U.S. patent application number 16/399489 was filed with the patent office on 2019-11-21 for tools and methods for use in completion of a wellbore.
The applicant listed for this patent is NCS MULTISTAGE, INC.. Invention is credited to Donald Getzlaf, Robert Nipper, Marty Stromquist, Timothy H. Willems.
Application Number | 20190353006 16/399489 |
Document ID | / |
Family ID | 44303582 |
Filed Date | 2019-11-21 |
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United States Patent
Application |
20190353006 |
Kind Code |
A1 |
Getzlaf; Donald ; et
al. |
November 21, 2019 |
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. A tool assembly and method for
completing a well are also provided. The tool includes debris
relief features that enable use in solids-laden environments, for
example in the presence of sand. Forward and reverse circulation
pathways to the isolated interval are present to allow clearing of
debris from the wellbore annulus while the sealing device remains
set against the wellbore.
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, INC. |
Calgary |
|
CA |
|
|
Family ID: |
44303582 |
Appl. No.: |
16/399489 |
Filed: |
April 30, 2019 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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15187507 |
Jun 20, 2016 |
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16399489 |
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|
14317975 |
Jun 27, 2014 |
9745826 |
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15187507 |
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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 23/01 20130101; E21B 2200/06 20200501; E21B 34/063 20130101;
E21B 43/25 20130101; E21B 33/129 20130101; E21B 43/26 20130101;
E21B 34/12 20130101; E21B 34/14 20130101; E21B 33/127 20130101;
E21B 43/12 20130101; E21B 43/00 20130101; E21B 17/1085 20130101;
E21B 17/20 20130101; E21B 47/06 20130101; E21B 33/12 20130101; E21B
17/00 20130101; E21B 43/114 20130101; E21B 33/134 20130101; E21B
43/267 20130101; E21B 23/02 20130101; E21B 34/10 20130101; E21B
43/14 20130101; E21B 34/08 20130101 |
International
Class: |
E21B 34/14 20060101
E21B034/14; E21B 47/06 20060101 E21B047/06; E21B 23/02 20060101
E21B023/02; E21B 33/12 20060101 E21B033/12; E21B 17/00 20060101
E21B017/00; E21B 34/08 20060101 E21B034/08; E21B 43/00 20060101
E21B043/00; E21B 43/16 20060101 E21B043/16; E21B 17/20 20060101
E21B017/20; E21B 43/12 20060101 E21B043/12; E21B 34/06 20060101
E21B034/06; E21B 43/25 20060101 E21B043/25; E21B 43/14 20060101
E21B043/14; E21B 43/114 20060101 E21B043/114; E21B 34/12 20060101
E21B034/12; E21B 34/10 20060101 E21B034/10; E21B 33/129 20060101
E21B033/129; E21B 23/01 20060101 E21B023/01; E21B 33/134 20060101
E21B033/134 |
Claims
1. An assembly for treating an interval of a wellbore, comprising:
a resettable sealing device deployed on a tubing string, the
sealing device including a J-profile with a pin slidably-disposed
in said J-profile for actuating the sealing device, wherein the
J-profile comprises one or more debris discharge ports through the
J-profile to permit discharge of debris upon sliding movement of
the pin within the J-profile.
2. The assembly recited in claim 1, further comprising a locator
having outwardly biased locating members configured to slide
against a cased wellbore to verify a downhole location of the
assembly prior to actuation of the resettable sealing device.
3. The assembly recited in claim 2, wherein the locator comprises a
cavity beneath the outwardly biased locating members configured to
allow the passage of fluid and debris through the locator to the
tubing string.
4. The assembly recited in claim 1, wherein the pin is actuated
along the J-profile by application of mechanical force to the
tubing string.
5. The assembly recited in claim 1, wherein the J-profile has a
width that is at least 1/16 inch greater than a diameter of the pin
to allow debris movement within the J-profile without impeding
travel of the pin along the J-profile.
6. The assembly recited in claim 1, wherein the J-profile has a
depth that is at least 1/16 inch greater than a length of the pin
to allow debris movement within the J-profile without impeding
travel of the pin along the J-profile.
7. The assembly recited in claim 1, wherein the J-profile has a
width that is at least 1/16 inch greater than a diameter of the pin
and a depth that is at least 1/16 inch greater than a length of the
pin to allow debris movement within the J-profile without impeding
travel of the pin along the J-profile.
8. The assembly recited in claim 1, wherein the resettable sealing
device is a mechanical set packer.
9. An assembly for treating an interval of a wellbore, comprising:
a resettable sealing device deployed on a tubing string, the
sealing device including a J-profile with a pin slidably-disposed
in said J-profile for actuating the sealing device wherein the pin
is held to the assembly by a clutch ring, and wherein the clutch
ring comprises an aperture to permit discharge of the debris from
about the pin while the pin slides within the J-profile.
