Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
20S4~1;
LOW-~ORQU~ CENTRALIZER
BACKGROUND OF INVENTION
FIELD OF INVENTION
This invention relates to an improved oil well
casing centralizer. More particularly, but not by way
of limitation, the invention pertains to a device for
reducing the torque required to rotate a casing
positioned in a borehole during primary cementing of
the casing.
DESCRIPTION OF PRIOR ART
In completing oil or gas wells, the borehole i5
usually lined with a steel pipe (known as a "casing" or
a "liner") held in place by cement located in the
annular area between the casing's outer surface and the
borehole wall. Typically, centralizers are used to
center the casinq in the borehole during cementing. A
centered casinq ensures a cement column of
substantially uniform thickness and reduces channeling
of the cement (discussed below).
One type of centralizing device is a bow spring
centralizer. A typical bow spring centralizer is
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comprised of a fixed slee~e, a slidable sleeve, and a
plurality of longitudinal bow springs extending
therebetween. The fixed and slidable sleeves
circumscribe the casing while the flexible bow springs
are bowed outwardly to contact the borehole wall. As
is well known in the art, longitudinal movement of the
slidable sleeve is used to vary the amount of curvature
of the bow springs. The centralizer, thereby, is able
to substantially center the casing in the borehole
despite variations in borehole diameter. Once
centered, the casing may be cemented in place by
pumping a column of cement into the annular space
between the casing and borehole wall.
One type of cementing employed in oil and gas well
completion is primary cementing. Primary cementing
occurs i~mediately after the casing is run into the
borehole. Its purpose is to provide a protective
sheath around the casing and to prevent production of
undesired fluids from strata above or below the zone of
interest.
A problem frequently encountered in primary
cementing is channeling of the cement. Such channeling
arises from the cement slurry's inability to completely
displace the drilling mud which surrounds the casing.
Typically, a cement slurry is pumped down through the
casing and then up the annulus to displace the dxilling
mud from the casing/borehole annulus. Mud channels
develop when portions of drilling mud are not displaced
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by the cement. This is sometimes caused by the casing
not being well centered in the borehole. ~nder such
circumstances, it is difficult ~or the cement to
displace the drilling fluid from the narrow side of the
5 casing/borehole annulus. The undisplaced drilling mud
may then later be displaced by ~ater (or gas) from a
surrounding reservoir through one or more of the
production perforations. The channel thereby causes
the production of unwanted fluid. This channeling
effect has been well documented in field and laboratory
studies including "An Investigation of Oil Well
Cementing", Dr ll. & Prod. Prac., API (1946) 76,
Teplitz, A. J. and Hassebrock, W. E. and "Factors to be
Considered in Obtaining Proper Cementing of Casing",
Drill. & Prod. Prac., API (1948) ~57, Howard, G. C. and
Clark, J. B.
A second type of cementing is remedial or squeeze
cementing, which is used to repair the primary cement
sheath. Such cementing involves injecting cement
behind the casing to recement channeled areas or to
block off an uncemented zone. Eliminating or
minimizing cement channeling facilitates primary
cementing. Improved primary cementing in turn helps
prevent lost hydrocarbons through interzonal flow,
minimizes production of unwanted fluids, and reduces
remedial cementing costs.
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A variety of techniques for preventing or
minimizing the channeling effect ~re known. ~hese
techniques generally focus on some method for improving
the displacement of drilling mud by the cement slurry.
5 "Displacement Mechanics in Primary Cementing", J. Pet.
Tech. (Feb., 1967) 251, McLean, R. H. et al. identifies
casing movement as one technique for improving mud
displacement. Moreover, McLean recommends casing
rotation as the preferred means of moving the casing.
Subsequent studies confirming improvement in primary
cementing from casing rotation in~lude, "Liner Rotation
While Cementing: An Operator's Experience South
Texas", SPE Prod. Eng. (March, 1986) 153, Arceneaux,
M. A., Smith, R. L. and "Rotation of a Long Liner in a
Shallow Long-Reach Well", J. Pet. Tech. (April, 1989)
401, Gust, D. A., MacDonald, R. R.
