U.S. patent application number 15/652750 was filed with the patent office on 2017-11-02 for tools and methods for use in completion of a wellbore.
The applicant listed for this patent is NCS MULTISTAGE, LLC. Invention is credited to Donald Getzlaf, Robert Nipper, Marty Stromquist, Timothy H. Willems.
Application Number | 20170314364 15/652750 |
Document ID | / |
Family ID | 44303582 |
Filed Date | 2017-11-02 |
United States Patent
Application |
20170314364 |
Kind Code |
A1 |
Getzlaf; Donald ; et
al. |
November 2, 2017 |
TOOLS AND METHODS FOR USE IN COMPLETION OF A WELLBORE
Abstract
A ported tubular is provided for use in casing a wellbore, to
permit selective access to the adjacent formation during completion
operations. A system and method for completing a wellbore using the
ported tubular are also provided. Ports within the wellbore casing
may be opened, isolated, or otherwise accessed to deliver treatment
to the formation through the ports.
Inventors: |
Getzlaf; Donald; (Calgary,
CA) ; Stromquist; Marty; (Calgary, CA) ;
Nipper; Robert; (Spring, TX) ; Willems; Timothy
H.; (Spring, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
NCS MULTISTAGE, LLC |
Calgary |
|
CA |
|
|
Family ID: |
44303582 |
Appl. No.: |
15/652750 |
Filed: |
July 18, 2017 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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14317975 |
Jun 27, 2014 |
9745826 |
|
|
15652750 |
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|
13100796 |
May 4, 2011 |
8794331 |
|
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14317975 |
|
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61394077 |
Oct 18, 2010 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 43/16 20130101;
E21B 34/10 20130101; E21B 34/063 20130101; E21B 33/127 20130101;
E21B 47/06 20130101; E21B 43/267 20130101; E21B 23/01 20130101;
E21B 34/12 20130101; E21B 2200/06 20200501; E21B 23/02 20130101;
E21B 34/08 20130101; E21B 43/25 20130101; E21B 17/20 20130101; E21B
33/12 20130101; E21B 33/134 20130101; E21B 43/12 20130101; E21B
34/14 20130101; E21B 33/129 20130101; E21B 43/00 20130101; E21B
43/26 20130101; E21B 17/1085 20130101; E21B 43/14 20130101; E21B
43/114 20130101; E21B 17/00 20130101 |
International
Class: |
E21B 34/12 20060101
E21B034/12; E21B 17/20 20060101 E21B017/20; E21B 23/01 20060101
E21B023/01; E21B 23/02 20060101 E21B023/02; E21B 33/12 20060101
E21B033/12; E21B 17/00 20060101 E21B017/00; E21B 43/25 20060101
E21B043/25; E21B 43/16 20060101 E21B043/16; E21B 43/14 20060101
E21B043/14; E21B 43/12 20060101 E21B043/12; E21B 43/114 20060101
E21B043/114; E21B 43/00 20060101 E21B043/00; E21B 34/14 20060101
E21B034/14; E21B 34/10 20060101 E21B034/10; E21B 34/08 20060101
E21B034/08; E21B 34/06 20060101 E21B034/06; E21B 33/134 20060101
E21B033/134; E21B 33/129 20060101 E21B033/129; E21B 47/06 20120101
E21B047/06 |
Claims
1. A method for delivering treatment fluid to a formation
intersected by a wellbore lined with tubing, the liner tubing
having at least a first ported segment and a second ported segment,
the method comprising the steps of: deploying a tool assembly
downhole in the lined wellbore on tubing string, the tool assembly
comprising an abrasive fluid perforation device and a sealing
member; locating the tool assembly at a depth generally
corresponding to the first ported segment; setting the sealing
member against the liner tubing below the first ported segment;
delivering treatment fluid to the first ported segment; unsetting
the sealing member from the liner tubing; locating the tool
assembly at a depth generally corresponding to the second ported
segment; resetting the sealing member against the liner tubing
below the second ported segment; and delivering treatment fluid to
the second ported segment.
2. The method recited in claim 1, wherein the step of locating the
tool assembly comprises the step of engaging a casing collar
locator on the tool assembly in at least one casing collar in the
liner tubing.
3. The method recited in claim 1, wherein the lateral openings are
ports provided in the liner tubing prior to lining the
wellbore.
4. The method recited in claim 1, wherein the tool assembly further
comprises a straddle isolation device comprising first and second
sealing members, and a treatment aperture between the first and
second sealing members, the treatment aperture continuous with the
tubing string for delivery of treatment fluid from the tubing
string to the formation through the port.
5. The method recited in claim 4, wherein the first and second
sealing members are inflatable sealing elements.
6. The method recited in claim 4, wherein the first and second
sealing members are compressible sealing elements.
7. The method recited in claim 4, wherein the first and second
sealing members are cup seals.
8. The method recited in claim 1, wherein the sealing member is
selected from the group consisting of mechanically-set packers,
inflatable packers, and bridge plugs.
9. The method recited in claim 1, wherein the first ported segment
comprises a closure over the lateral opening, and wherein the
method further comprises the step of moving the closure from over
the lateral opening.
10. The method recited in claim 9, wherein the closure comprises a
sleeve slidingly disposed within the tubular segment, and wherein
the method further comprises the step of sliding the sleeve to open
the lateral opening.
11. The method recited in claim 10, wherein the step of sliding the
sleeve comprises the application of hydraulic pressure to the
sleeve.
12. The method recited in claim 10, wherein the step of sliding the
sleeve comprises application of mechanical force to the sleeve by
the tool assembly.
13. The method recited in claim 10, wherein the step of sliding the
sleeve comprises application of mechanical force and hydraulic
pressure to the sleeve.
14. The method recited in claim 1, wherein the tubing string is
coiled tubing.
15. The method recited in claim 1, further comprising the step of
jetting perforations in the liner tubing.
16. The method recited in claim 15, wherein the step of jetting
perforations in the liner tubing comprises delivering abrasive
fluid through the tubing string to jet nozzles in the abrasive
fluid perforation device.
17. The method recited in claim 1, further comprising the steps of:
closing an equalization valve in the tool assembly to provide a
dead leg; and monitoring the bottom hole pressure while delivering
treatment fluid.
18. A method for hydraulically fracturing a formation intersected
by a wellbore comprising the steps of: lining the wellbore with
tubing, the liner tubing comprising at least one ported segment,
the ported segment having at least one lateral opening through the
liner tubing covered by a closure; deploying a tool assembly
downhole in the lined wellbore on tubing string, the tool assembly
comprising an abrasive fluid perforation device and a sealing
member; locating the tool assembly at a depth at which the sealing
member is adjacent the closure; setting the sealing member against
the closure; moving the closure by moving tool assembly; and,
delivering pressurized fluid to the ported segment.
19. A method for hydraulically fracturing a formation intersected
by a wellbore comprising the steps of: lining the wellbore with
tubing, the liner tubing comprising a plurality of ported segments;
deploying a tool assembly downhole in the lined wellbore on tubing
string, the tool assembly comprising an abrasive fluid perforation
device and a releasable sealing member; locating the tool assembly
at a depth not corresponding to a ported segment; jetting
perforations in the liner tubing with the abrasive fluid
perforation device; and, delivering pressurized fluid to the jetted
perforations.
20. A method for delivering treatment fluid to a formation
intersected by a wellbore lined with tubing, the liner tubing
having at least a first ported segment and a second ported segment
spaced apart from the first ported segment with each ported segment
having at least one lateral opening through the liner tubing, the
method comprising the steps of: deploying a tool assembly downhole
in the lined wellbore on tubing string, the tool assembly
comprising an abrasive fluid perforation device and a sealing
member; locating the tool assembly at a depth at which the sealing
member is adjacent the closure; setting the sealing member against
the closure; moving the tool assembly; determining whether the
closure has moved from a closed position; delivering pressured
fluid through the ported segment if the closure has moved from the
closed position; and jetting perforations in the liner tubing with
the abrasive fluid perforation device and delivering pressurized
fluid to the jetted perforations if the closure has not moved from
the closed position.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is a continuation of U.S. application Ser.
No. 14/317,975 filed Jun. 27, 2014, which is a division of U.S.
application Ser. No. 13/100,796 filed May 4, 2011, which claims the
benefit of U.S. provisional application No. 61/394,077 filed on
Oct. 18, 2010, the disclosures of which are hereby incorporated by
reference in their entireties.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
[0002] Not Applicable
BACKGROUND OF THE INVENTION
1. Field of the Invention
[0003] The present invention relates generally to oil, gas, and
coal bed methane well completions. More particularly, methods and
tool assemblies are provided for use in accessing, opening, or
creating one or more fluid treatment ports within a downhole
tubular, for application of treatment fluid therethrough. Multiple
treatments may be selectively applied to the formation through such
ports along the tubular, and new perforations may be created as
needed, in a single trip downhole.