10. An assembly for treating an interval of a wellbore, comprising:
a resettable sealing device deployed on a tubing string, the
sealing device including a J-profile with a pin slidably disposed
in said J-profile for actuating the sealing device; an equalization
valve for actuating slidable movement of the sliding pin within the
resettable sealing device wherein the equalization valve comprises
an equalization valve plug slidably disposed within an equalization
valve housing continuous with the resettable sealing device for
actuating slidable movement of the pin within the J-profile,
wherein the J-profile comprises one or more debris discharge ports
through the J-profile to permit discharge of debris upon sliding
movement of the pin within the J-profile.
11. The assembly recited in claim 10, wherein the equalization plug
is slidably actuated by application of mechanical force to the
tubing string to set or unset the resettable sealing device within
the wellbore.
12. The assembly recited in claim 10, wherein the equalization
valve comprises at least one inner port providing fluid
communication between a central, axial bore within the equalization
valve plug and an outer surface of the equalization valve plug and
at least one outer port in the equalization valve housing.
13. The assembly recited in claim 12, wherein the at least one
inner port and the at least one outer port are substantially
co-planar when the equalization valve is in a closed position.
14. A method for the treatment of a formation intersected by a
cased wellbore, the method comprising the steps of: providing a
tool assembly comprising a sealing device comprising a J-profile
with a pin for use in actuating the sealing device; deploying the
tool assembly on a tubing string within the cased wellbore; setting
the sealing device against the cased wellbore; while the sealing
device remains set against the cased wellbore, circulating
treatment fluid down an annulus formed by the cased wellbore to
treat the formation through one or more openings in the casing of
the cased wellbore; \ circulating the treatment fluid from the
annulus; reverse circulating the treatment fluid from the annulus
to surface through the tubing string; and unsetting the sealing
device from the cased wellbore, wherein the J-profile comprises one
or more debris discharge ports through the J-profile to permit
discharge of debris upon sliding movement of the pin within the
J-profile.
15. The method recited in claim 14, wherein the sealing device
remains set against the cased wellbore during reverse
circulation.
16. The method recited in claim 14, wherein the treatment fluid
comprises flowable solids, and wherein the flowable solids are
circulated through the J-profile.
17. A method for treatment of a formation intersected by a cased
wellbore, the method comprising the steps of: providing a tool
assembly comprising a sealing device comprising a J-profile with a
pin for use in actuating the sealing device; deploying the tool
assembly on a tubing string within the cased wellbore; setting the
sealing device against the cased wellbore; while the sealing device
is set against the cased wellbore, circulating treatment fluid down
an annulus between the cased wellbore and the tool assembly to
treat the formation through one or more openings in the casing of
the cased wellbore; opening an equalization passage extending
through the sealing device to permit fluid communication of a first
portion of the annulus beneath the sealing device to a second
portion of the annulus above the sealing device; and, unsetting the
sealing device from the cased wellbore, wherein the J-profile
comprises one or more debris discharge ports through the J-profile
to permit discharge of debris upon sliding movement of the pin
within the J-profile.
18. A pin carrier configured for use with a J-profile of a downhole
tool comprising: a generally annular body having an upper surface,
a lower surface, a generally cylindrical outer surface, and a
generally cylindrical inner surface; at least one passageway
extending from the upper surface to the lower surface of the
annular body and sized to allow the passage of fluid and debris
through the pin carrier.
19. The pin carrier recited in claim 18 wherein the at least one
passageway extending from the upper surface to the lower surface of
the annular body is a cutout in the generally cylindrical inner
surface of the generally annular body.
20. The pin carrier recited in claim 19 wherein the cutout in the
generally cylindrical inner surface of the generally annular body
has a semi-circular transverse cross section.
21. The pin carrier recited in claim 18 wherein the generally
annular body is a two-piece body wherein each piece of the
two-piece body has a substantially semi-circular transverse cross
section.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is a continuation of U.S. application Ser.
No. 15/187,507 filed Jun. 20, 2016, which is a continuation of U.S.
application Ser. No. 14/317,975 filed Jun. 27, 2014 now issued as
U.S. Pat. No. 9,745,826, which is a division of U.S. application
Ser. No. 13/100,796 filed May 4, 2011 now issued as U.S. Pat. No.
8,794,331, 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. The present invention also
relates to a tool string for use in stimulating multiple intervals
of a wellbore in the presence of flowable solids, such as sand.
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.
[0006] Recently, tool assemblies for performing multiple functions
in a single trip downhole have been developed, greatly reducing the
cost of well completion operations. For example, CA 2,397,460
describes a bottom hole assembly for use in the sequential
perforation and treatment of multiple wellbore intervals in a
single trip downhole. Perforation with an explosive charge followed
by sealing of the wellbore and application of treatment to the
wellbore annulus is described. No active debris relief is described
to maintain tool functionality in the presence of debris/solids,
such as sand. Accordingly, the use of this tool in the presence of
flowable solids would be associated with significant risk of
debris-related tool malfunction, jamming or immobility of the tool
assembly, and potential loss of the well if the tool assembly
cannot be retrieved.
