U.S. patent application number 16/654878 was filed with the patent office on 2020-02-13 for method and apparatus for wellbore fluid treatment.
This patent application is currently assigned to PACKERS PLUS ENERGY SERVICES INC.. The applicant listed for this patent is PACKERS PLUS ENERGY SERVICES INC.. Invention is credited to Jim Fehr, Daniel Jon Themig.
Application Number | 20200048989 16/654878 |
Document ID | / |
Family ID | 44067970 |
Filed Date | 2020-02-13 |
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United States Patent
Application |
20200048989 |
Kind Code |
A1 |
Themig; Daniel Jon ; et
al. |
February 13, 2020 |
Method and Apparatus for Wellbore Fluid Treatment
Abstract
An apparatus for fluid treatment of a wellbore includes (a) a
tubing string having (i) a wall defining an inner bore extending
along a longitudinal axis, and (ii) a plurality of spaced apart
ports in the wall; and (b) a plurality of axially spaced apart
valves configured to permit fluid to flow therethrough. The valves
are mounted along the tubing string. Each valve is (i) moveable in
a downhole direction along the inner bore from a first position in
which the one or more of the plurality of ports are closed, to a
second position in which the one or more of the plurality of ports
are open, and (ii) having a minimum inner diameter with respect to
an innermost surface of the valve when the valve is in the first
position. The minimum inner diameter of each valve is generally
equal.
Inventors: |
Themig; Daniel Jon;
(Calgary, CA) ; Fehr; Jim; (Sherwood Park,
CA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
PACKERS PLUS ENERGY SERVICES INC. |
Calgary |
|
CA |
|
|
Assignee: |
PACKERS PLUS ENERGY SERVICES
INC.
Calgary
CA
|
Family ID: |
44067970 |
Appl. No.: |
16/654878 |
Filed: |
October 16, 2019 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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16037022 |
Jul 17, 2018 |
10487624 |
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16654878 |
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14738506 |
Jun 12, 2015 |
10053957 |
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16037022 |
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14150514 |
Jan 8, 2014 |
9074451 |
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14738506 |
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13455291 |
Apr 25, 2012 |
8657009 |
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14150514 |
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12830412 |
Jul 5, 2010 |
8167047 |
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13455291 |
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12208463 |
Sep 11, 2008 |
7748460 |
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12830412 |
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11403957 |
Apr 14, 2006 |
7431091 |
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12208463 |
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10604807 |
Aug 19, 2003 |
7108067 |
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11403957 |
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60404783 |
Aug 21, 2002 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 33/124 20130101;
E21B 33/1285 20130101; E21B 43/16 20130101; E21B 2200/06 20200501;
E21B 34/12 20130101; E21B 34/10 20130101; E21B 33/122 20130101;
E21B 34/063 20130101; E21B 34/14 20130101; E21B 43/14 20130101;
E21B 43/25 20130101 |
International
Class: |
E21B 34/12 20060101
E21B034/12; E21B 34/14 20060101 E21B034/14; E21B 43/14 20060101
E21B043/14; E21B 43/25 20060101 E21B043/25; E21B 33/128 20060101
E21B033/128; E21B 34/06 20060101 E21B034/06; E21B 33/122 20060101
E21B033/122; E21B 33/124 20060101 E21B033/124; E21B 34/10 20060101
E21B034/10; E21B 43/16 20060101 E21B043/16 |
Claims
1. An apparatus for fluid treatment of a wellbore, the apparatus
comprising: a) a tubing string having (i) a wall defining an inner
bore extending along a longitudinal axis of the tubing string, and
(ii) a plurality of spaced apart ports in the wall; and b) a
plurality of axially spaced apart valves configured to permit fluid
to flow therethrough, the plurality of axially spaced apart valves
mounted along the tubing string, each valve: (i) moveable in a
downhole direction along the inner bore from a first position in
which the one or more of the plurality of ports are closed to
inhibit fluid communication between the inner bore and the wellbore
through the one or more of the plurality of ports, to a second
position in which the one or more of the plurality of ports are
open to permit fluid communication between the inner bore and the
wellbore through the one or more of the plurality of ports, and
(ii) having a minimum inner diameter with respect to an innermost
surface of the valve when the valve is in the first position,
wherein the minimum inner diameter of each valve is generally
equal.
2. The apparatus of claim 1, wherein each valve is moveable toward
the second position based on increasing fluid pressure at an uphole
side of the valve relative to a downhole side of the valve.
3. The apparatus of claim 2, wherein each valve has a conduit
extending along the axis between the uphole side and the downhole
side of the valve for permitting fluid to flow therethrough, the
conduit defining the minimum inner diameter and blockable to
facilitate increasing fluid pressure at the uphole side of the
valve relative to the downhole side of the valve.
4. The apparatus of claim 1, wherein the plurality of valves are
mounted in a common segment of the tubing string.
5. The apparatus of claim 1, wherein the inner diameter remains
constant when the valve moves from the first position to the second
position.
6. The apparatus of claim 1, wherein each valve is disposed in a
corresponding groove formed in an inner surface of the tubing
string.
7. The apparatus of claim 1, wherein each valve is spaced apart
from a corresponding stop surface in the inner bore when in the
first position, and abuts the corresponding stop surface when in
the second position to inhibit movement of the valve in the
downhole direction.
