U.S. patent application number 12/369863 was filed with the patent office on 2010-08-12 for method and apparatus for multi-zone stimulation.
Invention is credited to Perry Courville, Loyd East, JR., Dan Morrison, Milorad Stanojcic.
Application Number | 20100200230 12/369863 |
Document ID | / |
Family ID | 42537830 |
Filed Date | 2010-08-12 |
United States Patent
Application |
20100200230 |
Kind Code |
A1 |
East, JR.; Loyd ; et
al. |
August 12, 2010 |
Method and Apparatus for Multi-Zone Stimulation
Abstract
Methods of treating a well bore in a single trip are provided. A
tubing string may be inserted into a subterranean formation having
a well bore, where the tubing string has a locking device on an
end. A workover tool may be positioned in a first zone of the
subterranean formation, where the workover tool engages the locking
device. One or more perforations may be created or enhanced in a
first zone of a subterranean formation using the workover tool, and
the tubing string may be positioned in a second zone of the
subterranean formation. A fracturing fluid may be introduced into
the first zone of the subterranean formation at a rate and pressure
sufficient to create or enhance one or more fractures in the
subterranean formation. The first zone of the subterranean
formation may be isolated from the second zone of the subterranean
formation and one or more perforations in the second zone of the
subterranean formation may be created or enhanced using the
workover tool.
Inventors: |
East, JR.; Loyd; (Tomball,
TX) ; Morrison; Dan; (Katy, TX) ; Stanojcic;
Milorad; (Houston, TX) ; Courville; Perry;
(Houston, TX) |
Correspondence
Address: |
JOHN W. WUSTENBERG
P.O. BOX 1431
DUNCAN
OK
73536
US
|
Family ID: |
42537830 |
Appl. No.: |
12/369863 |
Filed: |
February 12, 2009 |
Current U.S.
Class: |
166/272.2 ;
166/386 |
Current CPC
Class: |
E21B 23/08 20130101;
E21B 43/267 20130101; E21B 43/11 20130101 |
Class at
Publication: |
166/272.2 ;
166/386 |
International
Class: |
E21B 43/247 20060101
E21B043/247; E21B 33/12 20060101 E21B033/12 |
Claims
1. A method of treating a well bore in a single trip, the method
comprising: inserting a tubing string into a subterranean formation
comprising a well bore, wherein the tubing string has a locking
device disposed on an end; positioning a workover tool in a first
zone of the subterranean formation, wherein the workover tool
engages the locking device; creating or enhancing one or more
perforations in a first zone of a subterranean formation using the
workover tool; positioning the tubing string in a second zone of
the subterranean formation; introducing a fracturing fluid into the
first zone of the subterranean formation at a rate and pressure
sufficient to create or enhance one or more fractures in the
subterranean formation; isolating the first zone of the
subterranean formation from the second zone of the subterranean
formation; and creating or enhancing one or more perforations in
the second zone of the subterranean formation using the workover
tool.
2. The method of claim 1 wherein inserting a tubing string into a
well bore comprises using a hydraulic workover unit to introduce
the tubing string into the well bore under pressure.
3. The method of claim 1 wherein the tubing string comprises
jointed tubing.
4. The method of claim 1 wherein positioning the workover tool or
positioning the tubing string comprises using a logging tool to
correlate the end with a depth in the well.
5. The method of claim 1 wherein introducing a fracturing fluid
comprises: pumping a fracturing fluid comprising a plurality of
proppant particulates between the tubing string and the well bore;
and simultaneously pumping a base fluid through the tubing
string.
6. The method of claim 1 wherein isolating the first zone comprises
introducing a plurality of proppant particulates into the well bore
between the first zone and the second zone to form a bridge.
7. The method of claim 1 wherein the workover tool comprises at
least one tool selected from the group consisting of: a
hydrajetting tool, a perforating gun, a washing tool.
8. The method of claim 1 wherein the workover tool may be
positioned in the subterranean formation using a method comprising
at least one method selected from the group consisting of: pumping
through the tubing string, placing with a wireline, placing with a
slickline, placing with a coiled tubing string, and dropping
through the tubing string.
9. The method of claim 4 further comprising circulating a fluid
through the tubing string prior to positioning the tubing string
using a logging tool.
10. A method of treating a well bore in a single trip, the method
comprising: using a hydraulic workover unit to introduce a tubing
string into a subterranean formation comprising a well bore,
wherein the tubing string has a locking device disposed on an end;
introducing a logging tool into a well bore to position the end of
the tubing string; engaging a hydrajetting tool with the locking
device in a first zone of the subterranean formation; creating or
enhancing one or more perforations in the first zone of the
subterranean formation using the hydrajetting tool; positioning a
hydrajetting tool in a second zone of the subterranean formation;
pumping a fluid at a rate and pressure sufficient to create or
enhance one or more fractures in the subterranean formation; and
isolating the first zone from the second zone.
11. The method of claim 10 wherein the pumping a fluid comprises
pumping a fracturing fluid comprising a plurality of proppant
particulates between the tubing string and the well bore while
simultaneously pumping a base fluid through the tubing string.
12. The method of claim 10 wherein the second zone is located above
the first zone.
13. The method of claim 10 wherein the hydrajetting tool is engaged
with the locking device by using a method comprising at least one
method selected from the group consisting of: pumping through the
tubing string, placing with a wireline, placing with a slickline,
placing with a coiled tubing string, and dropping through the
tubing string.
14. The method of claim 10 further comprising: washing the well
bore using a washing device engaged with the locking device on the
end of the tubing string.
15. The method of claim 10 wherein the isolating the first zone
from the second zone comprises creating a proppant bridge in a
casing between the first zone and the second zone.
16. The method of claim 10 wherein the isolating the first zone
from the second zone comprises using a dump bailer passed through
the tubing string to set a plug between the first zone and the
second zone.
17. The method of claim 11 wherein the fracturing fluid comprises a
gelling agent and the base fluid comprises a gel breaker.