[0007] The use of jet nozzles in cleaning cased wellbores, and
fracturing uncased wellbores, has been previously described in
detail. Notably, CA 2,621,572 describes the deployment of a fluid
jetting device above an inflatable packer. This type of packer
provides minimal sealing against the uncased wellbore, allowing the
assembly to travel up or downhole while the packers are inflated.
This system is not suitable for use in perforation of a cased
wellbore or in debris-laden environments, due in part to the
imperfect seal provided by the inflatable packers, and the
inability to clear solids that may settle over the packer and/or
may block the jet nozzles.
[0008] Use of any sealing device in the presence of significant
amounts of sand or other solids increases the risk of tool
malfunction. Further, the tool may be lost downhole should a solids
blockage occur during treatment, or when the formation expels
solids upon release of hydraulic pressure in the wellbore annulus
when treatment is complete. Moreover, when jetting abrasive fluid
to perforate a wellbore casing, the prior art does not provide a
suitable method for delivering clear fluid to the
perforations/removing settled solids from the perforations in the
event of a solids blockage. Typical completion assemblies have many
moving components for actuating various downhole functions, and the
presence of sand or other solids within these actuation mechanisms
would risk jamming these mechanisms, causing a malfunction or
permanent damage to the tool or well. Correcting such a situation
is costly, and poses significant delays in the completion of the
well. Accordingly, well operators, fracturing companies, and tool
suppliers/service providers are typically very cautious in their
use of sand and other flowable solids downhole. The addition of
further components to the assembly adds further risk of solids
blockages in tool actuation, and during travel of the tool from one
segment of the wellbore to another, further risking damage to the
assembly. Increasing the number of segments to be perforated and
treated in a single trip also typically increases the size of the
assembly, as additional perforating charges are required. Excessive
assembly lengths become cumbersome to deploy, and increase the
difficulty in removal of the assembly from the wellbore in the
presence of flowable solids.
BRIEF SUMMARY OF THE INVENTION
[0009] 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.
[0010] 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.
[0011] 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.
[0012] In another embodiment, the sealing member is a mechanical
set packer, inflatable packer, or bridge plug.
[0013] 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.
[0014] In further embodiments, the step of sliding the sleeve
comprises application of hydraulic pressure and/or mechanical force
to the sleeve.
[0015] In an embodiment, the tubing string is coiled tubing.
[0016] 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.
[0017] 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.
[0018] 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.
[0019] 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.
[0020] 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.
[0021] In an embodiment, the step of applying a downward force
comprises application of hydraulic pressure to the wellbore
annulus.
[0022] 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.
[0023] 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.
[0024] 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.
[0025] 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
[0026] In an embodiment, the step of applying a downward force
comprises applying hydraulic pressure to the wellbore annulus.
[0027] 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.
[0028] 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.
[0029] 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.
[0030] In an embodiment, the means for locking comprises engageable
profiles along adjacent surfaces of the sleeve and housing.
[0031] In another aspect, there is provided an assembly for
deployment within a wellbore, the assembly comprising: a
perforation device; a resettable sealing device operatively
assembled with the perforation device for deployment on tubing
string; a sliding member operatively associated with the tubing
string, for use in actuation of the resettable sealing device; and
a debris relief passageway operatively associated with the sliding
member, for use in discharge of settled debris about the sliding
member.
[0032] In one embodiment, the wellbore is a cased wellbore, and the
sliding member is a mechanical casing collar locator having
outwardly biased locating members for sliding against the casing to
verify the downhole location of the tool assembly prior to
actuation of the sealing device. In a further embodiment, the
debris relief passageway may comprise one or more apertures through
the locating members to allow passage of fluid and debris through
the locating members, thereby preventing accumulation of settled
debris against the locating members.
[0033] In another embodiment, the sliding member is an auto-J
profile slidable against a pin for actuation of the sealing member.
The debris relief passageway may comprise one or more debris ports
through the J-profile to permit discharge of debris upon slidable
movement of the pin within the J-profile. In a further embodiment,
the J-slot is sized at least 1/16 inch greater than the pin, to
allow debris accumulation and movement within the J-profile without
impeding travel of the pin along the J-profile. The pin may be held
to the assembly by a clutch ring, and the clutch ring may comprise
debris relief passageways to permit discharge of debris from about
the pin while the pin slides within the J-profile.
[0034] In another embodiment, the sliding member is an equalization
valve actuable to open a flowpath within the sealing device, for
unseating the sealing device from the wellbore. In a further
embodiment, the equalization valve comprises an equalization plug
slidable within an equalization valve housing. The equalization
plug, in one embodiment, may be actuated by application of force to
the tubing string.
[0035] In certain embodiments, the perforation device is a fluid
jet perforation device assembled above the sealing device. In a
further embodiment, the resettable sealing device comprises a
compressible sealing element actuated by the sliding of a pin
within an auto J profile. The J profile may comprise debris ports
for discharging debris upon slidable movement of the pin within the
J-profile.