8. An apparatus for fluid treatment in a wellbore, the apparatus
comprising: a) a tubing string including: (i) a wall defining an
inner bore extending along a longitudinal axis, (ii) at least one
first port in the wall; and (iii) at least one second port in the
wall, the at least one second port spaced axially downhole from the
at least one first port; b) a first valve mounted in the inner bore
and translatable along the axis in a downhole direction from a
first position in which fluid communication between the inner bore
and the wellbore through the at least one first port is blocked,
toward a second position in which the at least one first port is
open to provide fluid communication between the inner bore and the
wellbore through the at least one first port, the first valve
having a first conduit extending along the axis for permitting
passage of fluid through the first valve, the first conduit defined
at least in part by a minimum first radial extent measured
transversely from the axis to a radially innermost surface of the
first valve when the first valve is in the first position; and c) a
second valve mounted in the inner bore downhole of the first valve
and translatable along the axis in the downhole direction from a
third position in which fluid communication between the inner bore
and the wellbore through the at least one second port is blocked,
toward a fourth position in which the at least one second port is
open to provide fluid communication between the inner bore and the
wellbore through the at least one second port, the second valve
having a second conduit extending along the axis for permitting
passage of fluid through the second valve, the second conduit
defined at least in part by a minimum second radial extent measured
transversely from the axis to a radially innermost surface of the
second valve when the second valve is in the third position,
wherein the second radial extent is generally equal to the first
radial extent.
9. The apparatus of claim 8, wherein the at least one first port
comprises a plurality of first ports and the at least one second
port comprises a plurality of second ports.
10. The apparatus of claim 9, wherein the first ports are spaced
circumferentially apart from one another about the axis, and
wherein the second ports are spaced circumferentially apart from
one another about the axis.
11. The apparatus of claim 8, wherein the tubing string includes a
first stop surface between the first and second valves, the first
valve spaced axially uphole from the first stop surface when in the
first position, and the first valve in engagement with the first
stop surface when in the second position for inhibiting further
translation of the first valve in the downhole direction, and
wherein the tubing string includes a second stop surface downhole
of the second valve, the second valve spaced axially uphole from
the second stop surface when in the third position, and the second
valve in engagement with the second stop surface when in the fourth
position for inhibiting further translation of the second valve in
the downhole direction.
12. The apparatus of claim 8, wherein the bore is defined at least
in part by a bore inner radius measured from the axis to a radially
inner surface of the wall, and wherein the first radial extent is
generally equal to the bore inner radius.
13. The apparatus of claim 8, wherein the second valve is directly
downhole of the first valve, and the first and second valves are in
a common segment of the tubing string.
14. The apparatus of claim 8, wherein the apparatus is free of any
packers axially intermediate the at least one first port and the at
least one second port.
15. The apparatus of claim 8, further comprising: (d) a
port-opening sleeve in the bore uphole of the first and second
valves, the port-opening sleeve drivable through the tubing string
into engagement with the first valve to urge translation of the
first valve toward the second position, and when the first valve is
in the second position, the port-opening sleeve is drivable past
the first valve and into engagement with the second valve to urge
translation of the second valve toward the fourth position, the
port-opening sleeve having a sleeve conduit extending along the
axis for permitting passage of fluid through the port-opening
sleeve, and drivable by plugging the sleeve conduit with a sealing
device and applying fluid pressure to an uphole side of the
port-opening sleeve.
16. An apparatus for fluid treatment in a wellbore, the apparatus
comprising: a) a tubing string including: (i) a wall defining an
inner bore extending along a longitudinal axis, and (ii) a
plurality of axially spaced apart ports in the wall; and b) a
plurality of axially spaced apart valves mounted in the inner bore,
each valve independently translatable along the axis in a downhole
direction, each valve translatable from a closed position in which
fluid communication through at least one of the plurality of ports
is blocked, toward an open position in which the at least one of
the plurality of ports is open to provide fluid communication
between the inner bore and the wellbore through the at least one of
the plurality of ports, each valve having a conduit for permitting
passage of fluid through the valve, the conduit extending along a
centerline generally parallel with the axis, and the conduit having
a minimum radial extent measured from the centerline to a radially
innermost surface of the valve when the valve is in the closed
position, wherein the minimum radial extent of each valve is
generally equal.
17. The apparatus of claim 16, wherein each valve is drivable
toward the open position by increasing fluid pressure at an uphole
side of the valve relative to a downhole side of the valve.
18. The apparatus of claim 17, wherein the conduit is blockable to
facilitate increasing fluid pressure at the uphole side relative to
the downhole side of the valve.
19. The apparatus of claim 17, wherein the plurality of axially
spaced apart valves are mounted in a common segment of the tubing
string.
20. An apparatus for fluid treatment of a wellbore, the apparatus
comprising: a) a tubing string having: (i) a wall defining an inner
bore extending along a longitudinal axis of the tubing string, and
(ii) a plurality of spaced apart ports in the wall; and b) a
plurality of axially spaced apart valves configured to permit fluid
to flow therethrough, the plurality of axially spaced apart valves
mounted along the tubing string, each valve actuable by a common
plug movable through the tubing string, each valve actuable by the
plug to move the valve from a first position in which the valve is
configured to cover one or more of the plurality of ports to a
second position in which the valve is configured to open one or
more of the plurality of ports to permit fluid communication
between the inner bore and the wellbore, and each valve having a
minimum inner diameter with respect to an innermost surface of the
valve when the valve is in the first position, wherein the minimum
inner diameter of each valve is generally equal, and wherein each
valve is configured to permit passage of the plug therethrough when
in the second position.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application is a continuation of U.S. patent
application Ser. No. 16/037,022, filed Jul. 17, 2018, which is a
continuation application of U.S. patent application Ser. No.
14/150,514, filed Jan. 8, 2014. U.S. patent application Ser. No.
14/150,514 is a continuation application of U.S. patent application
Ser. No. 13/455,291, filed Apr. 25, 2012, now U.S. Pat. No.