2. Description of the Related Art Including Information Disclosed
Under 37 CFR 1.97 and 1.98
[0004] Various tools and methods for use downhole in the completion
of a wellbore have been previously described. For example,
perforation devices are commonly deployed downhole on wireline,
slickline, cable, or on tubing string, and sealing devices such as
bridge plugs, packers, and straddle packers are commonly used to
isolate portions of the wellbore for fluid treatment.
[0005] In vertical wells, downhole tubulars may include ported
sleeves through which treatment fluids and other materials may be
delivered to the formation. Typically, these sleeves are run in the
casing, tubing string, or production liner string, and are isolated
using external casing packers straddling the sleeve. Such ports may
be mechanically opened using any number of methods including: using
a shifting tool deployed on wireline or jointed pipe to force a
sleeve open mechanically; pumping a ball down to a seat to shift
the sleeve open; applying fluid pressure to an isolated segment of
the wellbore to open a port; sending acoustic or other signals from
surface, etc. These mechanisms for opening a port or shifting a
sliding sleeve are not always reliable, and are not intended for
use with coiled tubing.
BRIEF SUMMARY OF THE INVENTION
[0006] In one aspect, there is provided a method for delivering
treatment fluid to a formation intersected by a wellbore, the
method comprising the steps of: lining the wellbore with tubing,
the liner comprising one or more ported tubular segments, each
ported tubular segment having one or more lateral openings for
communication of fluid through the liner to a formation adjacent
the wellbore; deploying a tool assembly downhole on tubing string,
the tool assembly comprising an abrasive fluid perforation device
and a sealing member; locating the tool assembly at a depth
generally corresponding to one of the ported tubular segments;
setting the sealing member against the liner below the ported
tubular segment; and delivering treatment fluid to the ported
tubular segment.
[0007] In an embodiment, the lateral openings are perforations
created in the liner. In another embodiment, the openings are ports
machined into the tubular segment prior to lining the wellbore.
[0008] In an embodiment, the sealing member is a straddle isolation
device comprising first and second sealing members, and the tool
assembly further comprises a treatment aperture between the first
and second sealing members, the treatment aperture continuous with
the tubing string for delivery of treatment fluid from the tubing
string to the formation through the ports. For example, the first
and/or second sealing members may be inflatable sealing elements,
compressible sealing elements, cup seals, or other sealing
members.
[0009] In another embodiment, the sealing member is a mechanical
set packer, inflatable packer, or bridge plug.
[0010] In another embodiment, the ported tubular segment comprises
a closure over one or more of the lateral openings, and the method
further comprises the step of removing a closure from one or more
of the lateral openings. The closure may comprise a sleeve
slidingly disposed within the tubular segment, and the method may
further comprise the step of sliding the sleeve to open one or more
of the lateral openings.
[0011] In further embodiments, the step of sliding the sleeve
comprises application of hydraulic pressure and/or mechanical force
to the sleeve.
[0012] In an embodiment, the tubing string is coiled tubing.
[0013] In an embodiment of any of the aforementioned aspects and
embodiments, the method further comprises the step of jetting one
or more new perforations in the liner. The step of jetting one or
more new perforations in the liner may comprise delivering abrasive
fluid through the tubing string to jet nozzles within the tool
assembly.
[0014] The method may further comprise the step of closing an
equalization valve in the tool assembly to provide a dead leg for
monitoring of bottom hole pressure during treatment.
[0015] In a second aspect, there is provided a method for shifting
a sliding sleeve in a wellbore, comprising: providing a wellbore
lined with tubing, the tubing comprising a sleeve slidably disposed
within a tubular, the tubular having an inner profile for use in
locating said sleeve; providing a tool assembly comprising: a
locator engageable with said locatable inner profile of the
tubular; and a resettable anchor member; deploying the tool
assembly within the wellbore on coiled tubing; engaging the inner
profile with the locator; setting the anchor within the wellbore to
engage the sliding sleeve; applying a downward force to the coiled
tubing to slide the sleeve with respect to the tubular.
[0016] In an embodiment, the step of setting the anchor comprises
application of a radially outward force with the anchor to the
sleeve so as to frictionally engage the sleeve with the anchor. The
sleeve may comprise an inner surface of uniform diameter along its
length, free of any engagement profile. The inner surface may be of
a diameter consistent with the inner diameter of the tubing.
[0017] In an embodiment, the tool assembly further comprises a
sealing member associated with the anchor, and wherein the method
further comprises the step of setting the sealing member across the
sleeve to provide a hydraulic seal across the sleeve.
[0018] In an embodiment, the step of applying a downward force
comprises application of hydraulic pressure to the wellbore
annulus.
[0019] In a third aspect, there is provided a method for shifting a
sliding sleeve in a wellbore, comprising: providing a wellbore
lined with tubing, the tubing comprising a sleeve slidably disposed
within a tubular, the tubular having an inner profile for use in
locating said sleeve; providing a tool assembly comprising: a
locator engageable with said locatable inner profile of the
tubular; and a resettable sealing member; deploying the tool
assembly within the wellbore on coiled tubing; engaging the inner
profile with the locator; setting the sealing member across the
sliding sleeve; applying a downward force to the coiled tubing to
slide the sleeve with respect to the tubular.
[0020] In an embodiment, the step of setting the sealing member
comprises application of a radially outward force with the sealing
member to the sleeve so as to frictionally engage the sleeve with
the sealing member.
[0021] In an embodiment, the sleeve comprises an inner surface of
uniform diameter along its length, free of any profile. The inner
diameter may be consistent with the inner diameter of the
tubing.
[0022] In a fourth aspect, there is provided a method for shifting
a sliding sleeve in a deviated wellbore, comprising: providing a
deviated wellbore having a sleeve slidably disposed therein;
providing a work string for use in engaging the sleeve, the work
string comprising: tubing string; a sealing element operatively
attached to the tubing string; and sleeve location means
operatively associated with the sealing element; deploying said
work string within the wellbore to position the sealing element
proximal to said sleeve; setting the sealing element across the
wellbore to engage the sleeve; applying a downward force to the
sealing element to shift the sliding sleeve
[0023] In an embodiment, the step of applying a downward force
comprises applying hydraulic pressure to the wellbore annulus.
[0024] In a fifth aspect, there is provided a ported tubular for
installation within a wellbore to provide selective access to the
adjacent formation, the ported tubular comprising: a tubular
housing comprising one or more lateral fluid flow ports, the
housing adapted for installation within a wellbore; a port closure
sleeve disposed against the tubular housing and slidable with
respect to the housing to open and close the ports; and, location
means for use in positioning a shifting tool within the housing
below the port closure sleeve.
[0025] In an embodiment, the location means comprises a profiled
surface along the innermost surface of the housing or sleeve, the
profiled surface for engaging a location device carried on a
shifting tool deployable on tubing string. The sleeve may have an
inner surface of uniform diameter along its length, free of any
engagement profile. The inner diameter may be consistent with the
inner diameter of tubular segments adjacent the ported tubular
segment.
[0026] In another aspect, there is provided a ported tubular for
installation within a wellbore to provide selective access to the
adjacent formation, the ported tubular comprising: a tubular
housing comprising one or more lateral fluid flow ports, the
housing adapted for installation within a wellbore; a port closure
sleeve disposed against the tubular housing and slidable with
respect to the housing to open and close the ports; means for
locking the slidable position of the sleeve with respect to the
housing.
[0027] In an embodiment, the means for locking comprises engageable
profiles along adjacent surfaces of the sleeve and housing.
[0028] Other aspects and features of the present invention will
become apparent to those ordinarily skilled in the art upon review
of the following description of specific embodiments of the
invention in conjunction with the accompanying figures.
BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWING(S)
[0029] Embodiments of the present invention will now be described,
by way of example only, with reference to the attached Figures,
wherein:
[0030] FIG. 1a is a perspective view of a tool assembly, in one
embodiment, for use in accordance with the methods described
herein;
[0031] FIG. 1b is a schematic cross sectional view of the
equalizing valve and housing shown in FIG. 1a;
[0032] FIG. 2a is a perspective view of a tool assembly, in another
embodiment, for use in accordance with the methods described
herein;
[0033] FIG. 2b is a schematic cross sectional view of the
equalizing valve 24 shown in FIG. 2a;
[0034] FIG. 3 is a schematic cross sectional view of a ported sub,
in one embodiment, with hydraulically actuated sliding sleeve port
for use in accordance with the methods described herein;
[0035] FIG. 4a is a perspective, partial cross-section view of a
ported sub having an internal mechanically operated sliding
sleeve;
[0036] FIG. 4b is a perspective, cross-section view of the ported
sub of FIG. 4a, with sliding sleeve shifted to an open port
position;
[0037] FIG. 5a is a perspective, partial cross-section view of the
tool shown in FIG. 1a, disposed within the ported sub shown in FIG.
4a; and
[0038] FIG. 5b is a partial cross-sectional perspective view of the
tool shown in FIG. 1a, disposed within the ported sub as shown in
FIG. 4b
DETAILED DESCRIPTION OF THE INVENTION
[0039] Tools and methods for use in selective opening of ports
within a tubular are described. Ported tubular may be run in hole
as collars, subs, or sleeves between lengths of tubing, and
cemented in place. The ported tubulars are spaced at intervals
generally corresponding to desired treatment locations. Within
each, one or more treatment ports extends through the tubular,
forming a fluid delivery conduit from the tubular to the formation
(that is, through the casing or tubular). Accordingly, treatment
fluids applied within the tubing may exit through the ports to
reach the surrounding formation.
[0040] The ported tubulars may be closed with a sliding sleeve to
prevent fluid access to the ports. Such sleeves may be shifted or
opened by various means. For example, a tool assembly may interlock
or mate with the tubular to confirm downhole position of the tool
assembly, and the generally cylindrical sleeve may then be gripped
to mechanically drive the sleeve open. In another embodiment,
pressurized fluid may be selectively applied to a specific location
to open a port or slide a sleeve as appropriate.
[0041] With reference to the embodiments shown in FIGS. 1 and 2,
the tool assemblies generally described below include a sealing
member to facilitate isolation of a wellbore portion containing one
or more ported tubulars. A perforation device is also present
within the tool assembly. Should additional perforations be
desired, for example if specific ports will not open, or should the
ports clog or otherwise fail to take up or produce fluids, a new
perforation can be created without removal of the tool assembly
from the wellbore. Such new perforations may be placed within the
ported tubular or elsewhere along the wellbore.
[0042] The Applicants have previously developed a tool and method
for use in the perforation and treatment of multiple wellbore
intervals. That tool includes a jet perforation device and
isolation assembly, with an equalization valve for controlling
fluid flow through and about the assembly. Fluid treatment is
applied down the wellbore annulus to treat the perforated zone.
[0043] The Applicants have also developed a downhole straddle
treatment assembly and method for use in fracturing multiple
intervals of a wellbore without removing the tool string from the
wellbore between intervals. Further, a perforation device may be
present within the assembly to allow additional perforations to be
created and treated as desired, in a single trip downhole.
[0044] In the present description, the terms "above/below" and
"upper/lower" are used for ease of understanding, and are generally
intended to mean the relative uphole and downhole direction from
surface. However, these terms may be imprecise in certain
embodiments depending on the configuration of the wellbore. For
example, in a horizontal wellbore one device may not be above
another, but instead will be closer (uphole, above) or further
(downhole, below) from the point of entry into the wellbore.
Likewise, the term "surface" is intended to mean the point of entry
into the wellbore, that is, the work floor where the assembly is
inserted into the wellbore.
[0045] Jet perforation, as mentioned herein, refers to the
technique of delivering abrasive fluid at high velocity so as to
erode the wall of a wellbore at a particular location, creating a
perforation. Typically, abrasive fluid is jetted from nozzles
arranged about a mandrel such that the high rate of flow will jet
the abrasive fluid from the nozzles toward the wellbore casing.
Sand jetting refers to the practice of using sand as the abrasive
agent, in an appropriate carrier fluid. For example, typical
carrier fluids for use in sand jetting compositions may include one
or more of: water, hydrocarbon-based fluids, propane, carbon
dioxide, nitrogen assisted water, and the like. As the life of a
sand jetting assembly is finite, use of ported collars as the
primary treatment delivery route minimizes the need for use of the
sand jetting device. However, when needed, the sand jetting device
may be used as a secondary means to gain access to the formation
should treatment through a particular ported collar fail.
[0046] The ported tubulars referred to herein are tubular
components or assemblies of the type typically used downhole,
having one or more fluid ports through a wall to permit fluid
delivery from the inside of the tubular to the outside. For
example, ported tubular include stationary and sliding sleeves,
collars and assemblies for use in connection of adjacent lengths of
tubing, or subs and assemblies for placement downhole. In some
embodiments, the ports may be covered and selectively opened. The
ported tubulars may be assembled with lengths of non-ported tubing
such as casing or production liner, for use in casing or lining a
wellbore, or otherwise for placement within the wellbore.
Ported Casing Collars
[0047] Selective application of treatment fluid to individual
ports, or to groups of ports, is possible using one or more of the
methods described here. That is, selective, sequential application
of fluid treatment to the formation at various locations along the
wellbore is facilitated, in one embodiment, by providing a sliding
member, such as a sleeve, piston, valve, or other cover that
conceals a treatment port within a wellbore tubular, effectively
sealing the port to the passage of fluid. For example, the sliding
member may be initially biased or held over the treatment port, and
may be selectively moved to allow fluid treatment to reach the
formation through the opened port. In the embodiments shown in the
Figures, the ported tubular and sleeves are shown as collars or
subs for attachment of adjacent lengths of wellbore casing. It is,
however, contemplated that a similar port opening configuration
could be used in other applications, that is with other tubular
members, sleeves, liners, and the like, whether cemented in hole,
deployed on tubing string, assembled with production liner, or
otherwise positioned within a wellbore, pipe, or tubular.
[0048] Other mechanisms may be used to temporarily cover the port
until treatment is desired. For example, a burst disc,
spring-biased valve, dissolvable materials, and the like, may be
placed within the assembly for selective removal to permit
individual treatment at each casing collar.
[0049] In the ported collar 30 shown in FIG. 3, an annular channel
35 extends longitudinally within the collar 30 and intersects the
treatment ports 31. A sliding sleeve 32 within the channel 35 is
held over the treatment ports 31 by a shear pin 33. The channel 35
is open to the inner wellbore near each end at sleeve ports 34a,
34b. The sliding sleeve 32 is generally held or biased to the
closed position covering the port 31, but may be slidably actuated
within the channel 35 to open the treatment port 31. For example, a
seal may be positioned between the sleeve ports to allow
application of fluid to sleeve port 34a (without corresponding
application of hydraulic pressure through sleeve port 34b). As a
result, the sleeve 32 will slide within the channel 35 toward
opposing sleeve port 34b, opening the treatment port 31. Treatment
may then be applied to formation through the port 31. The port may
or may not be locked open, and may remain open after treatment. In
some embodiments, the port may be closed after treatment.
[0050] With reference to FIGS. 4a and 4b, a ported sub 40 with an
outer housing and inner sliding sleeve 41 is shown in port closed
and port open positions, respectively. The sub may be used to
connect lengths of casing or tubing as the tubing is made up at
surface, prior to running in hole and securing in place with cement
or external packers as desired. Ports 42 are formed through the sub
40, but not within the sliding sleeve 41. That is, the ports are
closed when the sleeve is positioned as shown in FIG. 4a. The
closed sleeve position may be secured against the collar ports
using shear pins 43 or other fasteners, by interlocking or mating
with a profile on the inner surface of the casing collar, or by
other suitable means.
[0051] While the sleeve 41 is slidably disposed against the inner
surface of the sub in the port closed position, held by shear pin
43, one or more seals 44 prevent fluid flow between these surfaces.
If locking of the sleeve in the port open position is desired once
the sleeve has been shifted, a lockdown, snap ring 45, collet, or
other engagement device may be secured about the outer
circumference of the sleeve 41. A corresponding trap ring 47 having
a profile, groove, or trap to engage the snap ring 46, is
appropriately positioned within the sub so as to engage the snap
ring once the sleeve has shifted, holding the sleeve open.
Accordingly, a downhole force and/or pressure may be applied to the
sliding sleeve to drive the sleeve 41 in the downhole direction,
shearing the pin 43 and sliding the sleeve 41 so as to open the
ports 42 and lock it open. The inner surface of the sleeve is
smooth and consistent in diameter, and is also comparable in inner
diameter to that of the connected lengths of tubing so as not to
provide a profile narrower than the inner diameter of the tubing.
That is, the sleeve does not provide any barrier or surface that
will impede the passage of a work string or tool down the
tubing.
