U.S. patent application number 14/457972 was filed with the patent office on 2015-02-19 for multi-zone single trip well completion system.
The applicant listed for this patent is Superior Energy Services, LLC. Invention is credited to Jed Landry, Anthony Thomas, Dewayne Turner, David Walker.
Application Number | 20150047837 14/457972 |
Document ID | / |
Family ID | 52465987 |
Filed Date | 2015-02-19 |
United States Patent
Application |
20150047837 |
Kind Code |
A1 |
Turner; Dewayne ; et
al. |
February 19, 2015 |
Multi-Zone Single Trip Well Completion System
Abstract
A well completion system having (i) a completion assembly; (ii)
a service tool positioned within the completion assembly, wherein
the service tool includes a substantially straight bore central
passage from an upper end of the service tool to a lower end of the
service tool; and (iii) a one-way valve positioned in an assembly
annulus formed between the service tool and an inner surface of the
completion assembly.
Inventors: |
Turner; Dewayne; (Tomball,
TX) ; Landry; Jed; (Breaux Bridge, LA) ;
Thomas; Anthony; (Houston, TX) ; Walker; David;
(Lafayette, LA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Superior Energy Services, LLC |
Harvey |
LA |
US |
|
|
Family ID: |
52465987 |
Appl. No.: |
14/457972 |
Filed: |
August 12, 2014 |
Related U.S. Patent Documents
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
|
|
61865206 |
Aug 13, 2013 |
|
|
|
Current U.S.
Class: |
166/254.2 ;
166/191; 166/316 |
Current CPC
Class: |
E21B 2200/06 20200501;
E21B 43/14 20130101; E21B 43/12 20130101 |
Class at
Publication: |
166/254.2 ;
166/316; 166/191 |
International
Class: |
E21B 47/00 20060101
E21B047/00; E21B 43/12 20060101 E21B043/12 |
Claims
1. A well completion system comprising: a. a completion assembly;
b. a service tool positioned within the completion assembly,
wherein the service tool includes a substantially straight bore
central passage from an upper end of the service tool to a lower
end of the service tool; and c. a one-way valve positioned in an
assembly annulus formed between the service tool and an inner
surface of the completion assembly.
2. The well completion system of claim 1, further comprising a work
string having an inner diameter being connected to the completion
system and the service tool's central passage having approximately
the same diameter as the work string's inner diameter.
3. The well completion system of claim 1, wherein the one-way valve
is a reverse bypass valve allowing fluid flow in an uphole to
downhole direction, but substantially blocks flow in a downhole to
uphole direction.
4. The well completion system of claim 3, wherein the reverse
bypass valve comprises: (i) a series of apertures in a valve body;
and (ii) a flexible material movable away from the apertures in
response to downhole fluid flow in the assembly annulus and movable
against the apertures in response to uphole fluid flow in the
assembly annulus.
5. The well completion system of claim 4, wherein the valve body is
substantially tubular and the apertures positioned
circumferentially around the valve body.
6. The well completion system of claim 5, wherein a flow path
through the tubular body transitions from an outer surface of the
body, to an inner surface of the body, and back to the outer
surface of the tubular body.
7. The well completion system of claim 5, wherein the tubular body
has one or more seals on an outer surface sized to engage a seal
bore formed on an inner surface of the completion assembly.
8. The well completion system of claim 7, wherein the inner surface
of the completion assembly has at least one section comprising a
seal bore and at least one section not having a seal bore, wherein
fluid in the assembly annulus may flow in an uphole or downhole
direction past the reverse bypass valve when the valve is in the
section not having a seal bore.
9. The well completion system of claim 1, wherein the one-way valve
allows fluid flow in an annulus between the completion assembly and
the service tool without substantial narrowing of the central
passage of the service tool.
10. The well completion system of claim 1, wherein the completion
assembly includes a tubing wall and a treating aperture is formed
in the tubing wall such that the treating aperture is openingly
closed by a treating sleeve internal to the tubing wall.
11-19. (canceled)
20. A well completion system comprising: a. a tubular completion
assembly including multiple production zones, each production zone
further comprising: (i) a zonal isolation packer; (ii) a screen
wrapped, closeable monitoring port; (iii) a closeable treating port
below the monitoring port; and (iv) a screen wrapped, pressure
activated valve below the treating port.
21. The well completion system of claim 20, wherein sliding sleeves
are used to selectively close the treating port and the monitoring
port.
22. The well completion system of claim 20, wherein each zone
includes an isolation packer above the monitoring port and an
isolation packer below the pressure activated valve.
23. The well completion system of claim 20, wherein each zone
includes a reduced diameter seal bore.
24. The well completion system of claim 20, wherein the completion
assembly further comprises (i) a shifting tool activation mechanism
below a lowermost zone and (ii) a shifting tool de-activation
mechanism above an uppermost zone.
25-29. (canceled)
30. A method of logging a wellbore having a completion system
therein, comprising the steps of: a. positioning a completion
assembly in the wellbore, including a service tool within the
completion assembly, wherein the service tool includes a
substantially straight bore central passage; b. inserting a logging
tool through the straight bore central passage and logging the
wellbore at selected positions along the length of the straight
bore central passage of the service and/or below the service
tool.
31. The method of logging a wellbore of claim 30, wherein a bottom
of the service tool is raised at least as high as an approximate
top of a zone being logged prior to logging the zone.
32. The method of logging a wellbore of claim 30, wherein the
completion system further comprises a one-way valve positioned in
an assembly annulus formed between the service tool and an inner
surface of the completion assembly and the logging tool passes the
one-way valve while traveling through the service tools central
passage.
33. The method of logging a wellbore of claim 31, wherein the zone
is logged after treating of the zone without moving the service
tool below the zone.
34. The method of logging a wellbore of claim 32, wherein the
one-way valve further comprises: (i) a series of apertures in a
valve body; and (ii) a flexible material movable away from the
apertures in response to downhole fluid flow in the assembly
annulus and movable against the apertures in response to uphole
fluid flow in the assembly annulus.
35-67. (canceled)
Description
[0001] This application claims the benefit under 35 U.S.C.
.sctn.119(e) of U.S. Provisional Application Ser. No. 61/865,206,
filed Aug. 13, 2013, which is incorporated by reference herein in
its entirety.
I. BACKGROUND
[0002] The present invention relates to the field of completion
assemblies for use in hydrocarbon producing wells. In particular
embodiments, the invention provides a method and apparatus for
completing and producing from multiple production zones,
independently or in any combination. It is becoming increasingly
desirable to economically complete and produce wells from different
production zones at different stages in the process (and in
differing combinations), while at the same time reducing the number
of "trips" down the wellbore which are needed to carry out these
operations. Thus, there is a continued need for improved multi-zone
completion assemblies which combine simplicity, reliability, safety
and economy, while also affording flexibility in use.
II. SUMMARY OF SELECTED EMBODIMENTS OF THE INVENTION
[0003] One embodiment disclosed herein is well completion system
having (i) a completion assembly; (ii) a service tool positioned
within the completion assembly, wherein the service tool includes a
substantially straight bore central passage from an upper end of
the service tool to a lower end of the service tool; and (iii) a
one-way valve positioned in an assembly annulus formed between the
service tool and an inner surface of the completion assembly.