[0036] In one embodiment, the J-slot is sized at least 1/16 inch
greater (in width and/or depth) than the pin, to allow debris
accumulation and movement within the J-profile without impeding
travel of the pin along the J-profile.
[0037] The pin, in any of the above-mentioned embodiments, may be
held to the assembly by a clutch ring comprising debris relief
passageways to permit discharge of debris from about the pin while
the pin slides within the J-profile.
[0038] In another embodiment, the assembly further comprises a
mechanical casing collar locator having outwardly biased locating
members for sliding against the casing to verify the downhole
location of the tool assembly prior to actuation of the sealing
device. One or more apertures through the mandrel and/or locating
members may be present to allow passage of fluid and debris through
the locating members, thereby preventing accumulation of settled
debris against the locating members.
[0039] In accordance with another aspect of the invention, there is
provided a multi-function valve for use within a downhole assembly
deployed on tubing string, the multi-function valve comprising: a
valve housing having an internal cavity continuous with a length of
tubing string and with a lower assembly mandrel, the valve housing
further comprising at least one cross flow port, to permit fluid
cross flow through the internal cavity; a forward flow-stop valve
operatively associated with the valve housing, for preventing fluid
flow from the tubing string into the valve housing; a valve plug
slidably disposed within the valve housing for movement between a
flow position and a sealed position, the valve plug comprising: an
internal fluid flowpath continuous with the forward flow-stop valve
and with the cross flow port of the valve housing when the valve
plug is in either the sealed or flow position, and, a valve stem
for sealing within the lower assembly mandrel when the valve plug
is in the sealed position, to prevent fluid communication between
the internal cavity of the valve housing and the lower assembly
mandrel.
[0040] In one embodiment, the valve plug is operationally coupled
to the tubing string so as to be actuable upon application of force
to the tubing string.
[0041] In accordance with another aspect of the invention, there is
provided a method for abrasive perforation and treatment of a
formation intersected by a cased wellbore, the method comprising
the steps of: deploying a tool assembly within the wellbore on
tubing string, the tool assembly comprising a fluid jet perforation
device and a sealing device; setting the sealing device against the
wellbore; jetting abrasive fluid from the perforation device to
perforate the wellbore casing; and circulating treatment fluid down
the wellbore annulus to treat the perforations and to flow solids
through at least a portion of the tool assembly.
[0042] In one embodiment, the sealing device comprises a
compressible sealing element actuated by application of force to
the tubing string. In a further embodiment, the sealing device is
actuated by sliding of a pin within an auto-J profile in response
to an application of force to the tubing string.
[0043] In an embodiment, the abrasive fluid comprises sand. The
treatment fluid may comprise flowable solids.
[0044] In an embodiment, the method comprises the step of
delivering fluid to the tubing string while treatment is delivered
down the wellbore annulus.
[0045] In various embodiments, the method further comprises the
steps of: monitoring the rate and pressure of fluid delivery down
the tubing string; monitoring the rate and pressure of fluid
delivery down the wellbore annulus; and estimating the fracture
extension pressure during treatment.
[0046] In an embodiment, the method further comprises the step of
reverse circulating fluid from the wellbore annulus to surface
through the tubing string.
[0047] In another embodiment, the method further comprises the step
of equalizing pressure above and below the sealing device by
applying a force to the tubing string to actuate an equalization
valve.
[0048] In another embodiment, the method further comprises the step
of equalizing pressure between the tubing string and wellbore
annulus without unseating the sealing device from the wellbore
casing.
[0049] In another embodiment, the method further comprises the step
of moving the tool assembly to another wellbore interval and
repeating any or all of the above steps.
[0050] In another embodiment, the method further comprises the step
of opening an equalization passage from beneath the sealing device
to the wellbore annulus above the sealing device.
[0051] In accordance with another aspect, there is provided a
mechanical casing collar locator for use within a downhole tool
assembly, the mechanical casing collar locator comprising outwardly
biased locating members for sliding against the casing to verify
the downhole location of the tool assembly prior to actuation of
the sealing device.
[0052] In accordance with one embodiment, the collar locator
comprises one or more apertures through the locating members to
allow passage of fluid and debris through the locating members,
thereby preventing accumulation of settled debris against the
locating members.
[0053] In accordance with another aspect, there is provided an
actuation device for use with a resettable downhole tool in the
presence of flowable solids, the actuation device comprising a pin
slidable within an auto J profile, wherein the auto J profile
comprises debris ports for discharging debris upon slidable
movement of the pin within the J-profile.
[0054] In one embodiment, the J-slot is sized at least 1/16 inch
greater than the pin, to allow debris accumulation and movement
within the J-profile without impeding travel of the pin along the
J-profile. The pin may be held to the assembly by a clutch ring
comprising debris relief passageways to permit discharge of debris
from about the pin while the pin slides within the J-profile.
