Note: Descriptions are shown in the official language in which they were submitted.
CA 02892293 2015-05-20
WEAR SLEEVE, AND METHOD OF USE, FOR A TUBING HANGER IN A
PRODUCTION WELLHEAD ASSEMBLY
TECHNICAL FIELD
[0001] This document discloses wear sleeves and methods of using and
installing
such sleeves within a tubing hanger in a production wellhead assembly.
BACKGROUND
[0002] A production wellhead may include a reciprocating surface rod drive,
such as
a pump jack. The pump jack reciprocates a polished rod, which connects to a
sucker rod,
which connects to a bottom hole pump (BHP) to pump oil up the well. If the
well bore
deviates from vertical at or near the surface, the polished rod may be drawn
to one side,
potentially rubbing against components in the wellhead and scoring the
polished rod. A
scored rod may lead to fluid leakage through, and potential damage to, the
seals on the
stuffing box above the tubing hanger.
SUMMARY
[0003] Wear sleeves and methods of using and installing such sleeves within
a tubing
hanger in a production wellhead assembly.
[0004] A method comprising positioning a wear sleeve around a polished rod
and
within a tubing hanger in a production wellhead assembly, the wear sleeve
defining a
production fluid passage.
[0005] A wear sleeve comprising: an outer part with pin threading sized to
fit uphole
facing box threading in an internal bore of a tubing hanger; an inner part
defining a polished
rod passage, the inner part comprising sacrificial material; a keyway defined
on an uphole
facing surface of one or both the outer part and the inner part; and a
production fluid passage
defined in use by one or more of the outer part or the inner part.
[0006] A production wellhead assembly comprising: a polished rod; a tubing
hanger;
and a wear sleeve positioned around the polished rod and within the tubing
hanger.
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[0007] A method of producing oil through a production oil fluid passage
defined by a
wear sleeve positioned around a polished rod and positioned within a tubing
hanger.
[0008] An insert for a retainer, such as an outer part, the retainer being
threaded into
uphole facing box threading in a tubing hanger, is disclosed. A kit of parts,
for example an
inner part and an outer part, or a series of inner parts, that make up a wear
sleeve is
disclosed. Wear sleeves are also disclosed for installation in a wellhead
hanger or other
suitable location in the production wellhead assembly. A polymeric polished
rod bushing is
disclosed for use in a production wellhead assembly.
[0009] In various embodiments, there may be included any one or more of the
following features: Driving the polished rod with a reciprocating rod drive to
produce oil
through the production fluid passage. The wear sleeve comprises: an outer part
with pin
threading sized to fit uphole facing box threading in an internal bore of the
tubing hanger;
and an inner part defining a polished rod passage, the inner part comprising
sacrificial
material. Positioning further comprises threading the outer part into the
uphole facing box
threading of the tubing hanger. The outer part is threaded into the uphole
facing box
threading of the tubing hanger, and in which positioning further comprises
inserting the inner
part into the outer part. Inserting further comprises seating the outer part
within an annular
recessed portion defined on an outer surface of the inner part. Inserting
further comprises
translating a downhole end of the inner part past a downhole end of the outer
part, the
downhole end of the inner part comprising a plurality of collet fingers
defining a downhole
shoulder of the annular recessed portion. Positioning further comprises:
positioning the inner
part of the wear sleeve on the polished rod; and inserting the inner part into
the outer part of
the wear sleeve. The production wellhead assembly comprises, in sequence in an
uphole
direction, the tubing hanger, a flow manifold, and a stuffing box, in which
positioning
further comprises: removing the stuffing box from the flow manifold;
disconnecting the
polished rod from a sucker rod string and withdrawing the polished rod from
the flow
manifold; positioning the inner part of the wear sleeve on the polished rod;
inserting the
polished rod with the inner part of the wear sleeve into the flow manifold;
inserting the inner
part into the outer part of the wear sleeve; connecting the polished rod to
the sucker rod
string; and connecting the stuffing box to the flow manifold. A maximum outer
diameter of
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the wear sleeve is defined by the pin threading of the outer part. The outer
part comprises an
outer sleeve, the inner part comprises an inner sleeve, and further comprising
a lock for
securing the inner sleeve within the outer sleeve. The inner sleeve comprises
a downhole
shoulder and an uphole shoulder spaced along an outer surface of the inner
sleeve to define
an annular recessed portion sized to seat the outer sleeve. The lock comprises
a plurality of
collet fingers that define the downhole shoulder. One or more of: an uphole
facing end
surface of the downhole shoulder is beveled; and a downhole facing end surface
of the outer
sleeve is beveled. One or more of: a downhole facing end surface of the
downhole shoulder
is beveled; and an uphole facing end surface of the outer sleeve is beveled.