[0052] The unprofiled, smooth nature of the inner surface of the
sliding sleeve resists engagement of the sleeve by tools or work
strings that may pass downhole for various purposes, and will only
be engageable by a gripping device that exerts pressure radially
outward, when applied directly to the sleeve. That is, the inner
surface of the sleeve is substantially identical to the inner
surfaces of the lengths of adjacent pipe. The only aberration in
this profile exists within the ported sub at the bottom of each
unshifted sliding sleeve, or at the top of each shifted sliding
sleeve, where a radially enlarged portion of the sub (absent the
concentric sliding sleeve) may be detected. In unshifted sleeves,
the radially enlarged portion below the unshifted sleeve may be
used to locate unshifted sleeves and position a shifting tool. The
absence of such a space (inability to locate) may be used to
confirm that shifting of the sleeve has occurred.
[0053] Despite the absence of an engagement profile to assist in
shifting the sleeve, the sleeve may be shifted by engagement with a
sealing member, packer, slips, metal or elastomeric seals, chevron
seals, or molded seals. Such seals will engage the sliding sleeve
by exerting a force radially outward against the sleeve. In some
embodiments, such engagement also provides a hydraulic seal. Thus,
once engaged, the sleeve may be shifted by application of
mechanical force and/or hydraulic pressure.
[0054] The appropriate design and placement of ported collars or
subs along a casing to provide perforations or ports through the
tubular will minimize the need for tripping in and out of hole to
add perforations during completion operations. Further, use of the
present tool assemblies for shifting sliding sleeves will also
provide efficiencies in completion operations by providing a
secondary perforation means deployed on the work string. As
perforation is generally time-consuming, hazardous, and costly, any
reduction in these operations improves efficiency and safety. In
addition, when the pre-placed perforations can be selectively
opened during a completion operation, this provides more
flexibility to the well operator.
[0055] The sleeves may further be configured to prevent locking in
the open position, so the ports may be closed after treatment is
complete, for example by sliding the sleeve into its original
position over the ports.
Tool Assembly
[0056] The tool assembly described herein includes at least a
sealing member and a perforation device. The sealing member allows
some degree of isolation during application of treatment fluid. The
perforation device allows a new perforation to be created in the
event that fluid treatment is unsuccessful, or when treatment of
additional wellbore locations not containing a ported tubular is
desired. Notably, the present tool assembly allows integration of
secondary perforating capacity within a fluid treatment operation,
without removal of the treatment assembly from the wellbore, and
without running a separate tool string downhole. In some
embodiments, the new perforation may be created, and treatment
applied, without adjusting the downhole location of the work
string.
[0057] With reference to FIG. 1, and to Applicants' co-pending U.S.
patent application Ser. No. 12/708,709, the content of which is
incorporated herein by reference, the Applicants have described a
sand jetting tool 100 and method for use in the perforation and
treatment of multiple wellbore intervals. That tool included a jet
perforation device 10 and a compressible sealing member 11, with an
equalization valve 12 for controlling fluid flow through and about
the assembly. The setting/unsetting of the sealing member using
slips 14, and control over the position of the equalization valve,
are both effected by application of mechanical force to the tubing
string, which drives movement of a pin within an auto J profile
about the tool mandrel, with various pin stop positions
corresponding to set and unset seal positions. Fluid treatment is
applied down the wellbore annulus when the sealing member is set,
to treat the uppermost perforated zone(s). New perforations can be
jetted in the wellbore by delivery of abrasive fluid down the
tubing string, to reach jet nozzles.
[0058] With reference to FIG. 2, and to co-pending U.S. patent
application Ser. No. 13/078,584, the content of which is
incorporated herein by reference, the Applicants have also
described a straddle assembly and method for use in fracturing
multiple intervals of a wellbore without removing the work string
from the wellbore between intervals. Upper straddle device 20
includes upper and lower cup seals 22, 23 around treatment
apertures 21. Accordingly, fluid applied to the tubing string exits
the assembly at apertures 21 and causes cup seals 22, 23 to flare
and seal against the casing, isolating a particular perforation
within a straddle zone, to receive treatment fluid. A bypass below
the cup seals may be opened within the tool assembly, allowing
fluid to continue down the inside of the tool assembly to be jetted
from nozzles 26 along a fluid jet perforation device 25. An
additional anchor assembly 24 may also be present to further
maintain the position of the tool assembly within the wellbore, and
to assist in opening and closing the bypass valve as necessary.
[0059] With reference to FIG. 5a, a work string for use in
mechanically shifting a sliding sleeve is shown. In the embodiment
shown, a casing collar locator 13 engages a corresponding profile
below the unshifted sleeve within the ported tubular, the profile
defined by the lower inner surface of the collar and the lower
annular surface of the sliding sleeve. Once the collar locator 13
is thus engaged, a seal 11 may be set against the sliding sleeve,
aided by mechanical slips 14. The set seal, for example a packer
assembly having a compressible sealing element, effectively
isolates the wellbore above the ported sub of interest. As force
and/or hydraulic pressure is applied to the work string and packer
from uphole, the sliding sleeve will be drawn downhole, shearing
pin 43 and collapsing collar locator 13. The applied force and/or
pressure may be a mechanical force applied directly to the work
string (and thereby to the engaged sliding sleeve) from surface,
for example coiled tubing, jointed pipe, or other tubing string.
The applied force and/or pressure may be a hydraulic pressure
applied against the seal through the wellbore annulus, and/or
through the work string. Any combination of forces/pressures may be
applied once the seal 11 is engaged with the sliding sleeve 41, to
shift the sleeve from their original position covering the ports
42. For example, the wellbore and work string may be pressurized
appropriately with fluid to aid the mechanical application of force
to the work string and shift the sleeve. In various embodiments,
some or all of the shifting may be accomplished by mechanical
force, and in other embodiments by hydraulic pressure. In many
embodiments, a suitable combination of mechanical force and
hydraulic pressure will be sufficient to shift the sleeve from
their position covering the ports.
[0060] With reference to FIG. 5b, once the lower inner surface of
the collar meets the lower annular surface of the sliding sleeve,
the ports 42 are open and treatment may be applied to the
formation. Further, with the sliding sleeve meeting the lower inner
surface of the collar, there is no longer a locatable profile for
engagement by the corresponding tubing deployed dogs/collar
locator. Accordingly, the work string may be run through the sleeve
without overpull, to verify that the sleeve has been opened.
[0061] Notably, after the sleeve has been opened, the seal and work
string may remain set within the wellbore to isolate the ports in
the newly opened sleeve from any previously opened ports below.
Alternatively, the seal may be unset for verifying the state of the
opened sleeve, or to relocate the work string as necessary (for
example to apply treatment fluid to the ports of one or more
collars simultaneously). Depending on the configuration of the work
string, treatment fluid may be applied to the ports through one or
more apertures in the work string, or via the wellbore annulus
about the work string.
[0062] It is noted that the work string and components, and the
sliding sleeve and casing collar shown and discussed herein, are
provided as examples of suitable embodiments for opening variously
configured downhole ports. Numerous modifications are contemplated
and will be evident to those reading the present disclosure. For
example, while downhole shifting of the sliding sleeves shown in
FIGS. 3 and 4 is described herein, the sleeve, collar and work
string components could be reversed such that the sleeve is shifted
uphole to open the ports. Further, various forms of locating the
collars and sleeves, and of shifting the sleeves, are possible.
Notably, either of the tool assemblies shown in FIG. 1 or FIG. 2
could be used to actuate either of the sliding sleeves depicted in
FIG. 3 or 4 and to treat the formation through the opened ports.
Various combinations of elements are possible within the scope of
the teachings provided herein.
Method
[0063] When lining a wellbore for use as discussed herein, casing
is made up and run in hole, and a predetermined number of ported
collars are incorporated between sections of casing at
predetermined spacing. Once the casing string is in position within
the wellbore, it is cemented into place. While the cementing
operation may cover the outer ports of the ported collars, the
cement plugs between the ported collar and the formation are easily
displaced upon delivery of treatment fluid through each port as
will be described below. If the well remains uncemented and the
ported collars are additionally isolated using external seals,
there is no need to displace cement.
[0064] Once the wellbore is ready for completion operations, a tool
assembly with at least one sealing or anchor member and a jet
perforation device is run in hole on coiled tubing. Depending on
the configuration of the well, the tool assembly, and the method of
operation of the ported collars, a particular ported sub of
interest is selected and the tool assembly is positioned
appropriately. Typically, the ported subs will be actuated and the
well treated starting at the bottom/lowermost/deepest collar and
working uphole. Appropriate depth monitoring systems are known in
the art, and can be used with the tool assembly in vertical,
horizontal, or other wellbores as desired to ensure accurate
positioning of the tool assembly.
