U.S. patent application number 14/054525 was filed with the patent office on 2014-04-17 for method for launching replacement balls.
This patent application is currently assigned to ISOLATION EQUIPMENT SERVICES INC.. The applicant listed for this patent is ISOLATION EQUIPMENT SERVICES INC.. Invention is credited to Boris (Bruce) P. CHEREWYK.
Application Number | 20140102717 14/054525 |
Document ID | / |
Family ID | 50474342 |
Filed Date | 2014-04-17 |
United States Patent
Application |
20140102717 |
Kind Code |
A1 |
CHEREWYK; Boris (Bruce) P. |
April 17, 2014 |
METHOD FOR LAUNCHING REPLACEMENT BALLS
Abstract
A method for successively releasing balls into a wellbore during
wellbore operations is disclosed. The method includes providing at
least a first ball injector for storing at least a primary set of
primary balls and at least a second set of redundant balls,
releasing a ball from the at least primary set of primary balls and
determining if the released ball properly seats and engages its
intended corresponding downhole tool. If it is determined that the
released ball did not properly engage and actuate its intended
corresponding tool, a redundant ball from the second set of
redundant balls can be released without interrupting wellbore
operations. In an alternate embodiment, the first ball injector can
be a primary ball injector for storing and releasing the at least
primary set of primary balls, and a second ball injector for
storing and releasing the at least second set of redundant balls,
the first and second ball injectors arranged in parallel.
Inventors: |
CHEREWYK; Boris (Bruce) P.;
(Calgary, CA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
ISOLATION EQUIPMENT SERVICES INC. |
Red Deer |
|
CA |
|
|
Assignee: |
ISOLATION EQUIPMENT SERVICES
INC.
Red Deer
CA
|
Family ID: |
50474342 |
Appl. No.: |
14/054525 |
Filed: |
October 15, 2013 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
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61714176 |
Oct 15, 2012 |
|
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Current U.S.
Class: |
166/381 ;
166/318 |
Current CPC
Class: |
E21B 33/10 20130101;
E21B 33/068 20130101 |
Class at
Publication: |
166/381 ;
166/318 |
International
Class: |
E21B 33/10 20060101
E21B033/10 |
Claims
1. A method of successively releasing one or more balls into a
fluid wellbore for engaging and actuating an intended downhole tool
corresponding thereto comprising: storing at least a primary set of
primary balls; storing at least a second set of redundant balls;
releasing a primary ball for actuating a corresponding downhole
tool; and determining if the corresponding downhole tool was
actuated by the primary ball, and if actuated, then releasing a
successive primary ball from the at least primary set of primary
balls, or if not actuated, releasing a redundant ball from the
second set of redundant balls, the redundant ball corresponding to
the primary ball.
2. The method of claim 1, wherein the releasing a primary ball for
actuating a corresponding downhole tool further comprises releasing
a primary ball from the at least primary set of primary balls
stored in at least a first ball injector, and storing the at least
second set of redundant balls further comprises storing the at
least second set of redundant balls in the at least first ball
injector.
3. The method of claim 2, wherein the at least first ball injector
further comprises a radial ball injector having at least one radial
array having an axial bore in fluid communication with the
wellbore, and two or more radial bores extending radially away from
the axial bore for storing the at least primary set of primary
balls and the at least second set of redundant balls.
4. The method of claim 3, wherein at least one primary ball and one
redundant ball are stored in the at least one radial array.
5. The method of claim 4, wherein each radial array of a stack of
radial arrays contains a primary ball and a corresponding redundant
ball.
6. The method of claim 1 wherein the at least first ball injector
further comprises a first ball injector and at least a second ball
injector and the fluid wellbore comprises a multi-injector
connector having two or more fluid axial wellbores arranged in
parallel and each in fluid communication with the fluid wellbore,
each of the two or more axial wellbores supporting the first ball
injector and the at least a second ball injector, the first ball
injector housing the at least primary set of primary balls; and the
at least second ball injector housing the at least second set of
redundant balls.
7. The method of claim 6, further comprising concurrently pumping
displacement fluid through each of the first and second ball
injectors for positively displacing any balls operably aligned with
the axial bore.
