of the
dynamic pressure seal within the annular cavity. The seal positioner comprises
a piston. The
seal positioner is upstream of the dynamic pressure seal. The seal positioner
comprises a
wedge. The seal positioner is a hydraulic seal positioner. The seal positioner
further
comprises a threaded rod mounted in the stationary housing. The hydraulic seal
positioner
has a hydraulic fluid input in the stationary housing. The stuffing box is
adapted for
production of wellbore fluids. The stuffing box is adapted for use in a
progressing cavity
pump application. The dynamic pressure seal comprises a lip seal. The stuffing
box
comprises bearings between the stationary housing and the tubular shaft.
[0006] These and other aspects of the device and method are set out in the
claims,
which are incorporated here by reference.
BRIEF DESCRIPTION OF THE FIGURES
[0007] Embodiments will now be described with reference to the figures, in
which
like reference characters denote like elements, by way of example, and in
which:
[0008] Fig. lA is a view of a progressing cavity pump oil well installation
in an earth
formation for production with a typical drive head, wellhead frame and
stuffing box;
[0009] Fig. 1B is a view similar to the upper end of Figure 1 but
illustrating a
conventional drive head with an integrated stuffing box extending from the
bottom end of
the drive head;
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[0010] Fig. 2 is a side elevation view, in section, of a stuffing box
with a tapered
outer bore on the tubular shaft for sealing with a dynamic seal. An exploded
view of a
portion of the stuffing box is also illustrated.
[0011] Fig. 2B is a section view taken along the 2B-i and 2B-ii section
lines from
Fig. 2, with the dynamic seal not shown for ease of illustration. Dashed lines
are used to
indicate the different proportions of the outer surface of the tubular shaft
between the 2B-i
and 2B-ii sections.
[0012] Figs. 3 and 4 are side elevation views, in section, of a stuffing
box, that
illustrate different positions of a hydraulic seal positioner.
[0013] Figs. 5 and 6 are side elevation views, in section, of a stuffing
box, that
illustrate different positions of a threaded rod seal positioner.
[0014] Figs. 7A-D are side elevation views, in section, of portions of
various stuffing
box embodiments illustrating the annular cavity and dynamic seal between the
tubular shaft
and stationary housing. In Figs. 7A - B, the annular cavity is defined by the
tubular shaft and
an inner standpipe of the stationary housing. Figs. 7A-D illustrate
embodiments where the
outward facing cylindrical surface of the stationary housing is tapered (Fig.
7A), the inward
facing cylindrical surface of the tubular shaft is tapered (Fig. 7B), the
inward facing
cylindrical surface of the stationary housing is tapered (Fig. 7C), and both
cylindrical
surfaces of the tubular shaft and stationary housing are tapered (Fig. 7A).
DETAILED DESCRIPTION
[0015] Immaterial modifications may be made to the embodiments described
here
without departing from the scope of the specification and drawings.
[0016] Fig. IA illustrates a known progressing cavity pump installation
10. The
installation 10 includes a typical progressing cavity pump drive head 12, a
wellhead frame
14, a stuffing box 16, an electric motor 18 , and a belt and sheave drive
system 20 , all
mounted on a flow tee 22. The flow tee is shown with a blowout preventer 24
which is, in
turn, mounted on a wellhead 25. The drive head 12 supports and drives a drive
shaft 26,
generally known as a "polished rod". The polished rod is supported and rotated
by means of
a polish rod clamp 28, which engages an output shaft 30 of the drive head by
means of
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milled slots (not shown) in both parts. Wellhead frame 14 may be open sided in
order to
expose polished rod 26 to allow a service crew to install a safety clamp on
the polished rod
and then perform maintenance work on stuffing box 16. Polished rod 26
rotationally drives a
drive string 32, sometimes referred to as a sucker rod, which, in turn, drives
a progressing
cavity pump 34 located at the bottom of the installation to produce well
fluids to the surface
through the wellhead.
[0017] Fig. 1B illustrates a typical progressing cavity pump drive head 36
with an
integral stuffing box 38 mounted on the bottom of the drive head and
corresponding to the
portion of the installation in Fig. 1A that is above the dotted and dashed
line 40. An
advantage of this type of drive head is that, since the main drive head shaft
is already
supported with bearings, stuffing box seals can be placed around the main
shaft, thus
improving alignment and eliminating contact between the stuffing box rotary
seals and the
polished rod. This style of drive head may also reduce the height of the
installation because
there is no wellhead frame, and also may reduce cost because there are fewer
parts since the
stuffmg box is integrated with the drive head. A disadvantage is that the
drive head must be
removed to do maintenance work on the stuffing box. Surface drive heads for
progressing
cavity pumps require a stuffing box to seal crude oil from leaking onto the
ground where the
polished rod passes from the crude oil passage in the wellhead to the drive
head.