[0065] Specifically, when positioning the tool assembly for
operating the sliding sleeve of the ported sub shown in FIG. 3, a
sealing member of the tool assembly is positioned between the
sleeve ports of a single ported sub to isolate the paired sleeve
ports on either side of the sealing member. Thus, when fluid is
applied to the wellbore, fluid will enter the annular channel 35 at
the ported collar of interest through only one of the sleeve ports,
as the other sleeve port will be on the opposing side of the
sealing member and will not take up fluid to balance the sleeve
within the channel. In the ported collar shown in FIG. 3, fluid
would be applied only to the upper sleeve port 34a. Accordingly,
the flow of fluid into the annular channel from only one end will
create hydraulic pressure within the upper portion of the annular
channel, ultimately shearing the pin holding the sliding sleeve in
place. The sliding sleeve will be displaced within the channel,
uncovering the treatment port and allowing the passage of
pressurized treatment fluid through the port, through the cement,
and into the formation.
[0066] For greater clarity, the ported sub shown in FIG. 3 is
opened as a result of a sealing member being positioned between its
sleeve ports, which allows only one sleeve port to receive fluid,
pressurizing the channel to shear the pin holding the sliding
sleeve over the treatment port (or in other embodiments, forcing
open the biased treatment port closure). The treatment ports within
the remainder of the ported collars along the wellbore will not be
opened, as fluid will generally enter both sleeve ports equally,
maintaining the balanced position of the sliding sleeve over the
ports in those collars.
[0067] Once treatment has been fully applied to the opened port,
for example either through the tubing or down the annulus,
application of treatment fluid to the port is terminated, and the
hydraulic pressure across the annular channel is dissipated. If the
sliding sleeve is biased to close the treatment port, the treatment
port may close when application of treatment fluid ceases. However,
closure of the treatment port is not required, particularly when
treatment is applied to wellbore intervals moving from the bottom
of the well towards surface. That is, once treatment of the first
wellbore segment is terminated, the tool assembly is moved uphole
to position a sealing member between the sleeve ports of the next
ported sub to be treated. Accordingly, the previously treated
collar is inherently isolated from receiving further treatment
fluid, and the ports may continue to be treated independently.
[0068] When a tool string having a straddle sealing assembly is
available, the tool assembly may be used in at least two distinct
ways to shift a sleeve. In the first instance, the straddle tool
may be used in the method described above, setting the lower
sealing member between the sleeve ports of a ported sub of interest
and applying treatment fluid down the tubing string.
[0069] Alternatively, the method may be altered when using a
straddle sealing assembly to allow the ported collars to be treated
in any order. Specifically, one of the sealing members (in the
assembly shown in FIG. 2, the lower sealing member) is set between
the sleeve ports of a ported collar of interest. Treatment fluid
may be applied down the tubing string to the isolated interval,
which will enter only the upper sleeve port, creating a hydraulic
pressure differential across the sliding sleeve and forcing the
treatment port open.
[0070] Should the ported collar fail to open, or treatment through
the ported collar be otherwise unsuccessful, the jet perforation
device may be used to create a new perforation in the casing. Once
the new perforation has been jetted, treatment can continue.
[0071] The method therefore allows treatment of pre-existing
perforations (such as ported casing collars) within a wellbore, and
creation of new perforations for treatment, as needed, with a
single tool assembly and in a single trip downhole.
Example 1
Tool Assembly with Single Sealing Member
[0072] With reference to the tool assembly shown in FIG. 1, a fluid
jetting device is provided for creating perforations through a
liner, and a sealing device is provided for use in the isolation
and treatment of a perforated interval. Typically, when carrying
out a standard completion operation, the tool string is assembled
and deployed downhole on tubing (for example coiled tubing or
jointed pipe) to the lowermost interval of interest. The sealing
device 11 is set against the casing of the wellbore, abrasive fluid
is jetted against the casing to create perforations, and then a
fluid treatment (for example a fracturing fluid) is injected down
the wellbore annulus from surface under pressure, which enters the
formation via the perforations. Once the treatment is complete, the
hydraulic pressure in the annulus is slowly dissipated, and the
sealing device 11 is released. The tool may then be moved up-hole
to the next interval of interest.
[0073] Notably, both forward and reverse circulation flowpaths
between the wellbore annulus and the inner mandrel of the tool
string are present to allow debris to be carried in the forward or
reverse direction through the tool string. Further, the tubing
string may be used as a dead leg during treatment down the annulus,
to allow pressure monitoring for early detection of adverse events
during treatment, to allow prompt action in relieving debris
accumulation, or maximizing the stimulation treatment.
[0074] When using the tool string in accordance with the present
method, perforation is a secondary function. That is, abrasive jet
perforation would generally be used only when a ported collar fails
to open, when fluid treatment otherwise fails in a particular zone,
or when the operation otherwise requires creation of a new
perforation within that interval. The presence of the ported subs
between tubulars will minimize the use of the abrasive jetting
device, and as a result allow more stages of treatment to be
completed in a single wellbore in less time. Each ported collar
through which treatment fluid is successfully delivered reduces the
number of abrasive perforation operations, thereby reducing time
and costs by reducing fluid and sand delivery requirements (and
later disposal requirements when the well is put on production),
increases the number of zones that can be treated in a single trip,
and also extends the life of the jetting device.
[0075] When abrasive fluid perforation is required, and has been
successfully completed, the jetted fluid may be circulated from the
wellbore to surface by flushing the tubing string or casing string
with an alternate fluid prior to treatment application to the
perforations. During treatment of the perforations by application
of fluid to the wellbore annulus, a second volume of fluid (which
may be a second volume of the treatment fluid, a clear fluid, or
any other suitable fluid) may also be pumped down the tubing string
to the jet nozzles to avoid collapse of the tubing string and
prevent clogging of the jet nozzles.
[0076] As shown in the embodiment illustrated in FIG. 1, the
sealing device 11 is typically positioned downhole of the fluid
jetting assembly 10. This configuration allows the seal to be set
against the tubular, used as a shifting tool to shift the sleeve,
provide a hydraulic seal to direct fluid treatment to the
perforations, and, if desired, to create additional perforations in
the tubular. Alternatively, the seal may be located anywhere along
the tool assembly, and the tool string may re-positioned as
necessary.
[0077] Suitable sealing devices will permit isolation of the most
recently perforated or port-opened interval from previously treated
portions of the wellbore below. For example, inflatable packers,
compressible packers, bridge plugs, friction cups, straddle
packers, and others known in the art may be useful for this
purpose. The sealing device is able to set against any tubular
surface, and does not require a particular profile at the sleeve in
order to provide suitable setting or for use in shifting of an
inner sliding sleeve, as such a profile may otherwise interfere
with the use of other tools downhole. The sealing device may be
used with any ported sub to hydraulically isolate a portion of the
wellbore, or the sealing device may be used to set a hydraulic seal
directly against an inner sliding sleeve to provide physical
shifting of the sleeve, for example to open ports. The sealing
device also allows pressure testing of the sealing element prior to
treatment, and enables reliable monitoring of the treatment
application pressure and bottom hole pressure during treatment. The
significance of this monitoring will be explained below.
[0078] Perforation and treatment of precise locations along a
vertical, horizontal, or deviated wellbore may be accomplished by
incorporation of a depth locating device within the assembly. This
will ensure that when abrasive fluid perforation is required, the
perforations are located at the desired depth. Notably, a
mechanical casing collar locator permits precise depth control of
the sealing and anchoring device in advance of perforation, and
maintains the position of the assembly during perforation and
treatment. The collar locator may also be used to locate a work
string at unshifted sleeves of the type shown in FIG. 5a.
[0079] When this tool assembly is used for perforation, the sealing
device is set against the casing prior to perforation, as this may
assist in maintaining the position and orientation of the tool
string during perforation and treatment of the wellbore.
Alternatively, the sealing assembly may be actuated following
perforation. In either case, the sealing assembly is set against
the casing beneath the perforated interval of interest, to
hydraulically isolate the lower wellbore (which may have been
previously perforated and treated) from the interval to be treated.
That is, the seal defines the lower limit of the wellbore interval
to be treated. Typically, this lower limit will be downhole of the
most recently formed perforations, but up-hole of any previously
treated jetted perforations or otherwise treated ports. Such
configuration will enable treatment fluid to be delivered to the
most recently formed perforations by application of said treatment
fluid to the wellbore annulus from surface. Notably, when jetting
new perforations in a wellbore having ported subs, in which the
ports are covered, unopened ported collars will remain closed
during treatment of the jetted perforation, and as a result such
newly jetted perforations may be treated in isolation.
