U.S. patent application number 12/139604 was filed with the patent office on 2009-12-17 for method and apparatus for exposing a servicing apparatus to multiple formation zones.
This patent application is currently assigned to HALLIBURTON ENERGY SERVICES, INC.. Invention is credited to Matthew Howell, Gregory Vargus, Shawn Webb.
Application Number | 20090308588 12/139604 |
Document ID | / |
Family ID | 41413704 |
Filed Date | 2009-12-17 |
United States Patent
Application |
20090308588 |
Kind Code |
A1 |
Howell; Matthew ; et
al. |
December 17, 2009 |
Method and Apparatus for Exposing a Servicing Apparatus to Multiple
Formation Zones
Abstract
A well bore servicing apparatus comprising an first sleeve
slidably disposed in a tubing section, an second sleeve slidably
disposed in the first sleeve, an indexing slot disposed on one of
the outer sleeve and inner sleeve, and a control lug disposed on
the other of the outer sleeve and the inner sleeve to communicate
with the indexing slot, and an expandable seat disposed in the
inner sleeve to receive a plurality of obturating members. A well
bore servicing apparatus comprising a work string, a tubing section
coupled to the work string, a plurality of sleeve assemblies
disposed in the tubing section, and a plurality of seats for
receiving an obturating member, one seat disposed in each of the
sleeve assemblies, wherein the plurality of seats are substantially
the same size.
Inventors: |
Howell; Matthew; (Duncan,
OK) ; Vargus; Gregory; (Duncan, OK) ; Webb;
Shawn; (Duncan, OK) |
Correspondence
Address: |
JOHN W. WUSTENBERG
P.O. BOX 1431
DUNCAN
OK
73536
US
|
Assignee: |
HALLIBURTON ENERGY SERVICES,
INC.
Houston
TX
|
Family ID: |
41413704 |
Appl. No.: |
12/139604 |
Filed: |
June 16, 2008 |
Current U.S.
Class: |
166/66.4 ;
166/373 |
Current CPC
Class: |
E21B 23/006 20130101;
E21B 21/103 20130101; E21B 43/26 20130101 |
Class at
Publication: |
166/66.4 ;
166/373 |
International
Class: |
E21B 4/04 20060101
E21B004/04; E21B 34/06 20060101 E21B034/06 |
Claims
1. A well bore servicing apparatus comprising: an first sleeve
slidably disposed in a tubing section; an second sleeve slidably
disposed in the first sleeve; an indexing slot disposed on one of
the outer sleeve and inner sleeve, and a control lug disposed on
the other of the outer sleeve and the inner sleeve to communicate
with the indexing slot; and an expandable seat disposed in the
inner sleeve to receive a plurality of obturating members.
2. The apparatus of claim 1 wherein the lug is disposed within the
indexing slot to guide relative movement between the first sleeve
and the second sleeve.
3. The apparatus of claim 1 wherein the plurality of obturating
members are the same size.
4. The apparatus of claim 2 wherein the indexing slot includes a
plurality of stop positions and a plurality of release positions
for the lug.
5. The apparatus of claim 4 wherein the plurality of stop positions
correspond to a contracted position of the expandable seat and the
plurality of release positions correspond to an expanded position
of the expandable seat for passing through the plurality of
obturating members.
6. The apparatus of claim 1 wherein the expandable seat includes a
plurality of collet fingers.
7. The apparatus of claim 6 wherein the collet fingers are normally
open.
8. The apparatus of claim 6 wherein the collet fingers are normally
closed.
9. The apparatus of claim 6 wherein the collet fingers are dipped
or coated.
10. A well bore servicing apparatus comprising: a work string; a
tubing section coupled to the work string; a plurality of sleeve
assemblies disposed in the tubing section; and a plurality of seats
for receiving an obturating member, one seat disposed in each of
the sleeve assemblies; wherein the plurality of seats are
substantially the same size.
11. The apparatus of claim 10 wherein the seats are operable to
receive a series of obturating members having substantially the
same size.
12. The apparatus of claim 11 wherein the series of obturating
members are operable to successively actuate the plurality of
sleeve assemblies adjacent multiple formation zones.
13. The apparatus of claim 10 wherein the tubing section having the
plurality of sleeve assemblies includes a substantially uniform
minimum flow bore diameter over its axial length.
14. The apparatus of claim 10 wherein all sleeve assemblies
disposed in the tubing section are actuatable by the same size
obturating member.
15. The apparatus of claim 10 further comprising an indexing slot
and a corresponding control lug disposed in each of the sleeve
assemblies.
16. The apparatus of claim 15 wherein the control lugs communicate
with positions in the indexing slot to count the number of
obturating members that pass through an inner sleeve assembly.
17. The apparatus of claim 10 further including an electronic
counter operable to detect the obturating member.
18. The apparatus of claim 10 further including a drive means
coupled to an indexing assembly in each of the sleeve
assemblies.
19. The apparatus of claim 11 further comprising an electronic tag
in each of the obturating members, an electronic counter in each of
an inner sleeve assembly disposed in each of the sleeve assemblies,
and an electro-mechanical actuator coupled to the inner
sleeves.