The production
fluid passage comprises a plurality of grooves in an inner surface of the
inner part from a
downhole end to an uphole end of the inner part. The plurality of grooves
comprise spiral
grooves. The sacrificial material comprises Teflon. A wear indicator.
[0010] 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
[0011] 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:
[0012] Fig. 1 is a side elevation section view of a wear sleeve positioned
within a
tubing hanger, with a polished rod illustrated in dashed lines.
[0013] Fig. IA is a perspective view of an outer part used in the wear
sleeve of Fig.
I.
[0014] Fig. 2 is an end elevation view of the collet end of an inner part
of the wear
sleeve of Fig. 1, positioned around a polished rod.
[0015] Fig. 3 is a perspective end view of the inner part of Fig. 2.
[0016] Fig. 4 is a side elevation view, partially in section, of a
production wellhead
with a wear sleeve positioned within .he tubing hanger.
[0017] Figs. 5 and 6 are an end elevation view, and a perspective view,
respectively,
of a further embodiment of an inner part of a wear sleeve.
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[0018] Figs. 7 and 8 are an end elevation view, and a perspective view,
respectively,
of a further embodiment of an inner part of a wear sleeve.
[0019] Fig. 9 is an end elevation view of a further embodiment of an inner
part of a
wear sleeve.
[0020] Figs. 10-12 are an end elevation view, a side elevation section
view, and a
perspective view, respectively, of a further embodiment of an inner part of a
wear sleeve.
Fig. 10 includes dashed lines to illustrate a polished rod.
[0021] Figs. 13-15 are an end elevation view, a side elevation section
view, partially
in section, and a perspective view, respectively, of a further embodiment of a
wear sleeve.
[0022] Figs. 16-18 are an end elevation view, a side elevation section
view, partially
in section, and a perspective view, respectively, of a further embodiment of a
wear sleeve.
[0023] Figs. 19-21 are an end elevation view, a side elevation section
view, and a
perspective view, respectively, of a further embodiment of a wear sleeve.
[0024] Figs. 22-24 are an end elevation view, a side elevation section
view, and a
perspective view, respectively, of a further embodiment of a wear sleeve.
DETAILED DESCRIPTION
[0025] Immaterial modifications may be made to the embodiments described
here
without departing from what is covered by the claims.
[0026] In the life of an oil well there are several phases - drilling,
completion, and
production. Once a well has been drihed, it is completed to provide an
interface with the
reservoir rock and a tubular conduit for the well fluids. Well completion is a
generic term
used to describe the installation of tubulars and equipment required to enable
safe and
efficient production from an oil or gas well. The production phase occurs
after successful
completion, and involves producing hydrocarbons through the well from an oil
or gas field.
[0027] Referring to Fig. 4, a production wellhead assembly 12 is
illustrated. The
assembly 12 is an assembly of components that form the surface termination of
a wellbore
and includes various production equipment at the surface. A production
wellhead assembly
may include spools, valves, manifolds, and assorted adapters that provide
pressure control of
a production well.
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[0028] The assembly 12 may incorporate components, such as a casing bowl or
spool
13, for internally mounting a casing hanger 14 during the well construction
phase. The
casing hanger 14 suspends a casing string 16, which may be steel pipe cemented
in place
during the construction process to stabilize the wellbore. The wellhead or
bowl 13 may be
welded onto the outer string of casing, which has been cemented in place
during drilling
operations, to form an integral structure of the well.
[0029] The assembly 12 may include surface flow-control components, such as
the
group of components that are sometimes collectively referred to as a Christmas
tree 22. The
Christmas tree 22 may installed on top of the casing spool 13, for example
with isolation
valves 24, and choke equipment such as production valves 26 to control the
flow of well
fluids during production. Other components such as a flow manifold 27, also
known as a
flow tee, a bonnet 94 and a rod blowout preventer (BOP) 29 may be provided as
part of the
production wellhead assembly 12. Manifold 27, bonnet 94, and BOP 29 may be
mounted on
a spool 31 mounted on the tubing head 18. The flow manifold 27 may direct
produced fluids
to processing or storage equipment, such as a surface production tank.