[0080] As shown, the sealing assembly 11 is mechanically actuated,
including a compressible sealing element for providing a hydraulic
seal between the tool string and casing when actuated, and slips 14
for engaging the casing to set the compressible sealing element. In
the embodiment shown, the mechanism for setting the sealing
assembly involves a stationary pin sliding within a J profile
formed about the sealing assembly mandrel. The pin is held in place
against the bottom sub mandrel by a two-piece clutch ring, and the
bottom sub mandrel slides over the sealing assembly mandrel, which
bears the J profile. The clutch ring has debris relief openings for
allowing passage of fluid and solids during sliding of the pin
within the J profile. Debris relief apertures are present at
various locations within the J-profile to permit discharge of
settled solids as the pin slides within the J profile. The J slots
are also deeper than would generally be required based on the pin
length alone, which further provides accommodation for debris
accumulation and relief without inhibiting actuation of the sealing
device. Various J profiles suitable for actuating mechanical set
packers and other downhole tools are known within the art.
[0081] In order to equalize pressure across the sealing device and
permit unsetting of the compressible sealing element under various
circumstances, an equalization valve 12 is present within the tool
assembly. While prior devices may include a valve for equalizing
pressure across the packer, such equalization is typically enabled
in one direction only, for example from the wellbore segment below
the sealing device to the wellbore annulus above the sealing
device. The presently described equalization valve permits constant
fluid communication between the tubing string and wellbore annulus,
and, when the valve is in fully open position, also with the
portion of the wellbore beneath the sealing device. Moreover, fluid
and solids may pass in forward or reverse direction between these
three compartments. Accordingly, appropriate manipulation of these
circulation pathways allows flushing of the assembly, preventing
settling of solids against or within the assembly. Should a
blockage occur, further manipulation of the assembly and
appropriate fluid selection will allow forward or reverse
circulation to the perforations to clear the blockage.
[0082] As shown in FIG. 1b, the equalization valve is operated by
sliding movement of an equalization plug 15 within a valve housing
16. Such slidable movement is actuated from surface by pulling or
pushing on the coiled tubing, which is anchored to the assembly by
a main pull tube. The main pull tube is generally cylindrical and
contains a ball and seat valve to prevent backflow of fluids
through from the equalization valve to the tubing string during
application of fluid through the jet nozzles (located upstream of
the pull tube). The equalization plug 15 is anchored over the pull
tube, forming an upper shoulder that limits the extent of travel of
the equalization plug 15 within the valve housing 16. Specifically,
an upper lock nut is attached to the valve housing and seals
against the outer surface of the pull tube, defining a stop for
abutment against the upper shoulder of the equalization plug.
[0083] The lower end of the valve housing 16 is anchored over
assembly mandrel, defining a lowermost limit to which the
equalization plug 15 may travel within the valve housing 16. It
should be noted that the equalization plug bears a hollow
cylindrical core that extends from the upper end of the
equalization plug 15 to the inner ports 17. That is, the
equalization plug 15 is closed at its lower end beneath the inner
ports, forming a profiled solid cylindrical plug 18 overlaid with a
bonded seal. The solid plug end and bonded seal are sized to engage
the inner diameter of the lower tool mandrel, preventing fluid
communication between wellbore annulus/tubing string and the lower
wellbore when the equalization plug has reached the lower limit of
travel and the sealing device (downhole of the equalization valve)
is set against the casing.
[0084] The engagement of the bonded seal within the mandrel is
sufficient to prevent fluid passage, but may be removed to open the
mandrel by applying sufficient pull force to the coiled tubing.
This pull force is less than the pull force required to unset the
sealing device, as will be discussed below. Accordingly, the
equalization valve may be opened by application of pulling force to
the tubing string while the sealing device remains set against the
wellbore casing. It is advantageous that the pull tube actuates
both the equalization plug and the J mechanism, at varying forces
to allow selective actuation. However, other mechanisms for
providing this functionality may now be apparent to those skilled
in this art field and are within the scope of the present
teaching.
[0085] With respect to debris relief, when the sealing device is
set against the wellbore casing with the equalization plug 15 in
the sealed, or lowermost, position, the inner ports 17 and outer
ports 18 are aligned. This alignment provides two potential
circulation flowpaths from surface to the perforations, which may
be manipulated from surface as will be described. That is, fluid
may be circulated to the perforations by flushing the wellbore
annulus alone. During this flushing, a sufficient fluid volume is
also delivered through the tubing string to maintain the ball valve
within the pull tube in seated position, to prevent collapse of the
tubing, and to prevent clogging of the jet nozzles.
[0086] Should reverse circulation be required, fluid delivery down
the tubing string is terminated, while delivery of fluid to the
wellbore annulus continues. As the jet nozzles are of insufficient
diameter to receive significant amounts of fluid from the annulus,
fluid will instead circulate through the aligned equalization
ports, unseating the ball within the pull tube, and thereby
providing a return fluid flowpath to surface through the tubing
string. Accordingly, the wellbore annulus may be flushed by forward
or reverse circulation when the sealing device is actuated and the
equalization plug is in the lowermost position.
[0087] When the sealing device is to be released (after flushing of
the annulus, if necessary to remove solids or other debris), a
pulling force is applied to the tubing string to unseat the
cylindrical plug 15 and bonded seal from within the lower mandrel.
This will allow equalization of pressure beneath and above the
seal, allowing it to be unset and moved up-hole to the next
interval.
[0088] Components may be duplicated within the assembly, and spaced
apart as desired, for example by connecting one or more blast
joints within the assembly. This spacing may be used to protect the
tool assembly components from abrasive damage downhole, such as
when solids are expelled from the perforations following
pressurized treatment. For example, the perforating device may be
spaced above the equalizing valve and sealing device using blast
joints such that the blast joints receive the initial abrasive
fluid expelled from the perforations as treatment is terminated and
the tool is pulled uphole.
[0089] The equalization valve therefore serves as a multi-function
valve in the sealed, or lowermost position, forward or reverse
circulation may be effected by manipulation of fluids applied to
the tubing string and/or wellbore annulus from surface. Further,
the equalization plug may be unset from the sealed position to
allow fluid flow to/from the lower tool mandrel, continuous with
the tubing string upon which the assembly is deployed. When the
equalization plug is associated with a sealing device, this action
will allow pressure equalization across the sealing device.
[0090] Notably, using the presently described valve and suitable
variants, fluid may be circulated through the valve housing when
the equalization valve is in any position, providing constant flow
through the valve housing to prevent clogging with debris.
Accordingly, the equalization valve may be particularly useful in
sand-laden environments.
[0091] During the application of treatment to the perforations via
the wellbore annulus, the formation may stop taking up fluid, and
the sand suspended within the fracturing fluid may settle within
the fracture, at the perforation, on the packer, and/or against the
tool assembly. As further circulation of proppant-laden fluid down
the annulus will cause further undesirable solids accumulation,
early notification of such an event is important for successful
clearing of the annulus and, ultimately, removal of the tool string
from the wellbore. A method for monitoring and early notification
of such events is possible using this tool assembly.
[0092] During treatment down the wellbore annulus using the tool
string shown in FIG. 1, fluid will typically be delivered down the
tubing string at a constant (minimal) rate to maintain pressure
within the tubing string and keep the jet nozzles clear. The
pressure required to maintain this fluid delivery may be monitored
from surface. The pressure during delivery of treatment fluid to
the perforations via the wellbore annulus is likewise monitored.
Accordingly, the tubing string may be used as a "dead leg" to
accurately calculate (estimate/determine) the fracture extension
pressure by eliminating the pressure that is otherwise lost to
friction during treatment applied to the wellbore. By understanding
the fracture extension pressure trend (also referred to as
stimulation extension pressure), early detection of solids
accumulation at the perforations is possible. That is, the operator
will quickly recognize a failure of the formation to take up
further treatment fluid by comparing the pressure trend during
delivery of treatment fluid down the wellbore annulus with the
pressure trend during delivery of fluid down the tubing string.
Early recognition of an inconsistency will allow early intervention
to prevent debris accumulation at the perforations and about the
tool.