18. A downhole tool system comprising: a profile nipple disposed on
a tubing string, wherein the profile nipple comprises a locking
receptacle; and a tool assembly, wherein the tool assembly has a
locking lug, wherein the locking lug engages the locking lug
receptacle, wherein the tool assembly may be passed through the
tubing string to engage the profile nipple.
19. The downhole tool system of claim 18 wherein the tool assembly
comprises at least one tool selected from the group consisting of:
a perforating gun, and a washing tool.
20. The downhole tool system of claim 18 wherein the tool comprises
a hydrajetting tool.
21. The downhole tool system of claim 20 wherein the hydrajetting
tool comprises dual check valves.
22. The downhole tool system of claim 18 wherein the tool assembly
may be engaged and retrieved by a wireline, coiled tubing, or a
slickline.
Description
BACKGROUND OF THE INVENTION
[0001] The present invention relates to stimulation of subterranean
formations, and more particularly, to a novel apparatus and methods
of multi-zone stimulation of subterranean formations, in
particular, at least in some embodiments, in high temperature, high
pressure wells.
[0002] Treatment fluids may be used in a variety of subterranean
treatments, including, but not limited to, stimulation treatments
and sand control treatments. As used herein, the term "treatment,"
or "treating," refers to any subterranean operation that uses a
fluid in conjunction with a desired function and/or for a desired
purpose. The term "treatment," or "treating," does not imply any
particular action by the fluid or any particular component
thereof.
[0003] One common production stimulation operation that employs a
treatment fluid is hydraulic fracturing. Hydraulic fracturing
operations generally involve pumping a treatment fluid (e.g., a
fracturing fluid) into a well bore that penetrates a subterranean
formation at a sufficient hydraulic pressure to create or enhance
one or more cracks, or "fractures," in the subterranean formation.
"Enhancing" one or more fractures in a subterranean formation, as
that term is used herein, is defined to include the extension or
enlargement of one or more natural or created fractures in the
subterranean formation. The treatment fluid may comprise
particulates, often referred to as "proppant particulates," that
are deposited in the fractures. The proppant particulates, inter
alia, may prevent the fractures from fully closing upon the release
of hydraulic pressure, forming conductive channels through which
fluids may flow to the well bore. Once at least one fracture is
created and the proppant particulates are substantially in place,
the treatment fluid may be "broken" (i.e., the viscosity of the
fluid reduced), and the treatment fluid may be recovered from the
formation.
[0004] Maintaining sufficient viscosity in these treatment fluids
is important for a number of reasons. Maintaining sufficient
viscosity is important in fracturing and sand control treatments
for particulate transport and/or to create or enhance fracture
width. Also, maintaining sufficient viscosity may be important to
control and/or reduce fluid-loss into the formation. Moreover, a
treatment fluid of a sufficient viscosity may be used to divert the
flow of fluids present within a subterranean formation (e.g.,
formation fluids, other treatment fluids) to other portions of the
formation, for example, by "plugging" an open space within the
formation. At the same time, while maintaining sufficient viscosity
of the treatment fluid often is desirable, it also may be desirable
to maintain the viscosity of the treatment fluid in such a way that
the viscosity may be reduced at a particular time, inter alia, for
subsequent recovery of the fluid from the formation.
[0005] To provide the desired viscosity, polymeric gelling agents
may be added to the treatment fluids. Examples of commonly used
polymeric gelling agents include, but are not limited to, guar gums
and derivatives thereof, cellulose derivatives, biopolymers,
polysaccharides, synthetic polymers, and the like. To further
increase the viscosity of a treatment fluid, often the molecules of
the gelling agent are "crosslinked" with the use of a crosslinking
agent. Conventional crosslinking agents usually comprise a metal
ion that interacts with at least two polymer molecules to form a
"crosslink" between them.
[0006] At some point in time, e.g., after a viscosified treatment
fluid has performed its desired function, the viscosity of the
viscosified treatment fluid should be reduced. This is often
referred to as "breaking the gel" or "breaking the fluid." This can
occur by, inter alia, reversing the crosslink between crosslinked
polymer molecules, breaking down the molecules of the polymeric
gelling agent, or breaking the crosslinks between polymer
molecules. The use of the term "break" herein incorporates at least
all of these mechanisms. Certain breakers that are capable of
breaking treatment fluids comprising crosslinked gelling agents are
known in art. For example, breakers comprising sodium bromate,
sodium chlorite, and other oxidizing agents have been used to
reduce the viscosity of treatment fluids comprising crosslinked
polymers.
[0007] Certain subterranean formations, however, have properties
that may make stimulation operations difficult, time consuming,
and/or expensive. For example, high-temperature high-pressure
("HTHP") wells may present operating difficulties. For example, the
conditions in the formation may reach temperatures as high as
600.degree. F. and experience high pressures of approximately 5,000
psi. HTHP wells may also be deep wells with bottom hole depths of
greater than 10,000 feet to 50,000 feet. For these deep wells, a
single trip with jointed tubing may take a considerable amount of
time, making any workover operation with several trips in and out
of the well bore expensive and inefficient. These wells may require
specialized tools to economically complete and workover in an
efficient manner.
[0008] An example of a treatment in a HTHP well may include
perforating the casing, which may require removing the tubing
during the perforation followed by replacing the tubing to treat
the perforated zone. This is particularly inefficient when multiple
intervals in a well are to be perforated and stimulated separately.
As another example, may be the replacement of worn or eroded tools
used to perform isolation of each interval to be treated such as
packers or bridge plugs; or in the case of hydra-jet perforating
the hydra-jetting tool may become worn or plugged requiring removal
of the tubing. In the case of hydra-jet perforating operation, it
may be necessary to remove the hydra-jetting device from the tubing
to allow high-rate pumping down the tubing during a fracturing
treatment. Yet another example that may involve the removal of the
tubing between stimulation treatments may be the remediation of
early screen-out of a fracturing treatment. In this embodiment, a
bottom-hole assembly used to fracture the interval may need to be
replaced with an assembly to facilitate well bore cleanout in order
to enable the continuation of a multiple interval completion
treatment.