20. A method of servicing a well bore comprising: disposing a
tubing section in the well bore; positioning the tubing section
adjacent a plurality of formation zones; passing a first obturating
member through a first moveable sleeve; catching the first
obturating member in a second moveable sleeve to actuate a sleeve
assembly adjacent a first formation zone; and catching a second
obturating member in the first moveable sleeve to actuate a second
sleeve assembly adjacent a second formation zone; wherein the first
and second obturating members are substantially the same size.
21. The method of claim 20 further comprising passing a plurality
of same-size obturating members through the first moveable sleeve
and actuating a plurality of sleeve assemblies below the first
moveable sleeve with the same-size obturating members.
22. A method of servicing a well bore comprising: placing a tubing
section in the well bore via a work string; and actuating a
plurality of sleeve assemblies in the tubing section with same-size
obturating members.
23. The method of claim 22 further comprising pumping a treatment
fluid through a flow bore in the tubing section having a
substantially uniform inner diameter.
24. The method of claim 22 further comprising maintaining constant
flow rates over the axial length of the tubing section having the
plurality of sleeve assemblies.
25. The method of claim 22 further comprising maintaining constant
treatment pressures over the axial length of the tubing section
having the plurality of sleeve assemblies.
26. A method of servicing a well bore comprising: disposing a
tubing section having a plurality of actuatable sleeve assemblies
in the well bore; providing a series of obturating members having
substantially the same size to actuate the sleeve assemblies; and
successively actuating the sleeve assemblies with the same-size
obturating member to successively treat a plurality of formation
zones.
Description
BACKGROUND
[0001] Hydrocarbon-producing wells often are stimulated by
hydraulic fracturing operations, wherein a fracturing fluid may be
introduced into a portion of a subterranean formation penetrated by
a well bore at a hydraulic pressure sufficient to create or enhance
at least one fracture therein. Stimulating or treating the well in
such ways increases hydrocarbon production from the well. The
fracturing equipment may be included in a completion assembly used
in the overall production process.
[0002] In some wells, it may be desirable to individually and
selectively create multiple fractures along a well bore at a
distance apart from each other, creating multiple "pay zones." The
multiple fractures should have adequate conductivity, so that the
greatest possible quantity of hydrocarbons in an oil and gas
reservoir can be drained/produced into the well bore. When
stimulating a formation from a well bore, or completing the well
bore, especially those well bores that are highly deviated or
horizontal, it may be advantageous to create multiple pay zones
with a series of actuatable sleeve assemblies disposed in a
downhole tubular. The actuatable sleeve assemblies are also
referred to as stimulation sleeves, or casing or tubing
windows.
[0003] A stimulation sleeve may include a section of tubing having
holes or apertures pre-formed in the tubing, and a sliding sleeve
movable relative to the tubing section. The sliding sleeve also
includes apertures alignable with the apertures in the tubing
section. Upon actuation of the stimulation sleeve, such as by ball
drop or other obturating member interference, the sliding sleeve
moves and the sliding sleeve apertures are aligned with the tubing
section apertures. This exposes the reservoir to the interior of
the tubing string, and vice versa. The flow path created between
the reservoir and the tubing string through the stimulation sleeve
can be used for fracturing or production operations. The apertures
in the tubing section may include jet forming nozzles to provide a
fluid jet into the formation, causing tunnels and fractures
therein.
[0004] While the stimulation sleeve just described is one
embodiment, other embodiments of actuatable sleeve assemblies may
be used in series along a downhole tubular to communicate with
multiple pay zones during fracturing or completion operations. To
selectively actuate each successive sleeve assembly, differently
sized balls or other obturating members are released into the
tubing string. Each sleeve assembly includes a ball seat having a
different inner diameter. The sleeve assembly having the largest
ball seat is disposed furthest uphole, or closest to the surface of
the well, while each successive sleeve assembly below the initial
assembly includes an incrementally decreasing ball seat diameter.
Thus, smaller balls may be released into the tubing string to pass
through the larger diameter ball seats and selectively actuate the
lower sleeve assemblies. Subsequently, incrementally larger sized
balls are released into the tubing string to actuate each
successive sleeve assembly in ascending order up the well.
[0005] Such a tubing assembly with successive diameter sleeves
tends to restrict the inner diameter of the flow bore through the
tubing string with the lower, smaller diameter sleeves, thereby
also restricting the flow rates and treatment pressures that can be
achieved with the tubing assembly. Further, a successive diameter
system limits the number of sleeve assemblies that can be disposed
in the tubing string because the flow bore of the tubing string has
a limited number of incremental diameters between the maximum
diameter of the flow bore and the minimum diameter that can still
achieve treatment pressure flow rates. To achieve desirable results
in the aforementioned treatment and production processes,
maintaining an inner diameter of the flow bore for flow rates and
treatment pressures, and increasing the number of pay zones is
needed. The present disclosure includes embodiments for maintaining
an increased or substantially uniform inner diameter of a treatment
or completion assembly having stimulation sleeves, and for
increasing the number of stimulation sleeves included in the
treatment or completion assembly.
