U.S. patent application number 13/102237 was filed with the patent office on 2011-11-24 for methods and tools for multiple fracture placement along a wellbore.
Invention is credited to Joseph A. Ayoub, Frank F. Chang, Kevin W. England, Dinesh R. Patel, George Waters.
Application Number | 20110284214 13/102237 |
Document ID | / |
Family ID | 44971488 |
Filed Date | 2011-11-24 |
United States Patent
Application |
20110284214 |
Kind Code |
A1 |
Ayoub; Joseph A. ; et
al. |
November 24, 2011 |
METHODS AND TOOLS FOR MULTIPLE FRACTURE PLACEMENT ALONG A
WELLBORE
Abstract
The invention discloses a tool for use in a wellbore,
comprising: a tubular elongated member; openings on the tubular
member able to be close with a valve or a sleeve; swellable packers
positioned between said opening on the tubular member; and a
control unit; the control unit operating the valve or sleeve for
fracturing a subterranean formation in a wellbore, in the stages:
a. fracturing the subterranean formation through a first stage at
predefined first locations; and b. fracturing the subterranean
formation through a second stage at second location(s) wherein each
location from the second location(s) is localized between the
predefined first locations.
Inventors: |
Ayoub; Joseph A.; (Katy,
TX) ; Patel; Dinesh R.; (Sugar Land, TX) ;
England; Kevin W.; (Houston, TX) ; Chang; Frank
F.; (Al-Khobar, SA) ; Waters; George;
(Oklahoma City, OK) |
Family ID: |
44971488 |
Appl. No.: |
13/102237 |
Filed: |
May 6, 2011 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61346306 |
May 19, 2010 |
|
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Current U.S.
Class: |
166/177.5 |
Current CPC
Class: |
E21B 43/26 20130101 |
Class at
Publication: |
166/177.5 |
International
Class: |
E21B 43/26 20060101
E21B043/26 |
Claims
1. A tool for use in a wellbore, comprising: a tubular elongated
member; openings on the tubular member able to be close with a
valve or a sleeve; swellable packers positioned between said
opening on the tubular member; and a control unit; the control unit
operating the valve or sleeve for fracturing a subterranean
formation in a wellbore, in the stages: a. fracturing the
subterranean formation through a first stage at predefined first
locations; and b. fracturing the subterranean formation through a
second stage at second location(s) wherein each location from the
second location(s) is localized between the predefined first
locations.
2. The tool of claim 1, wherein the wellbore has a section
substantially deviated or horizontal.
3. The tool of claim 1, wherein the wellbore has a horizontal
section where the tool is placed.
4. The tool of claim 1, wherein the control unit is a downhole
tool, a coiled tubing or a drill string.
5. The tool of claim 1, wherein the tool is deployed during
completion.
6. The tool of claim 1, wherein the swellable packers are activated
with oil based, water based, or alternative fluids.
7. The tool of claim 1, wherein the swellable packers set by
mechanical or thermal means.
8. A tool for use in a wellbore, comprising: a tubular elongated
member; openings on the tubular member able to be close with a
valve or a sleeve; swellable packers positioned between said
opening on the tubular member; and a control unit; the control unit
operating the valve or sleeve for fracturing a subterranean
formation in a wellbore, in the stages: a. fracturing the
subterranean formation through a first stage at predefined first
locations; b. fracturing the subterranean formation through a
second stage at second location(s) wherein each location from the
second location(s) is localized between the predefined first
locations; and c. fracturing the subterranean formation through a
third stage at third locations wherein each location from the third
locations is localized between the one of the predefined first
locations and one of the second location(s).
9. The tool of claim 9, wherein the wellbore has a section
substantially deviated or horizontal.
10. The tool of claim 9, wherein the wellbore has a horizontal
section where the tool is placed.
11. The tool of claim 9, wherein the control unit is a downhole
tool, a coiled tubing or a drill string.
12. The tool of claim 9, wherein the tool is deployed during
completion.
13. The tool of claim 9, wherein the swellable packers are
activated with oil based, water based, or alternative fluids.
14. The tool of claim 9, wherein the swellable packers set by
mechanical or thermal means.