[0009] If the tubing must be removed during a treatment, it may be
necessary to deploy a device to the Bottom hole Assembly that would
act to shut-off fluid flow up the tubing in order to enable safe
removal of the tubing under `live well` conditions. Such an
operation may involve yet another trip into the well with a profile
plug or similar tool run on slickline before safely removing the
tubing.
SUMMARY OF THE INVENTION
[0010] The present invention relates to stimulation of subterranean
formations, and more particularly, to a novel apparatus and methods
of multi-zone stimulation of subterranean formations, in
particular, at least in some embodiments, in high temperature, high
pressure wells.
[0011] An embodiment of the present invention provides a method of
treating a well bore in a single trip, the method comprising
inserting a tubing string into a subterranean formation comprising
a well bore, wherein the tubing string has a locking device
disposed on an end; positioning a workover tool in a first zone of
the subterranean formation, wherein the workover tool engages the
locking device; creating or enhancing one or more perforations in a
first zone of a subterranean formation using the workover tool;
positioning the tubing string in a second zone of the subterranean
formation; introducing a fracturing fluid into the first zone of
the subterranean formation at a rate and pressure sufficient to
create or enhance one or more fractures in the subterranean
formation; isolating the first zone of the subterranean formation
from the second zone of the subterranean formation; and creating or
enhancing one or more perforations in the second zone of the
subterranean formation using the workover tool.
[0012] Another embodiment of the present invention provides a
method of treating a well bore in a single trip, the method
comprising using a hydraulic workover unit to introduce a tubing
string into a subterranean formation comprising a well bore,
wherein the tubing string has a locking device disposed on an end;
introducing a logging tool into a well bore to position the end of
the tubing string; engaging a hydrajetting tool with the locking
device in a first zone of the subterranean formation; creating or
enhancing one or more perforations in the first zone of the
subterranean formation using the hydrajetting tool; positioning a
hydrajetting tool in a second zone of the subterranean formation;
pumping a fluid at a rate and pressure sufficient to create or
enhance one or more fractures in the subterranean formation; and
isolating the first zone from the second zone.
[0013] Still another embodiment of the present invention provides a
downhole tool system comprising a profile nipple disposed on a
tubing string, where the profile nipple comprises a locking
receptacle; and a tool assembly, where the tool assembly has a
locking lug, wherein the locking lug engages the locking lug
receptacle, wherein the tool assembly may be passed through the
tubing string to engage the profile nipple.
[0014] The features and advantages of the present invention will be
apparent to those skilled in the art. While numerous changes may be
made by those skilled in the art, such changes are within the
spirit of the invention.
BRIEF DESCRIPTION OF THE DRAWINGS
[0015] These drawings illustrate certain aspects of some of the
embodiments of the present invention, and should not be used to
limit or define the invention.
[0016] FIG. 1 illustrates a cross sectional view of a well bore
disposed in a subterranean formation in which an embodiment of the
disclosed invention may be used.
[0017] FIG. 2 illustrates a cross sectional view of an embodiment
of a locking device that may be disposed on a tubing string in the
present invention.
[0018] FIG. 3 illustrates a cross sectional view of an embodiment
of tool that may be useful with the present invention.
[0019] FIG. 4 illustrates a cross sectional view of an embodiment
of another tool that may be useful with the present invention.
[0020] FIG. 5 illustrates a cross sectional view of an embodiment
of still another tool that may be useful with the present
invention.
[0021] FIG. 6A illustrates a cross sectional view of a well bore
disposed in a subterranean formation in which an embodiment of the
disclosed invention may be used.
[0022] FIG. 6B illustrates another cross sectional view of a well
bore disposed in a subterranean formation in which an embodiment of
the disclosed invention may be used.
[0023] FIG. 6C illustrates yet another cross sectional view of a
well bore disposed in a subterranean formation in which an
embodiment of the disclosed invention may be used.
[0024] FIG. 6D illustrates still another cross sectional view of a
well bore disposed in a subterranean formation in which an
embodiment of the disclosed invention may be used.
[0025] FIG. 6E illustrates another cross sectional view of a well
bore disposed in a subterranean formation in which an embodiment of
the disclosed invention may be used.
[0026] FIG. 6F illustrates yet another cross sectional view of a
well bore disposed in a subterranean formation in which an
embodiment of the disclosed invention may be used.
[0027] FIG. 6G illustrates still another cross sectional view of a
well bore disposed in a subterranean formation in which an
embodiment of the disclosed invention may be used.
DETAILED DESCRIPTION
[0028] The present invention relates to stimulation of subterranean
formations, and more particularly, to a novel apparatus and methods
of multi-zone stimulation of subterranean formations, in
particular, at least in some embodiments, in high temperature, high
pressure wells.
[0029] As used herein, directional terms including "top", "above",
"upper", "bottom", "below", and "underneath" refer to directions
within the well bore such that the top of the well is the upper
most point and the bottom of the well is the furthest point from
the surface through the well bore. Some wells may not be entirely
vertical and may have horizontal or slanted portions. In these
wells, the bottom of the well still refers to the point in the well
bore furthest from the top, even though it may not be the deepest
point of the well on a strictly vertical basis.
[0030] Also, as used herein, the term "treatment fluid" refers
generally to any fluid that may be used in a subterranean
application in conjunction with a desired function and/or for a
desired purpose. The term "treatment fluid" does not imply any
particular action by the fluid or any component thereof. Similarly,
the term "treatment" does not refer to any type of treatment in
particular unless noted otherwise.
[0031] While there are many advantages of the apparatus and methods
disclosed herein, only some will be discussed or alluded to herein.
One advantage of the present invention is the incorporation of
several tools and methods into a single operation to allow the
efficient and cost effective treatment in a high-temperature
high-pressure ("HTHP") well. In an embodiment, the use of a
hydraulic workover unit may allow the workover of the HTHP well to
be completed under conditions of high pressure in a safe and
efficient manner. Utilizing a hydraulic workover unit may allow
fluid to be transferred in and out of the well bore through both a
tubing string and the annular space between the tubing and casing.