8,657,009, issued Feb. 25, 2014 which is a continuation application
of U.S. patent application Ser. No. 12/830,412, filed Jul. 5, 2010,
now U.S. Pat. No. 8,167,047, issued May 1, 2012, which is a
continuation-in-part application of U.S. patent application Ser.
No. 12/208,463, filed Sep. 11, 2008, now U.S. Pat. No. 7,748,460,
issued Jul. 6, 2010, which is a continuation of U.S. patent
application Ser. No. 11/403,957, filed Apr. 14, 2006, now U.S. Pat.
No. 7,431,091, issued Oct. 7, 2008, which is a divisional
application of U.S. patent application Ser. No. 10/604,807, filed
Aug. 19, 2003, now U.S. Pat. No. 7,108,067, issued Sep. 19, 2006.
This application also claims priority through the above-noted
applications to U.S. Provisional Application Ser. No. 60/404,783,
filed Aug. 21, 2002.
FIELD OF THE INVENTION
[0002] The invention relates to a method and apparatus for wellbore
fluid treatment and, in particular, to a method and apparatus for
selective flow control to a wellbore for fluid treatment.
BACKGROUND OF THE INVENTION
[0003] An oil or gas well relies on inflow of petroleum products.
When drilling an oil or gas well, an operator may decide to leave
productive intervals uncased (open hole) to expose porosity and
permit unrestricted wellbore inflow of petroleum products.
Alternately, the hole may be cased with a liner, which is then
perforated to permit inflow through the openings created by
perforating.
[0004] When natural inflow from the well is not economical, the
well may require wellbore treatment termed stimulation. This is
accomplished by pumping stimulation fluids such as fracturing
fluids, acid, cleaning chemicals and/or proppant laden fluids to
improve wellbore inflow.
[0005] In one previous method, the well is isolated in segments and
each segment is individually treated so that concentrated and
controlled fluid treatment can be provided along the wellbore.
Often, in this method a tubing string is used with inflatable
element packers thereabout which provide for segment isolation. The
packers, which are inflated with pressure using a bladder, are used
to isolate segments of the well and the tubing is used to convey
treatment fluids to the isolated segment. Such inflatable packers
may be limited with respect to pressure capabilities as well as
durability under high pressure conditions. Generally, the packers
are run for a wellbore treatment, but must be moved after each
treatment if it is desired to isolate other segments of the well
for treatment. This process can be expensive and time consuming.
Furthermore, it may require stimulation pumping equipment to be at
the well site for long periods of time or for multiple visits. This
method can be very time consuming and costly.
[0006] Other procedures for stimulation treatments use tubing
strings without packers such that tubing is used to convey
treatment fluids to the wellbore, the fluid being circulated up
hole through the annulus between the tubing and the wellbore wall
or casing.
[0007] The tubing string, which conveys the treatment fluid, can
include ports or openings for the fluid to pass therethrough into
the borehole. Where more concentrated fluid treatment is desired in
one position along the wellbore, a small number of larger ports are
used. In another method, where it is desired to distribute
treatment fluids over a greater area, a perforated tubing string is
used having a plurality of spaced apart perforations through its
wall. The perforations can be distributed along the length of the
tube or only at selected segments. The open area of each
perforation can be pre-selected to control the volume of fluid
passing from the tube during use. When fluids are pumped into the
liner, a pressure drop is created across the sized ports. The
pressure drop causes approximate equal volumes of fluid to exit
each port in order to distribute stimulation fluids to desired
segments of the well.
[0008] In many previous systems, it is necessary to run the tubing
string into the bore hole with the ports or perforations already
opened. This is especially true where a distributed application of
treatment fluid is desired such that a plurality of ports or
perforations must be open at the same time for passage therethrough
of fluid. This need to run in a tube already including open
perforations can hinder the running operation and limit usefulness
of the tubing string.
[0009] Some sleeve systems have been proposed for flow control
through tubing ports. However, the ports are generally closely
positioned such that they can all be covered by the sleeve.
SUMMARY OF THE INVENTION
[0010] A method and apparatus has been invented which provides for
selective communication to a wellbore for fluid treatment. In one
aspect, the method and apparatus provide for the running in of a
fluid treatment string, the fluid treatment string having ports
substantially closed against the passage of fluid therethrough, but
which are openable when desired to permit fluid flow into the
wellbore. The apparatus and methods of the present invention can be
used in various borehole conditions including open holes, lined or
cased holes, vertical, inclined or horizontal holes, and straight
or deviated holes.
[0011] In one embodiment, there is provided an apparatus for fluid
treatment of a borehole, the apparatus comprising a tubing string
having a long axis, a plurality of closures accessible from the
inner diameter of the tubing string, each closure closing a port
opened through the wall of the tubing string and preventing fluid
flow through its port, but being openable to permit fluid flow
through its port and each closure openable independently from each
other closure and a port opening sleeve positioned in the tubing
string and driveable through the tubing string to actuate the
plurality of closures to open the ports.
[0012] The sleeve can be driven in any way to move through the
tubing string to actuate the plurality of closures. In one
embodiment, the sleeve is driveable remotely, without the need to
trip a work string such as a tubing string, coiled tubing or a wire
line.
[0013] In one embodiment, the sleeve has formed thereon a seat and
the apparatus includes a sealing device selected to seal against
the seat, such that fluid pressure can be applied to drive the
sleeve and the sealing device can seal against fluid passage past
the sleeve. The sealing device can be, for example, a plug or a
ball, which can be deployed without connection to surface. This
embodiment avoids the need for tripping in a work string for
manipulation.