15. A tool for use in a wellbore, comprising: a tubular elongated
member; openings on the tubular member able to be close with a
valve or a sleeve; swellable packers positioned between said
opening on the tubular member; and a control unit; the control unit
operating the valve or sleeve for fracturing a subterranean
formation in a wellbore, in the stages: a. fracturing the
subterranean formation through a first stage at predefined first
locations; b. fracturing the subterranean formation through a
second stage at second location(s) wherein each location from the
second location(s) is localized between the predefined first
locations; c. fracturing the subterranean formation through a third
stage at third locations wherein each location from the third
locations is localized between the one of the predefined first
locations and one of the second location(s); and d. fracturing the
subterranean formation through a n-stage at n locations wherein
each location from the n locations is localized between the one of
the preceding locations.
16. The tool of claim 15, wherein the wellbore has a section
substantially deviated or horizontal.
17. The tool of claim 15, wherein the wellbore has a horizontal
section where the tool is placed.
18. The tool of claim 15, wherein the control unit is a downhole
tool, a coiled tubing or a drill string.
19. The tool of claim 15, wherein the tool is deployed during
completion.
20. The tool of claim 15, wherein the swellable packers are
activated with oil based, water based, or alternative fluids.
21. The tool of claim 15, wherein the swellable packers set by
mechanical or thermal means.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the benefit of U.S. Provisional
Application No. 61/346,306, filed May 19, 2010, which is
incorporated herein by reference in its entirety.
FIELD OF THE INVENTION
[0002] The invention relates to methods for treating subterranean
formations. More particularly, the invention relates to a tool for
fracturing subterranean formations.
BACKGROUND
[0003] The statements in this section merely provide background
information related to the present disclosure and may not
constitute prior art.
[0004] Hydrocarbons (oil, condensate, and gas) are typically
produced from wells that are drilled into the formations containing
them. For a variety of reasons, such as inherently low permeability
of the reservoirs or damage to the formation caused by drilling and
completion of the well, the flow of hydrocarbons into the well is
undesirably low. In this case, the well is "stimulated" for example
using hydraulic fracturing, chemical (usually acid) stimulation, or
a combination of the two (called acid fracturing or fracture
acidizing).
[0005] In hydraulic and acid fracturing, a first, viscous fluid
called the pad is typically injected into the formation to initiate
and propagate the fracture. This is followed by a second fluid that
contains a proppant to keep the fracture open after the pumping
pressure is released. Granular proppant materials may include sand,
ceramic beads, or other materials. In "acid" fracturing, the second
fluid contains an acid or other chemical such as a chelating agent
that can dissolve part of the rock, causing irregular etching of
the fracture face and removal of some of the mineral matter,
resulting in the fracture not completely closing when the pumping
is stopped. Occasionally, hydraulic fracturing can be done without
a highly viscosified fluid (i.e., slick water) to minimize the
damage caused by polymers or the cost of other viscosifiers.
[0006] It is an object of the present invention to provide an
improved method of fracturing by using a new tool deployed in the
well.
SUMMARY
[0007] In a first aspect, a tool for use in a wellbore, comprises a
tubular elongated member; openings on the tubular member able to be
close with a valve or a sleeve; swellable packers positioned
between said opening on the tubular member; and a control unit; the
control unit operating the valve or sleeve for fracturing a
subterranean formation in a wellbore, in the stages: (a) fracturing
the subterranean formation through a first stage at predefined
first locations; and (b) fracturing the subterranean formation
through a second stage at second location(s) wherein each location
from the second location(s) is localized between the predefined
first locations.
[0008] In a second aspect, a tool for use in a wellbore, comprises
a tubular elongated member; openings on the tubular member able to
be close with a valve or a sleeve; swellable packers positioned
between said opening on the tubular member; and a control unit; the
control unit operating the valve or sleeve for fracturing a
subterranean formation in a wellbore, in the stages: (a) fracturing
the subterranean formation through a first stage at predefined
first locations; (b) fracturing the subterranean formation through
a second stage at second location(s) wherein each location from the
second location(s) is localized between the predefined first
locations; and (c) fracturing the subterranean formation through a
third stage at third locations wherein each location from the third
locations is localized between the one of the predefined first
locations and one of the second location(s).