In addition, the present disclosure includes methods of using the
apparatus to perforate, fracture, and treat multiple formation
intervals in a single trip with jointed tubing into the well bore.
This may be advantageous for HTHP wells. For deep wells, a single
trip with jointed tubing may take a considerable amount of time,
making any workover operation with several trips in and out of the
well bore expensive and inefficient. The efficiencies gained by the
unique deployment of these tools may allow for an efficient
replacement of tools in the event of unplanned events such as the
premature failure of the tools or remediation of early screen-outs
during multiple interval stimulation treatments
[0032] In an embodiment, the apparatus of the present disclosure
may comprise a downhole tool system disposed on tubing string with
an interchangeable set of tools for performing treatment
operations.
[0033] In one embodiment, the present invention provides a downhole
tool system comprising: a profile nipple disposed on a tubing
string, wherein the profile nipple comprises a locking receptacle;
and a tool assembly, wherein the tool assembly has a locking lug,
wherein the locking lug engages the locking lug receptacle, wherein
the tool assembly may be passed through the tubing string to engage
the profile nipple. In some embodiments, the tool assembly
comprises at least one tool selected from the group consisting of:
a perforating gun, and a washing tool. In some embodiments, the
tool comprises a hydrajetting tool. In some embodiments, the
hydrajetting tool comprises dual check valves. In some embodiments,
the tool assembly may be engaged and retrieved by a wireline, a
slickline, or coiled tubing. These embodiments are discussed
below.
[0034] In an embodiment, a locking device may be disposed on the
end of a tubing string within a subterranean formation. A variety
of tools utilizing locking lugs for engaging the locking device may
be used to treat the formation by passing the tools through the
interior of the tubing string until they lockingly engage the
locking device on the end of the tubing string. In an embodiment, a
hydraulic workover unit may be utilized to allow the treatment
operations to proceed while the well is under pressure. The
downhole tool system and the various tools that may be used are
described in more detail below.
[0035] In an embodiment, the apparatus of the present disclosure
may be used in a well bore disposed in a subterranean formation. In
an embodiment shown in FIG. 1, a well bore 10 may be created so as
to extend into a subterranean formation 22. A casing 12 may be
disposed within the well bore and cement 14 may be introduced
between the casing 12 and the well bore 10 walls in order to hold
the casing 12 in place and prevent the migration of fluids between
the casing 12 and the well bore 10 walls. A tubing string 16 may be
disposed within the casing 12. In an embodiment, the tubing string
16 may be jointed tubing, coiled tubing, or any other type of
tubing suitable for use in a subterranean well environment.
Suitable types of tubing and an appropriate choice of tubing
diameter and thickness may be known to one skilled in the art,
considering factors such as well depth, pressure, temperature,
chemical environment, and suitability for its intended use. In an
embodiment, a hydraulic workover unit 20 may be disposed at or near
the top of the tubing string 16, the casing 12, or both. The
hydraulic workover unit 20 may allow for tubing and other items to
be introduced into the well bore 10 while a pressure exists and is
maintained within the well bore 10 and tubing string 16. The
existence of a pressure within the well bore may be referred to as
a live well condition.
[0036] In an embodiment shown in FIG. 2, the end of the tubing
string 16 may contain a locking device that may allow a connection
with a tool. In an embodiment, the locking device may be a profile
nipple 18. The profile nipple 18 may be designed to allow a variety
of tools to be connected to the tubing string such that they may
lock into a locking receptacle 24 on the profile nipple 10. In this
embodiment, the variety of tools may be passed through the tubing
string until locking lugs on the tools lockingly engage the locking
receptacles 24 on the profile nipple. The tool may then be utilized
on the end of the tubing string to perform a treatment operation.
While the terms locking receptacle and locking lugs are used
herein, the tools may engage the tubing string using any type of
locking device and should not be limited to locking devices with
lugs. As used herein, the term locking lugs refers to any device
capable of providing a temporary fixed relationship between a tool
and tubing. The locking lugs can be released from their temporary
fixed relationship through manipulation with a retrieving device on
slickline, wireline, coiled tubing, or through the exertion of a
physical force on the locking lugs such as pressure in the tubing
or a set down force on the tool itself.
[0037] In an embodiment, a tool capable of engaging the locking lug
receptacles on the tubing string may be passed through the tubing
string. In this embodiment, the tool may be lowered to the profile
nipple in any manner capable of placing a tool in a subterranean
formation. For example, the tool may be lowered using a wireline, a
slickline, or coiled tubing. In another embodiment, the tool may be
placed inside the tubing string and a pressurized fluid introduced
above the tool. The pressurized fluid may then cause the tool to
move through the tubing string so as to lock into position upon
reaching the profile nipple. In an embodiment, any of the same
methods may be used to remove the tool from the profile nipple once
the treatment operation has been completed. For example, a
slickline, wireline, or coiled tubing may be used to remove the
tool from the profile nipple. In another embodiment, a pressurized
fluid may be introduced into the annular space between the tubing
string and the casing so as to cause the tool to move back up the
tubing string towards the hydraulic workover unit. In still another
embodiment the locking lugs may be release with a pressure increase
within the tubing such that the locking lugs release and the tool
is released into the well bore.