[0014] In one embodiment, the closures each include a cap mounted
over its port and extending into the tubing string inner bore, the
cap being openable by the sleeve engaging against. The cap, when
opened, permits fluid flow through the port. The cap can be opened,
for example, by action of the sleeve breaking open the cap or
shearing the cap from its position over the port.
[0015] In another embodiment, the closures each include a
port-closure sleeve mounted over at least one port and openable by
the sleeve engaging and moving the port-closure sleeve away from
its associated at least one port. The port-closure sleeve can
include, for example, a profile on its surface open to the tubing
string and the port-opening sleeve includes a locking dog biased
outwardly therefrom and selected to engage the profile on the
port-closure sleeve such that the port-closure sleeve is moved by
the port opening sleeve. The profile is formed such that the
locking dog can disengage therefrom, permitting the sleeve to move
along the tubing string to a next port-closure sleeve.
[0016] In one embodiment, the apparatus can include a packer about
the tubing string. The packers can be of any desired type to seal
between the wellbore and the tubing string. For example, the packer
can be a solid body packer including multiple packing elements.
[0017] In view of the foregoing there is provided a method for
fluid treatment of a borehole, the method comprising: providing an
apparatus for wellbore treatment according to one of the various
embodiments of the invention; running the tubing string into a
wellbore to a position for treating the wellbore; moving the sleeve
to open the closures of the ports and increasing fluid pressure to
force wellbore treatment fluid out through the ports.
[0018] In one method according to the present invention, the fluid
treatment is a borehole stimulation using stimulation fluids such
as one or more of acid, gelled acid, gelled water, gelled oil,
CO.sub.2, nitrogen and any of these fluids containing proppants,
such as for example, sand or bauxite. The method can be conducted
in an open hole or in a cased hole. In a cased hole, the casing may
have to be perforated prior to running the tubing string into the
wellbore, in order to provide access to the formation.
[0019] The method can include setting a packer about the tubing
string to isolate the fluid treatment to a selected section of the
wellbore.
BRIEF DESCRIPTION OF THE DRAWINGS
[0020] A further, detailed, description of the invention, briefly
described above, will follow by reference to the following drawings
of specific embodiments of the invention. These drawings depict
only typical embodiments of the invention and are therefore not to
be considered limiting of its scope. In the drawings:
[0021] FIG. 1 is a sectional view through a wellbore having
positioned therein a fluid treatment assembly according to the
present invention;
[0022] FIG. 2 is a sectional view through a wellbore having
positioned therein a fluid treatment assembly according to the
present invention;
[0023] FIG. 3 is a sectional view along the long axis of a packer
useful in the present invention;
[0024] FIG. 4a is a section through another wellbore having
positioned therein another fluid treatment assembly according to
the present invention, the fluid treatment assembly being in a
first stage of wellbore treatment;
[0025] FIG. 4b is a section through the wellbore of FIG. 4a with
the fluid treatment assembly in a second stage of wellbore
treatment;
[0026] FIG. 4c is a section through the wellbore of FIG. 4a with
the fluid treatment assembly in a third stage of wellbore
treatment;
[0027] FIG. 5 is a sectional view along the long axis of a tubing
string according to the present invention containing a sleeve and
axially spaced fluid treatment ports;
[0028] FIG. 6 is a sectional view along the long axis of a tubing
string according to the present invention containing a sleeve and
axially spaced fluid treatment ports;
[0029] FIG. 7a is a section through a wellbore having positioned
therein another fluid treatment assembly according to the present
invention, the fluid treatment assembly being in a first stage of
wellbore treatment;
[0030] FIG. 7b is a section through the wellbore of FIG. 7a with
the fluid treatment assembly in a second stage of wellbore
treatment;
[0031] FIG. 7c is a section through the wellbore of FIG. 7a with
the fluid treatment assembly in a third stage of wellbore
treatment; and
[0032] FIG. 7d is a section through the wellbore of FIG. 7a with
the fluid treatment assembly in a fourth stage of wellbore
treatment.
DETAILED DESCRIPTION OF THE PRESENT INVENTION
[0033] Referring to FIG. 1, a wellbore fluid treatment assembly is
shown, which can be used to effect fluid treatment of a formation
10 through a wellbore 12. The wellbore assembly includes a tubing
string 14 having a lower end 14a and an upper end extending to
surface (not shown). Tubing string 14 includes a plurality of
spaced apart ports 17 opened through the tubing string wall to
permit access between the tubing string inner bore 18 and the
wellbore. Each port 17 includes thereover a closure that can be
closed to substantially prevent, and selectively opened to permit,
fluid flow through the ports.
[0034] A port-opening sleeve 22 is disposed in the tubing string to
control the opening of the port closures. In this embodiment,
sleeve 22 is mounted such that it can move, arrow A, from a port
closed position, wherein the sleeve is shown in phantom, axially
through the tubing string inner bore past the ports to a open port
position, shown in solid lines, to open the associated closures of
the ports allowing fluid flow therethrough. The sliding sleeve is
disposed to control the opening of the ports through the tubing
string and is moveable from a closed port position to a position
wherein the ports have been opened by passing of the sleeve and
fluid flow of, for example, stimulation fluid is permitted down
through the tubing string, arrows F, through the ports of the
ported interval. If fluid flow is continued, the fluid can return
to surface through the annulus.
[0035] The tubing string is deployed into the borehole in the
closed port position and can be positioned down hole with the ports
at a desired location to effect fluid treatment of the
borehole.
[0036] Referring to FIG. 2, a wellbore fluid treatment assembly is
shown, which can be used to effect fluid treatment of a formation
10 through a wellbore 12. The wellbore assembly includes a tubing
string 14 having a lower end 14a and an upper end extending to
surface (not shown). Tubing string 14 includes a plurality of
spaced apart ported intervals 16c to 16e each including a plurality
of ports 17 opened through the tubing string wall to permit access
between the tubing string inner bore 18 and the wellbore. The ports
are normally closed by pressure holding caps 23.