[0055] 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)
[0056] Embodiments of the present invention will now be described,
by way of example only, with reference to the attached drawing
figures, wherein:
[0057] FIG. 1A is a perspective view of a tool assembly, in one
embodiment, for use in accordance with the methods described
herein;
[0058] FIG. 1B is a schematic cross-sectional view of the
equalizing valve and housing shown in FIG. 1A;
[0059] FIG. 2A is a perspective view of a tool assembly, in another
embodiment, for use in accordance with the methods described
herein;
[0060] FIG. 2B is a schematic cross-sectional view of the
equalizing valve 24 shown in FIG. 2A;
[0061] 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;
[0062] FIG. 4A is a perspective, partial cross-section view of a
ported sub having an internal mechanically operated sliding
sleeve;
[0063] FIG. 4B is a perspective, cross-section view of the ported
sub of FIG. 4A, with the sliding sleeve shifted to an open port
position;
[0064] 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;
[0065] 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;
[0066] FIG. 6 is a perspective view of a tool assembly deployed
within a wellbore in accordance with one embodiment, with the
wellbore shown in cross section;
[0067] FIG. 7 is a cross sectional view of a jet perforation device
in accordance with one embodiment;
[0068] FIG. 8 is a cross sectional view of an equalization device
in accordance with one embodiment;
[0069] FIG. 9A is a cross sectional view of the equalization plug
141 shown in FIG. 8;
[0070] FIG. 9B is a cross sectional of the equalization valve
housing 145 shown in FIG. 8;
[0071] FIG. 10 is a cross sectional view of a portion of a tool
assembly in accordance with one embodiment, in which the
equalization device of FIG. 8 is shown assembled with a sealing
device 130;
[0072] FIG. 11A is a perspective and partial cutaway view of the
sealing assembly mandrel 135 shown in FIG. 8;
[0073] FIG. 11B is a diagram of the J-profile applied to the
sealing assembly mandrel shown in FIG. 10;
[0074] FIGS. 11C and 11D are top and side views, respectively, of
the clutch ring 136 shown in FIG. 10; and,
[0075] FIG. 12 is a perspective and partial cutaway view of a
mechanical casing collar locator for use within a tool assembly in
accordance with one embodiment.
DETAILED DESCRIPTION OF THE INVENTION
[0076] 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.
[0077] 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.
[0078] 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.
[0079] 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.
[0080] 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.
[0081] 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.
[0082] 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.
[0083] 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
[0084] 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.
[0085] 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.
[0086] 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.
[0087] 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.
[0088] 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.
[0089] 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.
[0090] 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.
[0091] 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.
[0092] 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
[0093] 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.
[0094] With reference to FIG. 1A and FIG. 1B, and to Applicants'
U.S. patent application Ser. No. 12/708,709 now issued as U.S. Pat.
No. 8,490,702, 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.
[0095] With reference to FIG. 2, and to Applicants' U.S. patent
application Ser. No. 13/078,584 now issued as U.S. Pat. No.
8,201,631, 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.
[0096] 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
the pins holding the sleeve to the housing 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.
[0097] 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.
[0098] 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.
[0099] 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
[0100] 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.
[0101] 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.
[0102] 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.
[0103] 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.
[0104] 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.
[0105] 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.
[0106] 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.
[0107] 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.
[0108] 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
[0109] Tool Assembly with Single Sealing Member
[0110] 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.
[0111] 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.
[0112] 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.
[0113] 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.
[0114] 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.
[0115] 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 bottomhole pressure during treatment. The
significance of this monitoring will be explained below.
[0116] 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.
[0117] 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.
[0118] 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.
[0119] 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.
[0120] 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.
[0121] 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.
[0122] 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.
[0123] 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 19 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.
[0124] 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.
[0125] 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.
[0126] 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.
[0127] 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.
[0128] 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.
[0129] 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.
[0130] 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.
[0131] 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.
[0132] 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.
[0133] 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.
[0134] 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.
[0135] 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.
[0136] 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.
[0137] 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.
[0138] It should be noted that the fluid flowpath from outer ports
19 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.
[0139] 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
[0140] Tool Assembly with Straddle Seals
[0141] 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.
[0142] 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.
[0143] As shown, the anchor assembly 27 includes an anchor device,
an actuator assembly, and a bypass/equalization valve. 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. 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.
[0144] 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.
[0145] 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 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.
[0146] 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.
[0147] 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.
[0148] 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.
[0149] 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.
[0150] 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.
[0151] 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
anchor/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.
[0152] 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.
[0153] 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.
[0154] 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
[0155] With reference to the tool assembly shown in FIG. 1 and the
sliding sleeve shown in FIG. 4A and FIG. 4B, 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.
[0156] 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.
[0157] 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.
[0158] 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.
[0159] 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.
[0160] 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.
[0161] 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.