With a typical centralizer, a casing may rotate
within the centralizer while bands or stop rings,
rigidly attached to the casing's outside diameter,
prevent the centralizer from moving longitudinally
along the casing. High torque, however, is usually
required to rotate a casing positioned by one or more
centralizers in a borehole. The coefficient of
friction produced by the contact of steel casing with a
centralizer's steel sleeves necessarily requires
significant torque at the surface to overcome the
static and kinetic frictional forces. In some cases,
the required torque at the surface may exceed the
capacity of the drilling riy. In other cases, high-
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cost casing connections with high-torque capacity are
reguired where casing rotation is desired and static
and kinetic frictional forces are high. The proposed
invention reduces the torque required to rotate a
s centralized casing during primary cementing which may
facilitate rotation with available equipment and/or
allow using lower-torque connections having lower cost.
Some previous patents have suggested a variety of
means for reducing static and kinetic frictional forces
lo in rotatin~ various types of drilling apparatus. None
of these patents, however, recognize the problems posed
by small clearances between the casing and borehole
wall, nonuniform wear caused by lateral loads on the
bearing surfaces, or increased friction and
deterioration of the bearing surfaces caused by
particles and debris in the drilling fluid.
In European Patent 140311, E. 0. Anders discloses
an apparatus for reducing friction resisting rotation
of a drill string in inclined well bores. The
apparatus includes a rigid tubular body adapted to
connect to a drill string and a sleeve of elastomeric
material loosely mounted on the tubular body. The
apparatus allows rotation of the drill string and
tubular body relative to the elastomeric sleeve which
contacts the borehole wall or casing. This rotation
thereby occurs with less frictional resistance than
would be produced by a drill string rotating against
the borehole wall or casing in the absence of such an
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apparatus. Anders, however, does not suggest any means
for adaptinq the elastomeric material to a bow spring
type centralizer. Furthermore, in Anders' apparatus,
the drill string rotates inside a stationary elastomer
5 bearing. In deviated wells, this will result in uneven
wear and there~ore reduced bearing life.
The bow spring centralizer is preferable to the
rigid centralizer described by Anders whers the
borehole diameter varies. Borehole diameter variations
o can arise where a tapered casing string is used, where
casing wall thicknesses may vary for tensile or
pressure designs purposes, or where borehole washout
has occurred at deeper depths. Borehole washout is
where the diameter of the borehole is greater than the
diameter of the bit used to drill it. This is caused
by the erosional effect of the circulating drilling
fluid or by spalling or caving in of unstable
formations. This phenomenon frequently occurs in well
drilling and is well known to those skilled in the art.
As described above, the bow spring centralizer can
either contract or expand its outside diameter to adapt
to a range of borehole diameters that may be found in a
single borehole. A rigid centralizer, however, has a
fixed outside diameter which must not exceed the
~5 minimum inner diameter of any previously-run casing.
If the elastomeric bearing surface is stationary,
as in Anders' apparatus, it will wear unevenly in
deviated wells where the side loads on the bearing act
_ 7 - 2~54~
predominantly toward one side (usually the low side) of
the hole. This will result in reduced bearing life,
which becomes a greater concern if clearance
considerations limit bearing thicknesses.
s Consequently, a need exists for an improved bow
spring type centralizer which reduces the torque
required to rotate the casing positioned in a borehole
during primary cementing. This improvement should be
easily and economically incorporated into such a
centralizer without reducing the centralizer's
adaptability to various borehole diameters. Also, the
improvement should facilitate extended rotation times
by providing for even wear of the principal bearing
surface.
SUMMARY OF INVENTION
This invention relates generally to an improved
centralizer that may reduce the torque required to
rotate a casing in a borehole during primary cementing.
Specifically, the centralizer is comprised of a fixed
sleeve and a slidable sleeve each circumscribing the
casing with a plurality of longitudinal bow springs
spaced around the casing. The bow springs extend
between the fixed and slidable sleeves and are rigidly
attached to an end band circumscribing each sleeve.