[0037] Packers 20d to 20e are mounted between each pair of adjacent
ported intervals. In the illustrated embodiment, a packer 20f is
also mounted below the lower most ported interval 16e and lower end
14a of the tubing string. Although not shown herein, a packer can
be positioned above the upper most ported interval. The packers are
disposed about the tubing string and selected to seal the annulus
between the tubing string and the wellbore wall, when the assembly
is disposed in the wellbore. The packers divide the wellbore into
isolated segments wherein fluid can be applied to one segment of
the well, but is prevented from passing through the annulus into
adjacent segments. As will be appreciated the packers can be spaced
in any way relative to the ported intervals to achieve a desired
interval length or number of ported intervals per segment. In
addition, packer 20f need not be present in some applications.
[0038] The packers can be, as shown, of the solid body-type with at
least one extrudable packing element, for example, formed of
rubber. Solid body packers including multiple, spaced apart packing
elements 21a, 21b on a single packer are particularly useful
especially for example in open hole (unlined wellbore) operations.
In another embodiment, a plurality of packers are positioned in
side by side relation on the tubing string, rather than using only
one packer between each ported interval.
[0039] Sliding sleeves 22c to 22e are disposed in the tubing string
to control the opening of the ports by opening the caps. In this
embodiment, a sliding sleeve is mounted for each ported interval
and can be moved axially through the tubing string inner bore to
open the caps of its interval. In particular, the sliding sleeves
are disposed to control the opening of their ported intervals
through the tubing string and are each moveable from a closed port
position away from the ports of the ported interval (as shown by
sleeves 22c and 22d) to a position wherein it has moved past the
ports to break open the caps and wherein fluid flow of, for
example, stimulation fluid is permitted through the ports of the
ported interval (as shown by sleeve 22e).
[0040] The assembly is run in and positioned downhole with the
sliding sleeves each in their closed port position. When the tubing
string is ready for use in fluid treatment of the wellbore, the
sleeves are moved to their port open positions. The sleeves for
each isolated interval between adjacent packers can be opened
individually to permit fluid flow to one wellbore segment at a
time, in a staged treatment process.
[0041] Preferably, the sliding sleeves are each moveable remotely,
for example without having to run in a line or string for
manipulation thereof, from their closed port position to their
position permitting through-port fluid flow. In one embodiment, the
sliding sleeves are actuated by devices, such as balls 24d, 24e (as
shown) or plugs, which can be conveyed by gravity or fluid flow
through the tubing string. The device engages against the sleeve
and causes it to move through the tubing string. In this case, ball
24e is sized so that it cannot pass through sleeve 22e and is
engaged in it when pressure is applied through the tubing string
inner bore 18 from surface, ball 24e seats against and plugs fluid
flow past the sleeve. Thus, when fluid pressure is applied after
the ball has seated in the sleeve, a pressure differential is
created above and below the sleeve which drives the sleeve toward
the lower pressure side.
[0042] In the illustrated embodiment, the inner surface of each
sleeve, which is the side open to the inner bore of the tubing
string, defines a seat 26e onto which an associated ball 24e, when
launched from surface, can land and seal thereagainst. When the
ball seals against the sleeve seat and pressure is applied or
increased from surface, a pressure differential is set up which
causes the sliding sleeve on which the ball has landed to slide
through the tubing string to an port-open position until it is
stopped by, for example, a no go. When the ports of the ported
interval 16e are opened, fluid can flow therethrough to the annulus
between the tubing string and the wellbore and thereafter into
contact with formation 10.
[0043] Each of the plurality of sliding sleeves has a different
diameter seat and, therefore, each accept a different sized ball.
In particular, the lower-most sliding sleeve 22e has the smallest
diameter D1 seat and accepts the smallest sized ball 24e and each
sleeve that is progressively closer to surface has a larger seat.
For example, as shown in FIG. 1b, the sleeve 22c includes a seat
26c having a diameter D3, sleeve 22d includes a seat 26d having a
diameter D2, which is less than D3 and sleeve 22c includes a seat
26e having a diameter D1, which is less than D2. This provides that
the lowest sleeve can be actuated to open it ports first by first
launching the smallest ball 24e, which can pass though all of the
seats of the sleeves closer to surface but which will land in and
seal against seat 26e of sleeve 22e. Likewise, penultimate sleeve
22d can be actuated to move through ported interval 16d by
launching a ball 24d which is sized to pass through all of the
seats closer to surface, including seat 26c, but which will land in
and seal against seat 26d.
[0044] Lower end 14a of the tubing string can be open, closed or
fitted in various ways, depending on the operational
characteristics of the tubing string which are desired. In the
illustrated embodiment, the tubing string includes a pump out plug
assembly 28. Pump out plug assembly 28 acts to close offend 14a
during run in of the tubing string, to maintain the inner bore of
the tubing string relatively clear. However, by application of
fluid pressure, for example at a pressure of about 3000 psi, the
plug can be blown out to permit actuation of the lower most sleeve
22e by generation of a pressure differential. As will be
appreciated, an opening adjacent end 14a is only needed where
pressure, as opposed to gravity, is needed to convey the first ball
to land in the lower-most sleeve. Alternately, the lower most
sleeve can be hydraulically actuated, including a fluid actuated
piston secured by shear pins, so that the sleeve can be driven
along the tubing string remotely without the need to land a ball or
plug therein.
[0045] In other embodiments, not shown, end 14a can be left open or
can be closed, for example, by installation of a welded or threaded
plug.