[0030] The production wellhead assembly 12 also incorporates a means of
hanging
production tubing 17. For example, the assembly 12 may include a tubing head
18 mounted
on the casing spool 13, the tubing head 18 internally mounting a tubing hanger
20. A tubing
hanger 20 is a component used in the completion of oil arid gas production
wells. It may be
set in the Christmas tree 22 or the wellhead and suspends the production
tubing 17 and/or
casing. Sometimes the tubing hanger 20 provides porting to allow the
communication of
hydraulic, electric and other downhole functions, as well as chemical
injection. The tubing
hanger 20 may also serve to isolate the annulus and production areas. The
production tubing
17 runs the length of the well to a bottom hole pump (BHP), and serves to
isolate the tubing
interior from the annulus for production up the interior of the tubing 17.
[0031] A production wellhead assembly 12 may connect to or house part of an
artificial lift system such as a reciprocating rod pump or drive. An
artificial lift is a system
that adds energy to the fluid column in a wellbore with the objective of
initiating and
improving production from the well. Artificial-lift systems use a range of
operating
principles, including rod pumping, gas lift and electric submersible pump. A
reciprocating
rod drive, such as a pump jack 28, is an artificial-lift pumping system that
uses a surface
power source to drive a BHP assembly (not shown). A beam and crank assembly in
the
pump jack 28 converts energy, for example in the form of rotary motion from a
prime
mover, into a reciprocating motion in a sucker-rod string 30 that connects to
a BHP
assembly. The BHP may contain a plunger and valve assembly to convert the
reciprocating
motion to vertical fluid movement.
[0032] A pump jack 28 is also known as an oil horse, donkey pumper,
nodding
donkey, pumping unit, horsehead pump, rocking horse, beam pump, dinosaur,
gasshopper
pump, Big Texan, thirsty bird, or jack pump in some cases. A pump jack or
other artificial
lift system may be used to mechanically lift liquid out of the well when there
is not enough
bottom hole pressure for the liquid to flow all the way to the surface. Pump
jacks are
commonly used for onshore wells producing little oil.
[0033] A reciprocating rod drive such as a pump jack 28 connects via a
bridle 32 to a
piston known as a polished rod 34 that passes through a stuffing box 36 to
enter the
wellbore. The polished rod 34 is the uppermost joint in the sucker rod string
30 used in a rod
pump artificial-lift system. The polished rod 34 enables an efficient
hydraulic seal to be
made by the stuffing box 36 around the reciprocating rod string. Thus, the
polished rod 34 is
able to move in and out of the stuffing box without production fluid leakage.
The bridle 32
follows the curve of the horse head 33 as it lowers and raises to create a
nearly vertical
stroke. The polished rod 34 is connected to a long string 30 of rods called
sucker rods, which
run through the tubing 17 to the down-hole pump 101, usually positioned near
the bottom of
the well.
[0034] The successful operation of the polished rod requires a tight
seal between the
polished rod 34 and the seals (not shown) of the stuffing box 36. If the
polished rod 34
becomes damaged, for example scored, the rod 34 must be replaced before damage
is done
to the stuffing box 36. In some cases the seals also must be replaced. Damage
to the polished
rod 34 may be caused from continued contact with internal components of the
production
wellhead assembly 12. In a perfectly vertical well, and even a well nominally
deviated from
vertical near the surface, the polished rod 34 reciprocates without contacting
anything but the
stuffing box seals. However, in some wells that deviate from true vertical
measured with
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Date recue / Date received 2021-10-29
CA 02892293 2015-05-20
respect to the surface of the earth, the rod 34 may be drawn to one side where
contact can
occur. Deviation is less of a concern the further from the surface the
deviation is, but in
many cases such deviation occurs before the first rod centralizer on the
sucker rod string 30.
In deviation situations contact often occurs with the interior bore 38 of the
tubing hanger 20.
[0035] A fluid leak may be caused if damage is done to the rod 34, such
leak leading
to potential environmental damage and cleanup cost. Production wellheads are
often
unmanned and in remote areas in many cases, and thus, even a relatively small
fluid leak
carries a potential for devastation because the leak may go unnoticed for days
and sometimes
weeks. Replacing the rod 34 requires a well service entity to kill the well,
lift the damaged
rod 34 out of the well, connect a new polished rod 34 to the sucker rod string
30, and repair
any damaged seals in the stuffing box 36 before connecting the new rod 34 to
the pump jack
28. In many cases the new rod 34 will itself become damaged in a short period
of time,
because the underlying cause of the damage still exists, namely the deviated
well. Often the
use of roller guides or centralizers on the rod 34 are unsuccessful in
preventing further
damage. Roller guides and centralizers merely ride along the polished rod 34
below the
tubing hanger 20, and thus have a minimal corrective effect when the rod 34 is
at or near a
bottom position in a stroke cycle.