[0093] During treatment, a desired volume of fluid is delivered to
the formation through the most recently perforated interval, while
the remainder of the wellbore below the interval (which may have
been previously perforated and treated) is hydraulically isolated
from the treatment interval. Should the treatment be successfully
delivered down the annulus, the sealing device may be unset by
pulling the equalization plug from the lower mandrel. This will
equalize pressure between the wellbore annulus and the wellbore
beneath the seal. Further pulling force on the tubing string will
unset the packer by sliding of the pin to the unset position in the
J profile. The assembly may then be moved uphole to perforate and
treat another interval.
[0094] However, should treatment monitoring suggest that fluid is
not being successfully delivered, indicating that solids may be
settling within the annulus, various steps may be taken to clear
the settled solids from the annulus. For example, pumping rate,
viscosity, or composition of the annulus treatment fluid may be
altered to circulate solids to surface.
[0095] Should the above clearing methods be unsuccessful in
correcting the situation (for example if the interval of interest
is located a great distance downhole that prevents sufficient
circulation rates/pressures at the perforations to clear solids),
the operator may initiate a reverse circulation cycle as described
above. That is, flow downhole through the tubing string may be
terminated to allow annulus fluid to enter the tool string through
the equalization ports, unseating the ball valve and allowing
upward flow through the tubing string to surface. During such
reverse circulation, the equalizer valve remains closed to the
annulus beneath the sealing assembly.
[0096] A method for deploying and using the above-described tool
assembly, and similar functioning tool assemblies, would include
the following steps, which may be performed in any logical order
based on the particular configuration of tool assembly used: lining
a wellbore, wherein the liner comprises one or more ported tubular
segments, each ported tubular segment having one or more lateral
treatment ports for communication of fluid from inside the liner to
outside; running a tool string downhole to a predetermined depth
corresponding to one of the ported tubular segments, the tool
string including a hydra-jet perforating assembly and a sealing or
anchor assembly; setting the isolation assembly against the
wellbore casing; pumping a treatment fluid down the wellbore
annulus from surface through the ported tubular; and monitoring
fracture extension pressure during treatment.
[0097] In addition, any or all of the following additional steps
may be performed: Engaging a sliding sleeve with the sealing or
anchor assembly and applying a force to the sleeve to slide the
sleeve; Opening the treatment ports; reverse circulating annulus
fluid to surface through the tubing string; equalizing pressure
above and below the sealing device or isolation assembly;
equalizing pressure between the tubing string and wellbore annulus
without unseating same from the casing; unseating the sealing
assembly from the casing; repeating any or all of the above steps
within the same wellbore interval; creating a new perforation in
the casing by jetting abrasive fluid from the hydra-jet perforating
assembly; and, moving the tool string to another predetermined
interval within the same wellbore and repeating any or all of the
above steps.
[0098] Should a blockage occur downhole, for example above a
sealing device within the assembly, delivery of fluid through the
tubing string at rates and pressures sufficient to clear the
blockage may not be possible, and likewise, delivery of clear fluid
to the wellbore annulus may not dislodge the debris. Accordingly,
in such situations, reverse circulation may be effected while the
inner and outer ports remain aligned, simply by manipulating the
type and rate of fluid delivered to the tubing string and wellbore
annulus from surface. Where the hydraulic pressure within the
wellbore annulus exceeds the hydraulic pressure down the tubing
string (for example when fluid delivery to the tubing string
ceases), fluid within the equalization valve will force the ball to
unseat, providing reverse circulation to surface through the tubing
string, carrying flowable solids.
[0099] Further, the plug may be removed from the lower mandrel by
application of force to the pull tube (by pulling on the tubing
string from surface). In this unseated position, a further flowpath
is opened from the lower tool mandrel to the inner valve housing
(and thereby to the tubing string and wellbore annulus). Where a
sealing device is present beneath the equalization device, pressure
across the sealing device will be equalized allowing unsetting of
the sealing device.
[0100] It should be noted that the fluid flowpath from outer ports
18 to the tubing string is available in any position of the
equalization plug. That is, this flowpath is only blocked when the
ball is set within the seat based on fluid down tubing string. When
the equalization plug is in its lowermost position, the inner and
outer ports are aligned to permit flow into and out of the
equalization valve, but fluid cannot pass down through the lower
assembly mandrel. When the equalization plug is in the unsealed
position, the inner and outer ports are not aligned, but fluid may
still pass through each set of ports, into and out of the
equalization valve. Fluid may also pass to and from the lower
assembly mandrel. In either position, when the pressure beneath the
ball valve is sufficient to unseat the ball, fluid may also flow
upward through the tubing string.
[0101] The sealing device may be set against any tubular, including
a sliding sleeve as shown in FIG. 4. Once set, application of force
(mechanical force or hydraulic pressure) to the sealing device will
drive the sliding sleeve downward, opening the ports.
Example 2
Tool Assembly with Straddle Seals
[0102] With reference to the tool assembly shown in FIG. 2, a tool
string is deployed on tubing string such as jointed pipe,
concentric tubing, or coiled tubing. The tool string will typically
include: a treatment assembly with upper and lower isolation
elements, a treatment aperture between the isolation elements, and
a jet perforation device for jetting abrasive fluid against the
casing. A bypass valve and anchoring assembly may be present to
engage the casing during treatment.
[0103] Various sealing devices for use within the tool assembly to
isolate the zone of interest are available, including friction
cups, inflatable packers, and compressible sealing elements. In the
particular embodiments illustrated and discussed herein, friction
cups are shown straddling the fracturing ports of the tool.
Alternate selections and arrangement of various components of the
tool string may be made in accordance with the degree of variation
and experimentation typical in this art field.
[0104] As shown, the anchor assembly 27 includes an anchor device
28 and actuator assembly (in the present drawings cone element 29),
a bypass/equalization valve 24. Suitable anchoring devices may
include inflatable packers, compressible packers, drag blocks, and
other devices known in the art. The anchor device depicted in FIG.
2 is a set of mechanical slips driven outwardly by downward
movement of the cone 29. The bypass assembly is controlled from
surface by applying a mechanical force to the coiled tubing, which
drives a pin within an auto J profile about the tool mandrel.
[0105] The anchoring device is provided for stability in setting
the tool, and to prevent sliding of the tool assembly within the
wellbore during treatment. Further, the anchoring device allows
controlled actuation of the bypass valve/plug within the housing by
application of mechanical force to the tubing string from surface.
Simple mechanical actuation of the anchor is generally preferred to
provide adequate control over setting of the anchor, and to
minimize failure or debris-related jamming during setting and
releasing the anchor. Mechanical actuation of the anchor assembly
is loosely coupled to actuation of the bypass valve, allowing
coordination between these two slidable mechanisms. The presence of
a mechanical casing collar locator, or other device providing some
degree of friction against the casing, is helpful in providing
resistance against which the anchor and bypass/equalization valve
may be mechanically actuated.
[0106] That is, when placed downhole at an appropriate location,
the fingers of the mechanical casing collar locator provide
sufficient drag resistance for manipulation of the auto J mechanism
by application of force to the tubing string. When the pin is
driven towards its downward-most pin stop in the J profile, the
cone 29 is driven against the slips, forcing them outward against
the casing, acting as an anchor within the wellbore. When used in
accordance with the present method, the tool is positioned with one
or both sets of friction cups between the sleeve ports 34 of the
annular channel 35 in the ported casing collar 30. Treatment fluid
is applied to one of the sleeve ports (in the collar shown in FIG.
3, to the upper port 34a), driving the sliding sleeve 33 downward
toward the lower sleeve port 34b. Once the treatment port 31 has
been uncovered, treatment fluid will enter the port. Pressurized
delivery of further amounts of fluid will erode any cement behind
the port and reach the formation.
[0107] With reference to FIG. 2b, the bypass valve includes a
bypass plug 24a slidable within an equalization valve housing 24b.
Such slidable movement is actuated from surface by pulling or
pushing on the tubing, which is anchored to the assembly by a main
pull tube. The main pull tube is generally cylindrical and provides
an open central passageway for fluid communication through the
housing from the tubing. The bypass plug 24a is anchored over the
pull tube, forming an upper shoulder that limits the extent of
travel of the bypass plug 24a within the valve housing 24b.
Specifically, an upper lock nut is attached to the valve housing
24b and seals against the outer surface of the pull tube, defining
a stop for abutment against the upper shoulder of the bypass plug
24a.
[0108] The lower end of the valve housing 24b is anchored over a
mandrel, defining a lowermost limit to which the bypass plug 24a
may travel within the valve housing 24b. The bypass plug 24a is
closed at its lower end, and is overlaid with a bonded seal. This
solid plug end and bonded seal are sized to engage the inner
diameter of the lower tool assembly mandrel, preventing fluid
communication between wellbore annulus/tubing string and the lower
wellbore when the bypass plug 24a has reached the lower limit of
travel.