SUMMARY
[0006] Disclosed herein is a well bore servicing apparatus
comprising an first sleeve slidably disposed in a tubing section,
an second sleeve slidably disposed in the first sleeve, an indexing
slot disposed on one of the outer sleeve and inner sleeve, and a
control lug disposed on the other of the outer sleeve and the inner
sleeve to communicate with the indexing slot, and an expandable
seat disposed in the inner sleeve to receive a plurality of
obturating members.
[0007] Also disclosed herein is a well bore servicing apparatus
comprising a work string, a tubing section coupled to the work
string, a plurality of sleeve assemblies disposed in the tubing
section, and a plurality of seats for receiving an obturating
member, one seat disposed in each of the sleeve assemblies, wherein
the plurality of seats are substantially the same size.
[0008] Further disclosed herein is a method of servicing a well
bore comprising disposing a tubing section in the well bore,
positioning the tubing section adjacent a plurality of formation
zones, passing a first obturating member through a first moveable
sleeve, catching the first obturating member in a second moveable
sleeve to actuate a sleeve assembly adjacent a first formation
zone, and catching a second obturating member in the first moveable
sleeve to actuate a second sleeve assembly adjacent a second
formation zone, wherein the first and second obturating members are
substantially the same size.
[0009] Further disclosed herein is a method of servicing a well
bore comprising placing a tubing section in the well bore via a
work string, and actuating a plurality of sleeve assemblies in the
tubing section with same-size obturating members.
[0010] Further disclosed herein is a method of servicing a well
bore comprising disposing a tubing section having a plurality of
actuatable sleeve assemblies in the well bore, providing a series
of obturating members having substantially the same size to actuate
the sleeve assemblies, and successively actuating the sleeve
assemblies with the same-size obturating member to successively
treat a plurality of formation zones.
BRIEF DESCRIPTION OF THE DRAWINGS
[0011] For a more detailed description of the embodiments,
reference will now be made to the following accompanying
drawings:
[0012] FIG. 1 is a schematic, partial cross-section view of a fluid
treatment and completion apparatus in an operating environment;
[0013] FIGS. 2A and 2B are cross-section views of a stimulation
sleeve in a closed position;
[0014] FIGS. 3A and 3B are cross-section views of the stimulation
sleeve of FIGS. 2A and 2B in an open position;
[0015] FIG. 4A is a partial cross-section view of a hydrojetting
casing window assembly;
[0016] FIG. 4B is a partial cross-section view of the casing window
assembly of FIG. 4A in a shifted open position;
[0017] FIG. 5 is a partial cross-section view of a well completion
assembly including embodiments of FIGS. 4A and 4B;
[0018] FIG. 6A is a partial cross-section view of an indexing
assembly;
[0019] FIG. 6B is a profile view of an indexing slot of the
indexing assembly of FIG. 6A;
[0020] FIG. 7 is a partial cross-section view of an alternative
embodiment of an indexing assembly in an initial position;
[0021] FIG. 8 is a partial cross-section view of the indexing
assembly of FIG. 7 receiving a dropped ball;
[0022] FIG. 9 is a partial cross-section view of the indexing
assembly of FIG. 7 in a release position;
[0023] FIG. 10 is a partial cross-section view of the indexing
assembly of FIG. 7 in a return position; and
[0024] FIG. 11 is a profile view of an indexing slot of the
indexing assembly of FIG. 7.
DETAILED DESCRIPTION
[0025] 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. The present invention is susceptible to
embodiments of different forms. Specific embodiments are described
in detail and are shown in the drawings, with the understanding
that the present disclosure is to be considered an exemplification
of the principles of the invention, and is not intended to limit
the invention to that illustrated and described herein. It is to be
fully recognized that the different teachings of the embodiments
discussed below may be employed separately or in any suitable
combination to produce desired results.
[0026] 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", "upwardly" or "upstream" meaning
toward the surface of the well and with "down", "lower",
"downwardly" or "downstream" meaning toward the terminal end of the
well, regardless of the well bore 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 term "seat" as used herein may be referred to as a
ball seat, but it is understood that seat may also refer to any
type of catching or stopping device for an obturating member or
other member sent through a work string fluid passage that comes to
rest against a restriction in the passage. 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 upon reading the following
detailed description of the embodiments, and by referring to the
accompanying drawings.
[0027] Disclosed herein are several embodiments of a well bore
servicing apparatus including multiple sleeve assemblies disposed
in a work string that are selectively actuatable to expose
different formation zones to an inner fluid passage of the work
string at different times. The sleeve assemblies may be
sequentially actuated to expose the inner fluid passage to the
formation zones such that they are treated at different times in a
certain order. The sleeve assemblies may also include an inner
indexing assembly allowing the sleeve assemblies to be actuated
without loss of the inner diameter of the fluid passage in the work
string, and without using multiple sizes of dropped balls. The
indexing assembly may include an inner sleeve that is moveable and
lockable relative to the moveable sleeve of the sleeve assemblies.
The indexing assembly can be manipulated to allow a pre-determined
number of obturating members to pass through a seat in the indexing
assembly before a selected obturating members is caught in the seat
and the indexing assembly is moved to actuate the sleeve assembly.