The fixed sleeve is rigidly attached to the casinq
while the the slidable sleeve is adapted to
longitudinally slide along the casing. The slidable
sleeve's movement allows each longitudinal bow spring,
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formed in an outwardly bowed arc, to adjust its maximum
radial offset from the casing in order to adapt to
variations in borehole diameter. The reduced torque is
achieved by interposing a special sleeve bearing
5 between each of the end bands and its respective fixed
or slidable sleeve. These sleeve bearings, which are
preferably made of a polymeric material such as teflon,
reduce the friction when rotating the casing with
respect to the end bands.
o In an alternative embodiment of this invention, the
fixed and slidable inner sleeves are eliminated. A
sleeve bearing is interposed between each of the
cen ralizer's end bands and the casing so as to
facilitate rotation of the casing. Preferably, the
sleeve bearing is adapted to rotate with the casing
while the centralizer end bands remain substantially
stationary. This promotes even wear of the bearing
surface and prolongs the useful life of the invention.
The sleeve bearing itself may include radially
outwardly extending end flanges which capture the end
band and ensure that the sleeve bearing remains inside
the end band when it moves longitudinally along the
casing. In this case, a longitudinal slit or "scarf
cut" in the sleeve bearing may be used to facilitate
insertion of the sleeve bearing into the end band. The
sleeve bearing is preferably made of a polymeric
material such as polyethylene, polytetrafluoroethylene,
polyurethane, or nylon.
~ 9 - 2054~S6
Alternatively, an extended length sleeve bearing
may be firmly attached to the casing with an adhesive.
In this case, the length of the sleeve bearing would be
sufficient to extend over the entire longitudinal
s "travel" of the end band.
BRIEF PESCRIPTION OF THE DRAWINGS
The actual operation of the proposed invention will
be better understood by referring to the following
detailed description and the attached drawings in
which:
FIGURE 1 illustrates an improved bow spring type
casing centralizer in accordance with the present
invention positioned on a section of casing;
FIGURE 2 is a cross-sectional view of the improved
bow spring type centralizer taken along line 2-2 of
FIGURE l;
FIGURE 3 is an enlarged cross-sectional view of the
fixed sleeve, sleeve bearing, and end band with bow
spring attached taken along line 2-2 of FIGURE 1;
FIGURE 4 is a cross-sectional view of the improved
bow spring type centralizer taken along line 4-4 of
FIGURE 1 and illustrating the use of mud grooves in the
sleeve bearing;
FIGURE 5 illustrates a first alternative embodiment
2s of the improved bow spring type centralizer which
utilizes a slit sleeve bearing;
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FIGURE 6 is a cross-sectional view of the
alternative embodiment of the improved bow spring type
centralizer illustrated in FIGURE 5 taken along line 6-
6 of FIGURE 5;
FIGURE 7 is an enlarged cross-sectional view of the
slit sleeve bearing and end band with bow spring
attached taken along line 6-6 of FIGURE 5;
FIGURE 8 is a cross-sectional view of the slit
sleeve bearing and end band taken along line 8-8 of
lo FIGURE 5 and illustrating the use of mud grooves in the
sleeve bearing;
FIGURE 9 is a cross-sectional view of the slit
sleeve bearing illustrating its curled position;
FIGURE 10 illustrates a second alternative
embodiment of the improved bow spring type centralizer
having extended length sleeve bearings;
FIGURE 11 illustrates a third alternative
embodiment of the improved bow spring type centralizer
in which the sleeve bearings are attached to the
centralizer's end bands;
FIGURE 12 is a cross-sectional view of the sleeve
bearing and end band taken along line 12-12 of
FIGURE 11.
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DESCRIPTION OF PREFERRED EMBODIMENT
Referring to FIGURE 1 a bow spring ~ype centralizer
10 with a fixed sleeve 12 and slidable sleeve 14 is
shown positioned on a section of casing 11. The
slidable sleeve 14 may move longitudinally along the
casing 11 in order to adjust the amount of curvature of
the bow springs. Thus, the centralizer is able to
adapt to variations in the borehole's diameter.