[0004] Another embodiment is a well completion system having a
tubular completion assembly, including multiple production zones,
where each production zone further comprising (i) a zonal isolation
packer; (ii) a screen wrapped, closeable monitoring port; (iii) a
closeable treating port below the monitoring port; and (iv) a
screen wrapped, pressure activated valve below the treating
port.
[0005] A further embodiment is a method of logging a wellbore
having a completion system therein. The method includes the steps
of (a) positioning a completion assembly in the wellbore, including
a service tool within the completion assembly, wherein the service
tool includes a substantially straight bore central passage; and
(b) inserting a logging tool through the straight bore central
passage and logging the wellbore at selected positions along the
length of the straight bore central passage within and/or below the
service tool.
[0006] Many additional embodiments will be apparent in the
following description and claims and their omission from the above
summary of selected embodiments should not be considered a
limitation on the scope of the present invention.
III. BRIEF DESCRIPTION OF THE DRAWINGS
[0007] FIGS. 1A to 1C illustrate one embodiment of a completion
assembly of the present invention.
[0008] FIGS. 2A to 2D illustrate one embodiment of a service tool
positioned within the completion assembly of FIGS. 1A to 1C to form
a completion system.
[0009] FIGS. 3A to 3D illustrate the completion system of FIGS. 2A
to 2D at the stage of being set in a cased well bore.
[0010] FIGS. 4A and 4B illustrate the completion assembly and
service tool during a treating operation.
[0011] FIG. 5 illustrates the completion assembly and service tool
during a reversing operation.
[0012] FIG. 6 illustrates the completion assembly and service tool
during collet de-activation.
[0013] FIGS. 7A and 7B schematically illustrate fluid flow in one
embodiment of a reverse bypass valve.
[0014] FIG. 7C illustrates a modified embodiment of the reverse
bypass valve.
[0015] FIGS. 8A and 8B illustrate one embodiment of a treating
sleeve.
[0016] FIG. 9 illustrates one embodiment of a screen wrapped
monitoring sleeve.
[0017] FIGS. 10A and 10B illustrate one embodiment of a
hydraulically set packer.
[0018] FIG. 11 illustrates a partial cross-section of one
embodiment of a mechanically locked PAC valve.
[0019] FIGS. 12A to 12D illustrate the operating sequence of the
valve of FIG. 1.
[0020] FIGS. 13A to 13D illustrate the operation sequence of one
embodiment of a re-crippling device.
IV. DETAILED DESCRIPTION OF SELECTED EMBODIMENTS
[0021] One aspect of the present invention contemplates a well
completion system having a completion assembly and a service tool
positioned within the completion assembly. The service tool
includes a substantially straight bore central passage from an
upper end of the service tool to a lower end of the service tool.
Additionally, a one-way valve is positioned in an assembly annulus
formed between the service tool and an inner surface of the
completion assembly.
[0022] FIGS. 1A to 1C illustrate one embodiment of the completion
assembly 2. The completion assembly is a "multi-zone assembly" in
that it designed to isolate different sections of the wellbore
between packers, which normally will correspond to different
production zones identified in the oil/gas formation being
produced. For example, FIG. 1A illustrates an upper zone ("Zone A")
between sealbore packer 4 and isolation packer 46A and a lower zone
("Zone B") between isolation packers 46A and hydraulically set
packer 46B shown in FIG. 1B. Naturally, the number of zones can be
many more than two depending on the particular formation being
produced.
[0023] As used in this disclosure, "up" means the direction along
the wellbore toward the surface and "down" means in the direction
toward the toe of the wellbore. Because the wellbore may often be
deviated or horizontal, "up" or "down" should not be assumed to be
in the vertical direction or to even have a vertical component.
Likewise, describing a first tool component as "above" or "below" a
second tool component means the first tool component is closer to
or further from the surface, respectively, along the wellbore path
(when the tool assembly is positioned in the wellbore) than the
second tool component.
[0024] Viewing FIG. 1A, the upper end of the completion assembly 2
generally includes a retrievable sealbore packer 4, packer
extension 8, cross-over sub 9, collet de-activator 11 (sometimes
referred to as a collet "re-crippler"), auto-locator 15, and
non-rotational connector 19. Sealbore packer 4 may be any number of
different conventional or future developed packers, but in the
illustrated embodiment, it is a hydraulically set polished bore
packer with a single high pressure sealing element that serves as
the uppermost packer on the multi-zone completion system. This
packer includes bi-directional slips for tensile and compressive
loading and for simple external release and retrieval (although it
may also be provided with an optional internal release). This
packer may alternatively be used as a production sealbore packer
after sand control operations are completed. One specific example
of a suitable retrievable sealbore packer is the CompSet.TM. Packer
available from Superior Energy Services, LLC, Completion Services
division located in Houston, Tex. Of course, the sealbore packer 4
need not be a retrievable packer in all embodiments, but could be
permanent packer or possibly any other class of packer that can
function as required. Packer extension 8 is generally a section of
pipe that is made up to the bottom of the retrievable sealbore
packer and provides the necessary spacing distance for isolation
seals to be run during production. Crossover sub 9 is a
conventional device which connects the packer to lower components,
including ultimately a sealbore associated with the packer's
operation. Collet de-activator 11 will function as a device to
"de-activate" a sleeve opening (or closing) tool or profile in
order that the opening tool will not open any further sleeves or
valves while moving through the completion assembly in the
deactivated state. Preferably, the collet de-activator is
constructed to leave a fully open ID after it has deactivated the
opening tool.
[0025] The auto-locator 15 may be any conventional auto-location
assembly which interacts with profiles on a service tool to
positively identify the position of the service tool in the
completion assembly 2. A preferred embodiment of the auto-locator
serves to locate the service tool positions by using an inward
facing indicating collet tied into an auto J indexing mechanism.
This embodiment will include three basic positions: 1) the pick-up
position which occurs when the collet is pulled to the top of its
travel, 2) the set down position, which occurs when the J is at the
bottom of its travel, and 3) the run through position which occurs
when the J is in an intermediate position. The auto-locator is
actuated by up and down movement of an auto-locater profile (on the
service tool) through the auto-locater collet. The auto-locater
collet moves to the pick-up position with upward movement through
the collet, to the run through position. The "run through position"
allows the auto-locator profile on the service tool to pass the
through the auto-locator collet. The next upward movement shifts
the collet back to the pick-up position, with the following
downward movement placing the collet in the set down position.
Repeated up and down movements of the profile through the collet
will continue to cycle the collet from the set down to the run
through positions. In the set down position, the profile is latched
into the collet and supported to take set down loads to offset work
string movement during treatments. The run through position allows
the profile on the service tool to pass through the auto-locator
collet with a snap indication. Normally, after performing the
intended well treatment, a lockout sleeve locks out the indicating
collet leaving a large ID. One example of an acceptable
auto-locator is disclosed in U.S. Pat. No. 7,490,669 which is
incorporated by reference herein in its entirety.