[0036] Referring to Figs. 1 and 4, a production wellhead assembly 12 is
illustrated
comprising a polished rod 34, a tubing hanger 20, and a wear sleeve 10
positioned around the
polished rod 34 and within the tubing hanger 20. Referring to Figs. 1- 3 and
1A, wear sleeve
may comprise an outer part 40, an inner part 42, a keyway 44, and a production
fluid
passage 46. In the example shown the outer part 40 comprises an outer sleeve
41 and the inner
part 42 comprises an inner sleeve 43. The inner sleeve 43 nests concentrically
within the outer
sleeve 41 during operation in the example shown. A lock, such as collet
fingers 45 on inner part
42, described further elsewhere in this document, may be provided for securing
the inner sleeve
43 within the outer sleeve 41.
[0037] Referring to Figs. 1 and IA, the outer part 40 has pin threading 48
sized to fit
uphole facing box threading 50 in internal bore 38 of tubing hanger 20. The
internal bore 38 of
tubing hanger 20 provides a passage for the polished rod 34 in use, and is
sized to provide
sufficient clearance between the rod 34 and hanger 20 to permit room for
production fluids to
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pass up towards the flow manifold 27. In use the rod 34 and internal bore 38
define an annulus
39 in which the wear sleeve 10 is positioned. The uphole facing box threading
50 in internal
bore 38 is normally used to connect to a running tool (not shown) for the
purpose of running the
tubing hanger 20 into position in the tubing head 18.
[0038] The keyway 44 may be defined on an uphole facing surface 52 of one
or both
the outer part and the inner part, in this case the outer part 40. The keyway
44 may comprise a
series of recesses 54 radially spaced about uphole facing surface 52, which
has a ring shape in
the example. The uphole facing surface 52 may be collectively defined by
projections 53
radially spaced and extended in an uphole direction from the pin threading 48,
with gaps
between the projections 53 defining the recesses 54. The keyway 44 permits a
key, such as a flat
plate or bar (not shown), for example sized to span cooperating recesses 54A
and 54B on
opposite sides of the outer part 40, to engage keyway 44 to transmit torque to
the outer part 40
for the purpose of threading or unthreading the outer part 40 into the tubing
hanger 20. In one
example a paint mixing attachment for a handheld drill may be used as a
suitable key. In
another a semi cylinder made up of a pipe cut lengthwise in half may be used
as a suitable key,
with or without projections at one end spaced to connect to two or more
recesses 54. Loctite,
sealing tape, torque rings, or other mechanisms may be used to secure the
outer part 40 within
the box threading 50 in use. The keyway may comprise a suitable shape, such as
a slot, ridge,
or hole.
[0039] Referring to Figs. 1-3, the inner part 42 defines a polished rod
passage or
passages 56. The polished rod passage 56 must be sized sufficient to permit
the polished rod 34
to pass as well as permitting the polished rod to reciprocate within the
passage 56. Referring to
Fig. 2, polished rod passage 56 may be defined by a series of radially spaced
inner fins or ridges
58 about the interior of the inner part 42. In other cases, the polished rod
passage 56 may be
defined by a cylindrical inner bore 60 of the wear sleeve 10 (Fig. 10).
Referring to Fig. 1, the
inner ridges 58 collectively define a passage with an ID 59 equivalent or
larger than the outer
diameter (OD) 61 of the polished rod 34. Referring to Fig. 2, ridges 58 may be
curved to follow
the contour of the circumference of polished rod 34.
[0040] Referring to Figs. 1 and 2, production fluid passage or passages 46
may be
defined in use by one or more of the outer part 40 or the inner part 42, in
this case the inner part
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42. The production fluid passages 46 may comprise a plurality of grooves 47 in
an inner
surface, which for example is made up of ridges 58, of the inner part 42. The
grooves 47 may
extend from a downhole end 62 to an uphole end 64 of the inner part 42. Thus,
in use
production fluids are pumped up the tubing 17 (Fig. 4) through the production
fluid passages 46
(Fig. 1), and into the flow manifold 27. Referring to Figs. 1 and 2, the
plurality of grooves 47
may comprise spiral grooves as shown. Referring to Figs. 1- 3, spiral grooves
47 may be
defined such that a groove axis 63 (Fig. 2) rotates partially around a wear
sleeve axis 66
(concentric with and equivalent in use to a tubing hanger axis) in a direction
from the downhole
end 62 to the uphole end 64. The rotation may only be a fraction of a radian,
for example a sixty
degree shift, or may be more substantial, for example a radian, full
circumferential rotation or
more. A sufficiently small angle of shift, such as sixty degrees, may be used
so that regardless
of deviation direction the rod always touches a plurality of fins 58.