In essence, the indexing assembly is configured to count the number
of passing obturating members before actuation. The number of
counted obturating members can be adjusted. The counting can be
achieved with a J-slot or indexing slot communicating between the
inner sleeve of the indexing assembly and the moveable or outer
sleeve of the sleeve assembly, and an expandable seat for the
obturating member.
[0028] Referring to FIG. 1, a schematic representation of an
exemplary operating environment for a fluid treatment or completion
apparatus 100 is shown. The apparatus 100 is an exemplary
embodiment, and various other embodiments of the apparatus 100
consistent with the teachings herein are included. As depicted, a
drilling rig 110 is positioned on the earth's surface 105 and
extends over and around a well bore 120 that penetrates a
subterranean formation F for the purpose of recovering
hydrocarbons. The well bore 120 may be drilled into the
subterranean formation F using conventional (or future) drilling
techniques. The well bore 120 may extend substantially vertically
away from the surface 105 over a vertical portion 122, or may
deviate at any angle from the surface 105 over a deviated or
horizontal portion 124. In some instances, all or portions of the
well bore 120 may be vertical, deviated, horizontal, and/or
curved.
[0029] At least a portion of the vertical well bore 122 may be
lined with casing 125 that may be cemented 127 into position
against the formation F in a conventional manner. Alternatively,
the horizontal portion 124 may be cased and cemented also, or the
operating environment for the apparatus 100 includes an uncased
well bore 120. The drilling rig 110 includes a derrick 112 with a
rig floor 114 through which a tubing or work string 118 extends
downwardly from the drilling rig 110 into the well bore 120. The
tubing string 118 suspends a representative downhole apparatus 100
to a predetermined depth within the well bore 120 to perform a
specific operation, such as perforating a casing, expanding a fluid
path therethrough, fracturing the formation F, producing the
formation F, or other completion operation. The tubing string 18
may also be known as the entire conveyance above and coupled to the
apparatus 100. The drilling rig 110 is conventional and therefore
includes a motor driven winch and other associated equipment for
extending the tubing string 118 into the well bore 120 to position
the apparatus 100 at the desired depth.
[0030] While the exemplary operating environment depicted in FIG. 1
refers to a stationary drilling rig 110 for lowering and setting
the apparatus 100 within a land-based well bore 120, one of
ordinary skill in the art will readily appreciate that mobile
workover rigs, well servicing units, such as coiled tubing units,
and the like, could also be used to lower the apparatus 100 into
the well bore 120. It should be understood that the apparatus 100
may also be used in other operational environments, such as within
an offshore well bore.
[0031] In one embodiment, the apparatus 100 comprises an upper end
having a liner hanger 132 such as, for example, a Halliburton
VersaFlex.RTM. liner hanger, a lower end 136, and a tubing section
134 extending therebetween. The lower end 136 may have a float shoe
138 and a float collar 140 of a type known in the art connected
therein, and other tubing conveyed devices 142, 144 connected
therein. The horizontal well bore 124 and the tubing section 134
define an annulus 146 therebetween. The tubing section 134 includes
an interior 148 that defines a flow passage 150 therethrough. In
the embodiment shown, an inner string 152 is disposed in tubing
section 134 and extends therethrough so that a lower end 154
thereof extends into and is received in a polished bore receptacle
144. The inner string 152 may be used to carry cement if the
completion operation requires cement. Alternatively, cement may not
be needed and the tubing section 134 may be without the inner
string 152 such that the flow passage 150 is the main flowbore
through the apparatus 100. A plurality of actuatable sleeve
assemblies or stimulation sleeves 158 are connected in the tubing
section 134. The stimulation sleeves 158 may be, for example, ball
drop activated, Delta Stim.RTM. Sleeves available from Halliburton
Energy Services, Inc.
[0032] Referring now to FIGS. 2A and 2B, the stimulation sleeve 158
comprises an outer housing 160 with an opening sleeve 162
detachably connected therein. The opening sleeve 162 has a lower
end 163. After becoming detached from the housing 160, the opening
sleeve 162 is slidable or movable in the housing 160 as explained
in more detail hereinbelow. The outer housing 160 has an upper end
164 and a lower end 166, both of which are adapted to be directly
connected or threaded into a tubing section such that the outer
housing 160 makes up a part of the tubing section 134. The opening
sleeve 162 is initially connected to the outer housing 160 with a
snap ring 168 which extends into a groove 170 defined on an inner
surface 172 of the outer housing 160. In addition, shear pins
extending through the outer housing 160 and into the sleeve 162 may
be utilized to detachably connect the sleeve 162 to the outer
housing 160. Guide pins 176 may be threaded or otherwise attached
to the sleeve 162 and may be received in axial grooves or axial
slots 178 in the housing 160. The guide pins 176 are slidable in
the axial slots 178, which will prevent relative rotation between
the sleeve 162 and the outer housing 160. The sleeve 162 has a
plurality of sleeve or door ports 180 therethrough. The outer
housing 160 has a plurality of housing ports 182 defined therein.