[0026] While the embodiment illustrated in the Figures has a single
auto-locator collet near the top of the completion assembly and
multiple auto-locator profiles on the service tool, this is merely
one alternative. Other embodiments of the invention could have a
single auto-locator profile on the service tool and multiple
auto-locator collets in the completion assembly (e.g., an
auto-locator in each zone of the completion assembly). Still
further embodiments might position the auto-locator collet on the
service tool and auto-locator profiles in different zones of the
completion assembly. All such variations are within the scope of
the present invention.
[0027] Non-rotational connector 19 is a conventional assembly that
allows connection of tubular components without threads and
relative rotation of the components. Non-rotational connectors
enable more efficient makeup of the retrievable sealbore packer
(and other components) and reduces failure risks associated with a
long heavy assembly make-up in the rotary table. The completion
assembly make up may be accomplished without assembly rotation and
may be secured by rotating a retainer nut. Connector 19
incorporates a spline to ensure engagement and to allow locked
rotation across the connector assembly after make-up.
[0028] The additional components of the completion assembly 2 seen
in FIG. 1A include screen wrapped monitoring sleeve 20, sealbore
sub 26, treating (or frac) sleeve 30, hydraulically activated shear
sub 36, screen wrapped pressure activated control (PAC) valve 40,
and testable isolation packer 46A. In the embodiment of FIG. 1A,
the components between retrievable sealbore packer 4 and isolation
packer 46A form "Zone A" or the upper most zone of the completion
assembly 2. It will be understood that not all the above identified
components will be repeated in each zone. For example, the next
lower zone, "Zone B" in FIG. 1B, includes the monitoring sleeve 20,
sealbore sub 26, treating sleeve 30, hydraulically activated shear
sub 36, and screen wrapped PAC valve 40, but Zone B does not
include collect de-activator 11 or auto-locator 15.
[0029] The screen wrapped monitoring sleeves 20 are shown in more
detail in FIG. 9. This embodiment of monitoring sleeve 20 comprises
a sleeve member 21 with a sleeve ports 22 formed therethrough and
an opening/closing profile 24 formed on sleeve member 21. Exterior
monitoring ports 23 are formed through the main body of monitoring
sleeve 20. It can be seen that when sleeve member 21 is in the
raised position, it covers exterior monitoring ports 23 and blocks
the flow of fluid through ports 23. When a suitable opening profile
(e.g., on a service tool) engages sleeve member 23 and moves it to
the downward position, the sleeve ports 22 and the monitoring ports
23 are aligned to allow fluid flow from the exterior of the
completion assembly to the interior. In certain embodiments, a
screen 25 is formed around the outside monitoring ports 23.
Although not shown in the drawings, in other embodiments, a second
screen material may be positioned internally to monitoring ports 23
(e.g., in addition to the exterior screen 25).
[0030] In one preferred embodiment, the monitoring sleeve 20 is a
Type O sliding sleeve designed (i.e., downward movement to open the
sleeve and upward movement to close the sleeve), which in a
multi-zone completion system allows monitoring of a dead string
while treating the zone by reading annulus pressure. Also, closing
the sleeve prior to treating allows treatments to be performed in
the squeeze position. This embodiment of the sleeve valve may
include a high performance equalizing seal, which allows
communication control between the tubing and annulus. An internal
screen filtering section may be incorporated to prevent treating
proppant from entering into the sleeve sealing areas and allows the
valve to be opened and closed multiple times without loss of seal
integrity. This preferred embodiment further includes an inside
shifting profile which is approximately equal to the treating
sleeve internal diameter in order to allow optimal ID clearances
for service tool operations.
[0031] As used herein, the term "sleeve" may be used to indicate a
sleeve assembly such as described above which includes a sleeve
member which can selectively cover and uncover a port to allow
fluid flow through the port. This sleeve assembly may also be
referred to as a valve (e.g., a sliding sleeve valve) since the
sleeve assembly functions to open and close a fluid flow
passage.
[0032] The illustrated embodiment of treating sleeve 30 seen in
FIGS. 8A and 8B is similar in operation to monitoring sleeve 20.
Treating sleeve 30 includes sleeve member 31, sleeve port 32, and
opening/closing profile 34 which will provide a positive latching
shifting profile for full open and full closed shifting engagement.
Downward movement of sleeve member 31 aligns sleeve port 32 with
the exterior treating port 33 to move the sleeve assembly into the
"open" position as suggested in FIG. 8B. Treating sleeve 30 differs
from monitoring sleeve 20 in that the former lacks a screen which
would prevent the transfer of granular materials used in many
treating fluids (e.g., gravel being transported through treating
port 33 to the exterior of the completion assembly during gravel
packing operations). Typically, the treating ports 33 will be
larger than monitoring ports 23 and the other components of
treating sleeve 30 are constructed more robustly due to the severe
abrasive forces normally encountered at and around treating sleeve
30.
[0033] In general, the treating sleeve assembly provides an
isolation sleeve which can be opened to provide treating ports for
high pump rates and large volumes of proppant while minimizing
erosion on the treating sleeve assembly, service tool, and casing.
The length of the treating sleeve should permit it to be opened and
remain opened while manipulating the service tool (e.g.,
upwards/downwards movement to establish the auto-locator set-down
position). Too short of a sleeve length increases the possibility
of a tool profile unintentionally engaging and moving the sleeve
from its fully open position.
[0034] From the above description, it will be recognized that
monitoring sleeve 20 and treating sleeve 30 operate on the
"down-to-open", "up-to-close" convention. While this is often
preferred, other embodiments could operate under the opposite
convention.
[0035] Although not specifically shown in the drawings, the
completion assembly 2 may also contain one or more sections of
centralizer blank pipe. These are essentially sections of pipe that
are made up above the screen joint and provide annular clearance
and volume space for proppant pumping operations. Centralizer blank
pipe may also be used to adjust the spacing distance of the
isolation packers that are positioned between sand control
intervals.
[0036] The hydraulically activated shear subs 36 will operate to
provide a release point for all components in the string below
shear sub 36 when certain conditions occur. In a preferred
embodiment, this shear sub contains a hydraulic release mechanism
which is utilized to carry the full load of the assembly into the
wellbore. This prevents the load from being carried by the shear
joint shear screws, thereby allowing long, heavy assemblies to be
run without fear of premature release. The hydraulic actuation
feature is initiated by applying a sufficient tubing-to-annulus
differential pressure. Once actuated, the load is relieved from the
hydraulic locking mechanism and transferred to the shear screws. A
preferred embodiment of the shear joint allows up to 24'' of travel
prior to seal release. One example of such a hydraulically
activated shear sub is seen in U.S. Pat. No. 7,490,669. The
hydraulically activated shear subs 36 also allow for staged removal
of packers and screen assemblies if needed.