[0009] In a second aspect, a tool for use in a wellbore, comprises
a tubular elongated member; openings on the tubular member able to
be close with a valve or a sleeve; swellable packers positioned
between said opening on the tubular member; and a control unit; the
control unit operating the valve or sleeve for fracturing a
subterranean formation in a wellbore, in the stages: (a) fracturing
the subterranean formation through a first stage at predefined
first locations; (b) fracturing the subterranean formation through
a second stage at second location(s) wherein each location from the
second location(s) is localized between the predefined first
locations; (c) fracturing the subterranean formation through a
third stage at third locations wherein each location from the third
locations is localized between the one of the predefined first
locations and one of the second location(s); and (d) fracturing the
subterranean formation through a n-stage at n locations wherein
each location from the n locations is localized between the one of
the preceding locations.
BRIEF DESCRIPTION OF THE DRAWINGS
[0010] FIGS. 1a, 1b, 1c, 1d and 1e are used as an example to
illustrate the sequence of hydraulic fracturing according to
embodiments disclosed herewith.
[0011] FIGS. 2a and 2b illustrate the symmetrical effect that
result in the third stage fracture (numbered 3) of the previous
embodiment in FIG. 1a.
[0012] FIGS. 3a, 3b and 3c illustrate schematically tools according
to embodiments disclosed herewith.
[0013] FIGS. 4a, 4b, 4c and 4d show example of stages to illustrate
the sequence of hydraulic fracturing according to embodiments
disclosed herewith.
DESCRIPTION
[0014] At the outset, it should be noted that in the development of
any actual embodiments, numerous implementation-specific decisions
must be made to achieve the developer's specific goals, such as
compliance with system and business related constraints, which can
vary from one implementation to another. Moreover, it will be
appreciated that such a development effort might be complex and
time consuming but would nevertheless be a routine undertaking for
those of ordinary skill in the art having the benefit of this
disclosure.
[0015] The description and examples are presented solely for the
purpose of illustrating embodiments of the invention and should not
be construed as a limitation to the scope and applicability of the
invention. In the summary of the invention and this detailed
description, each numerical value should be read once as modified
by the term "about" (unless already expressly so modified), and
then read again as not so modified unless otherwise indicated in
context. Also, in the summary of the invention and this detailed
description, it should be understood that a concentration range
listed or described as being useful, suitable, or the like, is
intended that any and every concentration within the range,
including the end points, is to be considered as having been
stated. For example, "a range of from 1 to 10" is to be read as
indicating each and every possible number along the continuum
between about 1 and about 10. Thus, even if specific data points
within the range, or even no data points within the range, are
explicitly identified or refer to only a few specific, it is to be
understood that inventors appreciate and understand that any and
all data points within the range are to be considered to have been
specified, and that inventors possession of the entire range and
all points within the range disclosed and enabled the entire range
and all points within the range.
[0016] The application discloses a method of delivery for more
closely spaced multiple hydraulic fracture treatments along a
deviated, horizontal or extended reach well. These fractures are
typically placed in sequence/stages starting from the toe of the
well and moving towards the heel. It has been noted that increasing
the number of hydraulic fracture treatments along horizontal wells,
in particular for shale gas wells, results in significant increase
of the production. Shale gas formation characteristics seem to
favor closer spacing fracture treatments than economically
advisable in more permeable reservoirs. However, there is a limit
as to how closely the fractures can be placed as each fracture
alters the stress state in the formations around it, which can
interfere with the outcome of the subsequent fracturing
treatment/stage aimed at propagating a fracture within the affected
area and can impact negatively its intended initiation,
propagation, orientation, etc.
[0017] A method of fracturing a subterranean formation in a
wellbore, comprises: fracturing the subterranean formation through
a first stage at predefined first locations; and fracturing the
subterranean formation through a second stage at second location(s)
wherein each location from the second location(s) is localized
between the predefined first locations. Each location from the
second location(s) may be localized in the middle between the
predefined first locations. The method may further comprise
fracturing the subterranean formation through a third stage at
third locations wherein each location from the third locations is
localized between the one of the predefined first locations and one
of the second location(s). Each location from the third locations
may be localized in the middle between the one of the predefined
first locations and one of the second location(s). The method may
further comprise fracturing the subterranean formation through a
n-stage at n locations wherein each location from the n locations
is localized between the one of the preceding locations. Each
location from the n locations may be localized in the middle
between the one of the preceding locations. In one embodiment, the
wellbore is horizontal and/or the subterranean formation contains
at least partially rock material which is shale.