Referring to Figs. 1 and 2,
spiral flutes or grooves 47 produce spiral ridges 58, which, when viewed down
the axis 66 (Fig.
2) provide continuous circumferential contact about the polished rod 34. Thus,
regardless of the
direction of well deviation 67, at some point along the axis 66 the polished
rod 34 will be in
contact with a plurality of ridges 58 as well as the center 65 of a plurality
of ridges 58. Grooves
47 maximize the contact area with the polished rod 34.
[0041] The inner part 42 may comprise sacrificial material, such as fEFLON
TM.
1EFLON TM includes polytetrafluoroethylene (PTFE), a synthetic fluoropolymer
of
tetrafluoroethylene. In one case the outer part 40 comprises sacrificial
material as well, and in
further cases the entire wear sleeve 10 is made of sacrificial material. A
suitable sacrificial
material may be used that wears on contact with the polished rod 34 without
wearing the
surface of the polished rod 34. Other sacrificial materials may be used, such
as other polymers,
fluoropolymers, plastics, nylon, rubber, urethane, fabric, graphite, nylon,
and in some cases
metals, such as brass, that are softer than the material of the polished rod.
In one example the
sacrificial material comprises ethylene tetrafluoroethylene (ETFE), which is a
fluorine based
plastic designed to have high corrosion resistance and strength over a wide
temperature range.
ETFE, is also known as poly(ethene-co-tetrafluoroethene).
[0042] The material of the wear sleeve 10 may comprise material that is
resistant to
chemicals such as acid, well treatment fluids, and downhole fluids. The
material of the wear
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sleeve 10 may also be resistant to high temperature fluids such as steam
periodically used in
well treatments. In some cases a lubricant is provided on the inner bore 60
(Fig. 10) or ridges 58
(Fig. 2) to lubricate between the wear sleeve 10 and the polished rod 34, but
oil in the
production fluids may achieve the same effect. The material may also be
resistant to abrasion
from sand and other abrasives potentially found in production fluids.
[0043] Referring to Figs. 1 and 3, the inner sleeve 42 may comprise a
downhole
shoulder 68 and an uphole shoulder 69 spaced along an outer surface 70 of the
inner sleeve 42.
The shoulders 68 and 69 may define an annular recessed portion 72 sized to
seat the outer
sleeve 40. The downhole shoulder 68 may be uphole facing, and the uphole
shoulder 69 may be
downhole facing. Referring to Fig. 1, the shoulders 68 and 69 may be separated
a distance 73
equal or larger than a length 75 between downhole and uphole shoulders 74 and
76 separated by
an inner surface 77 of the outer part 40. Shoulders 74 and 76 may comprise
ends of the outer
part 40 as shown.
[0044] Referring to Figs. 1 and 3, as described elsewhere in this document,
collet
fingers 45 may provide a lock for securing the inner sleeve 43 within the
outer sleeve 41. Collet
fingers 45 may comprise projections radially spaced about axis 66 and
separated by gaps 78
(Fig. 3). Collet fingers 45 may define the downhole shoulder 68. Gaps 78 may
extend from
downhole end 62 and partially into the annular recessed portion 72. Referring
to Fig. 1, to =
install the guide sleeve 42 in the outer part 40, the downhole end 62 of the
inner part 42 may be
translated past a downhole end 71 of the outer part 40. The downhole end 62
may be inserted
into the outer part 40 in a downhole direction.
[0045] Referring to Fig. 1, during installation, the downhole end 62 of
fingers 45
contacts uphole shoulder 76, which may also define an uphole end 79, of outer
part 40. The
contact acts to apply radially inward pressure on collet fingers 45, causing
the fingers 45 to
move from a neutral position into a radially compressed position to allow
downhole end 62 to
fit within, and continue translation through, the outer part 40. Once the
downhole shoulder 68 of
the inner part 42 clears the downhole shoulder 68 of the outer part 40, the
pressure on collet
fingers 45 is removed, allowing the fingers 45 to move radially outwards back
into the neutral
position. The outer part 40 is now seated within the annular recessed portion
72, to prevent
CA 02892293 2015-05-20
relative movement between the outer and inner parts 40, 42 during production
and reciprocation
of the polished rod 34.
[0046] Collet fingers 45 are one example of a lock, and other suitable
locks may be
used. For example, latch, magnet, strap, adhesive, dog, friction fit, pressure
lock, twist lock,
tongue and groove, pin and hole, pin and slot, and other suitable locks may be
used. In one
example the collet fingers 45 may be positioned at either the downhole end 62,
the uphole end
64, or both.