[0038] In an embodiment shown in FIG. 3, the tool may be a
hydrajetting tool 30. The hydrajetting tool 30 may have one or more
locking lugs 32 for lockingly engaging the locking receptacles on
the profile nipple. Disposed within the hydrajetting tool 30 may be
fishing profile insets 44. These insets 44 may be used to allow a
fishing apparatus to be passed through the interior of the tubing
string and into the hydrajetting tool 30, engage the hydrajetting
tool 30 and remove it from profile nipple. The hydrajetting tool 30
may contain a check ball 36, which may be configured in a single or
double check configuration. A ball sub check 34 may be disposed
above the check ball 36 and act as a valve seat to prevent back
flow of any fluid through the hydrajetting tool 30. In an
embodiment with a double check valve configuration, there may be
two check balls and associated ball sub checks arranged in series
to provide a double check valve. A ball cage 38 may be disposed on
one side of the check ball 36 opposite the ball sub check 34. The
ball cage 38 may limit the movement of the check ball 36 when the
check ball 36 is not seated on the ball sub check 34. One or more
hydrajetting nozzles 40 may be disposed on the end of the
hydrajetting tool 30. In an embodiment, the hydrajetting tool 30
may have between one and thirty hydrajetting nozzles 40. The number
and diameter of the hydrajetting nozzles 40 may depend on the
number and size of the perforations desired the well bore diameter,
the casing size, and the composition of the subterranean formation.
An optional downjet 42 for washing down the well bore may be
included on a hydrajetting tool 30 depending on the treatment
operation being conducted.
[0039] In another embodiment shown in FIG. 4, the tool may be a
perforating gun 50. The perforating gun may have locking lugs 52 to
lockingly engage the locking receptacles on the profile nipple.
Disposed within the perforating gun 50 may be fishing profile
insets 54. These insets 54 may be used to allow a fishing apparatus
to be passed through the interior of the tubing string and into the
perforating gun 50 to engage the perforating gun 50 and remove it
from profile nipple. A piston 58 may be disposed within the
perforating gun 50. One or more shear pins 56 may be disposed
within the body of the perforating gun 50 and extend into the
piston 58. The shear pins 56 may be designed to shear at a specific
shear force. The shear force may be provided by fluid pressure
supplied to the top side of the piston 58, which may be supplied
with fluid and pressure through a hydraulic workover unit. A firing
pin 60 may be connected to the piston such that when the piston 58
moves in response to a fluid pressure, the firing pin 60 is driven
towards an explosive initiator 62. The explosive initiator 62 may
contain the explosive charges designed to form perforations in the
surrounding casing and subterranean formation. In an embodiment,
the explosive initiator 62 may contain shaped charges for forming
perforations. There may be between 1 and 50 charges for creating
perforations depending on the number of perforations desired.
[0040] In an embodiment shown in FIG. 5, the tool may be a washing
tool 70 for washing down the tubing in the event of a wash out or
removing debris from the well bore following a treatment operation.
The washing tool 70 may have one or more locking lugs 72 for
lockingly engaging the locking receptacles on a profile nipple.
Disposed within the washing tool 30 may be fishing profile insets
74. These insets 74 may be used to allow a fishing apparatus to be
passed through the interior of the tubing string and into the
washing tool 70 to engage the washing tool 70 and remove it from
profile nipple. The washing tool 70 may contain a check ball 78 for
creating a check valve. A ball sub check 76 may be disposed above
the check ball 78 and act as a valve seat to prevent back flow of
any fluid through the washing tool 70. In another embodiment, there
may be two check balls and two ball sub checks arranged in series
for creating a double check valve configuration in the washing tool
70. A ball cage 80 may be disposed on one side of the check ball 78
opposite the ball sub check 76. The ball cage 80 may limit the
movement of the check ball 78 when the check ball 78 is not seated
on the ball sub check 76.
[0041] In certain embodiments, the methods disclosed herein may be
used to perform a treatment in several different intervals within a
subterranean well bore. In an embodiment, the treatment may be a
perforating operation, a fracturing operation, or both. The methods
of the present invention may be used to treat subterranean
formations in such a way that, among other things, may allow for
more time- and cost-efficient treatments of multiple zones of
certain subterranean formations. In certain embodiments, such
improvements in time and cost efficiency may be the result of
performing the methods of the present invention in a single trip
into the well bore.
[0042] In some embodiments, the methods of the present invention
provide a method of treating a well bore in a single trip, the
method comprising: inserting a tubing string into a subterranean
formation comprising a well bore, wherein the tubing string has a
locking device disposed on an end; positioning a workover tool in a
first zone of the subterranean formation, wherein the workover tool
engages the locking device; creating or enhancing one or more
perforations in a first zone of a subterranean formation using the
workover tool; positioning the tubing string in a second zone of
the subterranean formation; introducing a fracturing fluid into the
first zone of the subterranean formation at a rate and pressure
sufficient to create or enhance one or more fractures in the
subterranean formation; isolating the first zone of the
subterranean formation from the second zone of the subterranean
formation; and creating or enhancing one or more perforations in
the second zone of the subterranean formation using the workover
tool. The term "zone" as used herein simply refers to a portion of
the formation and does not imply a particular geological strata or
composition
[0043] In certain embodiments, the methods of the present invention
provide a method that comprises introducing a tubing string into a
subterranean formation comprising a well bore, creating or
enhancing one or more perforations in a first zone of a
subterranean formation, introducing a fracturing fluid into the
first zone of the subterranean formation at a rate and pressure
sufficient to create or enhance one or more fractures in the
subterranean formation, and isolating the first zone of the
subterranean formation from a second zone of the subterranean
formation.
[0044] In certain embodiments as shown in FIGS. 6A through 6D, the
methods of the present invention comprise a method of treating a
well bore in a single trip, the method comprising: using a
hydraulic workover unit to introduce a tubing string 16 into a
subterranean formation 22 comprising a well bore 10, wherein the
tubing string 16 has a locking device 18 disposed on an end;
introducing a logging tool into a well bore to position the end of
the tubing string 16; engaging a hydrajetting tool 30 with the
locking device 18 in a first zone of the subterranean formation 22;
creating or enhancing one or more perforations 60 in the first zone
of the subterranean formation 22 using the hydrajetting tool 30;
positioning a hydrajetting tool 30 in a second zone of the
subterranean formation 22; pumping a fluid at a rate and pressure
sufficient to create or enhance one or more fractures 62 in the
subterranean formation 22; and isolating the first zone from the
second zone.