8. The method of claim 1, wherein determining the corresponding
downhole tool has been actuated by a primary ball further comprises
monitoring a pressure in the wellbore wherein an increase in the
pressure is indicative of actuation.
9. A system for successively releasing one or more balls into a
fluid wellbore for engaging and actuating an intended downhole
corresponding thereto comprising: a primary set of primary balls
fluidly connected to the fluid wellbore; at least a second set of
redundant balls fluidly connected to the fluid wellbore; and at
least a first ball injector for injecting the primary set of
primary balls and the at least second set of redundant balls into
the fluid wellbore.
10. The system of claim 9, wherein the at least a first ball
injector further comprises a first ball injector having a first
axial wellbore and for storing and releasing the at least primary
set of primary balls, and at least a second ball injector having a
second axial wellbore and for storing and releasing the at least
second set of redundant balls.
11. The system of claim 10 further comprising a multi-injector
connector for fluidly arranging the first and the second axial
wellbores in parallel and for fluidly connecting the first and
second axial wellbores with the fluid wellbore.
12. The system of claim 11 further comprising an isolation gate
valve between the multi-injector connector and a wellhead
structure.
13. The system of claim 12 wherein the wellhead structure further
comprises a fracturing head.
Description
CROSS-RELATED APPLICATIONS
[0001] This application claims the benefits under 35 U.S.C. 119(e)
of U.S. Provisional Application Ser. No. 61/714,176, filed Oct. 15,
2012, the entirety of which is incorporated fully herein by
reference.
FIELD
[0002] This invention relates generally to a method for injecting
subsequent balls into a wellbore for interacting with downhole
tools, such as activating tools that allow select zones or zone
intervals in the wellbore to be stimulated, more particularly for
injecting a redundant or replacement ball when a previously
injected ball does not properly actuate its intended tool.
BACKGROUND
[0003] It is known to conduct fracturing or other stimulation
procedures in a wellbore by isolating zones of interest, or
intervals within a zone, using packers and the like. The isolated
zone is subjected to treatment fluids, including liquids and gases,
at treatment pressures. In a typical fracturing procedure for a
cased wellbore, for example, the casing of the well is perforated
to admit oil and/or gas into the wellbore and fracturing fluid is
then pumped into the wellbore and through the perforations into the
formation. Such treatment opens and/or enlarges drainage channels
in the formation, enhancing the producing ability of the well.
[0004] It is typically desired to stimulate multiple zones in a
single stimulation treatment, typically using on-site stimulation,
fluid pumping equipment. A tubular string conveying series of
spaced packers, in a packer arrangement, is inserted into the
wellbore, each of the packers located for corresponding with
intervals for isolating one zone from an adjacent zone. It is known
to introduce a ball into the wellbore to selectively engage an
actuator for one of the packers in order to block fluid flow
therethrough, creating an isolated zone for subsequent treatment or
stimulation. Once the isolated zone has been stimulated, a
subsequent ball is dropped to block off a subsequent packer, uphole
of the previously actuated packer, for isolation and stimulation
thereabove. The process is continued until all the desired zones
have been stimulated. Typically the balls range in diameter from a
smallest ball, suitable to block the most downhole packer, to the
largest diameter, suitable for blocking the most uphole packer.
Similarly, the balls can actuate successive sliding sleeves in a
completion string.
[0005] At surface, the wellbore is fit with a wellhead including
valves and a pipeline connection block, such as a frachead, which
provides fluid connections for introducing stimulation fluids,
including sand, gels and acid treatments, into the wellbore.
[0006] There are a variety of surface tools for introducing balls
into the wellbore. It is known to feed a plurality of
perforation-sealing balls using an automated device as set forth in
U.S. Pat. No. 4,132,243 to Kuus. Same-sized balls are used for
sealing perforations and are able to be fed one by one from a stack
of balls. The apparatus appears limited to same-sized balls and
there is no positive identification whether a ball was successfully
indexed from the stack for injection.
[0007] In another prior art arrangement, such as that set forth in
FIG. 1, a vertically stacked manifold of pre-loaded balls is
oriented in a bore above the wellbore of a wellhead and frachead.