[0047] Referring to Figs. 1, 1A, and 3, portions of the outer and inner
parts 40, 42, of
the wear sleeve 10 may be bevelled, for example to facilitate insertion,
removal, or both
insertion and removal of the inner part 42. Referring to Figs. 1 and 3, an
uphole facing end
surface 81 of the downhole shoulder 68 may be bevelled. Referring to Figs. 1
and IA, a
downhole facing end surface 82 of the outer part 40 may be bevelled. Referring
to Fig. 1, when
it is desired to remove the inner part 42 from the outer part 40, bevelling of
end surfaces 81 and
82 may again act to wedge the inner part 42 within the outer part 40, by
converting some of the
axial translation force that is oriented in an uphole direction into radially
inward force during
retrieval. In some cases bevelling of one or more of downhole facing end
surfaces 96 and
uphole facing surfaces 97 of the downhole shoulder 68 and outer part 40,
respectively, may act
to wedge the inner part 42 within the outer part 40, by converting some of the
axial translation
force that is oriented in a downhole direction into radially inward force
during insertion.
[0048] A bevel may refer to the fact that the end surface is sloped,
curved, or both
sloped and curved such that a plane defined by a portion of the end surface
forms an obtuse
angle with the axis 66, in order to produce a wedging effect. A bevel may be
used instead of a
ninety degree edge between components. The uphole shoulder 69 and uphole end
79 may also
be selectively bevelled. The structure and shape of the end surfaces may be
selected to permit
wedging to occur only upon application of a force above a selected threshold
force, which is
greater than the axial force exerted upon the wear sleeve by the polished rod
34 during use.
Thus, the inner part 42 may remain stationary within the outer part 40 during
pumping of
production fluids, but still be able to be easily removed upon application of
axial translation
force.
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[0049] Referring to Fig. 1, the wear sleeve 10 may comprise a wear
indicator 84. The
wear indicator 84 may be adapted to alert the well operator to a worn
condition of the wear
sleeve 10, for example a worn condition of the inner part 42. The worn
condition may be
selected as a fail, near fail, or partially worn condition of the inner part
42, a fail corresponding
to a penetration of the polished rod 34 into contact with the outer part 40.
The wear indicator 84
may be spaced from inner bore 60 a selected distance corresponding to a
proportion of wear
required on the inner part 42 before contacting the wear indicator 84. Thus, a
wear indicator
inset 50% of the width of the inner part 42 may become active when the inner
part 42 is 50%
worn.
[0050] The wear indicator may comprise a dye selected to stain the polished
rod such
that a stained portion of polished rod is visible when the stained or
discolored portion is drawn
out of the stuffing box 36 during a stroke cycle. The dye may be selected to
be removable upon
cleaning the polished rod and replacing the inner part 42.
[0051] Another example of a wear indicator 84 is a series of screws, for
example brass
screws, laterally inset within the inner part 42 around the axis 66. Brass is
a softer material than
the polished rod 34, and thus contact with the polished rod 34 will result in
deposition of brass
upon the polished rod 34, in a manner that will be visible to the well
operator. Brass is suitable
because if the screws fall down the well such screws will not interfere with
downhole
operations. Other wear indicators 84 may be used, for example incorporating an
alarm, a
sensor, a sight glass, and a rod marker may be used. In one example the wear
indicator 84
may be selected to lightly score the polished rod 34 in a manner that does not
affect stuffing
box operation.
[0052] Referring to Fig. IA, a maximum outer diameter 91 of the wear sleeve
10 may
be defined by the pin threading 48 of the outer part 40. In such a case, the
projections 53
extended in an uphole direction relativ., . to the pin threading 48 may
collectively define an equal
or smaller OD than the maximum OD 91 of the pin threading 48. The uphole
facing surface 52
may be situated in a downhole direction from an uphole end 55 of the tubing
hanger 20 as
shown in Fig. 1.
[0053] Referring to Figs. 5-6, 7-8, and 9, three further embodiments,
respectively, of an
inner part 42 suitable for use in outer part 40 of Fig. lA is illustrated. In
each embodiment the
12
inner part 42 is shown with a plurality of grooves or notches 47 structured
such that the groove
axes 63 are parallel to the sleeve axis 66 across the axial length of the
sleeve 10. All three
embodiments also illustrate different groove 47 shapes that may be used, from
archways or
half-rounds 88 (Fig. 6) notched into the inner bore 60, to cylindrical
conduits 89 (Fig. 8) to
troughs 90 in a wave shaped inner bore 60 (Fig. 9). A groove axis 63 may be
defined as the
center of cross-sectional area within a groove 47. Other suitable production
fluid passages 46
may be used.