As illustrated in FIGURE 3, fixed sleeve 12
lo preferably comprises an inner sleeve 12a which is
attached to the casing 11 by set screws 13, two end
caps 17 which are attached to inner sleeve 12a by
screws 15, a sleeve bearing 20, two thrust bearings 22,
and end band 18 to which the end of each bow spring 16
is attached. Slidable sleeve 14 is preferably
identical to fixed sleeve 12, except that inner sleeve
14a (see FIGURE 2) is not attached to casing 11.
Rather, inner sleeve 14a is permitted to slide
longitudinally along casing 11.
The longitudinal bow springs 16 extend between each
sleeve and are attached at each end band 18 which
circumscribes its respective sleeve. The bow springs
16 form an outwardly bowed arc so that preferably at
least some portion of each bow spring 16 contacts the
borehole wall (not shown).
- 12 - 20S41~
As seen in FIGURES 2 and 3, an end band 18
circumscribes each inner sleeve 12a, 14a. A sleeve
bearing 20 is fitted between each end band 18 and its
respective inner sleeve 12a, 14a. The sleeve bearings
5 20 are preferably comprised of a polymer such as
polytetrafluoroethylene (PTFE), polyethylene (PE),
polyurethane or nylon. These sleeve bearings 20
thereby reduce the torque required to rotate the
casing 11 relative to the end bands 18 which are held
lo in a relatively fixed position by the attached bow
springs 16 contacting the borehole wall (not shown).
Preferably sleeve bearing 20 is fixed to inner
sleeve 12a, 14a such that rotation occurs between the
outer surface of the sleeve bearing 20 and the inner
surface of end band 18. With this construction, the
polymer sleeve bearings 20 will rotate relative to the
stationary end bands 18 thereby causing even wear of
the polymer material. Further friction reduction might
be achisved by polishing the inner surface of the
centralizer end ~ands 18 or by lining the centralizer
end bands 18 with a friction reducing material such as
PTFE, PE, polyurethane or nylon.
Additionally, FIGURES 2 and 3 illustrate the end
caps 17 used to prevent the longitudinal movement of
the end bands 18 with respect to the sleeves 12, 14.
Two end caps 17 circumscribe each sleeve 12, 14 and are
attached to their respective sleeve's surface by screws
15 at various points around the end cap (see FIGURE 1).
- 13 - 20S4~56
The end caps 17 also form the channel circumscribing
the fixed sleeve 12 and slidable sleeve 14 in which
their respective polymer thrust bearings 22, sleeve
bearing 20, and end band 18 are mounted. Using screws
s 15 (or some similar means) to attach the end caps 17 to
their respective sleeves 12, 14 permits the centralizer
to 10 to be broken down for ease of assembly.
Alternatively, a shoulder (not shown) formed integrally
with each inner sleeve 12a, 14a may be substituted for
o the end cap located at the outer ends of each sleeve
12, 14.
Use of a polymer thrust bearing 22 is preferred to
reduce frictional forces that arise between each end
band 18 and its respective end caps 17. FIGURE 3 shows
how polymer thrust bearings 22 circumscribing the inner
sleeve 12a may be placed between edge 23 of the end
band 18 and the edge 24 of the end cap 17. Polymer
thrust bearings 22 may be adapted to the slidable
sleeve 14 (see FIGURE 2) in likewise fashion.
Referring to FIGURE 4, a plurality of mud grooves
26 running longitudinally along each sleeve bearing 20
would serve to trap solid particles and debris which
may make their way between the end band 18 and sleeve
bearing 20 surfaces. By trapping these particles, the
25 mud grooves 26 would help protect the sleeve bearing 20
surface and preserve its friction-reducing properties.
Small particles (e.g., barite fines), however, may
become embedded in a polymer sleeve beariny 20 without
- 14 - 2 ~ 54 IS 6
significantly reducing the eleeve 1 5 effectiveness in
minimi~ing the torque required to rotate the
centralized casing 11.