In the position shown in FIGS. 2A and 2B, the sleeve ports 180 are
misaligned from the housing ports 182 such that the stimulation
sleeve 158 is in a closed position. The sleeve 162 has a seat ring
184 operably associated therewith and is connected therein at or
near the lower end 163. The seat ring 184 has a central opening 186
defining a diameter 188 therethrough, and has a seat surface 190
for engaging an obturating member to be dropped through the tubing
string.
[0033] To move the opening sleeve 162 from the closed position to
an open position, an obturating member 194, such as a closing ball
shown in FIG. 3B, is dropped through the tubing string 118 so that
it will engage the seat 190 on the seat ring 184. Although shown as
a closing ball, the obturating member 194 may be other closing
devices such as plugs and darts that will engage the seat 190 and
prevent flow therethrough. Pressure is increased to overcome the
holding force applied by the snap ring 168 and the shear pins,
thereby moving the opening sleeve 162 to the position shown in
FIGS. 3A and 3B in which the sleeve ports 180 and the casing ports
182 are aligned to allow for the passage of fluids
therethrough.
[0034] Referring now to FIGS. 4A and 4B, an exemplary casing window
assembly 300 is shown and can be adapted for use as an alternative
embodiment of the stimulation sleeve 158. As used herein, the term
"casing window" refers to a section of casing configured to enable
selective access to one or more specified zones of an adjacent
subterranean formation. A casing window has a window that may be
selectively opened and closed by an operator, for example, movable
sleeve member 304. The casing window assembly 300 can have numerous
configurations and can employ a variety of mechanisms to
selectively access one or more specified zones of an adjacent
subterranean formation.
[0035] The casing window 300 includes a substantially cylindrical
outer casing 302 that receives a movable sleeve member 304. The
outer casing 302 includes one or more apertures 306 to allow the
communication of a fluid from the interior of the outer casing 302
into an adjacent subterranean formation. The apertures 306 are
configured such that fluid jet forming nozzles 308 may be coupled
thereto. In some embodiments, the fluid jet forming nozzles 308 may
be threadably inserted into the apertures 306. The fluid jet
forming nozzles 308 may be isolated from the annulus 310 (formed
between the outer casing 302 and the movable sleeve member 304) by
coupling seals or pressure barriers 312 to the outer casing
302.
[0036] The movable sleeve member 304 includes one or more apertures
314 configured such that, as shown in FIG. 4A, the apertures 314
may be selectively misaligned with the apertures 306 so as to
prevent the communication of a fluid from the interior of the
movable sleeve member 304 into an adjacent subterranean formation.
The movable sleeve member 304 may be shifted axially, rotatably, or
by a combination thereof such that, as shown in FIG. 4B, the
apertures 314 selectively align with the apertures 306 so as to
allow the communication of a fluid from the interior of the movable
sleeve member 304 into an adjacent subterranean formation. The
movable sleeve member 304 may be shifted via the use of a ball drop
mechanism.
[0037] Referring now to FIG. 5, an exemplary well completion
assembly 400 includes open casing window 402 and closed casing
window 404 formed in a tubing section or conduit 406.
Alternatively, the well completion assembly 400 may be selectively
configured such that the casing window 404 is open and the casing
window 402 is closed, such that the casing windows 402 and 404 are
both open, or such the that casing windows 402 and 404 are both
closed.
[0038] A fluid 408 may be pumped down the conduit 406 and
communicated through the fluid jet forming nozzles 410 of the open
casing window 402 against the surface of the well bore 120 in the
zone 414 of the subterranean formation F. The fluid 408 would not
be communicated through the fluid jet forming nozzles 418 of the
closed casing window 404, thereby isolating the zone 420 of the
subterranean formation F from any well completion operations being
conducted through the open casing window 402 involving the zone
414. The fluid 408 may include any of the embodiments disclosed
elsewhere herein.
[0039] In one embodiment, the fluid 408 is pumped through the fluid
jet forming nozzles 410 at a velocity sufficient for fluid jets 422
to form perforation tunnels 424. In one embodiment, after the
perforation tunnels 424 are formed, the fluid 408 is pumped into
the conduit 406 and through the fluid jet forming nozzles 410 at a
pressure sufficient to form cracks or fractures 426 along the
perforation tunnels 424.
[0040] Referring back to FIG. 1, a plurality of the sleeve
assemblies 158 are included in the tubing section 134 of the
treatment and completion apparatus 100. The sleeve assemblies 158
are positioned adjacent the selected zones to be treated, such as
the plurality of selected zones 80, 82, 84, 86, 88 and 90 that may
be treated and produced with the methods and apparatus described
herein. After work string 118 having apparatus 100 is lowered into
well bore 120, and the apparatus 100 is appropriately set, a first
ball or other obturating member may be dropped into the work string
118. The ball seats in the lowermost sleeve assembly 158 to
actuate, as described herein, the sleeve assembly and establish a
fluid path to the formation zone 90. Then, a treatment fluid, such
as an acidizing fluid or a fracturing fluid, may be flowed through
the work string 118, the tubing section 134, the fluid path in the
sleeve assembly, and toward the zone 90. In some embodiments, a
high pressure fluid is communicated through the sleeve assembly
fluid path to provide a hydrojet stream to the zone 90. As used
herein, high pressure, for example, is generally greater than about
1,000 p.s.i., alternatively greater than about 3,500 p.s.i.,
alternatively greater than about 10,000 p.s.i., and alternatively
greater than about 15,000 p.s.i. Once the selected zone 90 has been
treated, a second ball is dropped to engage the sleeve seat in the
next sleeve assembly 158 in ascending order, adjacent the zone 88.