Each ball is temporarily supported by a rod or finger. Each finger
is sequentially actuated to withdraw from the bore when required to
release or launch the next largest ball. As the balls are already
stacked in the bore, the lowest ball (closest to the wellbore) is
necessarily the smallest ball. There are no options for changing
the sequence or order of ball drop.
[0008] As shown in FIG. 2 and extracted from US Published Patent
Application Serial No. US 2012/0279717 to Young et al., another
type of vertical ball injector is shown which stores and drops
successive balls from a ball cartridge. A ball rail forms a tapered
hopper within the cartridge for storing a small ball at the apex
and ever larger balls thereabove within the cartridge. The hopper
forms an aperture at a bottom end thereof, the ball rail and
aperture being actuable to open just enough to allow the bottom,
smallest ball in turn to drop into the wellbore.
[0009] Another ball injector, as shown in FIG. 3, is that disclosed
in U.S. Pat. No. 8,136,585 to Applicant, the entirety of which is
incorporated fully herein by reference, discloses a radial ball
injector comprising a plurality of vertically stacked radial ball
arrays, with each ball array having one or more radial bores
housing a ball cartridge. Each ball cartridge can be loaded with a
ball of graduated sized, each cartridge being misaligned with the
wellbore for storing the ball and operationally aligned for
dropping or releasing a selected ball into the wellbore.
[0010] Despite improvements to providing successive balls, there
are still operational events that require greater surface control
and flexibility for dropping balls down a wellbore. For example, it
is not uncommon for a ball to be damaged or to disintegrate upon
arrival at the downhole tool requiring a replacement ball or one of
the same diameter to be reloaded and launched again. Further,
damaged or scarred packer balls can fail to isolate the zone
requiring an operator to then drop an identical ball down the bore
of the ball injector. Further still, an initial packer ball may not
seat or engage its intended downhole tool properly, if at all, and
may not actuate its intended downhole tool. In such circumstances,
a replacement or redundant ball of the same size must be dropped
into the wellbore.
[0011] In the prior art apparatus of FIGS. 1 and 2, the injector
must be depressurized, removed and reloaded to get a replacement
smaller ball under the remaining loaded balls. This requires time
consuming and properly managed procedures to maintain safe control
in a hazardous environment and to complete testing and
re-pressurization procedures upon reinstallation to the wellhead.
This is extremely inefficient, time consuming, costly and can
adversely compromise the treatment and health of the wellbore.
[0012] Another option can be to manually introduce a redundant ball
into the system through a bypass system. However, such manual
introduction of a redundant ball still requires a shutdown of the
operations which can cause many problems including settling of
sand, failure of the stage to ever again resulting in abandonment
and hours or even days of delay which is very expensive.
[0013] There remains a need for a safe, efficient and remotely
operated apparatus and mechanism for introducing successive balls
to a wellbore without interrupting downhole operations.
SUMMARY
[0014] The present invention teaches a method of successively
launching or injecting balls into a wellbore without interrupting
wellbore operations, regardless of failure of a primary ball
corresponding to a specified downhole tool.
[0015] Should a ball of the required size for the particular step
in the wellbore operation be lost or damaged for some reason or
fails to properly engage its intended downhole tool for any reason,
a redundant ball can be provided without isolating or removing the
ball injecting apparatus from the wellhead structure, or otherwise
interrupting wellbore operations. As operations are ongoing, a
replacement or redundant ball can be dropped or released into the
wellbore for engaging its intended downhole tool.
[0016] In a broad aspect of the invention, a method of successively
dropping two or more balls into a wellbore for engaging and
actuating a corresponding downhole tool involves providing at least
a first ball injector, storing at least a primary set of primary
balls in the at least first ball injector, storing at least a
second set of redundant balls in the at least first ball injector
which can be the same or at least a second ball injector, releasing
a stored primary ball from the at least first set of primary balls
into the wellbore, determining if the corresponding downhole tool
was actuated by the primary ball, and if actuated, then repeating
the releasing a subsequent or successive primary ball from the at
least first set of primary balls, or if the corresponding tool is
not actuated, then, releasing a redundant ball from the at least a
second set of redundant balls, corresponding to the primary
ball.