[0018] The tools and method outlined in this application enable the
placement of more closely spaced fractures intersecting the
wellbore. The method proposed consist of using specialized
equipment, which enables alternating the fracture placement order
so that in a first phase, fractures are placed far enough from each
other to avoid interference and in a second phase another set of
fractures are created half way between the fractures of the first
phase. Symmetry allows the second set of fractures to propagate in
the intended direction parallel to the first set.
[0019] FIGS. 1a, 1b and 1c are used as an example to illustrate the
sequence of hydraulic fracturing according to embodiments disclosed
herewith. A downhole equipment is deployed in the wellbore and
allows a non-consecutive sequence for fracturing. Instead of
pumping stages 1-5 sequentially along the wellbore starting from
the toe (FIG. 1a--prior art), we would pump stages 1, 2, 3 with
longer spacing and then go back and pump stages 4 and 5 between the
fractures 1-2 and 2-3 respectively (FIG. 1b). We can also place
additional fractures between 1 and 4, then between 4 and 2 . . . if
economics are positive for such action, as long as higher
fracturing pressures could be handled in practice (FIG. 1c). FIGS.
1d and 1e show another type of stimulation starting at the
heel.
[0020] FIG. 2 illustrates the symmetrical effect that result in the
third stage fracture (number 3) being able to propagate parallel to
stages 1 and 2. Placing fracture 3 before fracture 2 would result
in fracture 3 moving away from fracture 1 and tending to initiate
along the wellbore due to the stress regime created by fracture
1.
[0021] According to a first embodiment, downhole sliding sleeves 32
or other devices with similar functionality are deployed on a pipe
30 that is equipped with packers 31 that isolate the annulus space
34 between the pipe and the wellbore around each set of sliding
sleeves/devices. The wellbore could be open hole 40,
cased/un-cemented (slotted, pre-perforated, etc) or cased/cemented
& perforated in multiple clusters that would be grouped to fall
between the isolation packers. Optionally, the cased hole could be
pre-perforated in clusters. The space between packers could contain
multiple clusters of perforations. In one or more embodiments, the
opening of the valve/sliding sleeve could detonate charges deployed
simultaneously with the valves, which would perforate the casing.
The packer elements could be simply swellable packers or could be
activated by mechanical, hydraulic and electrical means or a
combination. A fracture 50 is generated. In general the well
comprises a casing 10 and a production packer 11. The frac valve
operating tool 12 may be deployed in the wellbore with a coiled
tubing 13. FIG. 3a is a view of such configuration.
[0022] The downhole sliding sleeves tool can include one or more
subs and/or sections threadably connected to form a unitary
body/mandrel having a bore or flow path formed therethrough. In one
or more embodiments, the tool can include one or more valve
sections, one or more sliding sleeves, one or more sealing devices
and/or one or more openings or radial apertures formed therethrough
to provide fluid communication between the inner bore and external
surface of the tool. The tool comprises a lower end (localized at
the toe of the wellbore) and an upper end. In one or more
embodiments, the lower end can be adapted to receive or otherwise
connect to a drill string, a similar tool or other downhole tool,
while the upper end can be adapted to receive or otherwise connect
a similar tool, a coiled tubing, a drill string or other types of
downhole tools. In one or more embodiments, the tool can be
fabricated from any suitable material, including metallic,
non-metallic, and metallic/nonmetallic composite materials. In one
or more embodiments the tool may be done from a drillable material.
In one or more embodiments, the end of the tool can include one or
more threaded ends to permit the connection of a casing string or
additional combination tool sections as described herein.
[0023] In one or more embodiments, the sealing devices positioned
on the outside surface from the unitary body are swellable packers.
The swellable packers are localized on both side of the radial
openings (lower and upper front) as shown on FIG. 3a. When the
swellable packers are activated the zone of the wellbore between
both packers is isolated. The swellable packers may be activated
with oil based, water based, or alternative fluids. The packers may
also be set by mechanical or thermal means.
[0024] In the fracturing process, fluid communication between the
interior and exterior of the tool is permitted. Such fluid
communication is advantageous for example when it is necessary to
fracture the hydrocarbon bearing zones surrounding the tool by
pumping a slurry at high pressure through the casing string, into
the bore of the tool. The high pressure slurry passes through the
tool and exits the tool via the radial openings when the valve or
the sliding sleeve is opened.