When the ball is seated, fluid flow is blocked to the lower sleeve
assembly and fluid pressure will increase to actuate the new sleeve
assembly. The zone 88 can then be treated. This procedure may be
followed to selectively and successively actuate the sleeve
assemblies 158 in ascending order, and service any and/or all of
the zones 80, 82, 84, 86, 88, 90. Typically, the center opening 186
(FIGS. 2B and 3B) in each of the sleeve assemblies 158 is of a
diameter 188 such that the balls 194 may pass therethrough to
engage the seat sleeves 184 in sleeve assemblies therebelow.
Therefore, the seat sleeve diameter 188 will be gradually and
incrementally larger from the lowermost seat sleeve through the
final seat sleeve in the uppermost sleeve assembly.
[0041] Referring now to FIG. 6A, an assembly is shown that is
adaptable to be used with the various sleeve assembly embodiments
described herein. A sliding sleeve sub or indexing assembly 500
includes an outer sleeve 502 and an inner sleeve member 504
disposed therein. For reference purposes, the outer sleeve 502 is
analogous to the opening sleeve 162 of FIGS. 2A-3B. The inner
sleeve member 504 includes an upper end 506, a lower end 508 and a
flow bore 505 therethrough. The upper end 506 includes an increased
diameter portion 510 having an indexing slot or J-slot pattern 512
that receives a control lug 514 disposed on an inner surface of the
outer sleeve 502. The interaction between the lug 514 and the
indexing slot 512, as will be described in more detail hereinbelow,
is the primary mode of communication between the outer sleeve 502
and the inner sleeve member 504. The lower end 508 includes a
projection 522 and a series of collet fingers 524. Disposed between
an outer sleeve shoulder 520 and an inner sleeve shoulder 518 is a
biasing spring 516. The inner surface of the outer sleeve 502 also
includes a recessed portion 526.
[0042] Referring next to FIG. 6B, the indexing slot 512 is shown in
an unwrapped or flattened profile view. The indexing slot 512 may
also be referred to as a continuous J-slot or a control groove. The
indexing slot 512 includes a plurality of biased, reset or stop
positions 530, 532, 534 and a plurality of release positions 536,
538 for the lug 514. The slot 512 also includes a final engagement
or actuation position 540. The indexing slot 512 is disposed about
the upper portion of the tube forming the inner sleeve 504. The
indexing slot 512, in some embodiments, may be a solid member, such
as a metal sheet, having a slot or groove formed therein. The
indexing slot may be shaped to extend around a cylindrical member,
as is shown in FIG. 6A. In some embodiments described, the lug 514
includes a circular shape from a top view of the lug. The lug may
include other shapes, such as an oval or elliptical shape.
Furthermore, other control slot operating members may interact with
the indexing slot 512 to provide the relationships described
herein.
[0043] In operation, the indexing assembly 500 is assembled as
shown in FIG. 6A, with the inner sleeve 504 biased upward by the
spring 516 such that the collet fingers 524 and the projection 526
are above the recess 526. The control lug 514 is initially disposed
in one of the stop positions 530, 532, 534 and limits the upward
movement of the inner sleeve 504. Preferably, the initial position
of the lug 514 is the furthest from the final position 540 to allow
the most number of cycles through the indexing slot, though the
initial position can be selected to pre-determine the number of
cycles through the indexing slot and thus the number of balls that
pass through the inner sleeve 504. A first ball, such as that shown
in FIG. 8, passes through the flow bore 505 and arrives at a seat
542 in the lower end 508. A pressure buildup above the ball causes
the inner sleeve to overcome the biasing force of the spring 516
and move downward, as similarly depicted in FIG. 9. As the inner
sleeve 504 moves downward, the projection 526 slides into the
recess 526 and the collet fingers expand into the recess, as shown
in FIG. 9. Simultaneously, the inner sleeve 504 and the indexing
slot 512 are guided about the lug 514, which is stationary on the
outer sleeve 502, such that the lug moves from initial slot 530 to
the release position 536. The ball is then allowed to pass into the
flow bore 544 below the inner sleeve 504. After the ball passes,
the pressure on the inner sleeve 504 is relieved the biasing spring
moves the inner sleeve 504 upward. At the same time, the inner
sleeve 504 and the indexing slot 512 are guided about the lug 514
such that the lug is now placed in the stop position 532.
[0044] The lug 514 is guided through any number of sets of stop and
release positions until the lug 514 reaches the final position 540.
