Note: Descriptions are shown in the official language in which they were submitted.
EROSION RESISTANT BAFFLE FOR DOWNIIOLE WELLBORE TOOLS
STATEMENT REGARDING FEDERALLY SPONSORED
RESEARCH OR DEVELOPMENT
100011 Not applicable.
REFERENCE TO A MICROFICHE APPENDIX
100021 Not applicable.
BACKGROUND
100031 It is common to utilize downhole wellbore equipment with baffles
containing seats
for use in operating of the equipment. For example, well formations that
contain hydrocarbons are
sometimes non-homogeneous in their composition along the length of wellbores
that extend into
such formations. It is sometimes desirable to treat and/or otherwise manage
the formation and/or
the µvellbore differently in response to the differing formation composition.
Some wellbore
servicing systems and methods allow such treatment, referred to by some as
zonal isolation
treatments. In these systems, zones can be treated separately.
100041 In some treatment methods a plurality of spaced tools are installed in
a well and
selectively operated. For example, in some well treatment systems a plurality
of sleeve valves are
installed in the well and opened in sequence starting with the bottom most
valve. Once treatment
CA 2989547 2017-12-18
through the bottom most valve is completed, the next higher up valve is opened
and treatment
per brined through that valve.
[0005] In obturator actuated systems, an obturator is transported down the
wetlbore to
engage a downhole well tool. '[he terms, "up", "upward", "down" and
"downward", when used to
refer to the direction in the well bore without regard to the orientation of
the well bore. Up, upward
and up hole refer to the direction toward the well head. Down, downward, and
down hole refer to a
direction away from the well head. In these systems, each downhole well tool
typically includes a
metallic baffle containing seat to seal against the obturator and activate the
tool.
[0006] It is common to perform fracturing formation treatments using multiple
sleeve
valves spaced along the well. Fracturing necessarily involves pumping large
quantities of abrasive
materials called proppants at high pressures and high flow rates into the well
and through the
baffles in these valves. As a frac treatment material flow through the valves
their baffles are
subject to erosion damage. The potential damage can be more severe when the
upper valves in a
wellbore are subjected to erosion effects of multiple frac operations
accounted with the lower
valves.
[0007] Accordingly, there exists a need for erosion resistant for use in
systems and
methods for treating multiple zones of a wellbore,
SUMMARY
100081 Disclosed herein are wellbore tool baffles for use in abrasive wellbore
servicing
systems and methods. In the disclosed example the baffle is armored against
erosion damage from
materials flowing through the tool.
13RI DLSCRIPTION OF TI IF, DRAWING S
[0009] For a more complete understanding of the present disclosure and the
advantages
thereoh reference is now made to the following brief description, taken in
connection with the
accompanying drawings and detailed description:
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100101 Figure 1 is a cut-away view of an embodiment of a wellbore servicing
system
according to the disclosure containing multiple well tools;
[00111 Figure 2 is a cross-sectional view of a sleeve valve containing an
embodiment of
the baffle of the present invention lbr use in the wellbore servicing system
of Figure 1 showing the
sleeve valve in the run-in configuration;
100121 Figure 3 is a cross-sectional view of a sleeve valve containing an
embodiment of
the baffle of the present invention for use in the wellbore servicing system
of Figure 1 showing the
sleeve valve in the actuated baffle configuration;
[0013] Figure 4 is a cross-sectional view of a sleeve valve containing an
embodiment of
the baffle of the present invention for use in the wellbore servicing system
of Figure 1 showing the
sleeve valve with the ball landed on the baffle seat configuration;
[00141 Figure 5 is a cross-sectional view of a sleeve valve containing an
embodiment of
the baffle of the present invention for use in the wellbore servicing system
of Figure 1 showing the
sleeve valve in the open configuration;
[0015] Figure 6 is a cross-sectional view of a sleeve valve containing an
embodiment of
the baffle of the present invention for use in the wellbore servicing system
of Figure 1 showing the
sleeve valve in the open flowback configuration;
100161 Figure 7 is an enlarged cross-sectional view of the sleeve valve of
Figure 2
illustrating details of the electro-hydraulic sleeve lock;
100171 Figure 8 is an enlarged section view of the eleetro-hydraulic actuator
of the sleeve
system of Figure 7;
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100181 Figure 9 is a perspective view of an embodiment of the baffle in the
sleeve valve of
Figure 2; and
100191 Figure 10 is a top plan view of third alternative embodiment of the
seat assembly of
the sleeve system of Figure
DETAILED DESCRIPTION OF THE EMBODIMENTS
10020] In the drawings and description that follow, like parts are typically
marked
throughout the specification and drawings with the same reference numerals,
respectively. The
drawing figures are not necessarily to scale. Certain features of the
invention may be shown
exaggerated in scale or in somewhat schematic form and some details of
conventional elements
may not be shown in the interest of clarity and conciseness.