[0162] With reference to FIG. 6, a fluid jetting device 110 is
provided for creating perforations 120 in the casing 181, and a
sealing device 130 is provided for use in the isolation and
treatment of the perforated interval. The tool string 105 is
assembled and deployed downhole on tubing (for example coiled
tubing or jointed pipe) to the lowermost interval of interest. The
fluid jetting device 110 is then used to perforate the casing 181,
providing access to the hydrocarbon-bearing formation 190
surrounding the cased wellbore.
[0163] While the sealing device 130 is set against the casing 181
of the wellbore, a fluid treatment (for example a fracturing fluid)
is injected down the wellbore annulus 182 from surface under
pressure, which enters the formation 190 via the perforations 120,
to fracture the formation 190. Once the treatment is complete, the
hydraulic pressure in the annulus 182 is slowly dissipated, and the
sealing device 130 is released. The tool may then be moved up-hole
to the next interval of interest.
[0164] As the environment in which the present tool string is used
may be sand-laden (due to the formation characteristics, abrasive
fluids used in jetting, and/or proppant-laden treatment fluids),
there is a significant risk that debris may accumulate within the
apertures, slots, chambers, and moving parts of the tool during
deployment. For example, jet perforation using abrasive fluid may
cause solids to accumulate over the sealing device, if the sealing
device is set prior to perforation. Further, when applying a
proppant-laden fracturing fluid, proppant and/or formation debris
may accumulate over the sealing device, and enter the tool
assembly, settling in the moving external and internal workings of
the tool. Accordingly, debris relief may be incorporated into the
tool, as will be described in detail below.
[0165] Briefly, both forward and reverse circulation flowpaths
between the wellbore annulus and the inner mandrel of the tool
string are provided to allow debris to be carried in the forward or
reverse direction through the tool string. Further, debris relief
features are incorporated into the moving/sliding parts of the tool
string to prevent accumulation of sand, proppant, and other debris
that might otherwise prevent actuation or retrieval of the tool.
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.
Fluid Jetting Device
[0166] In the embodiment shown in the drawings, the perforation
device 110 is an abrasive fluid jet assembly, deployed on tubing
string (for example coiled tubing or jointed pipe). Such fluid
delivery assemblies with jet nozzles are generally known, and have
been used previously in well cleaning operations, application of
fracturing treatment, and in placing casing perforations. For
perforation operations, pressurized abrasive fluid is applied
through the tubing, and is forced through jet nozzles 111 to
perforate the wellbore.
[0167] In a typical jet perforation assembly 110, nozzles 111 are
typically inserts fixed within the perforation mandrel, the nozzles
having engineered apertures that allowing pressurized fluid to
escape at high velocities. As shown in FIG. 7, jet nozzles 111 are
arranged about the perforation mandrel as desired. Typically, about
four nozzles is suitable, however the number of nozzles may range
from one through about ten or more, depending on the length of the
span of the interval to be perforated. A specific volume of
abrasive fluid is delivered to the tubing string at a rate suitable
for jet perforation of the casing, after which the casing may be
tested or treatment initiated to confirm that suitable perforation
was effected.
[0168] Once perforation is successful, the abrasive jetted fluid
may be circulated from the wellbore to surface by flushing the
tubing string with an alternate fluid prior to treatment
application to the perforations (if desired). During treatment of
the perforations by application of fluid to the wellbore annulus
182, 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.
[0169] Alternatively, treatment down the wellbore annulus may be
possible without simultaneous delivery of fluid down the tubing
string. For example, if the jet nozzles can be closed, the tubing
string could be pressurized with fluid to avoid collapse during
treatment down the annulus. Other methods for treatment of the
perforations using the presently described tool string (with or
without modification) are possible, using the knowledge and
experience typical of operators in this field of art.
Sealing Device
[0170] As shown in the embodiment illustrated in FIG. 6, the
sealing device 130 is typically positioned downhole of the fluid
jetting assembly 110. This configuration allows the seal to be set
against the casing in advance of perforation, if desired, and to
remain set until treatment of the perforated interval is complete.
Alternatively, the seal may be located anywhere along the tool
assembly, and the tool string may repositioned after perforation is
complete prior to setting the sealing device below the perforations
for treatment.
[0171] Suitable sealing devices will permit isolation of the most
recently perforated 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. It is preferable
that the sealing device forms a hydraulic seal against the casing
to allow pressure testing of the sealing element prior to
treatment, and to enable reliable monitoring of the treatment
application pressure and bottomhole pressure during treatment. The
significance of this monitoring will be explained below.
[0172] Using a configuration in which a single sealing device is
positioned below the jetting device, perforation and treatment of
precise locations along a vertical or deviated wellbore may be
accomplished by incorporation of a depth locating device within the
assembly. Notably, a mechanical casing collar locator permits
precise setting of the sealing device in advance of perforation,
and maintains the position of the assembly during perforation and
treatment. This location ability, particularly in combination with
coiled tubing deployment, overcomes positional difficulties
commonly encountered with other perforation and treatment
systems.