[0025] In one or more embodiments, the tool deployed could be
manipulated via coiled tubing. The coiled tubing could be equipped
with a retractable key that engages the devices selectively to
mechanically open or close them as needed to affect the sequence
described above. The coiled tubing could be left in the wellbore
during the fracture treatments and could carry monitoring equipment
including pressure/temperature/optical/geophysical sensors. It
could also be used to deliver specialty materials that are used to
better monitor the treatments or modify properties of pumped
materials.
[0026] In one or more embodiments, these tools can be designed and
deployed so that they can be controlled electrically or
hydraulically via a control cable 16 or hydraulic line (FIG. 3b).
The elongated pipe may be a tubing 15. They could also be designed
to be operated wirelessly via acoustic or electromagnetic signals.
The signals could be sent remotely from surface or using a downhole
signal generator/transmitter. The electromagnetic or acoustic
triggers of the devices could also be deployed via wireline
with/without tractor or via coiled tubing. Also some sensor 60 can
be used to monitor parameters of the wellbore for example to
control efficiency of the fracture. In one or more embodiments, the
tools can be operated open or closed via pressure signals applied
from surface that are uniquely coded for each devices. The operator
would thus be able to selectively open or close the appropriate
device to allow the fracture treatments to be placed as per the
sequence described above. In one or more embodiments, the signal
can be transmitted to tool by pumping a RFID tag to open or close
the tool. Each tool could be uniquely coded and pumped RFID tag
will have corresponding code.
[0027] In one or more embodiments, the tool can be run with liner
19 and cemented in place (FIG. 3c). A liner hanger 17 connects the
liner 19 to the casing 10. The cement 18 provides isolation between
zones or frac valves. The cemented frac valves or sleeves would
operate in the same manner.
[0028] In one or more embodiments, the technique could be applied
to dual lateral (could also be expanded to tri-lateral,
quad-lateral or more complex wellbores. As well the very similar
process could be applied to multiple horizontal wellbores. FIG. 4
shows a graphical representation how this type of process could be
applied. Please note that for simplicity of explanation in the
figures the fractures for each stage are only shown propagating in
one direction. In line with hydraulic fracturing theory it is
normally the case that a second "wing" of the fracture will
propagate at approximately 180-degrees.
[0029] In one or more embodiments, the technique could be applied
in conjunction for simultaneous multistage stimulation of long
horizontal wells. In an open hole environment, the formation is
notched using mechanical means, water jetting, or perforating
charges to create fracturing initiation sites in such a manner as
to enable simultaneous propagation of multiple fractures along the
horizontal wells. More than one set of notches may be used and the
fracturing treatment may be performed in two stages or more. The
first stage treats the first set of notches placed far enough from
each other such that the stress changes induced by the propagating
fractures do not create interference. Following the first stage, a
new set of notches are created half way between the
notches/fractures of the first stage and a second stage/treatment
is pumped to propagate a new set of fractures. Depending on
geometry of the fractures created in the first stage, the level and
orientation of local stress alteration will be different.
Therefore, the geometry of the second set of the notches will be
designed based on the stress alteration created by the first set of
fractures and by taking into account the mechanical properties of
local rock so that the fracturing pressure required to initiate new
set of fractures can be managed. The new notches could be wider and
deeper than the previous set, or the notch tips could be sharper.
The tools will have focus injection ports pin pointed at the notch
locations narrowly packed off by the packers to ensure that the
fractures are controllably initiated from the notches. The process
can be repeated if a higher density of fractures intersecting the
wellbore is economically desirable.
[0030] The possibilities for creating the activation of the
mechanism(s) to create fracture initiation points and provide
isolation for the stimulation can range all the way from the
simplest, more time-consuming methods (aka "dumb completion") to
the most technically complex and continuous methods (aka
"intelligent or smart completion"). One skilled in the art could
envision a number of ways to achieve the overall intent of the
invention.
[0031] The foregoing disclosure and description of the invention is
illustrative and explanatory thereof and it can be readily
appreciated by those skilled in the art that various changes in the
size, shape and materials, as well as in the details of the
illustrated construction or combinations of the elements described
herein can be made without departing from the spirit of the
invention.
* * * * *