BRIEF DESCRIPTION OF THE DRAWINGS
[0017] FIG. 1 is schematic view of a prior art apparatus
implementing a plurality of pre-loaded balls, the balls supported
on a plurality of finger actuators for bottom-up release;
[0018] FIG. 2 is a side cross-sectional view of another prior art
apparatus implementing a plurality of pre-loaded balls an actuable
hopper for bottom-up injection;
[0019] FIG. 3 is an overall schematic representation of Applicant's
own prior art ball injector disclosed in U.S. Pat. No. 8,136,585,
including a partial side cross-sectional view of Applicant's ball
injector housing discrete balls for unique downhole tools;
[0020] FIGS. 4A to 4C are side cross-sectional views of an
embodiment of Applicant's ball injector disclosed in U.S. Pat. No.
8,136,585, illustrating a sequence of steps for releasing a
redundant ball into a wellbore;
[0021] FIG. 5A is a flow chart and single array of one embodiment
of the redundant ball operation using a radial injector according
to FIG. 3, the flow chart illustrating a method of deploying a
subsequent ball to replace a previously deployed, yet failed
primary ball of the same size, both primary and redundant balls
stored within the same array of the ball injector;
[0022] FIG. 5B is a side view of a radial injector, the structure
of which corresponds to Applicant's radial injector of FIG. 3; each
array storing pairs of primary and redundant balls;
[0023] FIG. 6 is a side view of an embodiment illustrating two ball
injectors fluidly connected to a wellbore in parallel fashion using
two or more fluid wellbores, a first injector for releasing primary
balls from a first set of balls, and the second injector for
releasing redundant balls of a second set of balls, as necessary;
and
[0024] FIG. 7 is a side view of an embodiment illustrating a radial
injector fluidly connected to a fracturing head, the fracturing
head receiving a treatment fluid and the radial injector receiving
a displacement fluid for positively displacing a ball from the
injector.
DETAILED DESCRIPTION
[0025] In the prior art, in instances where no such indication of
proper engagement of a ball or actuation of a downhole tool is
received, pumping operations can be temporarily stopped, and a
redundant ball of similar size is manually dropped into the bore of
a ball injector. Then the pumping operation is recommenced to
deploy the redundant ball downhole to the corresponding
non-actuated tool. However, interruption and stoppage of the
pumping operations can cause many problems, and in some cases, that
particular stage may not open at all requiring the abandonment of
that stage. Other problems can arise because the wellbore and
conveyance string need to be completely flushed of sand before the
redundant ball is deployed. Further, if the surface equipment
requires complete bleed out, if using gases such as propane,
butane, carbon dioxide or nitrogen, corrosive pumping fluids, such
as acids, must also be completely flushed before redundant balls
are introduced. The flushing of the system also requires additional
pumping of fluid and sand which can also increase operational
costs. Each shut down of pumping operations could mean an extra
day, or at the very least several extra hours of delay which can
lead to increasing operational costs.
[0026] Accordingly, with reference to known ball injectors of FIGS.
3 and 4A through 4C, the injector 10 is illustrated according to
U.S. Pat. No. 8,136,585 to Applicant. As shown, two radial ball
arrays 60,60 are shown for staging eight different sized balls.
Treatment fluid is arranged for flow through the axial bore 70 and
effectively carrying an injected ball downhole to a treatment or
downhole tool. As shown in FIG. 4A, a first ball 100a is
operationally aligned with the bore with the cartridge oriented
downhole for release into the bore. The ball 100a falls through an
open isolation valve 50 and is carried downhole.
[0027] As shown in FIG. 4B, if the ball is not successful in
actuating its respective tool, then it has been known to close the
isolation valve 50 to enable safe access to the bore 70 of the
injector 10. Cartridge 90, for the failed ball release, is
misaligned from the bore 70. A replacement ball 110a of same size
is manually inserted into the bore, bypassing the cartridge 90 for
staging atop the isolation valve 50.