A first alternative embodiment of the present
invention is illustrated in FIGURES 5-9. In this
embodiment, the fixed and slidable inner sleeves, 12a
and 14a respectively, and the end caps 17 are
eliminated. As best illustrated in FIGURE 7, a sleeve
bearing 27 with integral annular thrust bearings 27a,
o 27b serves as the only inner sleeve placed between each
end band 18 and the casing 11. Preferably, the sleeve
bearing 27 is comprised of a polymer such as PTFE, PE,
polyurethane, or nylon. Eliminating the inner sleeves
12a, 14a and end caps 17 (see FIGURE 2) reduces the
cost of manufacturing and assembling the improved bow
spring centralizer. Also, this embodiment allows the
outer diameter of the end band 18 to be kept at a
minimum. ThiC benefit is particularly significant
where th6! nominal clearance between the casing 11 and
borehole wall (not shown) is small.
Referring to FIGURE 7, the end band 18 is
positioned between two annular thrust bearings 27a, 27b
integrally formed with the sleeve bearing 27. These
thrust bearings 27a, 27b should be designed so as to
ensure that end bands 18 and their respective sleeve
bearings 27 will longitudinally slide along the
casing 11 as a unit. Preferably, the inner surface of
end band 18 is polished or coated with a friction
- 15 - 2~541~
reducing material so that rotation occurs between the
outer surface of the sleeve bearing 27 and the inner
surface of the end band 18 in order to ensure even wear
of the entire bearing surface. Alternatively or
additionally, a friction increasing material may be
coated either on the inner surface of sleeve bearing 27
or the outer surface of casing 11 to ensure that sleeve
bearing 27 and casing 11 rotate as a unit. Naturally,
these surfaces also may be abraded, rather than coated
lo with a friction increasing material, to enhance the
coefficient of friction at their interface.
The rotation of the sleeve bearing 27 as a unit
with the casing 11 promotes uniform wear about the
outer surface of the sleeve bearing 27, especially in a
15 horizontal or deviated wellbore. This in turn
eliminates localized wear. Localized wear typically
occurs where the casing 11 rotates inside a stationary
sleeve bearing. Such rotation may place more pressure
on one portion of the sleeve bearing than another
portion. Mitigating the localized wear effect usually
requires greater thickness in the sleeve bearing
material because only a portion of the available
bearing surface is being utilized. Greater material
thickness may not be a practical solution, however,
2s where the nominal clearance between the casing li and
borehole wall (not shown) is small.
- 16 - 2 54~ 56
FIGURE 7 depicts a slidable sleeve 14 which may
move longitudinally alonq casing 11. As shown in
FIGURES 5 and 6, both the sleeve assemblies 14 are
constructed identically and are longitudinally
slidable. Longitudinal movement of the centralizer 10
may be restricted with stop collars 19 fixed on the
outside of each sleeve 14 by set screws 21.
Alternatively, stop collars 19 may be located on both
the inboard and outboard sides of either of the two
lo sleeve assemblies 14 or a single stop collar 19 may be
located between the two sleeve assemblies 14.
Where the sleeve bearing 27 has two integral thrust
bearings 27a, 27b, as illustrated in FIGURE 7, it may
be difficult to insert the sleeve bearing 27 into the
15 end band 18. FIGURES 8 and 9 illustrate a "scarf cut"
or slit 25 which allows the sleeve bearing 27 to be
temporarily curled to a reduced diameter. As a result,
such a sleeve bearing 27 may be eaæily fitted into the
end band 18.
As more fully described above, a plurality of mud
grooves 26 may be used to protect the bearing surfaces
and thereby facilitate rotation between the outer
surface of sleeve bearing 27 and the inner surface of
end band 18. As illustrated in FIGURES 8 and 9, these
mud grooves 26 should be located in the outer surface
of a sleeve bearing 27 which is designed to rotate as a
unit with casing 11.
- 17 -
2054~S6
Another modification (not shown) to the first
alternative embodiment includes substi$uting detached
thrust bearings 22 for integral thrust bearings 27a,
27b. Of course, a detached thrust bearing 22 would be
5 required between the sleeve assembly 14 and any stop
collar 19, used to limit the longitudinal movement of
end band 18. A natural advantage to this modification
is that it would not require a slit 25 to facilitate
fitting sleeve bearing 27 into end band 18.
lo A second alternative embodiment of the invention is
illustrated in FIGURE 10. This embodiment uses an
adhesive or other means for attaching sleeve bearing 27
to casing 11. The adhesive would be placed bet~een the
outer surface of casing 11 and inner surface of sleeve
bearing 27. As illustrated in FIGURE 10, such an
embodiment would require sleeve bearings having greater
length than their respective end bands 18. Such
extended sleeve bearings 27 provide the additional
bearing surface needed to accommodate longitudinal
movement of the end bands 18 caused by flexing of the
bow springs 16.