[0054] Referring to Figs. 10-12 a further embodiment of an inner part 42
suitable for
use in outer part 40 of Fig. 1A is illustrated. In the example shown the
production fluid passage
46 is defined by a cylindrical inner bore 60 being sized with an ID 59
sufficiently larger than an
OD 61 of the polished rod 34, to pen-nit production fluid flow across wear
sleeve 10 in a
sufficiently unrestricted manner.
[0055] The ID 57 (Fig. 1) of outer part 40 may be smaller than the
nominal ID 99 (Fig.
4) of the tubing 17. The use of wear sleeve 10 reduces the internal cross
sectional area available
to permit tools and production fluid to pass, than if no wear sleeve 10 were
present. The 1113 57
of the outer part 40 may be proportional to the 1113 99 of the tubing 17. In
one example, the ID
57 of the outer part 40 is 1.920 inches for 2 3/4 tubing ID 99. The production
fluid passages 46
may be dimensioned to reduce cross sectional flow area, but without
substantially increasing the
pressure drop across the wear bushing 10. Pressure drop can be calculated in
order to ascertain
suitable dimensions of wear sleeve 10 and production fluid passage 46. A 2 and
3/8" pump has
a maximum pump rate of 40 cubes a day, and at representative production flow
rates of 28
L/min, a suitable wear sleeve 10 may cause only a 3kPa differential drop. At
higher, unrealistic
pump rates, such as 100 L/minute, a 100kPa pressure differential may result
with the same wear
sleeve 10, but such pump rates are not attainable so may be irrelevant. Thus,
at production
pump rates a pressure drop of 1-10 kPa may be experienced, in some cases more.
Pressure drop
is a function of cross-sectional area and flute design.
[0056] Referring to Figs. 13-24 four different embodiments of wear
sleeves 10 are
illustrated. A common difference between the embodiments of Figs. 13-21 and
the
embodiment of Fig. 1-12 is that in the former the outer and inner parts 40, 42
are integrally
formed as a single unit. In such an example the wear sleeve 10 has a form
similar to a
13
Date recue / Date received 2021-10-29
CA 02892293 2015-05-20
Phillips set screw bored through the center. A difference between the
embodiments of Figs.
13-15, 16-18, and 19-21 are the dimensions of the wear sleeve 10. The various
embodiments
are provided for different tubing hanger sizes. Referring to Figs. 22-24
another embodiment
of a wear sleeve 10 is illustrated with a neck sleeve 86 extended in a
downhole direction
below the pin threading 48. The neck sleeve 86 may have a length 85 equivalent
to one or
more times the length 87 of the pin threading 48. The extended neck sleeve 86
may provide
additional surface area to contact rod 34 and provide additional centralizing
effect on the rod
34.
[0057] Referring to Fig. 4, a method is illustrated. At a high level a wear
sleeve 10 is
positioned around a polished rod 34 and within a tubing hanger 20 in a
production wellhead
assembly 12. Once in position the polished rod 34 may be driven with a
reciprocating rod drive
such as pump jack 28 to produce oil through the production fluid passage 46.
[0058] Installing or positioning the wear sleeve 10 may be done by suitable
methods.
Several examples will be described, although it should be understood that
other suitable
methods are within the scope of this document. In an initial stage the pin
threading 48 of outer
part 40 is threaded into the uphole facing box threading 50 of the tubing
hanger 20.
[0059] In a new well that is being completed, the outer part 40 may be
threaded into the
tubing hanger 20 before the equipment above line A in Fig. 4 is installed,
including before the
polished rod 34 is installed. Before the wear sleeve 10 is installed, the well
may need to be
killed by injecting a sufficiently large volume or pad of liquid down the
tubing to overcome the
reservoir pressure. In addition, in many cases a frac or completion wellhead
(not shown) may be
installed above line A during the completion stage, and such a wellhead may
need to be
removed prior to installing the wear sleeve 10.
[0060] If the wear sleeves 10 of Figs. 13-24 are used, once the wear sleeve
10 is
threaded in place, the equipment above line A need be installed as if wear
sleeve 10 was not
present. After the wear sleeve 10 is in place, the pumping wellhead, for
example the BOP 29,
flow tee 27, and other suitable valving and lines may be installed. The bottom
hole pump (BHP,
not shown) may be run down the well, along with the sucker rod string 30 and
the polished rod
34. The stuffing box 36 may be positioned on the rod 34 before the rod is
coupled, for example
by coupling 95 to the sucker rod string 30, after which the stuffing box 36
may be secured to the
14
CA 02892293 2015-05-20
wellhead assembly 12. The fluid pad is removed from the tubing, the polished
rod 34 is
connected to the bridle 32, and production begins.