[0046] While the illustrated tubing string includes three ported
intervals, it is to be understood that any number of ported
intervals could be used. In a fluid treatment assembly desired to
be used for staged fluid treatment, at least two openable ports
from the tubing string inner bore to the wellbore must be provided
such as at least two ported intervals or an openable end and one
ported interval. It is also to be understood that any number of
ports can be used in each interval.
[0047] Centralizer 29 and other tubing string attachments can be
used, as desired.
[0048] The wellbore fluid treatment apparatus, as described with
respect to FIG. 2, can be used in the fluid treatment of a
wellbore. For selectively treating formation 10 through wellbore
12, the above-described assembly is run into the borehole and the
packers are set to seal the annulus at each location creating a
plurality of isolated annulus zones. Fluids can then pumped down
the tubing string and into a selected zone of the annulus, such as
by increasing the pressure to pump out plug assembly 28.
Alternately, a plurality of open ports or an open end can be
provided or lower most sleeve can include a piston face for
hydraulic actuation thereof. Once that selected zone is treated, as
desired, ball 24e or another sealing plug is launched from surface
and conveyed by gravity or fluid pressure to seal against seat 26e
of the lower most sliding sleeve 22e, this seals off the tubing
string below sleeve 22e and drives the sleeve to open the ports of
ported interval 16e to allow the next annulus zone, the zone
between packer 20e and 20f, to be treated with fluid. The treating
fluids will be diverted through the ports of interval 16e whose
caps have been removed by moving the sliding sleeve. The fluid can
then be directed to a specific area of the formation. Ball 24e is
sized to pass though all of the seats closer to surface, including
seats 26c, 26d, without sealing thereagainst. When the fluid
treatment through ports 16e is complete, a ball 24d is launched,
which is sized to pass through all of the seats, including seat 26c
closer to surface, and to seat in and move sleeve 22d. This opens
the ports of ported interval 16d and permits fluid treatment of the
annulus between packers 20d and 20e. This process of launching
progressively larger balls or plugs is repeated until all of the
zones are treated. The balls can be launched without stopping the
flow of treating fluids. After treatment, fluids can be shut in or
flowed back immediately. Once fluid pressure is reduced from
surface, any balls seated in sleeve seats can be unseated by
pressure from below to permit fluid flow upwardly therethrough.
[0049] The apparatus is particularly useful for stimulation of a
formation, using stimulation fluids, such as for example, acid,
gelled acid, gelled water, gelled oil, CO.sub.2, nitrogen and/or
proppant laden fluids.
[0050] Referring to FIG. 3, a packer 20 is shown which is useful in
the present invention. The packer can be set using pressure or
mechanical forces. Packer 20 includes extrudable packing elements
21a, 21b, a hydraulically actuated setting mechanism and a
mechanical body lock system 31 including a locking ratchet
arrangement. These parts are mounted on an inner mandrel 32.
Multiple packing elements 21a, 21b are formed of elastomer, such as
for example, rubber and include an enlarged cross section to
provide excellent expansion ratios to set in oversized holes. The
multiple packing elements 21a, 21b can be separated by at least
0.3M and preferably 0.8M or more. This arrangement of packing
elements aid in providing high pressure sealing in an open
borehole, as the elements load into each other to provide
additional pack-off.
[0051] Packing element 21a is mounted between fixed stop ring 34a
and compressing ring 34b and packing element 21b is mounted between
fixed stop ring 34c and compressing ring 34d. The hydraulically
actuated setting mechanism includes a port 35 through inner mandrel
32, which provides fluid access to a hydraulic chamber defined by
first piston 36a and second piston 36b. First piston 36a acts
against compressing ring 34b to drive compression and, therefore,
expansion of packing element 21a, while second piston 36b acts
against compressing ring 34d to drive compression and, therefore,
expansion of packing element 21b. First piston 36a includes a skirt
37, which encloses the hydraulic chamber between the pistons and is
telescopically disposed to ride over piston 36b. Seals 38 seal
against the leakage of fluid between the parts. Mechanical body
lock system 31, including for example a ratchet system, acts
between skirt 37 and piston 36b permitting movement therebetween
driving pistons 36a, 36b away from each other but locking against
reverse movement of the pistons toward each other, thereby locking
the packing elements into a compressed, expanded configuration.
[0052] Thus, the packer is set by pressuring up the tubing string
such that fluid enters the hydraulic chamber and acts against
pistons 36a, 36b to drive them apart, thereby compressing the
packing elements and extruding them outwardly. This movement is
permitted by body lock system 31. However, body lock system 31
locks the packers against retraction to lock the packing elements
in their extruded conditions.
[0053] Ring 34a includes shears 38 which mount the ring to mandrel
32. Thus, for release of the packing elements from sealing position
the tubing string into which mandrel 32 is connected, can be pulled
up to release shears 38 and, thereby, release the compressing force
on the packing elements.
[0054] FIGS. 4a to 4c shows an assembly and method for fluid
treatment, termed sprinkling, wherein fluid supplied to an isolated
interval is introduced in a distributed, low pressure fashion along
an extended length of that interval. The assembly includes a tubing
string 212 and ported intervals 216a, 216b, 216c each including a
plurality of ports 217 spaced along the long axis of the tubing
string. Packers 220a, 220b are provided between each interval to
form an isolated, segment in the wellbore 212.
[0055] While the ports of interval 216c are open during run in of
the tubing string, the ports of intervals 216b and 216a, are closed
during run in and sleeves 222a and 222b are mounted within the
tubing string and actuatable to selectively open the ports of
intervals 216a and 216b, respectively. In particular, in FIG. 4a,
the position of sleeve 222b is shown when the ports of interval
216b are closed. The ports in any of the intervals can be size
restricted to create a selected pressure drop therethrough,
permitting distribution of fluid along the entire ported
interval.