[0028] Turning to FIG. 4C, the isolation valve 50 is opened and the
replacement ball 110a is conveyed downhole. As discussed, the
closing of the isolation valve 50 and interruption of the fluid
flow may be undesirable.
[0029] In detail in FIG. 3, the ball injecting apparatus or
injector 10 receives and releases balls, including drop balls, frac
balls, packer balls, and the like, for isolating zones of interest
during wellbore operations such as fracturing, and is supported on
a wellhead structure 20 having a wellbore 30. The wellhead
structure 20 can include a high pressure wellhead or a frac head 40
and an isolation gate valve 50. Although the injector 10 can be any
apparatus for injecting balls into the wellbore, in a preferred
embodiment, the injector 10 can be the radial ball injector as
disclosed in Applicant's issued patent U.S. Pat. No. 8,136,585, the
entirety of which is incorporated fully herein by reference. As
shown, the preferred radial ball injector 10 can comprise at least
one radial ball array 60 having an axial bore 70 extending
therethrough and two or more radial bores 80 extending radially
away from the axial bore 70, the axial bore 70 in fluid
communication with the wellbore 30. Housed within each radial bore
80 is a ball cartridge 90, for storing a ball therein, which is
either operably misaligned with the wellbore 30 for storing the
ball, or operably aligned with the wellbore 30 for releasing the
ball into the wellbore 30.
Redundant Ball Configuration--Radial Array
[0030] Turning to FIGS. 5A and 5B, and in a base embodiment for an
injector that avoids wellbore interruption, two of the radial bores
80 of the radial array 60 of FIG. 3 can be loaded with at least two
primary balls 100a,100b for specified tools A and B, and two others
of the radial bores 80 are loaded providing redundant balls
110a,110b should either of the primary balls fail to perform their
tool actuating function when released. Each of the radial bores 80
house a ball cartridge 90 for storing and deploying its respective
ball.
[0031] As shown, two radial bores of the same radial housing are
loaded with balls 100a,110a of the same size, one for serving as
the primary ball 100a for the specified tool A, and another serving
as a redundant or replacement ball 110a in cases where the dropped
ball does not properly actuate the downhole tool A. Another pair of
the two ball cartridges can also each be loaded with balls 100b,
110b of the same size as each other, yet different from the first
pair 100a,110a so as to act as specified successive balls for
actuating successive tool B. Again, the successive and redundant
ball 110b serves as a replacement ball for the primary ball 100b in
case the dropped successive ball does not seat, engage or otherwise
actuate the downhole tool B.
[0032] Thus, redundant balls 110a, 110b . . . are readily available
for each size of released primary ball 100a, 100b . . . that fails
to properly actuate its intended downhole tool, thereby, providing
a quick and efficient method for safely deploying replacement balls
without the need to temporarily shut down pumping operations.
[0033] As shown, in instances where there is an indication that the
primary released ball 100a, 100b . . . properly actuated its
intended downhole tool, such as a by a pressure spike in the
supplied treatment fluid, an operator can simply continue with
pumping operations and deploy the successive ball for actuation of
the successive tool, the redundant ball remaining in its redundant
bore for removal after the conclusion of the operation. In
embodiments, the wellbore 30 is monitored for proper seating or
engagement of a dropped ball with its intended corresponding
downhole tool, such as is often indicated by a pressure spike,
ranging from about 1000 to 2000 psi for example. However, where the
ball fails, the operator can quickly and efficiently select a
redundant or replacement ball 110a, 110b . . . from the same or
other radial ball array 60 for operation.
[0034] The deployment of the redundant ball does not require the
shutdown of pumping of treatment fluids and can proceed without
interruption of operations.
[0035] As shown in FIG. 5B, a stack of four radial arrays, with
complete redundancy, enables eight stages of operation, housing
eight primary balls. In the cross-sectional view, four primary
balls are visible 100a,100c,100e and 100g, for actuating four
downhole tools (not shown). Further, four redundant balls
110a,110c,110e and 110g, are visible, paired or corresponding to a
primary ball 100a,100c,100e,100g, having the same size and
characteristics as an operational replacement therefore. Four
additional primary balls (b,d,f,h) and corresponding redundant
balls (b,d,f,h) are not shown, being oriented into the page of the
drawing.