[0109] Closing of the bypass prevents fluid passage from the tubing
string to below, but the bypass may be opened by applying
sufficient pull force to the coiled tubing. This pull force is less
than the pull force required to unset the anchor due to the
slidability of the bypass plug 24a within the housing 24b.
Accordingly, the equalization valve may be opened by application of
pulling force to the tubing string while the anchor device remains
set against the wellbore casing. This allows equalization of
pressure from the isolated zone and unsetting of the cup seals
without slippage and damage to the cup seals while pressure is
being equalized.
[0110] Notably, the bypass valve 24 provides a central fluid
passageway from the tubing to the lower wellbore. Bypass plug 24a
is slidable within the assembly upon application of force to the
tubing string, to open and close the passageway. Notably, while the
states of the bypass and anchor are both dependent on application
of force to the tubing string from surface, the bypass plug is
actuated initially without any movement of the pin within the J
slot.
[0111] When this tool string is assembled and deployed downhole on
tubing for the purpose of shifting the sliding sleeve shown in FIG.
3, it may be positioned with the lower cup between the sleeve ports
of a particular ported collar of interest. That is, the lower seals
are positioned below the treatment port, but above the lower sleeve
port. The bypass valve 24 is closed and the anchor set against the
casing, and fluid is pumped down the tubing under pressure, exiting
the tubing string at treatment apertures 21, as the closed bypass
valve prevents fluid from passing down the tool string to the jet
perforation device 25. Fluid delivery through the apertures 11
results in flaring of the friction cups 22, 23, with the flared
cups sealing against the casing. Once the cups have sealed against
the wellbore, the hydraulic pressure will rise within the isolated
interval, and fluid will enter the upper sleeve port, ultimately
displacing the sliding sleeve and opening the treatment port. Once
opened, continued delivery of fluid will result in erosion of any
cement behind the treatment port, and delivery of treatment fluid
to the formation.
[0112] When treatment is terminated, the bypass valve 24 is pulled
open to release pressure from the isolated zone, allowing fluid and
debris to flow downhole through the bottom portion of the tool
string. Once the pressure within the fractured zone is relieved,
the cup seals relax to their running position. When treatment is
complete, the cone 29 is removed from engagement with the
inwardly-biased slips by manipulation of the pin within the J
profile to the release position, allowing retraction of the slips
28 from the casing. The anchor is thereby unset and the tool string
can be moved to the next interval of interest or retrieved from the
wellbore.
[0113] If perforation of the wellbore is desired, the bypass valve
24 is open and the friction cups are set across the wellbore above
the zone to be perforated. Pumping abrasive fluid down the tubing
string will deliver fluid preferentially through the treatment
ports 11 until the friction cups seal against the wellbore. As this
interval is unperforated, once the interval is pressurized, fluid
will be directed down the assembly to exit jet nozzles 26.
Continued delivery of fluid will result in jetting of abrasive
fluid against the casing to perforate the wellbore adjacent the jet
nozzles. When fluid pressure is applied the cup seals will engage
the casing, and the tool string will remain fixed, stabilizing the
jet sub while abrasive fluid is jetted through nozzles 26.
[0114] In order to allow fluid delivered to the tubing string to
reach jet nozzles 26, the bypass valve must be in the open
position. It has been noted during use that when fluid is delivered
to the bypass valve at high rates, the pressure within the valve
typically tends to drive the valve open. That is, a physical force
should be applied to hold the valve closed, for example by setting
the anchor. Accordingly, when jet perforation is desired, the valve
is opened by pulling the tubing string uphole to the perforation
location. When fluid delivery is initiated with the bypass valve
open, the hydraulic pressure applied to the tubing string (and
through treatment apertures) will cause the cup seals to seal
against the casing. If no perforation is present within that
interval, the hydraulic pressure within the interval will be
maintained between the cups, and further pressurized fluid in the
tubing will be forced/jetted through the nozzles 26. Fluid jetted
from the nozzles will perforate or erode the casing and, upon
continued fluid application, may pass down the wellbore to open
perforations in other permeable zones. Typically, the fluid jetted
from nozzles 26 will be abrasive fluid, as generally used in sand
jet perforating techniques known in the prior art.
[0115] Once jetting is accomplished, fluid delivery is typically
terminated and the pressure within the tubing string and straddled
interval is dissipated. The tool may then be moved to initiate a
further perforation, or a treatment operation.
Example 3
Method for Shifting Sliding Sleeve Using Tool Deployed on Coiled
Tubing
[0116] With reference to the tool assembly shown in FIG. 1 and the
sliding sleeve shown in FIG. 4, a method is provided for
mechanically shifting a sliding sleeve using a tool deployed
downhole on coiled tubing, by application of downhole force to the
tool assembly.
[0117] The wellbore is cased, with ported subs used to join
adjacent lengths of tubing at locations corresponding to where
treatment may later be desired. The casing is assembled and
cemented in hole with the ports in the closed position, as secured
by shear pin 43.
[0118] A completion tool having the general configuration as shown
in FIG. 1 is attached to coiled tubing and is lowered downhole to a
location below the lowermost ported casing collar. The collar
locator 13 is of a profile corresponding with the space in the
lower end of the collar. That is, the radially enlarged annular
space defined between the lowermost edge of the sliding sleeve and
the lowermost inner surface of the collar when the sleeve is in the
port closed position.
[0119] As the tool is slowly pulled upward within the wellbore, the
collar locator 13 will become engaged within the above-mentioned
radially enlarged annular space, identifying to the operator the
position of the tool assembly at the lowermost ported collar to be
opened and treated. The packer 11 is set by application of
mechanical force to the tubing string, with the aid of mechanical
slips 14 to set the packer against the inner surface of the sleeve.
Application of this mechanical force will also close the
equalization valve 12 such that the wellbore above the packer is
hydraulically sealed from the wellbore below. As further mechanical
pressure is applied to the coiled tubing, additional downward force
may be applied by delivering treatment fluid down the wellbore
annulus (and to down the coiled tubing to the extent that will
avoid collapse of the tubing). As pressure against the packer, and
sliding sleeve 41, builds, the shear pin 43 will shear. The sleeve
simultaneously shift down the casing collar to open (or unblock)
the ports 42 in the casing collar, allowing treatment fluid to
enter the ports and reach the formation. When the sleeve moves
down, the collar locator dogs are pushed out of the locating
profile. After the zone is treated, the collar locator can move
freely through the sleeve since the mandrel is now covering the
indicating profile. Free uphole movement of the collar locator past
the sleeve confirms that the sleeve is shifted.
[0120] During treatment, the operator is monitoring wellbore
conditions as in Examples 1 and 2 above. Should it be determined
that fluid is not being delivered to the formation through the
ports, attempts may be made to use alternate circulation flowpaths
to clear a blockage. Should these further attempts to treat the
wellbore continue to be unsuccessful, fluid can be delivered at
high volumes through the tubing to jet fluid from the perforation
nozzles 10 in the tool assembly, while the equalization valve 12
remains closed, to jet new perforations through the casing. The
operator may wish to unset the packer and adjust the position of
the assembly to prior to jetting such new perforations. Upon
re-perforation, treatment of the formation may be continued.
[0121] After treatment of the lowermost ported collar is complete,
the packer 11 is unset from the wellbore, and the work string is
pulled upward until the collar locator engages within another
ported collar. The process is repeated, working upwards to surface.
This progression, in an upward direction, enables each opened
ported collar to be treated in isolation from the remaining
wellbore intervals, as only a single opened port will be present
above the set packer for each treatment application.
[0122] The tool may also be configured to open the ports in a
downhole direction, and treatment of the formation could be
accomplished in any order with or without isolation of each ported
collar from the remaining opened collars during treatment.
[0123] The above-described embodiments of the present invention are
intended to be examples only. Each of the features, elements, and
steps of the above-described embodiments may be combined in any
suitable manner in accordance with the general spirit of the
teachings provided herein. Alterations, modifications and
variations may be effected by those of skill in the art without
departing from the scope of the invention, which is defined solely
by the claims appended hereto.
[0124] The foregoing presents a particular embodiment of a system
embodying the principles of the invention. Those skilled in the art
will be able to devise alternatives and variations which, even if
not explicitly disclosed herein, embody those principles and are
thus within the invention's spirit and scope. Although particular
embodiments of the present invention have been shown and described,
they are not intended to limit what this patent covers. One skilled
in the art will understand that various changes and modifications
may be made without departing from the scope of the present
invention as literally and equivalently covered by the following
claims.
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