[0018] Referring to Fig. 2, a stuffing box 42 is illustrated according to
the
embodiments disclosed herein. Stuffing box 42 comprises a stationary housing
44, a tubular
shaft 46, and a dynamic pressure seal 48. Housing 44 defines a passage 50, for
example a
bore, for receiving a well tubular 52. Tubular shaft 46 is mounted on the
stationary housing
44 for rotation within the passage 50. Tubular shaft 46 defines an inner axial
bore 54 adapted
to form a static seal around well tubular 52 in use. Thus, tubular shaft 46
rotates with well
tubular 52 in use.
[0019] Referring to Figs. 2 and 2B, the dynamic pressure seal 48 (shown in
Fig. 2
only, since the dynamic seal is not shown in Fig. 2B for ease of illustration)
are mounted
within an annular cavity 57 defined by respective cylindrical surfaces 58 and
60 of the
stationary housing 44 and tubular shaft 46. One or both of the respective
cylindrical surfaces
58 and 60, in this case outwardly facing surface 60, are tapered to decrease
the radial cross
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sectional area 61 (Fig. 2B) of a seal travel portion 63 (Fig. 2) of the
annular cavity 57 in an
axial direction 65 downstream from a well end 67 of the stuffing box 42. In
the example
shown in Fig. 2, surface 60 of the tubular shaft 46 is tapered outwardly in
axial direction 65
downstream from well end 67. A tapered cylindrical surface forms a truncated
cone, so that
the one or both of the respective cylindrical surfaces 58 and 60 are conical
in shape.
[0020] Fig. 2B illustrates in dashed lines the different dimensions of
surface 60
between the 2B-i and 2B-ii sections, taken from Fig. 2, that illustrate the
corresponding
downstream decrease in cross sectional area 61 between surfaces 58 and 60. The
axial
direction 65 is understood to be defined relative to a bore axis 62 of the
stuffing box 42, and
downstream is understood to be defined relative to the flow of fluids through
the stuffing box
42 from the well end 67. A portion or the entirety of seal travel portion 63
may be tapered.
[0021] As stuffing box 42 is used, dynamic seal 48 experiences wear and a
corresponding reduction in seal cross sectional area as material is stripped
off of seal 48.
Normally, when a seal 48 wears past a certain point, leakage occurs across
seal 48, leading
ultimately to failure of the stuffing box 42 to contain well fluids. However,
by tapering the
annular cavity 57 in the manner illustrated, the dynamic seal 48 is able to
automatically
reposition itself to compensate for wear during use. Thus, for example as
dynamic seal 48 is
effectively reamed across an inner lip 82 to increase a minimum inner sealing
dimension 49
(Fig. 2B), pressure from well bore fluids presses the worn seal 48 upwards
within cavity 57
where the worn seal 48 is able to seat with a relatively tighter fit within
the narrower confines of
cavity 57 downstream from the initial position of the seal 48. Thus, the
lifespan of both the seal
48 and the stuffing box 42 are increased.
[0022] As shown in Fig. 2, the respective cylindrical surface 60 of the
tubular shaft
46 is outward facing and the respective cylindrical surface 58 of the
stationary housing 44 is
inward facing. Referring to Figs.7A-B, this orientation may be reversed, for
example if
dynamic seal 48 seals between an inner standpipe 51 of housing 44. Referring
to Figs. 7A-D,
various combinations of tapering of surfaces 58 and 60 may be used. For
example, surface
58 may be tapered (Fig. 7B), surface 60 may be tapered (Figs. 7A, 7C), or both
surfaces 58
and 60 may be tapered (Fig. 7D).
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[0023] Referring to Fig. 2, the dynamic pressure seal 48 may comprise one
or both
an upper pressure seal 64 and a lower pressure seal 66. Additional seals 48
may be used. The
dynamic seal 48 is considered to be a pressure seal because fluid pressure
from wellbore
fluids energizes and wedges seal 48 downstream within cavity 57, creating a
stronger seal at
higher pressures. By contrast, placing seal 48 within a cavity 57 of uniform
cross sectional
area 61 in axial direction 65 does not generally allow seal 48 to act as a
pressure seal and
thus is prone to leakage after a certain amount of seal 48 wear.
[0024] Referring to Figs. 3-6, a seal positioner 70 may be provided for
adjustment,
for example manual adjustment, of the position of the dynamic pressure seal 48
within the
annular cavity 57. Seal positioner 70 may comprise one or more pistons 72, for
example
upstream of the dynamic pressure seal 48 to allow seal 48 to be pressed
downstream within
cavity 57 to ensure that seal 48 seats sufficiently within cavity 72. Piston
72 may be
positioned at least partially within cavity 57 as shown, and may be an axial
piston as shown.