[0037] The screen wrapped PAC valves 40 may be any number of
conventional or future develop valves, whether sliding sleeve
valves or other valve types. In a preferred embodiment, valves 40
comprise a screen joint incorporating a PAC valve with a lock out
mechanism. The screen joints may be wire wrap (or mesh type) sand
exclusion screens designed to be used in high-rate water packs
(HRWP), fracturing and open-hole environments. These joints allow
easy spacing for either short or long intervals within a multi-zone
completions system. The screen joints may also be incorporated with
a special high rib design to provide strength and optimize flow
area under the screen wrap. The base pipe is preferably
non-perforated with the PAC valve(s) positioned as needed. In this
embodiment of the valves 40, actuation is initiated by first
running a mechanical unlocking tool through the valve to unlock the
sleeve, and then applying differential pressure from valve ID to
OD. The mechanical unlocking tool may be a separate profile (i.e.,
a profile that will not shift the monitoring and treating sleeves)
which is positioned on the service tool. Alternatively this
separate profile may be positioned on a different production tool
employed in later stages of production. Initial actuation pressure
further activates the valves for opening while maintaining pressure
integrity. Reducing the actuation pressure to equal the annular
pressure then allows the valve to cycle to the full open
position.
[0038] This PAC valve actuation method allows multiple valves to be
used and opened in the same interval. These preferred valves
provide complete isolation of the productive interval during all
phases of completion operations; require no well intervention to be
actuated for production operations; and provide a full open-flow
path through the screen-base pipe assembly. As a contingency, the
valves can be opened mechanically with wireline or colleted type
shifting tools. In preferred embodiments, the valves 40 are of the
type which unlocked mechanically and then may be hydraulically
activated. Nevertheless, it is not necessary for all embodiments of
valves 40 to be mechanically unlocked and then pressure activated.
For example, the valves 40 could alternatively be purely
mechanically activated (i.e., both unlocked and opened
mechanically) or purely pressure activated, Although generally
preferred, it may not be necessary in all embodiments for the
valves to be "lockable."
[0039] FIGS. 11 and 12 illustrate one embodiment of a mechanically
unlocked and hydraulically activated PAC valve. FIG. 11 illustrates
the main body of PAC valve 40 which has female and male
end-connectors allowing the PAC valve 40 to be made up as part of
completion assembly 2. The main body or housing of this embodiment
of PAC valve 40 generally comprises the top sub 175, spring housing
176, spring retainer 180, ported outer housing 185, and bottom sub
187. Positioned within this main housing is spring sleeve 178 which
is able to move up and down relative to spring retainer 180 along
the main longitudinal axis of the tool. The spring sleeve retainer
177 is positioned on top of spring sleeve 178 with a biasing
device, e.g., spring 179, positioned between the spring sleeve
retainer 177 and spring retainer 180. It can be seen from FIG. 11
that spring 179 will tend to bias sleeve 178 in an upward
direction, which as explained below, will tend to bias the valve in
an open position. The lower end of spring sleeve 178 will connect
to lower piston (also sometimes referred to as "lower sleeve") 183.
In FIG. 11, lower piston 183 is shown blocking flow ports 186,
i.e., the valve is in the closed position. However, it should be
readily apparent that when spring sleeve 178 and lower piston 183
move upward, flow ports 186 become unblocked and the valve will
then be in the open position. FIG. 11 also shows how lower piston
183 has the piston shoulder or surface 184 and the lower part of
spring sleeve 178 includes the fluid aperture 182. It may be
envisioned how fluid pressure applied in the central passage of
valve 40 translates through fluid aperture 182 and acts on piston
surface 184, tending to move lower piston 183 in a downward
direction. Finally, FIG. 11 shows a lock/release mechanism 190
which initially locks lower piston 183 in the valve closed position
and upon a series of operations, releases lower piston 183 into the
valve open position.
[0040] The structure and operation of lock/release mechanism 190 is
shown in more detail in FIGS. 12A to 12D. FIG. 12A illustrates the
lock/release mechanism 190 generally comprising lock ring (split
ring) 191, locking piston 194, locking sleeve 195, and lock collet
199 (see FIG. 12B). Locking piston 194 is shown with an
equalization aperture 206 to prevent differential fluid pressure
from developing between its inner and outer surfaces. In FIG. 12A,
lock ring 191 is shown disposed in the ring groove 192 (more
clearly seen in FIG. 12D) formed on the end of lower piston 183. It
can be seen that while lock ring 191 is disposed in ring groove
192, lower piston 183 cannot move upward (leftward in FIGS. 2A-2D)
since lock ring 191 will encounter and be restrained by the upper
ledge 210 (again more clearly seen in FIG. 2D). Likewise, lower
piston 183 cannot move downward (rightward in FIGS. 2A-2D) because
it abuts against locking piston 194 which is in turn held in place
by locking sleeve 195. The locking collet 199 is attached to a
guide pin 200 which rides in guide slot 201 (see FIG. 2B) formed on
an outer surface of locking sleeve 195. Locking collet 199 may
shift between two positions where it engages either collet groove
202A or 202B which are formed on an inner surface of the bottom sub
extension 188. In FIG. 12A, it can be seen that locking collet 199
engages collet groove 202A. Additionally, the locking shoulder 198
on sleeve extension 197 of locking sleeve 195 acts to hold locking
collet 199 in collet groove 202A. Additionally, FIG. 12A shows a
shear pin 205A positioned between locking piston 194 and sleeve
extension 188 and shear pin 205B position between locking sleeve
195 and sleeve extension 188. Immediately above FIGS. 2A-2D is a
schematic representation of guide slot 201 and guide pin 200's
relative position therein. It will be understood that in FIG. 12A,
the lock/release mechanism 190 is in the mechanically locked
position.
[0041] To begin the process of unlocking lock/release mechanism
190, a conventional tool with opening collet (not shown) may be
conveyed downhole to PAC valve 40 via coil tubing or another
conventional means for mechanically manipulating tools within a
wellbore. The opening tool will engage the profile 196 on locking
sleeve 195 and apply sufficient downward force to fail shear pin
205B and move locking sleeve 195 downward (i.e., toward the right
in the figures) until locking sleeve threads 208 engage the bottom
sub threads 209 as suggested in FIG. 12B. As is well known in the
art, the locking sleeve threads 208 and bottom sub threads 209 may
have inclined surfaces in one direction which facilitate engagement
of the threads, but resists disengagement. Because guide slot 201
allows initial rightward movement of locking sleeve 195 without
immediately engaging guide pin 200, the locking shoulder 198 is
removed from its supporting position under locking collet 199 prior
to locking collet 199 being force rightward. However, continued
rightward movement of locking sleeve 195 eventually pulls locking
collet out of its position in collet groove 201A and moves it to
collet groove 201B as suggested in FIG. 12B.
[0042] Next in the opening sequence, fluid pressure is applied to
the central passage of valve 40. As suggested in FIG. 11, this
fluid pressure is communicated through aperture 182 and acts on
piston surface 184 and causes lower piston 183 to move to the right
in FIG. 2C. With sufficient fluid pressure, the force which lower
piston 183 places against locking piston 194 fails shear pin 205A
and locking piston 194 moves rightward until its front lip
encounters the end of bottom sub extension 188. Importantly, as
lower piston 183 moves rightward, it pushes locking ring 191
rightward. Because locking ring 191 is a spring steel split ring
configuration, as locking ring 191 encounters the wider outer
shoulder area 193 (see FIG. 12B), the locking ring 191 expands out
of ring groove 192 and completely removes itself from the path of
lower piston 183 as seen in FIG. 12C.