[0045] Any suitable tool or apparatus that may be used to create or
enhance perforations in the subterranean formation may be
introduced into and removed from the well bore using a variety of
methods. In an embodiment, a tubing string may be introduced into
the well bore using any means capable of disposing a tubing string
within a well bore, including those known in the art. The tubing
string may be disposed within the well bore such that the depth of
the end of the tubing string is correlated with a specific
formation zone to be treated. A variety of depth correlation
techniques may be used to help ensure that the end of the tubing is
located adjacent to a desired zone. In one embodiment, a logging
tool may be used to correlate the depth of the tubing string in the
well bore. In one embodiment, the logging tool may be a collar
locator tool that may be run in with the tubing string to sense the
collars in the casing, allowing a determination of the depth in the
well. In another embodiment, a bridge plug may be set with a
wireline below the zones of interest followed by tagging the bridge
plug with the tubing string and correlating the depth with depth
counters. In still another embodiment, the tubing may be disposed
in the well bore and a collar locator tool may be utilized inside
the tubing string to locate the joints in jointed tubing, if
jointed tubing is used. In yet another embodiment, the logging tool
may be a wire-line gamma ray logging tool that may be run inside
the tubing and used to correlate the depth and position the end of
the tubing string with a desired formation interval.
[0046] In order to ensure proper positioning of the tubing string
and work tools during a treatment operation, a fluid may be
circulated down the tubing string and out through the annulus
between the tubing string and the casing prior to performing a
depth correlation. This circulation may cool the tubing string and
well bore, causing thermal contraction of the tubing string. The
effect of thermal contraction on the placement of the end of the
tubing string may increase as the depth of the well increases.
[0047] In some embodiments as shown in FIGS. 6A and 6B, the tubing
string 16 may have a profile nipple 18 for connecting a variety of
treatment tools disposed on an end of the tubing string 16. The
profile nipple 18 may be introduced into the well bore 10 already
attached to the tubing string 16. In some embodiments, the tool or
apparatus may be introduced into the well bore 10 by any means
capable of disposing the tool within the well bore 10 and engaging
the tool with the tubing string 16. Methods of disposing the tool
within the well bore 10 may include, but are not limited to,
pumping the tool through the tubing string to engage the tool with
the profile nipple as shown in FIG. 6B, and placing the tool into
an engagement with the profile nipple using a wireline, a
slickline, or coiled tubing. In another embodiment, a tool may be
disposed in the well bore by engaging the tool with the profile
nipple at the surface and then placing the tubing string with the
attached profile nipple with the attached tool into the well
bore.
[0048] Following placement of the tubing string and the tool or
apparatus to be used to create or enhance perforations in a first
zone of the subterranean formation, one or more such perforations
may be created or enhanced in the subterranean formation. The
perforations may be formed using a variety of methods, including
but not limited to, using a hydrajetting tool or a perforating
gun.
[0049] In an embodiment shown in FIG. 6B, one or more perforations
60 may be formed using a hydrajetting tool 30 engaged to the
profile nipple 18 on the end of the tubing string 16. In this
embodiment, an abrasive fluid may be pumped through high-pressure
jets and directed at the casing 12, the cement, and the formation
22. The abrasive fluid may be a carrier fluid containing a solid
material, which may be any material with abrasive properties and
may generally range from 70/170 to 20/40 mesh. In an embodiment,
the solid material may be sand, a metal oxide, or any other
material with abrasive properties. The abrasive fluid may be pumped
through the tubing string at a predetermined rate for a specific
period of time. The time required to perforate varies depending on,
but not limited to, the solid material concentration in the carrier
fluid, the abrasive fluid pump rate, the number of strings of
tubing or casing that must perforated, their respective
thicknesses, and the formation composition. In an embodiment, a
perforation 60 created using a hydrajetting tool 30 may be
approximately three times the nozzle diameter or larger. The fluid
pumped through the hydrajetting tool 30 may be returned to the
surface or the top of the well by flowing in the annular space
between the tubing string 16 and the casing 12. A choke device may
be present in an embodiment in which a hydraulic workover unit 20
is used to collect and recirculate the abrasive fluid to the
hydrajetting tool 30. The hydrajetting tool 30 may be retrieved
after the perforations 60 are formed. In an embodiment, a wireline,
slickline, or coiled tubing may be used to engage the fishing
profile in the hydrajetting tool 30, release it from its engagement
with the profile nipple 18, and return it to the top of the well.
In another embodiment, a fluid may be circulated down through the
annular space between the casing 12 and the tubing string 16 and up
through the interior of the tubing string 16 as a sufficient
pressure to return the hydrajetting tool 30 to the surface, as
shown in FIG. 6C.
[0050] In another embodiment, a perforating gun engaged in the
profile nipple may be used to create perforations in the
subterranean formation. In this embodiment, a fluid pressure may be
used to activate the perforating gun once the tubing string and
perforating gun tool are properly placed within the well bore. As
shown in FIG. 4, a pressure applied to the top of the piston 58,
which may be done by pumping or pressurizing a fluid within the
tubing string, may be used to move the piston 58 towards the
explosive initiator 62. In this embodiment, shear pins 56 may be
used to maintain the piston 58 in a fixed position until a
sufficient pressure is provided to the top of the piston 58 to
cause the shear pins 56 to fail. At this point, the piston 58 may
move downward and drive the firing pin 60 into the explosive
initiator 62, causing the perforating charges to fire. There may be
one or more perforating charges, which may be for example, shaped
charges, capable of creating one or more perforations through the
casing, cement, and into the formation. In an embodiment in which a
perforating gun is used to create perforations in the well bore,
the perforating gun may be retrieved after the perforations are
formed. In an embodiment, a wireline, slickline, or coiled tubing
may be used to engage the fishing profile in the perforating gun,
releasing it from its engagement with the profile nipple. The
perforating gun may then be returned to the top of the well using
the wireline, slickline, coiled tubing, fluid suction on the top of
the perforating gun tool, or any combination thereof. In this
embodiment, a new tool may be engaged into the profile nipple. The
new tool may be a hydrajetting tool, a washing tool, or any other
tool capable of providing a fluid to the end of the tubing string
located at or near the perforations.