[0173] The sealing device therefore serves to maintain the position
of the tool assembly downhole, and ensure the perforated wellbore
is hydraulically isolated from the previously treated portion of
the wellbore below. The sealing device shown in the drawings is a
mechanically actuated resettable packer. Other suitable sealing
devices may be used in substitution.
[0174] When the sealing device is set against the casing prior to
perforation, 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 uphole of previously treated
perforations. 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 182 from
surface.
[0175] As shown in FIG. 10, the sealing assembly 130 is
mechanically actuated, including a compressible packing element 131
for providing a hydraulic seal between the tool string and casing
when actuated, and slips 132 for engaging the casing to set the
compressible packing element 131. In the embodiment shown in FIGS.
10 through 11C, the mechanism for setting the sealing assembly
involves a stationary pin 133 sliding within a J profile 134 formed
about the sealing assembly mandrel 135. The pin 133 is held in
place against the bottom sub mandrel by a two-piece clutch ring
136, and the bottom sub mandrel 150 slides over the sealing
assembly mandrel 135, which bears the J profile. The clutch ring
has debris relief openings 137 for allowing passage of fluid and
solids during sliding of the pin 133 within the J profile 134.
[0176] Various J profiles suitable for actuating mechanical set
packers and other downhole tools are known within the art. One
suitable J profile 134 is shown in FIG. 11B, having three
sequential positions that are repeated about the mandrel. Debris
relief apertures 138 are present at various locations within the
J-profile to permit discharge of settled solids as the pin 133
slides within the J profile. The J slots 134 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.
[0177] With reference to the J profile shown in FIG. 11B, three pin
stop positions are shown, namely a compression set position 139a, a
seal release position 139b, and a running-in position 139c. The
sealing assembly mandrel 135 is coupled to the pull tube 149, which
is slidable with respect to the bottom sub mandrel 150 that holds
the pin 133. The bottom sub mandrel 150 also bears mechanical slips
for engaging the casing to provide resistance against sliding
movement of the sealing assembly mandrel 135, such that the pin 133
slides within the J profile 134 as the pull tube (and sealing
assembly mandrel) is manipulated from surface.
Equalization Valve
[0178] In order to equalize pressure across the sealing device and
permit unsetting of the compressible packing element under various
circumstances, an equalization valve 140 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.
[0179] As shown in FIG. 8, the present equalization valve is
operated by sliding movement of an equalization plug 141 within a
valve housing 145 (FIGS. 9A and 9B). 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 149. 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 141 is anchored over the pull tube 149, forming an upper
shoulder 141a that limits the extent of travel of the equalization
plug 141 within the valve housing 145. Specifically, an upper lock
nut 143 is attached to the valve housing 145 and seals against the
outer surface of the pull tube 149, defining a stop 143a for
abutment against the upper shoulder 141a of the equalization
plug.
[0180] The lower end of the valve housing 145 is anchored over
assembly mandrel 160, defining a lowermost limit to which the
equalization plug 141 may travel within the valve housing 145. It
should be noted that the equalization plug bears a hollow
cylindrical core that extends from the upper end of the
equalization plug 141 to the inner ports 142. That is, the
equalization plug 141 is closed at its lower end beneath the inner
ports, forming a profiled solid cylindrical plug 144a overlaid with
a bonded seal 144b. The solid plug end 144a and bonded seal 144b
are sized to engage the inner diameter of the lower tool mandrel
160, preventing fluid communication between wellbore annulus/tubing
string and the lower wellbore when the equalization plug 141 has
reached the lower limit of travel and the sealing device (downhole
of the equalization valve) is set against the casing.
[0181] The engagement of the bonded seal 144b within the mandrel
160 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.
[0182] With respect to debris relief, when the sealing device is
set against the wellbore casing with the equalization plug 141 in
the sealed, or lowermost, position, the inner ports 142 and outer
ports 146 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.
[0183] 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.
[0184] 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 144a and bonded seal 144b from within the lower
mandrel 160. This will allow equalization of pressure beneath and
above the seal, allowing it to be unset and moved up-hole to the
next interval.
[0185] 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.
[0186] The equalization valve therefore serves as a multi-function
valve, and may be incorporated into various types of downhole
assemblies, and manipulated to effect various functions, as
required. That is, the equalization valve may be placed within any
tubing-deployed assembly and positioned within the assembly to
provide selective reverse circulation capability, and to aid in
equalizing pressures between wellbore annulus segments, and with
the tubing string flowpath to surface. When the equalization plug
is 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. 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.
[0187] 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 when
incorporated into downhole assemblies deployed in sand-laden
environments.
[0188] It is noted that the presently described equalization plug
may be machined to any suitable configuration that will provide a
valve stem for seating within the lower assembly mandrel, and which
is actuable from surface without impeding flow from the outer ports
146 of the valve housing 145 to the ball valve. By similar logic,
the ball valve may be replaced with any suitable check
valve/one-way valve.