[0043] Now, when the pressure in the valve central passage is
relieved and downward force from piston surface 184 is removed,
spring 179 will tend to force lower piston 183 upward (leftward in
FIG. 12D). Since locking ring 191 no longer obstructs movement of
lower piston 183, the lower piston will move upward to a point
where it uncovers flow ports 186. The valve 40 is now in the open
position.
[0044] In the illustrated embodiment, testable isolation packer 46A
is dual element packer with a self-contained setting tool having
bi-directional slips. The setting tool is integrated between the
two elements and is actuated with tubing pressure through the ID of
the packer mandrel. The isolation packer contains a rupture disc
which is actuated by applying pressure greater than the required
packer setting pressure. Once the disc is ruptured, pressure is
applied between the two elements of the packer and the casing ID
giving a positive indication of packer setting. This packer may be
retrieved by a straight upward pull by a conventional retrieval
tool. While many other conventional or future developed packer
systems could be utilized, one acceptable isolation packer is the
ComPlete.TM. MST System Isolation Packer available from the
Completion Services division of Superior Energy Services, LLC
located in Houston, Tex. While the above described embodiment
employs a "testable" isolation packer, it will be obvious that
alternative embodiments could employ a non-testable type of packer.
Likewise, many conventional in-string packers with bidirectional
slips could also be employed.
[0045] FIG. 1B illustrates the lower production zone ("Zone B" in
FIG. 1B) which below the upper isolation packer 46A, includes
several of the components described in reference to Zone A, i.e.,
screen wrapped monitoring sleeve 20, sealbore sub 26, treating
sleeve 30, hydraulically activated shear sub 36, and screen wrapped
PAC valve 40. Zone B terminates with the lower hydraulic set packer
46B. This packer is a single element packer with a self-contained
setting tool that has bi-directional slips. The hydraulic set
packer will typically be used as the lowermost or sump packer for
the multi-zone system but can alternately be used as an isolation
packer between zones. Running the hydraulic set packer as the sump
packer on the system has the advantage of eliminating a wireline
trip and a subsequent debris cleanout trip. This packer's setting
tool chamber is integrated into the packer and is actuated with
tubing pressure through the ID of the packer mandrel. This packer
is also retrievable by straight upward pull.
[0046] Although FIGS. 1A-1C show only two zones, it will be readily
understood that any number of zones could be added to the
completion assembly 2 by repeating a similar series of components
for each additional zone.
[0047] Below the lowest zone, completion assembly 2 comprises
several further components. These include a sealbore sub 26, a
hydraulic tubing release 50, a scrapper 54, a collet activator 58,
a test assembly 64, and a fixed ball seat 70. Generally, the
sealbore subs are internally honed, reduced inner diameter,
sections of pipe that provide a seal with the reverse bypass tool
(explained below) when the latter is positioned within the sealbore
subs. However, the sealbore subs can also be utilized to isolate a
treating sleeve in the event that concentrically run production
seals are traversed across the section. The lower sealbore sub 26
seen in FIG. 1C does not necessarily interact with the service
tool, but is present to seal with a production string inserted into
the wellbore in later stages. The hydraulic tubing release 50 will
release the tubing below it and allow the lower components to fall
away when no longer needed. In particular, activating tubing
release 50 is one manner of opening the end of completion assembly
2 after a ball seat 70 has been effectively sealed by the setting
of the ball. Scrapper 54 may be any conventional or future
developed scrapper device, including those using blades, brushes,
and/or others means for scrapping sand, perforation/gun debris or
other debris from the interior of the casing as the completion
assembly is run in. One example of an acceptable scrapper is an
M&M Casing Scraper available from M&M Oil Tools, Inc., of
New Iberia, La.
[0048] Collet activator 58 is one example of an activating
mechanism employed to activate a de-activated opening tool and is
described in more detail below in reference to the opening tool on
service tool 100. The test assembly 64 is a tubular sub on the end
of completion assembly 2 which includes the breakable plate 68
positioned across the inner diameter to form a seal and allow fluid
to be pressurized (for leak integrity testing purposes) above
breakable plate 68. Test assembly 64 also includes a one-way valve
64 which allows fluid from the wellbore into the test assembly, but
prevents the exiting of fluid and thereby allows pressurization to
occur. In the illustrated embodiment, one-way valve 67 is a rubber
bladder covering a series of apertures in the test assembly body.
Higher pressure outside the test assembly tends to push the bladder
aside and allow fluid inflow. Higher pressure inside the test
assembly tends to press the bladder against the apertures and block
fluid outflow. One example of such a valve is seen in FIG. 14 of
U.S. Pat. No. 7,490,669. The terminal end of the completion
assembly 2 includes a conventional ball seat 70 which will create a
seal when a ball of suitable size is dropped from the surface and
migrates through the completion assembly onto seat 70.
[0049] A second main component of the completion system is a
service tool which will be inserted into completion assembly 2 to
perform various tasks. FIGS. 2A-2D illustrate one embodiment of a
service tool 100 positioned in completion assembly 2. FIGS. 2A-2D
suggest how service tool 100 is positioned in the completion system
when it is being deployed into the wellbore and ultimately the
formation of interest. FIGS. 2A-2D also illustrate completion
system 1 within the well casing 150 which forms a casing annulus
152 between the inner wall of the casing 150 and the outer surface
of the completion assembly 2. FIG. 2A illustrates how the uppermost
section of service tool 100 includes the sealbore packer setting
tool 102 which is connected to the main tubular body portion 101 of
the service tool. One function of setting tool 102 is to set
retrievable sealbore packer 4. Setting tool 102 will also engage
and releasably lock into the completion assembly 2, thereby
supporting the completion assembly 2 both as it is assembled near
the surface (described below) and as it is lowered downhole to the
formation of interest. A seal on the bottom of the setting tool
seals against the packer sealbore to allow testing of the packer
once it is set. The setting tool chamber is actuated with tubing
pressure. Once the packer is fully set, applying additional tubing
pressure releases the retrievable sealbore packer setting tool from
the packer (i.e., releases the service tool from the completion
assembly).
[0050] FIG. 2A further illustrates how setting tool 102 is also
connected to work string 160, which in turn forms the connection of
the completion system to the surface. As used herein, "work string"
is a generic term describing a tubular member string used to convey
fluids or for well service activities. Both coiled and jointed
tubular strings may be referred to as work strings. In additional
to the casing annulus 152, two other spaces extending along the
length of the completion system are seen in FIG. 2A; i.e., the
service tool's central passage 114 and the completion annulus 75
formed between the outer surface of service tool 100 and the inner
surface of completion assembly 2.