[0061] If the wear sleeve of Fig. 1-3 is installed, the initial positioning
stage may
comprise threading in the outer part 40 with or without the inner part 42
inserted in the outer
part 40. If the inner part 42 is not inserted in the outer part 40 at this
stage, the inner part 42 may
be inserted as follows. After the outer part 40 is threaded into the tubing
hanger 20, the BOP 29,
flow tee 27, and other suitable valving and lines may be installed. The BHP is
run with the
sucker rod string 30, and the inner part 42, coupling 95 and stuffing box 36
are positioned on
the polished rod 34, with the inner part 42 positioned between the coupling 95
and the stuffing
box 36. The polished rod 34 is then inserted into the wellhead 12. The inner
part 42 is installed
by applying axial force in a downhole direction, for example by tapping the
inner part 42 with a
tool, such as a semi-cylinder, until the collet 45 locks. The polished rod 34
is coupled to the
sucker rod, and the stuffing box 36 is connected. The inner part 42 may be
installed before or
after the rod 34 is connected to string 30. In some cases the rod 34 is left
sitting on the string 30
while the inner part 42 is installed, following which the rod 34 is connected
to string 30. The
remaining steps to production may be the same as described above.
[0062] Referring to Fig. 4, in order to permit the inner part 42 to pass
through the flow
tee 27, a maximum OD 92 of the inner part may be equal to or less than a
minimum ID (not
shown) of the flow manifold 27 and other components such as BOP 29 and bonnet
94 that may
be present above line A. Such a dimensional feature also permits the
replacement of worn inner
parts 42 without requiring removal of the flow tee 27 and equipment above A,
with the
exception of the stuffing box 36. Tubing hanger box threads 50 are the same
size as male and
female threads on the flow tee 27, the BOP 29, and the bonnet 94. Thus, the OD
92 of the inner
part 42 may be sized smaller than the maximum outer diameter 91 of the pin
threading 48.
[0063] Replacing the inner part 42 may proceed as follows. In one example,
positioning
further comprises: positioning the inner part 42 of the wear sleeve 10 on the
polished rod 34,
and inserting the inner part 42 into the outer part 40 of the wear sleeve 10.
After the worn inner
part 42 is removed, the replacing method may be exactly the same as the
installation of a new
inner part 42. To remove the inner part, the polished rod 34 is pulled, for
example by a servicing
rig, in an uphole direction along with coupling 95, after the rod 34 is
separated from sucker rod
CA 02892293 2015-05-20
string 30. The coupling 95 will contact the downhole end 62 of the inner part
42, and upon
application of sufficient force in an uphole direction will unlock the collet
and release the inner
part 42 up the well. The worn insert 42 is removed, and a new one installed as
per the remainder
of the method described above.
[0064] The wear sleeves 10 and methods provided in this document do not fix
well
deviations. Instead such sleeves 10 merely permit prolonged use of a polished
rod 34 in such
wells without damaging the rod 34 or stuffing box 36.
[0065] Directional language such as downhole, uphole, up, top, and bottom
are relative
terms and are not to be construed as limited to absolute directions defined
relative to the
direction of gravitational force. The sequence of method steps provided may
take a logical order
that is not in the order iterated in all cases. Positioning a wear sleeve may
mean positioning part
of a wear sleeve. The wear sleeve 10 may be provided in a plurality of semi-
cylindrical parts
that are assembled laterally about a polished rod 34 rather than a sleeve
axially inserted around
the polished rod 34. The disclosed methods and wear sleeves 10 may be used on
oil and gas
wells, water wells, and other suitable types of wells. Connections between
components may
be direct or indirect through other tools, spools, or parts. Production
wellhead assembly 12
includes subsea and surface wellheads, and part of the wellhead assembly 12
may be located
below the surface of the ground or seabed. Reciprocating rod drive embodiments
include
embodiments where no pump jack is used, for example the ROTOFLEX TM unit made
by
Weatherford. Threading may be pitched and have any suitable threading style,
for example
EUE, API, and others.
[0066] In the claims, the word "comprising" is used in its inclusive sense
and does
not exclude other elements being present. The indefinite articles "a" and "an"
before a claim
feature do 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.
16