100211 Unless otherwise specified, any use of any form of the terms "connect,"
"engage,"
"couple," "attach," or any other term describing an interaction between
elements is not meant to
limit the interaction to direct interaction between the elements and may also
include indirect
interaction between the elements described. In the following discussion and in
the claims, the terms
-including" and "comprising" are used in an open-ended fashion, and thus
should be interpreted to
mean "including, but not limited to ...." Reference to up or down will be made
for purposes of
description with "up," "upper," "upward," or "upstream" meaning toward the
surface of the
wellbore and with "down," "lower," "downward," or "downstream" meaning toward
the terminal
end of the well, regardless of the wellbore orientation. The term "zone" or
"pay zone" as used
herein refers to separate parts of the wellbore designated for treatment or
production and may refer
to an entire hydrocarbon formation or separate portions of a single formation
such as horizontally
and/or vertically spaced portions of the same formation. The various
characteristics mentioned
above, as well as other features and characteristics described in more detail
below, will be readily
apparent to those skilled in the art with the aid of this disclosure upon
reading the following
detailed description of the embodiments and by referring to the accompanying
drawings.
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100221 Disclosed herein are improved components, more specifically, an
improved baffle
assembly with erosion resistance characteristics, for use in downhole tools.
Such a baffle may be
employed alone or in combination with other components.
[0023] Referring to Figure 1, an embodiment of a wellbore servicing system 100
is
shown in an example of an operating environment. As depicted, the operating
environment
comprises a rig 106 (e.g., a drilling, completion, or workover rig) positioned
on the earth's
surface 104 over a wellbore I 14 that penetrates a subterranean formation 102
for the purpose of
recovering hydrocarbons. The wellbore 114 may be drilled into the subterranean
formation 102
using any suitable drilling technique. The wellbore 114 extends substantially
vertically away
from the earth's surface 104 over a vertical wellbore portion 116, deviates
from vertical relative
to the earth's surface 104 over a deviated wellbore portion 136, and
transitions to a horizontal
wellbore portion 118. In alternative operating environments, all or portions
of a wellbore may be
vertical, deviated at any suitable angle, horizontal, and/or curved.
100241 At least a portion of the vertical wellbore portion 116 is lined with a
casing 120
that is secured into position against the subterranean formation 102 in a
conventional manner
using cement 122. In alternative operating environments, a horizontal wellbore
portion may be
cased and cemented and/or portions of the wellbore may be uncased. The rig 106
comprises a
derrick 108 with a rig floor 110 through which a tubing or work string 112
(e.g., cable, wireline,
Z-line, jointed pipe, coiled tubing, easing, or liner string, etc.) extends
downward from the
servicing rig 106 into the wellbore 114 and defines an annulus 128 between the
work string 112
and the wellbore 114. The work string 112 delivers the wellbore servicing
system 100 to a
selected depth within the wellbore 114 to perform an operation such as
perforating the casing 120
and/or subterranean formation 102, creating perforation tunnels and/or
fractures (e.g., dominant
fractures, micro-fractures, etc.) within the subterranean formation 102,
producing hydrocarbons
from the subterranean formation 102, and/or other completion operations. The
servicing rig 106
comprises a motor driven winch and other associated equipment for extending
the work string
112 into the wellbore 114 to position the wellbore servicing system 100 at the
selected depth.
CA 2989547 2017-12-18
(0025] While the operating environment depicted in Figure 1 refers to a
stationary servicing
rig 106 for lowering and setting the wellbore servicing system 100 within a
land-based wellbore
114. in alternative embodiments, mobile workover rigs, wellbore servicing
units (such as coiled
tubing units), and the like may be used to lower a wellbore servicing system
into a wellbore. It
should be understood that a wellbore servicing system may alternatively be
used in other
operational environments, such as within an offshore wellbore operational
environment.