[0051] Viewing FIGS. 2A to 2D, it can be seen how in this
embodiment the tubular body 101 of service tool 100 extends
downward through however many completion zones have been created
along the length of completion assembly 2. Various tools or
functional elements may be positioned along the length of service
tool 110. For example, FIGS. 2B and 2C show auto-locator profiles
105 at predetermined positions along service tool 100. As described
in U.S. Pat. No. 7,490,669, when different auto-locator profiles
105 engage auto-locator 15 on the completion assembly 2, this
positively identifies the position of the service tool relative to
various positions within completion assembly 2 and insures the
proper alignment of the respective components of service tool 100
and completion assembly 2 in order to carry out many of the
functions described below. In particular, auto-locator profiles may
be used to locate the position of the reverse bypass valve and to
keep the reverse bypass valve aligned while at the same time
applying set down weight during treating operations.
[0052] Additional components positioned toward the lower end of
service tool 100 are seen in FIG. 2D. For example, in the
embodiment of FIG. 2D, the terminal end of service tool 100
includes the conventional mule shoe 131, which among other
functions, provides a means of breaking a sand bridge while
washing. Positioned above mule shoe 131 is the opening shifting
tool (or collet) 124, which when activated, will open the above
described treating and monitoring sleeves on completion assembly 2.
In one particular embodiment, a multi-acting shifting tool ("MST")
125 may be employed. This MST tool 125 has a first sleeve opening
profile, and then positioned above this opening profile, MST tool
125 has a second closing profile. The distance between these
profiles is not critical so long as the opening and closing
profiles are not so closely spaced that up and down service tool
movement in operating the auto-locator causes profiles to
unintentionally engage sleeves. One example of the MST may consist
of an internal integrity member known as the inner mandrel. Outer
components consist of 1) a collet and 2) end caps that make up to
the collet and control its travel. The MST is collapsed during
deployment and activated upon contacting the collet activator. The
MST is constructed to engage on the two service sleeves; i.e., the
treating and annular monitoring sleeves. Engagement in the down
direction opens either sleeve as engagement in the up direction
closes either sleeve. The shifting tool is deactivated once all
zonal treatments are completed by engaging into the de-activator or
re-crippler mechanism.
[0053] Also shown in the embodiment of FIG. 2D is a closing only
profile 109 positioned still further above opening profile 124 (or
MST tool 125). The closing only profile 109 may be advantageous in
particular situations, for example an opening tool unintentionally
becoming activated (e.g., on the services tool's initial run-in)
and opening sleeves when not desired. One example of an acceptable
activatable opening profile is suggested in FIG. 11c of U.S. Pat.
No. 7,490,669 while an example of a closing profile is seen in FIG.
10b of U.S. Pat. No. 7,490,669.
[0054] FIG. 2D further illustrates schematically a reverse bypass
valve 115 positioned between opening profile 124 and the closing
profile 109. This embodiment of reverse bypass valve 115 is
essentially a one-way valve placed on the outer surface of service
tool 100 and within the completion annulus 75. When positioned
within a sealbore sub 26, reverse bypass valve 115 allows fluid in
completion annulus 75 to flow in a downhole direction through
bypass valve 115, but prevents flow in the uphole direction through
the valve 115.
[0055] One example of reverse bypass valve 115 is seen in FIGS. 7A
and 7B. A substantially tubular valve body 116 will have a series
of circumferentially positioned apertures 118 formed therein. Valve
body 116 will also have an outer circumferential seal 120 (e.g.,
molded Viton) which is intended to engage the inner surface 27 of a
sealbore sub 26 (illustrated in FIG. 2D) to form a seal against
sealbore inner surface 27. Additionally, the flexible seal material
119 will be positioned interiorly of apertures 118. As suggested by
flow arrows in FIG. 7A, fluid flowing in the downhole direction in
the completion annulus 75 will flow through apertures 118, move
flexible seal 119 away from apertures 118, flow into the valve
body's interior space 121, and then exit the valve along the
valve's downstream path 122 and continue along the completion
annulus below bypass valve 115. In essence, the concentric flow
path through the tubular body transitions from an outer surface of
the valve body (upstream path 117) to an inner surface of the body
(space 121), and back to the outer surface of the tubular body
(downstream path 122). However, when fluid attempts to flow in the
uphole direction as suggested in FIG. 7B, the fluid pushes the
flexible seal 119 against apertures 118 and thereby blocks the flow
path through valve body 116. It will be understood that reverse
bypass valve 115 forms a one-way valve only when it is engaging a
sealbore sub 26. When valve 115 is positioned above or below a
sealbore sub 26, fluid can flow in either direction around the
outside of the entire valve, i.e., between inner wall of the
completion assembly 2 and the outside of outer circumferential seal
120.
[0056] There may be circumstances where very high pressures occur
below the particular sealbore sub 26 being engaged by the
circumferential seal 120 and such high pressures may be sufficient
to force reverse bypass valve 115 to move upward. The embodiment of
FIG. 7C illustrates a hold down assembly 165 to resist such
unintentional upward movement of valve 115. Hold down assembly 165
generally comprises a body or mandrel 166, and a collet 167 (in
this example, a basket collet). Collet 167 includes a collet finger
168 sized to engage a collet groove 169 formed on the inside wall
of the sealbore sub 26. Positioned within mandrel 166 directly
below collet finger 168 is a piston member 170. When fluid pressure
increases sufficiently in cavity 171, piston member 170 will press
against collet finger 168 and move collet finger 168 into
engagement with collet groove 169, thus locking or "holding down"
reverse bypass valve 115 against upward movement. When pressure
decreases sufficiently, collet finger 168 flexes back to its
original position, out of engagement with collet groove 169, and
valve 115 is free to be moved out of engagement with sealbore sub
26. Those skilled in the art will recognize many variations of hold
down assembly 165 could be constructed to perform the function
described above. While FIG. 7C illustrates one collet groove 169,
other embodiments may have multiple collet grooves spaced together
in order that collet finger 168 has multiple points of potential
engagement.
[0057] The completion system will typically be initially assembled
by making up the individual components forming a separate
completion zone and as each successive zonal assembly is made up,
the completion assembly is hung off the rig floor and pressure
tested for integrity. The first or lowest zone will include the
components seen in FIG. 1C forming the lower end of the completion
assembly; e.g., hydraulic tubing release 50, scrapper 54, collet
activator 58, test assembly 64, and fixed ball seat 70. The lowest
zone will also include components typically found in all successive
zones; e.g., a lower packer 46B, production (or PAC) valves/sleeves
40, shear sub 36, one or more sealbore subs 26, treating sleeve(s)
30, monitoring sleeve(s) 20, and an upper packer 46A. Of course,
successive production zones may comprise components different that
than the first production zone, as required by the particulars of
the well and different production zones.
[0058] Typically, as each zone of components is made up, the
completion assembly thus far connected is filled with fluid and the
assembly is tested for leaks with a low volume test pump; e.g., by
pressuring up to 500 psi for 5 minutes. The final or uppermost
completion zone assembly may include certain components located at
the upper end of completion assembly 2; e.g., in the embodiment of
FIG. 1A, the non-rotational 19, auto-locator 15, collet deactivator
11, and retrievable sealbore packer 4. As suggested above, many
variations could be made from the assembly shown in the figures,
for example, an auto-locator could be position in each zone rather
than a single auto-locator in the uppermost zone.