[0051] As shown in FIGS. 6A through 6D, the tubing string 16 may be
repositioned to another interval in the well bore 10 after
perforations 60 are created in the well bore 10. Such a
repositioning may be necessary, inter alia, to allow for the
fracturing step described below and/or the perforation of
additional zone(s). In an embodiment, the tubing string 16 may be
repositioned to a second zone in which it is desirable to create
perforations. In certain embodiments, the second zone may be
located uphole from the first zone. In an embodiment, a logging
tool may be used to correlate the tubing string depth with a known
interval of interest, as described above. In another embodiment,
the tubing string may remain at the perforation location and be
moved after a treatment operation.
[0052] Suitable fracturing fluids for use in the present invention
generally comprise a base fluid, a suitable gelling agent, and
proppant particulates. Optionally, other components may be included
if desired, as recognized by one skilled in the art with the
benefit of this disclosure. For example, the fluids used in the
present invention optionally may comprise one or more additional
additives known in the art, including, but not limited to, fluid
loss control additives, gel stabilizers, gas, salts (e.g., KCl),
pH-adjusting agents (e.g., buffers), corrosion inhibitors,
dispersants, flocculants, acids, foaming agents, antifoaming
agents, H.sub.2S scavengers, lubricants, oxygen scavengers,
weighting agents, scale inhibitors, surfactants, catalysts, clay
control agents, biocides, friction reducers, particulates (e.g.,
proppant particulates, gravel particulates), combinations thereof,
and the like. For example, a gel stabilizer compromising sodium
thiosulfate may be included in certain treatment fluids of the
present invention. Individuals skilled in the art, with the benefit
of this disclosure, will recognize the types of additives that may
be suitable for a particular application of the present invention.
For example, particulates may be included in the treatment fluids
of the present invention in certain types of subterranean
operations, including fracturing operations, gravel-packing
operations, and the like.
[0053] The aqueous base fluid used in the treatment fluids of the
present invention may comprise fresh water, saltwater (e.g., water
containing one or more salts dissolved therein), brine, seawater,
or combinations thereof. Generally, the water may be from any
source, provided that it does not contain components that might
adversely affect the stability and/or performance of the treatment
fluids of the present invention, for example, copper ions, iron
ions, or certain types of organic materials (e.g., lignin). In
certain embodiments, the density of the aqueous base fluid can be
increased, among other purposes, to provide additional particle
transport and suspension in the treatment fluids of the present
invention. In certain embodiments, the pH of the aqueous base fluid
may be adjusted (e.g., by a buffer or other pH adjusting agent),
among other purposes, to activate a crosslinking agent, and/or to
reduce the viscosity of the treatment fluid (e.g., activate a
breaker, deactivate a crosslinking agent). In these embodiments,
the pH may be adjusted to a specific level, which may depend on,
among other factors, the types of gelling agents, crosslinking
agents, and/or breakers included in the treatment fluid. One of
ordinary skill in the art, with the benefit of this disclosure,
will recognize when such density and/or pH adjustments are
appropriate.
[0054] The gelling agents utilized in the present invention may
comprise any polymeric material capable of increasing the viscosity
of an aqueous fluid. In certain embodiments, the gelling agent may
comprise polymers that have at least two molecules that are capable
of forming a crosslink in a crosslinking reaction in the presence
of a crosslinking agent, and/or polymers that have at least two
molecules that are so crosslinked (i.e., a crosslinked gelling
agent). The gelling agents may be naturally-occurring, synthetic,
or a combination thereof. In certain embodiments, suitable gelling
agents may comprise polysaccharides, and derivatives thereof that
contain one or more of these monosaccharide units: galactose,
mannose, glucoside, glucose, xylose, arabinose, fructose,
glucuronic acid, or pyranosyl sulfate. Examples of suitable
polysaccharides include, but are not limited to, guar gums (e.g.,
hydroxyethyl guar, hydroxypropyl guar, carboxymethyl guar,
carboxymethylhydroxyethyl guar, and carboxymethylhydroxypropyl guar
("CMHPG")), cellulose derivatives (e.g., hydroxyethyl cellulose,
carboxyethylcellulose, carboxymethylcellulose, and
carboxymethylhydroxyethylcellulose), and combinations thereof. In
certain embodiments, the gelling agents comprise an organic
carboxylated polymer, such as CMHPG. In certain embodiments, the
derivatized cellulose is a cellulose grafted with an allyl or a
vinyl monomer, such as those disclosed in U.S. Pat. Nos. 4,982,793;
5,067,565; and 5,122,549, the relevant disclosures of which are
incorporated herein by reference. Additionally, polymers and
copolymers that comprise one or more functional groups (e.g.,
hydroxyl, cis-hydroxyl, carboxylic acids, derivatives of carboxylic
acids, sulfate, sulfonate, phosphate, phosphonate, amino, or amide
groups) may be used.
[0055] The gelling agent may be present in the treatment fluids of
the present invention in an amount sufficient to provide the
desired viscosity. In some embodiments, the gelling agents may be
present in an amount in the range of from about 0.12% to about 2.0%
by weight of the treatment fluid. In certain embodiments, the
gelling agents may be present in an amount in the range of from
about 0.18% to about 0.72% by weight of the treatment fluid.