In the final position 540, vertical movement of the inner sleeve
504 is restricted such that the pressure buildup in the inner
sleeve 504 is transferred to the outer sleeve 502 and the overall
sleeve assembly is actuated as described herein. For example, when
the lug 514 is in the final position 540, the ball seat 542 acts
analogously to the ball seat 190 in the seat ring 184 of FIGS. 2B
and 3B. The outer sleeve 502 then moves similarly to the sleeve 162
of the sleeve assembly 158. Thus, the indexing assembly 500 can
replace the seat ring 184 arrangement of the sleeve assembly 158
while providing increased flexibility for inner sleeve 504 movement
and ball pass-through while the overall sleeve assembly remains
unactuated.
[0045] The indexing assembly 500 can be pre-set to count any number
of ball pass-throughs. For example, if an indexing assembly 500 is
placed in the second lowermost position, wherein another assembly
is below it, and it is known that one ball must pass through the
indexing assembly 500, then the assembly is adjusted accordingly.
In one embodiment, the indexing slot 512 is simply manufactured to
have the initial position 532, the release position 538, the reset
position 534 and the final position 540. Therefore, one cycle from
position 532 to position 538 to position 534 allows one ball to
pass through the indexing assembly 500 before the final position
540 is reached and the sleeve assembly is actuated. In another
embodiment, the indexing slot 512 is manufactured to have any
number of stop and release positions, and the indexing assembly 500
is assembled such that the initial position of the lug 514 is in
the second to last stop position, or position 532.
[0046] A plurality of indexing assemblies 500 may be disposed in a
tubing section in series, such as in the series of stimulation
sleeves 158 shown in FIG. 1. The series of indexing assemblies 500
will include ball seats 542 all having the same unexpanded diameter
to receive the same size balls. For example, the diameter of
unexpanded ball seat 542 in FIG. 6A may be 2.75 inches, while the
balls may be 3 inches in diameter. Each assembly 500 can be pre-set
to catch and release a different number of 3-inch balls such that
the series of assemblies will actuate a series of sleeve assemblies
158 or 300 to successively expose the work and tubing strings to
different zones of interest 80, 82, 84, 86, 88, 90 while passing
the same size ball through the plurality of indexing and sleeve
assemblies. In alternative embodiments, a first series of indexing
and sleeve assemblies is adapted to receive a first size ball while
a second series of indexing and sleeve assemblies is adapted to
receive a second size ball, thereby further expanding the total
number of sleeve assemblies that can be actuated in the well.
Alternatively, a third series may be added and so on. For example,
a bottom series of four indexing and sleeve assemblies may be
adapted to successively actuate upon receiving a series of four
2-inch balls. A next series of four indexing and sleeve assemblies
may be adapted to successively actuate upon receiving a series of
four 2.25-inch balls. A third series disposed uphole of the second
series may be adapted to successively actuate upon receiving a
series of four 2.5-inch balls. In this embodiment, a total of
twelve indexing and sleeve assemblies can be actuated to expose
zones of interest. Further added series will add indexing and
sleeve assemblies in increments of four, or however many balls the
indexing assembly is designed to catch and release as designed
herein.
[0047] In some embodiments, the collet fingers 524 are dipped in
stiffening or hardening agents for added strength or resistance. In
one embodiment, the collet fingers 524 are at rest in the
contracted position shown in FIG. 6A, and the force of the ball
passing through the collet fingers causes them to expand into the
recess 526. These collet fingers 524 may also be referred to as
"normally closed" or "normally contracted." In another embodiment,
the collet fingers are formed and strengthened to normally be in
the expanded position shown in FIG. 9, such that the collet fingers
are forced together as shown in FIG. 6A and allowed to spread
automatically when placed in the position of FIG. 9. These collet
fingers 524 may also be referred to as "normally open" or "normally
expanded." In other embodiments, the collet fingers 524 are dipped
in an elastomer or other compressible material such that when the
collet fingers are contracted as shown in FIG. 6A, the elastomer
coating on one finger will compress against the elastomer coating
on an adjacent finger to close the spaces between the fingers and
provide a sealed ball seat 542.
[0048] In an alternative embodiment, the control lug 514 is
disposed on the outer surface of the inner sleeve 504 and the
indexing slot 512 is disposed on the inner surface of the outer
sleeve 502, i.e., they are switched. In this embodiment, the
profile view of FIG. 6B would be flipped such that the stop
positions would be on top and the release positions on bottom, and
the final position would be on top.
[0049] With reference to FIG. 7-11, a further embodiment includes
an indexing assembly 600 having similar components as the assembly
500, such as an outer sleeve 602 and an inner sleeve 604. However,
assembly 600 further includes an upper recessed portion 627. In
operation, a ball 670 enters the flow bore 605 and arrives at the
seat 642 as shown in FIG. 8. The pressure buildup above the ball
670 overcomes the biasing force provided by the spring 616 and
moves the inner sleeve 604 downward. As shown in FIG. 9, the collet
fingers 624 expand into the recess 626, either by the force
provided by the ball 670 or by the normally open disposition of the
fingers, and the ball 670 passes through the fingers 624 and the
seat 642 to travel downward 650 through the flow bore 644. The
biasing force of the spring 616 then returns the inner sleeve 604
to the middle position shown in FIG. 8, readying the indexing
assembly 600 to receive another ball 670. During this process, the
lug 614 and indexing slot 612 operate as previously described.