[0059] Next, service tool 100 will be made up, with components
positioned on the lower end of service tool 100 first being
connected as suggested by the embodiment of FIG. 2D; e.g., mule
shoe 131, opening tool profile 124 (or MST 125), reverse bypass
valve 115, closing tool profile 109, and various auto-locator
profiles 105. The service tool 100 is gradually inserted further
into completion assembly 2 as further segments of service tool 100
are made up. Similar to testing the completion assembly, service
tool 100 may be tested for pressure integrity as it is made up (if
the reverse bypass valve is engaging a sealbore). Once service tool
100 has been extended into completion assembly 2 to its full
operating length, the entire completion system may be pressure
tested. Although the opening tool profile 124 on service tool 100
should be de-activated at this point, pressure testing confirms no
valves/sleeves were inadvertently opened while running in service
tool 100.
[0060] After all pressure integrity testing has been completed, the
completion system is made ready running into the formation area of
the wellbore. This combine completion assembly and service tool
being running to the wellbore may sometimes be referred to as the
integrated completion assembly. The service tool is temporarily
extended further into completion assembly 2 (i.e., by adding
addition lengths of tubing) such that mule shoe 131 ruptures
breakable seal plate 68 and opening tool profile 124 is brought
into engagement with the activating mechanism (e.g., collet
activator 58) in order to activate the opening tool profile such
that it will now engage sleeves as it moves past. Service tool 100
is then positioned at its lowermost run in position within
completion assembly 2 and sealbore packer setting tool 102 engages
and locks into the top of completion assembly 2 as seen in FIG. 2A.
With sealbore packer setting tool 102 supporting completion
assembly 2, the entire completion system may be run in to its final
depth on work string 160.
[0061] Typically, the straight central passage of the service tool
100 is open and unobstructed at the time the completion assembly is
run into the wellbore. However, there may be specialized
embodiments where the central passage of the service tool initially
has some mechanism for closing or blocking the service tool's
central passage during run-in and that mechanism is opened or
removed before the start of operations with the completion
assembly.
[0062] One aspect of the present invention is a method of washing
out a the wellbore while running in the completion system 1. The
well may contain debris from various earlier activities, including
perforating the casing with perforating guns. The scrapper 54 on
completion assembly 2 will tend to push such debris below the
completion system as it is run downhole. However, it may often be
advantageous to wash such debris completely out of the wellbore as
the completion system is run in. This operation also acts to remove
gas or liquid hydrocarbons from the wellbore prior to setting the
packers. As seen in FIGS. 2A-2D, the packers are not set at this
stage. Therefore, fluid pumped down the casing annulus 152 will
circulate down the annulus, around completion assembly 2 (the
sealbore packer setting tool seen in FIG. 2A prevents fluid from
entering the completion annulus 75), and back into the completion
assembly 2 via unblocked ball seat 70, and ultimately back into the
central passage 114 of service tool 100 (as suggested by the flow
arrows in FIG. 2D) for eventual return to the surface through work
string 160. If the service tool 100 is positioned with reverse
bypass valve 115 within a sealbore sub 26, the uni-directional flow
character of bypass valve 115 will block return fluid from
travelling by up the completion annulus 75. However, even if bypass
valve 115 is not positioned in a sealbore sub 26, typically the
completion annulus 75 will already be filled with completion fluid
which will prevent circulating fluid from entering completion
annulus 75.
[0063] This "reverse washing" process being performed as the
completion system 1 is lowered to its final position in the
wellbore allows a debris removing washing operation to be carried
out with no addition use of other tools (i.e., additional trips
down hole) or by any special positioning/repositioning of the
completion system 1. Rather, this useful washing operation can be
carried out simultaneously with positioning the completion system
at its final depth. Nonlimiting examples of debris which may be
removed using this technique include pill remnants, gun debris, and
formation solids.
[0064] Another embodiment of the present invention is a method of
logging a wellbore which has the completion system 1 positioned in
the wellbore. This method employed before or after treatment. For
example, logging might be performed prior to setting the packers in
order to confirming the packer location. More typically, logging is
performed after treating a zone. With the completion system 1
positioned at depth, a logging tool on an e-line may be run down
the work string, through the service tool's straight bore central
passage and to the desired depth in the formation. In certain
circumstances, service tool 100 may be raised out of the zone which
is being logged, but this re-positioning of service tool 100 is not
always the case. It will be understood that the straight bore
nature of service tool 100 allows logging without the necessity of
removing service tool 100 from the wellbore. This may be
distinguished from prior art completion system where obstructions
in the service tool (e.g., cross-over valves) prevent the running
of logging tools directly through the service tool.
[0065] After the completion of any desired logging operations and
removal of the logging tool, the steps necessary to set the
completion system 1 in place within the formation may be
undertaken. As suggested in FIG. 3D, a ball will be dropped and
allowed to gravitate to fixed ball seat 70. Once the ball is in
place, pressure is applied through service tool 100 to increase the
pressure within the completion annulus 75. If the reverse bypass
tool is not engaging the sealbore at this time, pressure will be
increased along the entire length of the completion assembly. With
sufficient pressure, several pressure activated components will
change state. For example, the hydraulically set packers 46 will be
activated and set against the casing wall. The sealbore packer
setting tool 102 is likewise activated and releases service tool
100 from completion assembly 2.
[0066] The shear subs 36 are activated such that loads are now
supported by their shear pins. Once all other pressure activated
components change to their active state and desired pressure
testing performed (for example, pressure testing of uppermost and
lowermost packers), additional pressure may be applied to activate
hydraulic tubing release 50 and have all components below it fall
to the wellbore rathole. It will be understood that one immediate
effect of this release is to remove the closed end of the
completion assembly that had been formed by the ball lodged within
ball seat 70. Successful release of hydraulic tubing release 50 may
be confirmed at the surface by noting a pressure drop in
circulating fluid.
[0067] Once the completion system is in place with the packers set
and pressure tested, any number of completion (or other) operations
may be carried out. Various conventional and/or future developed
treating methods may be employed with completion system 1,
including stimulating (e.g., acidizing), high rate water packing,
frac packing, or gravel packing
[0068] While the above embodiments describe the use of the
auto-locator to determine the position of the service string within
the completion assembly, there may be instances where the
auto-locator malfunctions, or the completion system is an
alternative embodiment which does not incorporate an auto-locator.
In these examples, the treating position of the service string may
be determined "hydraulically" by first positioning the end of the
service string below the anticipated zone treating depth and
establishing forward circulation at a comparatively slow rate and
low pressure (e.g., <400 psi). The service tool is then slowly
raised at one foot intervals until returns stop and work string
pressure increases. At this point, it may be presumed that the
reverse bypass valve 115 has entered the first sealbore sub 26 in
that zone, e.g., the sealbore sub 26 below the treating sleeve 30
in FIG. 4B. This process may be repeated to locate the upper
sealbore sub 26 in that zone (not specifically shown in figures).