[0056] Once the tubing string is run into the well, stage 1 is
initiated wherein stimulation fluids are pumped into the end
section of the well to ported interval 216c to begin the
stimulation treatment (FIG. 4a). Fluids will be forced to the lower
section of the well below packer 220b. In this illustrated
embodiment, the ports of interval 216c are normally open size
restricted ports, which do not require opening for stimulation
fluids to be jetted therethrough. However, it is to be understood
that the ports can be installed in closed configuration, but opened
once the tubing is in place.
[0057] When desired to stimulate another section of the well (FIG.
4b), a ball or plug (not shown) is pumped by fluid pressure, arrow
P, down the well and will seat in a selected sleeve 222b sized to
accept the ball or plug. The pressure of the fluid behind the ball
will push the cutter sleeve against any force or member, such as a
shear pin, holding the sleeve in position and down the tubing
string, arrow S. As it moves down, it will open the ports of
interval 216b as it passes by them. Sleeve 222b eventually stops
against a stop means. Since fluid pressure will hold the ball in
the sleeve, this effectively shuts off the lower segment of the
well including previously treated interval 216c. Treating fluids
will then be forced through the newly opened ports. Using limited
entry or a flow regulator, a tubing to annulus pressure drop
insures distribution. The fluid will be isolated to treat the
formation between packers 220a and 220b.
[0058] After the desired volume of stimulation fluids are pumped, a
slightly larger second ball or plug is injected into the tubing and
pumped down the well, and will seat in sleeve 222a which is
selected to retain the larger ball or plug. The force of the moving
fluid will push sleeve 222a down the tubing string and as it moves
down, it will open the ports in interval 216a. Once the sleeve
reaches a desired depth as shown in FIG. 4c, it will be stopped,
effectively shutting off the lower segment of the well including
previously treated intervals 216b and 216c. This process can be
repeated a number of times until most or all of the wellbore is
treated in stages, using a sprinkler approach over each individual
section.
[0059] The above noted method can also be used for wellbore
circulation to circulate existing wellbore fluids (drilling mud for
example) out of a wellbore and to replace that fluid with another
fluid. In such a method, a staged approach need not be used, but
the sleeve can be used to open ports along the length of the tubing
string. In addition, packers need not be used when the apparatus is
intended for wellbore circulation as it is often desirable to
circulate the fluids to surface through the wellbore annulus.
[0060] The sleeves 222a and 222b can be formed in various ways to
cooperate with ports 217 to open those ports as they pass through
the tubing string.
[0061] With reference to FIG. 5, a tubing string 214 according to
the present invention is shown including a movable sleeve 222 and a
plurality of normally closed ports 217 spaced along the long axis x
of the string. Ports 217 each include a pressure holding, internal
cap 223. Cap 223 extends into the bore 218 of the tubing string and
is formed of shareable material at least at its base, so that it
can be sheared off to open the port. Cap 223 can be, for example, a
cobe sub or other modified subs. As will be appreciated, due to the
use of ball actuated sleeves, the caps are selected to be resistant
to shearing by movement of a ball therepast.
[0062] Sleeve 222 is mounted in the tubing string and includes a
cylindrical outer surface having a diameter to substantially
conform to the inner diameter of, but capable of sliding through,
the section of the tubing string in which the sleeve is selected to
act. Sleeve 222 is mounted in tubing string by use of a shear pin
250 and has a seat 226 formed on its inner facing surface with a
seat diameter to be plugged by a selected size ball 224 having a
diameter greater than the seat diameter. When the ball is seated in
the seat, and fluid pressure is applied therebehind, arrow P, shear
pin 250 will shear and the sleeve will be driven, with the ball
seated therein along the length of the tubing string until stopped
by shoulder 246.
[0063] Sleeve 222 includes a profiled leading end 247 which is
formed to shear or cut off the protective caps 223 from the ports
as it passes, thereby opening the ports. Sleeve 222 and caps 223
are selected with consideration as to the fluid pressures to be
used to substantially ensure that the sleeve can shear the caps
from and move past the ports as it is driven through the tubing
string.
[0064] While shoulder 246 is illustrated as an annular step on the
inner diameter of the tubing string, it is to be understood that
any configuration that stops movement of the sleeve though the
wellbore can be used. Shoulder 246 is preferably spaced from the
ports 217 with consideration as to the length of sleeve 222 such
that when the sleeve is stopped against the shoulder, the sleeve
does not cover any ports. Although not shown, the sleeve can be
disposed in a circumferential groove in the tubing string, the
groove having a diameter greater than the id of the tubing string.
In such an embodiment, the sleeve could be disposed in the groove
to eliminate or limit its extension into the tubing string inner
diameter.
[0065] Sleeve 222 can include seals 252 to seal between the
interface of the sleeve and the tubing string, where it is desired
to seal off fluid flow therebetween.
[0066] The caps can also be used to close off ports disposed in a
plane orthogonal to the long axis of the tubing string, if
desired.
[0067] Referring to FIG. 6, there is shown another tubing string
314 according to the present invention. The tubing string includes
an axially movable sleeve 322 and a plurality of normally closed
ports 317a, 317a', 317b, 317b'. Ports 317a, 317a' are spaced from
each other on the tubing circumference. Ports 317b, 317b' are also
spaced circumferentially in a plane orthogonal to the long axis of
the tubing string. Ports 317a, 317a' are spaced from ports 317b,
317b' along the long axis x of the string.