Redundant Ball Configuration--Parallel Bore
[0036] With reference to FIG. 6, in another embodiment, the
wellhead structure 20 can comprise a multi-injector connector 300
having two or more fluid axial wellbores 71,72 arranged in parallel
for supporting at least two injectors, a first or primary injector
11 and at least a second injector 12. As shown, two axial wellbores
71,72 form a "Y"-shaped multi-injector connector 300 between the
ball injectors 11,12 and the wellbore 30. The first axial wellbore
71 is fit with the first injector 11 and the second axial wellbore
72 is fit with the second injector 12. The first injector 11 is
pre-loaded with the at least first set of primary balls
100a,100b,100c,100d for corresponding downhole tools 250a,250b,250c
and 250d respectively, and the second ball injector 12 is
pre-loaded with a second set of redundant balls
110a,110b,110c,110d.
[0037] Each injector 11,12 can be selected from a range of known
ball injectors, shown here as a radial ball injector of the type
illustrated in FIG. 3. Each ball injector 11,12 has at least one
radial ball array 60, each array having two or more radial bores 80
extending radially away from the axial wellbore 71,72 and in fluid
communication therewith, each axial wellbore 71,72 being in fluid
communication with the wellbore 30. The first injector 11 stores a
primary set of balls having two or more primary balls 100a,100b . .
. the second injector 12 stores a redundant set of two or more
balls redundant balls 110a,110b.
[0038] In operation, a stored primary ball from the primary set of
balls is released from the first injector 11 for actuating its
intended corresponding downhole tool. As operations dictate, one
repeats the release and dropping into the wellbore successive
primary balls from first set of primary balls for actuating
successive tools. Accordingly, the balance of the primary set of
balls can be operated in sequence to introduce or release each
successively larger, right sized ball at the correct time in the
operation. In an embodiment, to ensure that a ball has left the
injector and exited its respective axial wellbore 71,72, a
displacement fluid, such as the treatment fluid itself, can be
pumped through the ball injector 11,12 in use.
[0039] Again, if a dropped ball were to fail to actuate its
intended corresponding downhole tool, the primary ball injector 11
need not be isolated nor disassembled from the wellhead structure.
The second ball injector 12 can be actuated to provide a
replacement or redundant ball corresponding to the failed primary
ball. For example, if primary ball 100c fails, then redundant ball
110c is released from the second injector 12. As shown, for
simplicity, the arrangement of the redundant balls
110a,110b,110c,110d loaded in the second ball injector 12 are
substantially similar to the arrangement of the primary balls
100a,100b,100c,100d loaded in the primary ball injector 10.
[0040] In an embodiment, and with reference to FIG. 7, the ball
injector 10 can be fluidly connected to a wellhead structure 20,
such as a fracturing head 40 for receiving treatment fluid therein.
The wellhead structure 20 can further have an isolation gate valve
50 for isolating the ball injector 10 from the wellbore 30,
providing further operator control of the launching of balls.
Accordingly, the ball injector 10 can be isolated from the wellbore
30, but downhole operations can continue without interruption as
treatment fluid can be continuously injected downhole through the
fracturing head 40. Thus, with the ball injector 10 isolated from
the wellbore 30, a ball can be dropped onto the isolation valve 50
without the ball immediately being released into the wellbore 30.
At an appropriate time, the gate valve 50 can be opened to release
the dropped ball into the wellbore 30.
[0041] In such an embodiment, and as shown, the ball injector 10
can further be adapted to receive displacement fluid for positively
displacing the ball from the injector 10. In an embodiment, and as
shown, the displacement fluid can be from a separate source or in
an alternate embodiment (not shown), the displacement fluid can be
treatment fluid fluidly communicated to the ball injector 10 via a
bypass fluid line.
[0042] Further still, in another embodiment, redundant balls can be
used for different stages of a downhole operation, and not
necessarily be limited to use as a redundant ball for a particular
stage where a primary ball has failed to actuate its intended
corresponding downhole tool.
* * * * *