Likewise, when circulation is re-established and pressure drops
while raising the service tool, it may be presumed that the reverse
bypass valve 115 has cleared the upper sealbore sub 26. The opening
tool profile 124 is then run downward to engage and open monitoring
sleeve 20 and treating sleeve 30. Thereafter, service tool 100 is
raise such that its open end is positioned above the open treating
sleeve/port and the reverse bypass valve engages the upper sealbore
sub 26. It can be understood from FIG. 4B how the pressure in
casing annulus 152 (which is substantially the pressure against the
formation) is approximately the same as at the open monitoring
sleeve/port 20. The pressure in casing annulus 152 is transmitted
through monitoring sleeve 20, through the completion annulus, and
to the casing annulus above the uppermost completion packer where
the annulus pressure can be monitored on the surface. It can be
understood that without this pressure monitoring path, the packers
would prevent the direct translation of formation pressure to the
annulus area above the completion assembly.
[0069] It can also be understood from FIG. 4B that the completely,
downwardly open end of service tool 100 (i.e., no passage
deviations for directing treating fluids in a particular direction)
allows for the maximum volume of treating fluid to be pumped out of
the completion assembly while minimizing abrasion conditions that
occur when the fluid abruptly forced to change path directions (as
is typically the case in prior art treatment systems). In essence,
the treating fluid flow is directed substantially straight downhole
from the open end of service tool 100. This allows the treating
fluid to enter the all circumferentially positioned treating sleeve
ports at substantially equal flow rates and pressure.
[0070] When the treating operation has been completed in that zone,
the service tool 100 is lowered sufficiently to place a closing
tool profile beneath treating sleeve 30. Upon raising the closing
tool profile, first treating sleeve 30 and ultimately monitoring
sleeve 20 will be closed as the closing tool profile engages and
closes those sleeves. While the service tool 100 is being raised
during this closing movement, a reversing operation may take place
to remove the treating fluid as suggested in FIG. 5. The reversing
operation consists of pumping fluid down the completion annulus 75
such that such that it passes around the end of service tool 100
and flows back up the central passage of the service tool. It will
be understood that this reverse flow may continue regardless of
whether reverse bypass valve 115 is passing through a sealbore sub
26. When bypass valve 115 is not in a sealbore sub, fluid may
freely flow around bypass valve 115. When bypass valve 115 is in a
sealbore sub, the one-way nature of bypass valve 115 continues to
allow fluid flow downward through the valve body.
[0071] Each zone in the completion assembly 2 may be successively
treated and reversed out as just described. When treatment of the
uppermost zone is complete, it is often desirable to make a final
wash all the way down to the lowermost zone. However, it would not
be desirable to reopen all the closed sleeves as the opening
profile on the service tool moves downward. One method for avoiding
this undesirable effect is suggested in FIG. 6. Service tool 100 is
raised until its opening profile engages the deactivation mechanism
(e.g., collet de-activator 11) positioned near the upper end of
completion assembly 2. This action de-activates or re-cripples the
opening profile so it cannot engage and open sleeves (i.e., returns
the opening profile to its de-activated condition when initially
run into the completion assembly 2). With the opening profile
deactivated, service tool 100 may be run past the lowest zone while
continuously performing reverse washing operations.
[0072] The half cross-section views in FIGS. 13A to 13D illustrate
one embodiment of an opening tool de-activator or "re-crippler"
device 11. First viewing FIG. 13A, re-crippler 11 is shown having
an outer housing assembly 220 which, while not specifically
illustrated, will be understood to connect into the main body of
the completion assembly 2 at the position generally suggested in
FIG. 1A. The opening tool (carrying the opening tool profile 124
described above) will have a structure adapted to function with
this version of re-crippler 11. This opening tool includes an outer
sleeve 221 and inner sleeve 222. The outer sleeve 221 is initially
fixed to inner sleeve 222 by shear pin 223. Outer sleeve 221
includes the shoulder 243 on its inner surface, shoulder 239 on its
outer surface, and terminates with the hood section 225. Inner
sleeve 222 will be directly connected to service tool 100 (not
shown in FIG. 13A), thereby also indirectly connecting outer sleeve
221 to service tool 100 so long as shear pin 223 remains unsheared.
Inner sleeve 222 includes the collet collar 242 which is ultimately
attached to the opening profile collet 227. It will be understood
that opening profile collet 227 is a conventional collet assembly
which flexes outward (as shown in FIG. 13A) in its activated state
and may flex inward (as shown in FIG. 13C) to obtain its
de-activated state.
[0073] Positioned between outer sleeve 221 and housing assembly 220
is the re-crippling collet assembly 230. Re-crippling collet
assembly 230 includes upper collet section 232 and lower collect
section 231 which are joined by collet shear pin 233. Upper collet
section 232 include the collet fingers 236 and 237, while lower
collet section 231 includes outwardly facing profile 238 and
inwardly facing profile 234. The shear pin 235 initially connects
lower collet section 231 to housing assembly 220.
[0074] FIG. 13A illustrates the situation where the opening profile
collet 227 is flexed outward in the active state and service tool
100 has been raised to the point where the operator has detected
the load indication suggesting that opening profile member 227 has
engaged the lower collet profile 234. Next in FIG. 13B, the
operator has set down on service tool 100 with sufficient force to
fail shear pin 235 and drive collet profile 234 downward into
engagement with outer sleeve shoulder 240. It will be understood
that shear pins 223 and 233 have a greater load rating and have not
failed at this point. The lower collet profile 238 will shift
downward into the recess in outer housing assembly 220 adjacent to
outer body internal shoulder 241 and the upper collet finger 237
will shift downward to engage shoulder 239 on outer sleeve 221.
[0075] Next in FIG. 13C, upward force is pulled on service tool 100
sufficient to shear pin 233 (but still not sufficient to shear
collet release shear pin 235. The upward force is also sufficient
to disengage opening profile 227 from the lower collet profile 234.
Because collect profile 238 is retained against outer body internal
shoulder 241 and collet finger 237 engages outer sleeve shoulder
239, inner sleeve 222 continues to move upward with respect to the
now stationary outer sleeve 221. This will ultimately force opening
profile collet 227 against hood 225 and cause the opening profile
collet 227 to collapse under hood 225 into its de-activated
(crippled) state. Inner sleeve 221 will continue to move upward
until the collet collar 242 meets the outer sleeve shoulder 243. It
will be understood that shear pin 223 is designed to withstand
sufficient load that opening profile collet 227 can be forced under
hood 225 and forced into its de-activated position.
[0076] In the final operation suggested in FIG. 13D, further upward
force has been applied to inner sleeve 222 which is transferred to
outer sleeve 221 because of the abutment of collet collar 242 and
sleeve shoulder 243. Force sufficient to shear shear pin 225 is now
applied and upper collect section 232 is separated from lower
collet section 231 (which is still held in place by profile 238
engaging shoulder 241 on outer housing assembly 220). As upper
collet section 232 moves upward, its collet finger 237 transitions
back into recess 245. At this stage, opening collet profile 227 has
been re-crippled and all components of re-crippling collet 230 have
been moved out of the way to provide the same full inner diameter
for completion assembly 2 as existed prior to the start of the
re-crippling procedure. Service tool 100 will likewise now be able
to move up and down completion assembly 2 without the risk of
opening collet profile 227 inadvertently opening treatment sleeves
or activating other tools in the completion assembly.
* * * * *