A modification to this embodiment (not shown) would
use a single extended length sleeve bearing 27 for the
end band 18 which is free to move longitudinally.
2s However, the opposing end band 18 would not re~uire an
extended length sleeve bearing 27 since its
longitudinal movement would be restricted by two stop
collars 19, one inboard and the other outboard.
- 18 - 2 0 541 S 6
Another modification (not shown) to the second
alternative embodiment includes attaching sleeve
bearing 27 to stop collar 19. This modification
thereby eliminates the need for an adhesive to attach
sleeve bearing 27 to casing 11. Sleeve bearing 27 may
be attached to stop collar 19 by rigidly clamping the
stop collar 19 over the thrust bearing 27a or
integrally binding sleeve bearing 27 with stop
collar 19 using screw or adhesive means.
For the second alternative embodiment shown in
FIGURE 10 each extended sleeve bearing requires only
one integral thrust bearing 27a to reduce potential
frictional loads acting on the edge of its end band 18.
The single integral thrust bearing 27a is located on
the outboard end of each sleeve bearing 27. A stop
collar l9 outboard of each end band 18, will ensure
that neither end band 18 slides off its respective
sleeve bearing 27. As discussed above, this embodiment
may also be achieved using a detached thrust bearing 22
rather than an integral thrust bearing 27a.
A third alternative embodiment having each sleeve
bearing 27 attached to its respective end band 18 is
illustrated in FIGURES 11 and 12. Such attachment may
be accomplished by placing an adhesive, appropriate for
adhering a polymer to steel, between the sleeve bearing
27 and end band 18. Other attachment means known to
those skilled in the art may also be employed. Of
course, with this embodiment rotation occurs between
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the inner surface of sleeve bearing 27 and casing 11.
Consequently, the mud grooves 26 must be placed in the
inner surface of sleeve bearing Z7 to be useful in
protecting that surface from deterioration by various
particles and debris mixed with the drilling fluid.
This embodiment may be preferable under certain
circumstances. One such circumstance would be where
there is a large nominal clearance between the
casing ll and borehole wall (not shown). Consequently,
the sleeve bearing's thickness may be increased to
mitigate the localized wear effect described above.
Alternatively, where the nominal casing-to-borehole
wall clearance remains small the sleeve bearing may be
constructed from a wear resistant material to enhance
its resistance to the localized wear effect.
FIGURE 11 illustrates one of several configurations
possible with the third alternative embodiment. As
shown two stop collars 19, one inboard and the other
outboard, are placed adjacent to a single end band 18.
Another two collar configuration (not shown) would
position one collar 19 outboard with respect to each
end band 18. A third configuration (not shown) would
place a single collar 19 between the two end bands 18.
In each of these configurations the collar 19 may be
attached to casing 11 using set screws 21.
As seen in FIGURE 11 thrust bearings 27a, 27b are
required to reduce frictional forces arising from
contact between the end band 18 and its respective stop
- 20 - 20SAIS6
collars 19. A modification of this embodiment (not
shown) would use detached thrust bearings 22 instead of
integral thrust bearings 27a, 27b. Naturally, the
other collar configurations described for this
s embodiment would require either integral thrust
bearings 27a, 27b or detached thrust bearings 22 where
contact between stop collar 19 and end band 18 may
occur. Such thrust bearings 27a, 27b or 22 would be
positioned between the stop collar 19 and its
respective end band 18. A slit or scarf cut 25 is also
required where the sleeve bearing 27 has two integral
thrust bearings 27a, 27b formed into each end.
The preferred embodiments and mode of practicing
the invention have been described. It is to be
understood that the foregoing is illustrative only and
that other means and techniques can be employed without
departing from the true scope of the invention defined
in the following claims.