[0026] The subterranean formation 102 comprises a zone 150 associated with
deviated
wellbore portion 136. The subterranean formation 102 further comprises first,
second, third,
fourth, and fifth horizontal zones, 150a, 150b, 150e, 150d, 150e,
respectively, associated with the
horizontal wellbore portion 118. In this embodiment, the zones 150, 150a,
150b, 150e, 150d,
150c are offset from each other along the length of the wellbore 114 in the
following order of
increasingly downhole location: 150, 150e, 150d. 150c, 150b, and 150a. In this
embodiment,
stimulation and production sleeve systems 200, comprising sleeve valves 200a,
200b, 200e,
200d, 200e, and 200f are located within wellbore 114 in the work string 112
and are associated
with zones 150, 150a, 150b, 150c, 150d, and 150c, respectively. It will be
appreciated that zone
isolation devices such as annular isolation devices (e.g., annular packers
and/or swellpackers)
may be selectively disposed within wellbore 114 in a manner that restricts
fluid communication
between spaces immediately uphole and downhole of each annular isolation
device.
[0027] The stimulation and production sleeve systems 200 illustrated in Figure
1 each
sleeve valve comprises one or more sleeves which can be moved to selectively
open ports spaced
along the Nvall or the work string 112 to provide a fluid paths between the
interior of the work
string and the surrounding formation. In the stimulation and production sleeve
systems 200
illustrated in Figure 1 the sleeve valves 200a-2001' can be opened in sequence
starting with
opening the ports associated bottom most sleeve valve 200a. Sleeve valve 200a
is opened by
inserting an obturator into the well to contact a seat on a baffle in the
valve. With the valve 200a
open horizontal zone 150a can be treated by pumping fluids into the zone
through the ports
opened by valve 200a. Once valve 200a is opened and treatment through this
bottom most valve
200a is completed, the next higher up valve 200b is opened and treatment
performed through that
valve. Next the valve 200b is opened to treat zone 150b. The valves 200b-200f
each also
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comprises a baffle with seat which with the obturator block or seals off the
interior of the work
string 112 below the valve. This sequence can be repeated for each of the
sleeve valves 200c-
2001' until the uppermost sleeve valve 200f is actuated and used to treat zone
150f.
[00281 Referring now to Figure 2, a cross-sectional view of an embodiment of
sleeve
valve 200a of the stimulation and production sleeve system 200 (hereinafter
referred to as "sleeve
system" 200) is shown. Valve 200a is typical of the construction of the valves
200b-200f. Many
of the components of sleeve valve 200a lie substantially coaxial with a
central axis 202 of sleeve
valve 200a.
[00291 Sleeve valve 200a comprises an upper adapter 204, a lower adapter 206,
and a
ported case assembly 208. The ported case assembly 208 is joined between the
upper adapter
204 and the lower adapter 206. Together, inner surfaces of the upper adapter
204, the lower
adapter 206, and the ported case assembly 208, respectively, substantially
define a sleeve flow
bore 216. The upper adapter 204 comprises a collar configured for attachment
to an element of
work string 112. The lower adapter 206 is configured for attachment to an
element of work
string 112. The upper and lower adapters comprise threads for connecting to
the ported case
assembly 208 and work string, 112.
[00301 The ported ease assembly 208 is substantially tubular in shape and
comprises an
upper sleeve portion 230 and a lower baffle portion 240. The sleeve portion
230, baffle portion
240, upper adapter 204 and lower adapter 206 each have substantially the same
inner and outer
diameters. "I-he upper sleeve portion 230 further comprises ports 232. As will
be explained in
further detail below, ports 232 are through holes extending radially through
the upper sleeve
portion 230 and are selectively used to provide fluid communication between
sleeve flow bore
216 and the annulus 128 immediately exterior to the upper sleeve portion 230.
[0031] The upper sleeve portion 230 comprises a sleeve 234 mounted to slide
axially
within the sleeve portion 232 selectively block and open ports 232. As is
illustrated Figure 2 and
in detail in Figures 7 and 8, sleeve 234 is hydraulically locked in the upper
or run in position
illustrated in Figure 2. In Figures 2, 7 and 8, the upper or uphole direction
is to the left sides of
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each figure. Sleeve 234 is held in this position by filling annular chamber
236 with a hydraulic
fluid. Chamber 236 extends from sleeve portion 230 and into baffle portion
240. Chamber 236
can be filled with hydraulic fluid using removable plug 242. A rupture disk
244 closes off the
lower end of chamber 236. When rupture disk 244 is pierced or broken,
hydraulic fluid in
chamber 236 is vented, the position of sleeve 234 is unlocked, allowing sleeve
234 to axially
slide in the downhole direction (to the right side of the page).