[0068] Sleeve 322 is normally mounted by shear 350 in the tubing
string. However, fluid pressure created by seating of a plug 324 in
the sleeve, can cause the shear to be sheared and the sleeve to be
driven along the tubing string until it butts against a shoulder
346.
[0069] Ports 317a, 317a' have positioned thereover a port-closing
sleeve 325a and ports 317b, 317b' have positioned thereover a port
closing sleeve 325b. The sleeves act as valves to seal against
fluid flow though their associated ports, when they are positioned
thereover. However, sleeves 325a, 325b can be moved axially along
the tubing string to exposed their associated ports, permitting
fluid flow therethrough. In particular, with reference to ports
317a, 317a', each set of ports includes an associated sliding
sleeve disposed in a cylindrical groove, defined by shoulders 327a,
327b about the port. The groove is formed in the inner wall of the
tubing string and sleeve 325a is selected to have an inner diameter
that is generally equal to the tubing string inner diameter and an
outer diameter that substantially conforms to, but is slidable
along, the groove between shoulders 327a, 327b. Seals 329 are
provided between sleeve 325a and the groove, such that fluid
leakage therebetween is substantially avoided.
[0070] The port closing sleeves, for example 325a, are normally
positioned over their associated ports 317a, 317a' adjacent
shoulder 327a, but can be slid along the groove until stopped by
shoulder 327b. In each case, the shoulder 327b is spaced from its
ports with consideration as to the length of the associated sleeve
so that when the sleeve is butted against shoulder 327b, the port
is open to allow at least some fluid flow therethrough.
[0071] The port-closing sleeves 325a, 325b are each formed to be
engaged and moved by sleeve 322 as it passes through the tubing
string from its pinned position to its position against shoulder
346. In the illustrated embodiments, sleeves 325a, 325b are moved
by engagement of outwardly biased dogs 351 on the sleeve 322. In
particular, each sleeve 325a, 325b includes a profile 353a, 353b
into which dogs 351 can releasably engage. The spring force of dogs
and the co acting configurations of profiles and the dogs are
together selected to be greater than the resistance of sleeve 325
moving within the groove, but less than the fluid pressure selected
to be applied against ball 324, such that when sleeve 322 is driven
through the tubing string, it will engage against each sleeve 325a
to move it away from its ports 317a, 317a' and against its
associated shoulder 327b. However, continued application of fluid
pressure will drive the dogs 351 of the sleeve 322 to collapse,
overcoming their spring force, to remove the sleeve from engagement
with a first port-closing sleeve 325a, along the tubing string 314
and into engagement with the profile 353b of the next-port
associated sleeve 325b to move that sleeve and open ports 317b,
317b' and so on, until sleeve 322 stopped against shoulder 346.
[0072] Referring to FIGS. 7a to 7d, the wellbore fluid treatment
assemblies described above can also be combined with a series of
ball activated focused approach sliding sleeves and packers as
described in applicant's corresponding US Application 2003/0127227
to allow some segments of the well to be stimulated using a
sprinkler approach and other segments of the well to be stimulated
using a focused fracturing approach.
[0073] In this embodiment, a tubing or casing string 414 is made up
with two ported intervals 316b, 316d formed of subs having a series
of size restricted ports 317 therethrough and in which the ports
are each covered, for example, with protective pressure holding
internal caps and in which each interval includes a movable sleeve
322b, 322d with profiles that can act as a cutter to cut off the
protective caps to open the ports. Other ported intervals 16a, 16c
include a plurality of ports 417 disposed about a circumference of
the tubing string and are closed by a ball or plug activated
sliding sleeves 22a, 22c. Packers 420a, 420b, 420c, 420d are
disposed between each interval to create isolated segments along
the wellbore 412.
[0074] Once the system is run into the well (FIG. 7a), the tubing
string can be pressured to set some or all of the open hole
packers. When the packers are set, stimulation fluids are pumped
into the end section of the tubing to begin the stimulation
treatment, identified as stage 1 sprinkler treatment in the
illustrated embodiment. Initially, fluids will be forced to the
lower section of the well below packer 420d. In stage 2, shown in
FIG. 7b, a focused frac is conducted between packers 420c and 420d;
in stage 3, shown in FIG. 7c, a sprinkler approach is used between
packers 420b and 420c; and in stage 4, shown in FIG. 7d, a focused
frac is conducted between packers 420a and 420b.
[0075] Sections of the well that use a "sprinkler approach",
intervals 316b, 316d, will be treated as follows: When desired, a
ball or plug is pumped down the well, and will seat in one of the
cutter sleeves 322b, 322d. The force of the moving fluid will push
the cutter sleeve down the tubing string and as it moves down, it
will remove the pressure holding caps from the segment of the well
through which it passes. Once the cutter reaches a desired depth,
it will be stopped by a no-go shoulder and the ball will remain in
the sleeve effectively shutting off the lower segment of the well.
Stimulation fluids are then pumped as required.
[0076] Segments of the well that use a "focused stimulation
approach", intervals 16a, 16c, will be treated as follows: Another
ball or plug is launched and will seat in and shift open a pressure
shifted sliding sleeve 22a, 22c, and block off the lower segment(s)
of the well. Stimulation fluids are directed out the ports 417
exposed for fluid flow by moving the sliding sleeve.
[0077] Fluid passing through each interval is contained by the
packers 420a to 420d on either side of that interval to allow for
treating only that section of the well.
[0078] The stimulation process can be continued using "sprinkler"
and/or "focused" placement of fluids, depending on the segment
which is opened along the tubing string.
[0079] It will be apparent that changes may be made to the
illustrative embodiments, while falling within the scope of the
invention and it is intended that all such changes be covered by
the claims appended hereto.
* * * * *