[0050] However, at some point, it may be desirable to return a ball
or balls to the surface of the well. A ball may be forced upward
along a return path 660 in the flow bore 644 by fluid pressure or
other means, and the indexing assembly 600 is adapted to work in
reverse wherein the upper recess 627 receives the expanding collet
fingers 624 as shown in FIG. 10. As shown in FIG. 11, a reserve
position 648 is provided in the indexing slot 612 to accommodate
the upward movement of the inner sleeve 604 as shown in FIG. 10.
For example, the indexing assembly 600 may be assembled such that
the lug 614 is given an initial position 630. Ball engagement on
the seat 642 causes the inner sleeve 604 to move downward, and thus
the lug 614 moves upward in the indexing slot 612 to the first
release position 636. The ball 670 passes through the collet
fingers 624, thereby relieving the pressure in the inner sleeve
604. The biasing spring 616 returns the inner sleeve 604 and the
indexing slot 612 to a position placing the lug 614 in a first
reset position 632. Another ball 670 may be cycled through the
inner sleeve 604, placing the lug 614 in a second release position
638, then in a second reset position 634 which is also the catch
position. Position 634 is a catch position because the lug 614 is
not allowed to move upward to a position similar to positions 636,
638, thereby preventing downward movement of the inner sleeve 604
and release of the ball 670. The pressure buildup above the ball
670 is transferred to the outer sleeve 602, which is the slidable
sleeve of a larger sleeve assembly as described herein. However,
unlike indexing slot 512, the slot 612 provides an additional
position 648 that allows upward movement of the inner sleeve 604 to
accommodate the return of the ball 670 shown in FIG. 10. Once the
balls have been returned as described, the well can be produced
unobstructed and without intervention to drill out the ball-engaged
indexing and sleeve assemblies. In other embodiments, the balls or
other obturating members are breakable or dissolvable to remove
them from the inner flow bores.
[0051] In other embodiments, the total number of reset and release
positions is adjusted to increase or decrease the number of balls
the indexing assemblies are designed to catch and release. For
example, the indexing slots 512, 612 are designed to release two
balls before catching the third ball. However, additional sets of
reset and release positions can be added to increase the number of
balls that are released before the final ball is caught.
[0052] The number of zones, indexing assemblies and sleeve
assemblies shown herein is not intended to be limiting and is shown
only for exemplary purposes. Any desired number of zones may be
treated or produced. The plurality of zones will be treated
sequentially upwardly. For example, when a sleeve assembly is moved
to align openings, dissolving fluid and then treatment fluid may be
flowed into the zone to be treated, and the next zone desired to be
treated is done so in the manner described. Once the selected zones
have been treated, the balls can be flowed back to the surface, as
previously described, or drilled out and the well can be produced
through each of the selected zones in a manner known in the
art.
[0053] In alternative embodiments, the mechanical assemblies 500,
600 may be similar with the exception of the indexing slots 512,
612. The indexing slots 512, 612 act as counter mechanisms to count
the number of balls that pass through the assemblies. While the
other elements and components of the assemblies remain similar, the
indexing slots 512, 612 can be replaced by alternative counting
mechanisms. The electro-mechanical sliding sleeve assemblies or
subs may incorporate electronics, and the counter or reader in the
sleeve assembly could be actuated by magnets, RFID tags or other
"smarts" in the balls. For example, the sliding sleeve sub can be
placed in the open or release position as the normal position. An
electronic reader in the inner sleeve electronically counts the
magnets or tags in the balls as they pass through the expandable
seat, and upon counting a pre-determined number of balls, the
sleeve is actuated to move to the closed position. The inner sleeve
can be moved to the closed position by a motor or other drive means
known in the art. Thus, while the sliding inner sleeve and collet
finger arrangement provides the same uniformity of flow bore
diameter and ball size, the counting of the balls is accomplished
by electronic or electrical means rather than mechanical means, and
the inner sleeve is driven not by fluid pressure but by a drive
means such as an electro-mechanical actuator. In alternative
embodiments, the electro-mechanical actuator can be replaced by
pressurized chambers adjacent the inner sliding sleeve. An
unpressurized chamber is adjacent and communicates with the inner
sleeve, and is separate from a pressurized chamber by a burst disc.
Upon an actuation command from the electronic counter, the disc can
be burst to expose the unpressurized chamber and thus the inner
sliding sleeve to fluid pressure to move the sleeve to its closed
position as described herein.
[0054] In addition to servicing, treatment and completion systems,
the embodiments of the indexing or sliding sleeve assemblies can be
used in other systems. For example, a system including a series
open-hole packer can incorporate the indexing or sliding sleeve
assemblies for successive actuation of the packers.
[0055] While specific embodiments have been shown and described,
modifications can be made by one skilled in the art without
departing from the spirit or teaching of this invention. The
embodiments as described are exemplary only and are not limiting.
Many variations and modifications are possible and are within the
scope of the invention. Accordingly, the scope of protection is not
limited to the embodiments described, but is only limited by the
claims that follow, the scope of which shall include all
equivalents of the subject matter of the claims.
* * * * *