[0032] The structure for piercing the rupture disk 244 is best illustrated in
reference to
Figures 7 and 8 and various embodiments are disclosed in U.S. Patent 8,322,426
and U.S.
Publications 2013/0048290 and 2013/0048291. The piercing structure comprises a
cutter 246,
actuator 248 and electronic package 250. In the illustrated embodiment the
actuator 248
comprises an explosive charge which when ignited by the electronic package 250
drives the
cutter 246 in the uphold direction to pierce rupture disk 244. Electronic
package 250 comprises
means for sensing and recording the passage along the sleeve bore 216 of
obturators passing
through the sleeve valve 200a. When a set number of obturators pass through
the valve 200a,
electronic package 258 initiates the actuator 248. Porting 252 provides a path
for the hydraulic
fluid to vent from chamber 236 into flow bore 216.
[0033] The baffle portion 240 (240 also encloses the electronics, batteries,
thruster, and
rupture disc) comprises an annular baffle assembly 260 mounted in the bore of
the baffle portion
242 to slide axially in the flow bore 216. The details of construction of the
baffle assembly will
be described in more detail by reference to Figures 8 and 9. The baffle
assembly 260 comprises
a sleeve 262 and a C-ring baffle 264 having an uphole facing seat 266. Sleeve
262 is held in
axial position in the baffle 240 illustrated in Figure 7 by a releasable
mechanism such as a shear
pin or snap ring (not shown). As will be described, baffle 264 is illustrated
in its expanded
condition where in its internal diameter is substantially the same as sleeve
262 and the gap 263 is
present in the C-ring structure. In the position illustrated in Figure 10 the
seal ring comprising
baffle 264 is spring-loaded are resiliently urged radially outward to engage
sleeve 262. Baffle
264 has tabs 267 which lock into a groove in sleeve 262; this axially holds
the baffle 264 in
position. (they are locked together axially only in the state where the baffle
is expanded). As
will be described
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in more detail, when baffle 264 and sleeve 262 are forced together (by axial
forces Fs and Pb)
baffle 264 will climb up the ramp services and tabs 267 to a point where the
gap 263 in the C-
ring structure of baffle 264 is closed and the internal diameter of the baffle
264 is less than the
internal diameter of the sleeve 262. When the baffle 264 is in the expanded
position illustrated
in Figure 10, an obturator with an external diameter less than that of the
sleeve 262 will pass
through the baffles 264 without engaging it. It should be appreciated that
when the baffle 264
contracts, that it can be of a sufficiently small internal diameter to engage
an obturator.
[0034] To protect the baffle 264 and the seat 266 against erosion from flowing
treatment
materials, a baffle erosion buffer or shield is provided. This shield allows
the system to be used
to treat a greater number of treatment zones (treatment stages). In the
illustrated embodiment,
the shield comprises a nose cone ring 268 and a seat abutting ring 270 (Fig.
9). The nose cone
ring 268 as substantially the same into your an exterior diameters as the
sleeve 262 and baffle
264 when arranged as illustrated in Figures 2, 7 and 10. The annular surface
of the ring 268
Pacing in the upward direction is tapered or rounded or angled to reduce flow
turbulence.
Turbulent flow has a more erosive impact on the components; an angled or
rounded face reduces
flow turbulence. . Ring 268 can be formed from an erosion resistant material
such as carbide,
hard steel or the like.
[0035] The seat abutting ring 270 is located downhole of the nose cone ring
268 and
inside of the baffle 264. Ring 268 has a section 272 that covers the gap 263
to provide a
continuous cylindrical surface on the interior of the baffle assembly 260 to
reduce turbulence and
the erosion of fact a flow there through. In this embodiment the seat abutting
ring 270 is made
from a frangible material, such as, ceramic, cast-iron, phenolic are similar
brittle erosion
(abrading affect or particle impact affect which erode/corrode the material)
resistant materials.
100361 The operation sleeve system 200 will be described by reference to
Figures 2-8.
The system 200 is of the type which is used in conjunction with an obturator
280 comprising
magnetic material. In the present embodiment, the obturator 280 is a spherical
ball formed from
the nonmagnetic material with a number of cylindrical magnets installed in the
outer diameter of
the obturator 280 created a magnetic field around the outer diameter.