[0189] In the embodiment shown in the drawings, 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.
Further Debris Relief Features
[0190] The present J profile bears debris relief apertures 138 to
allow clearance of solid particles from the J slot that may
otherwise complicate setting and unsetting of the packer. The
relative proportions of the pin and slot include sufficient
clearance (for example 1/16 or 1/8-inch clearance) in both depth
and width to permit sliding of pin in the slot when a certain
amount of debris is present, enabling the sand to be driven along
the slot and through the apertures 138 by the pin during actuation
of the packer by application of force from surface. The number and
shape of the apertures may vary depending on the environment in
which the tool is used. For example, if a significant amount of
debris is expected to contact the J slot, the slot may instead
include a narrow opening along the entire base of the slot to allow
continuous debris movement through the J slot.
[0191] A mechanical casing collar locator (MCCL) is incorporated
into the particular tool string that is shown in the Figures. When
this type of locating device is present within a tool string, the
fingers 161 of the locator are typically biased outwardly so as to
slide against the casing as the assembly is moved within the
wellbore. As shown in FIG. 12, the MCCL mandrel 160 of the present
assembly includes fingers 161 that are biased (for example using
resilient element 162) outwardly so as to engage the casing as the
assembly is moved along the wellbore. As shown, each finger 161 is
held within a cavity against the resilient element 162 by a
retention sleeve 164 threaded over the MCCL mandrel 160. A narrow
slot 163 extends longitudinally within each cavity over which the
resilient element is placed, to allow fluid communication between
the cavity and the tubing string. Further, another slot within the
outer surface of the mandrel extends across each cavity such that
fluid may enter each cavity from the wellbore annulus. Once
assembled, a fluid flowpath extends between the wellbore annulus
182, to the cavity beneath each finger 161, and through the cavity
to the tubing string. Accordingly, this permits flushing of fluid
past the fingers during operation. This open design minimizes the
risk of debris accumulation adjacent the resilient element, which
may force the fingers to remain extended against the casing or
within a casing joint.
Detection of Adverse Events
[0192] 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.
[0193] During treatment of the perforations down the wellbore
annulus using the tool string shown in the Figures, 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.
[0194] 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 successfully, 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 133 to the unset
position 139b in the J profile. The assembly may then be moved
uphole to perforate and treat another interval.
[0195] 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.
[0196] 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.
Method
[0197] A method for deploying and using the above-described tool
assembly, and similar functioning tool assemblies, is provided. The
method includes at least the following steps, which may be
performed in any logical order based on the particular
configuration of tool assembly used: running a tool string downhole
to a predetermined depth, the tool string including a hydra-jet
perforating assembly and a packer assembly below the perforating
assembly setting the packer assembly against the wellbore casing
creating perforations in the casing by jetting fluid from nozzles
within the perforating assembly pumping a treatment fluid down the
wellbore annulus from surface under pressure, while simultaneously
pumping fluid down the tubing string and through the jet nozzles;
and monitoring fracture extension pressure during treatment.
[0198] In addition, any or all of the following additional steps
may be performed: reverse circulating annulus fluid to surface
through the tubing string equalizing pressure above and below the
sealing device 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 moving the tool
string to another predetermined interval within the same wellbore
and repeating any or all of the above steps
[0199] A method of providing a reverse circulation pathway within a
downhole assembly is described. This method is particularly useful
in sand-laden environments, where debris accumulation may require
alternate circulation flowpaths. With reference to FIGS. 8, 9A, and
9B, an equalization valve 140 is provided, associated with a ball
and seat valve or similar device for diverting fluid from the
tubing string during normal operation of the assembly, i.e. when
reverse circulation is not required. That is, delivery of fluid to
the tubing string from surface will force the ball into its seat,
and prevent direct fluid communication from the tubing string to
the equalization valve. The equalization valve is, however, in
indirect fluid communication with the tubing string, as fluid
diverted from the tubing string into the wellbore annulus flows
through outer ports 146 of the valve housing to bathe/flush the
equalization plug 141 and inner surfaces of the valve housing 145.
As the equalization plug 141 also includes inner ports 142, fluid
may flow through outer ports 146 and inner ports 142, whether or
not said ports are aligned. Accordingly, the equalization valve is
continually washed with wellbore annulus fluid, assisting
circulation downhole and preventing settling or accumulation of
solids against the tool or within the valve.
[0200] Typically, the equalization plug will be slidable within the
valve housing between a sealed position--in which the cylindrical
plug 144a and bonded seal 144b are engaged within the lower
mandrel, with inner and outer ports 142, 146 aligned as discussed
above--and an unsealed position. The plug is operatively attached
to a pull tube 149, which may be actuated from surface to control
the position of the equalization plug 141 within the valve housing
145.
[0201] 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.
[0202] 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.
[0203] It should be noted that the fluid flowpath from outer ports
146 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.
[0204] 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.
[0205] 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.
* * * * *