Piston 72 may be an annular or non-annular piston. In some cases seal
positioner 70 may
incorporate a biasing device, for example a spring for compressing seal 48 or
piston 72
against seal 48 in use.
[0025] The seal positioner 70 may be a hydraulic seal positioner (Figs. 3-
4), for
example with a hydraulic fluid input 83 in the stationary housing 44. Fluid
input 83 may be a
valve such as a one-way valve (not shown) for connection to a hydraulic fluid
source (not
shown), such as an air compressor. Thus, supply or application of hydraulic
fluids
compresses piston 72 against seal 48 and advances seal 48 downstream within
cavity 57 as
shown in the sequence from Figs. 3-4.
[0026] The seal positioner 70 may comprise a wedge, for example piston 74
connected for lateral force transfer to piston 72 (Figs. 5-6). For example, a
tapered end 77 of
piston 74 contacts a tapered end 79 of piston 72 in order to allow lateral,
and in this case
axial, displacement of piston 72 against seal 48. A threaded rod 81 may be
mounted in the
stationary housing 44, for example to provide lateral force into piston 74 as
shown in the
sequence from Figs. 5 and 6. In some embodiments, zero, one, two, or more
pistons may be
used with seal positioner 70.
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[0027] Referring to Fig. 2, one or more set of bearings 76 may be provided
between
the stationary housing 44 and the tubular shaft 46. Bearings 76 reduce the
amount of friction
generation associated with rotation of tubular shaft 46 within stationary
housing 44, and thus
increase seal and component life.
[0028] Referring to Fig. 2, an example of a dynamic pressure seal 48 is
illustrated.
Seal 48 may comprise one or more of a packing seal, lip seal, or other
suitable seal, although
a lip seal is illustrated here with outer and inner lips 80 and 82,
respectively. 0-rings (not
shown) may be incorporated as seals as well. Lips 80 and 82 flex under
compression to form
a sufficient seal against surfaces 58 and 60 when under wellbore fluid
pressure and when
positioned within cavity 57. Lip seals may be advantageous for use as dynamic
seals,
because of the reduced contact area afforded by a lip seal, thus reducing
friction even under
relatively high pressures. Seal 48 may be designed to seal at high and low
pressures. Thus,
seal 48 may be designed to handle high pressure abrasive crude oil for example
in a
progressing cavity pumping application, while also being designed to seal low
pressure
slurry for example in a transfer application. Seal positioner 70 (Figs. 3-6)
is advantageous for
low pressure applications. Pressure seal 48 should be suitable for dynamic
sealing
applications, and may be hardened or adapted for long-term dynamic use.
[0029] Stuffing box 42 may be used for production of wellbore fluids, such
as
production in a progressing cavity pumping application. As shown in Fig. 2,
stuffing box 42
may be adapted to be retrofitted into a wellhead 78, for example below the
drive head (not
shown). In other cases stuffing box 42 may be adapted for an integral
application, for
example in the style shown in Fig. 1B.
[0030] Referring to Fig. 2, it should be understood that various other
components
may be incorporated into stuffing box 42. For example, secondary seals 90 may
provided at
various points between tubular shaft 46 and housing 44.
[0031] In general, where the word seal is mentioned in this document, one
or more
seals may be provided to effectively operate as a single seal, for example
observed in the
stacking of plural lip seals 96 provided as the stationary seals for sealing
against well tubular
52 in use. In addition, it should be understood that various other components
may be
provided with the stuffing box 42 for various wellhead applications to be
carried out. For
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example, wellhead 78 may include any one or more of the other components
illustrated in
Fig. 1A. In some applications, a drive head may rotate a well tubular 52,
while other
applications may incorporate a pump jack attached to reciprocate well tubular
52 as a
polished rod. Stuffing box 42 may also be used for injection or pulling of
tubulars, for
example in a coiled tubing application. Stuffing box 42 may also be used in a
slew pump
application. Stuffing box 42 may incorporate a lubrication system (not shown)
for lubricating
various components, such as the dynamic pressure seal 48.
[0032] Various components discussed herein may include various sub-
components,
such as the plural sleeves that thread together to make up the tubular shaft
46 of Fig. I.
Connections between components, or the mounting of one component to another,
may be
done through intermediate parts.
[0033] Figures may not be drawn to scale, and may have dimensions
exaggerated to
indicate relative angles between surfaces and components. The 0 symbol
indicates a non zero
angle relative to the bore axis 62 of stuffing box 42. Suitable tapers within
the annular cavity
may have angles of up to and above one degree relative to bore axis 62.
[0034] In the claims, the word "comprising" is used in its inclusive sense
and does
not exclude other elements being present. The indefinite article "a" before a
claim feature
does not exclude more than one of the feature being present. Each one of the
individual
features described here may be used in one or more embodiments and is not, by
virtue only
of being described here, to be construed as essential to all embodiments as
defined by the
claims.
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