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[0037] Prior to running the sleeve system 200 into the well, the electronic
package of
each of the stimulation and production sleeve valves 200a-200f is programmed
to count a certain
number of obturators 280 passing through the valve. The run-in condition of
valve 200a is
illustrated in Figure 2 with the baffle 264 in the expanded our pass through
condition. The run-in
and operation of valve 200a is typical of the run in operation of valves 200b-
200f.
100381 In Figure 3, the baffle 264 has been activated by the electronic
package 250
sensing the passage of a set number of obturators 280 through the sleeve valve
200a. If for
example, electronic package 250 of valve 200a has been programed to release
the hydraulic lock
on sleeve 234 after the passage of a single obturator 280, then sleeve 234
moves in a downhole
direction to contact the baffle assembly 260. This movement of sleeve 234
causes the baffle 264
to ride down the ramp services and tabs 267 and contract to assume the
obturator catching
position illustrated in Figure 3. As the baffle 264 contracts the frangible
scat abutting ring 270
breaks apart and fall down the wellbore. It is to be noted that at this point,
that even though the
sleeve 234 has moved downward the ports 230 remain blocked.
100391 The next step in the operation of valve 200a is illustrated in Figure
4. In this step,
the next obturator 280 moving down the wellbore engages baffle 264 and seals
against the seat
266. With the obturator 280 in this position, the lower portion of the work
string 212 below
valve 200a is sealed off. In this step, sleeve 262 is held in axial position
by the shear pins.
100401 With the obturator 280 landed on the baffle 264, pressure in the work
string 212 is
raised to the point where the force on the sleeve 262 causes the shear pins to
release. With the
pins shared sleeve 262 and sleeve 234 move in a downhole direction to the
position illustrated in
Figure 5. In this position sleeve 234 has moved away from ports 230 opening up
a flow pathway
between a flow bore 216 and annulus 128. In this position treatment? fluid can
be pumped down
the work string 112 to treat the horizontal zone 150a. The obturator 280 and
baffle scat 266
block are prevent -flow of treatment fluids from passing downhole through the
valve 200a.
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100411 The above-described process is then repeated for all of the sleeve
valves 200b-
200f. Once the treatments are completed, the pressure in work string 112 is
reduced, flow back
from the various zones will force the balls to flow back up the well to the
rig 106 where they are
recovered from the well. As the balls flow up the work string 112, the balls
will contact the
baffles 264 and force them into the expanded position illustrated in Figure 6.
Expanding the
baffles 264 eliminates the flow restriction resulting from the contracted
baffle position illustrated
in Figure 5.
10042] In some embodiments, operating a wellbore servicing system such as
wellbore
servicing system 100 may comprise providing a first sleeve system (e.g., of
the type of sleeve
systems 200 ) in a wellbore and providing wellbore servicing pumps and/or
other equipment to
produce a fluid flow through the sleeve flow bores of the sleeve system.
Subsequently, an obturator
may be introduced into the fluid flow so that the obturator travels downhole
and into engagement
with the seat of a baffle in first sleeve valve. When the obturator contacts
the scat, fluid pressure
may be increased to cause the first sleeve system to open ports to provide
treatment paths.
[0043] In the described embodiments, a method of performing a wellbore
servicing
operation may comprise providing a work string comprising a plurality of
sleeve systems in a
configuration as described above and positioning the work string within the
wellbore such that one
or more of the plurality of sleeve systems is positioned proximate and/or
substantially adjacent to
one or more of the zones. The zones may be isolated, for example, by actuating
one or more
packers or similar isolation devices.
100441 In the described embodiments, a method of performing a wellbore
servicing
operation may comprise providing well casing comprising a plurality of sleeve
systems in a
configuration as described above and positioning the casing such that one or
more of the plurality of
sleeve systems is positioned proximate and/or substantially adjacent to one or
more of the zones.
The zones may be isolated, for example, by actuating one or more packers or
similar isolation
devi ces
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[0045] One of skill in the art will appreciate that the servicing fluid
communicated to
the zone may be selected dependent upon the servicing operation to be
performed. Nonlimiting
examples of such servicing fluids include a fracturing fluid, a hydrajetting
or perforating fluid, an
acidizing, an injection fluid, a fluid loss fluid, a sealant composition, or
the like.
[0046] Use
of broader terms such as comprises, includes, and having should be
understood to provide support for narrower terms such as consisting of,
consisting essentially of,
and comprised substantially of. Accordingly, the scope of protection is not
limited by the
description set out above but is defined by the claims that follow, that scope
including all
equivalents of the subject matter of the claims.
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