[0056] In those embodiments of the present invention wherein it is
desirable to crosslink the gelling agent, the treatment fluid may
comprise one or more of the crosslinking agents. The crosslinking
agents may comprise a metal ion that is capable of crosslinking at
least two molecules of the gelling agent. Examples of suitable
crosslinking agents include, but are not limited to, borate ions,
zirconium IV ions, titanium IV ions, aluminum ions, antimony ions,
chromium ions, iron ions, copper ions, and zinc ions. These ions
may be provided by providing any compound that is capable of
producing one or more of these ions; examples of such compounds
include, but are not limited to, boric acid, disodium octaborate
tetrahydrate, sodium diborate, pentaborates, ulexite, colemanite,
zirconium lactate, zirconium triethanol amine, zirconium lactate
triethanolamine, zirconium carbonate, zirconium acetylacetonate,
zirconium maleate, zirconium citrate, zirconium diisopropylamine
lactate, zirconium glycolate, zirconium triethanol amine glycolate,
zirconium lactate glycolate, titanium lactate, titanium malate,
titanium citrate, titanium ammonium lactate, titanium
triethanolamine, and titanium acetylacetonate, aluminum lactate,
aluminum citrate, antimony compounds, chromium compounds, iron
compounds, copper compounds, zinc compounds, and combinations
thereof. In certain embodiments of the present invention, the
crosslinking agent may be formulated to remain inactive until it is
"activated" by, among other things, certain conditions in the fluid
(e.g., pH, temperature, etc.) and/or contact with some other
substance. In some embodiments, the crosslinking agent may be
delayed by encapsulation with a coating (e.g., a porous coating
through which the breaker may diffuse slowly, or a degradable
coating that degrades downhole) that delays the release of the
crosslinking agent until a desired time or place. The choice of a
particular crosslinking agent will be governed by several
considerations that will be recognized by one skilled in the art,
including but not limited to the following: the type of gelling
agent included, the molecular weight of the gelling agent(s), the
pH of the treatment fluid, temperature, and/or the desired time for
the crosslinking agent to crosslink the gelling agent
molecules.
[0057] When included, suitable crosslinking agents may be present
in the treatment fluids of the present invention in an amount
sufficient to provide, inter alia, the desired degree of
crosslinking between molecules of the gelling agent. In certain
embodiments, the crosslinking agent may be present in the treatment
fluids of the present invention in an amount in the range of from
about 0.0005% to about 0.2% by weight of the treatment fluid. In
certain embodiments, the crosslinking agent may be present in the
treatment fluids of the present invention in an amount in the range
of from about 0.001% to about 0.05% by weight of the treatment
fluid. One of ordinary skill in the art, with the benefit of this
disclosure, will recognize the appropriate amount of crosslinking
agent to include in a treatment fluid of the present invention
based on, among other things, the temperature conditions of a
particular application, the type of gelling agents used, the
molecular weight of the gelling agents, the desired degree of
viscosification, and/or the pH of the treatment fluid.
[0058] In some embodiments, the fracturing fluid may comprise a
plurality of proppant particulates, inter alia, to stabilize the
fractures created or enhanced. Particulates suitable for use in the
present invention may comprise any material suitable for use in
subterranean operations. Suitable materials for these particulates
may include, but are not limited to, sand, bauxite, ceramic
materials, glass materials, polymer materials, TEFLON.RTM.
(polytetrafluoroethylene) materials, nut shell pieces, cured
resinous particulates comprising nut shell pieces, seed shell
pieces, cured resinous particulates comprising seed shell pieces,
fruit pit pieces, cured resinous particulates comprising fruit pit
pieces, wood, composite particulates, and combinations thereof.
Suitable composite particulates may comprise a binder and a filler
material wherein suitable filler materials include silica, alumina,
fumed carbon, carbon black, graphite, mica, titanium dioxide,
meta-silicate, calcium silicate, kaolin, talc, zirconia, boron, fly
ash, hollow glass microspheres, solid glass, and combinations
thereof. The mean particulate size generally may range from about 2
mesh to about 400 mesh on the U.S. Sieve Series; however, in
certain circumstances, other mean particulate sizes may be desired
and will be entirely suitable for practice of the present
invention. In particular embodiments, preferred mean particulates
size distribution ranges are one or more of 6/12, 8/16, 12/20,
16/30, 20/40, 30/50, 40/60, 40/70, or 50/70 mesh. It should be
understood that the term "particulate," as used in this disclosure,
includes all known shapes of materials, including substantially
spherical materials, fibrous materials, polygonal materials (such
as cubic materials), and mixtures thereof. Moreover, fibrous
materials, that may or may not be used to bear the pressure of a
closed fracture, may be included in certain embodiments of the
present invention. In certain embodiments, the particulates
included in the treatment fluids of the present invention may be
coated with any suitable resin or tackifying agent known to those
of ordinary skill in the art. In certain embodiments, the
particulates may be present in the fluids of the present invention
in an amount in the range of from about 0.5 pounds per gallon
("ppg") to about 30 ppg by volume of the treatment fluid.
[0059] In an embodiment, a fracturing fluid carrying the proppant
may be pumped down the annulus between the casing and the tubing
string and a base fluid may be pumped down through the tubing. The
base fluid may contain a gel breaker that may be mixed with the
fracturing fluid at or near the end of the tubing string, which may
be at or near the perforations in the well bore. In this
embodiment, the dual pumping scheme comprising two fluids being
transported through the annulus and the tubing string may allow for
thermal cooling of the fracturing fluid by the fluid in the tubing
string, helping to prevent premature breakdown of the fracturing
fluid in a HTHP well. Fracturing of the subterranean formation
through the perforations may continue until the desired fractures
in the formation have been achieved.
[0060] In certain embodiments, the fracturing fluid may comprise a
gelling agent, which may also be known as a viscosifying agent. As
used herein, the term "gelling agents" refer to a material capable
of increasing the viscosity of the fracturing fluid. A fluid that
comprises a gelling agent may be referred to herein as a
viscosified fluid, a gel, or an equivalent term. Suitable gelling
agents for specific applications are known to one skilled in the
arts. Examples of suitable gelling agents include, without
limitation, natural or derivatized polysaccharides that are
soluble, dispersible, or swellable in an aqueous liquid, modified
celluloses and derivatives thereof, and biopolymers. Synthetic
gelling agents may also be used if desired.
[0061] In an embodiment, a base fluid transported through the
tubing string may contain a gel breaker, which may be useful for
reducing the viscosity of the viscosified fracturing fluid at a
specified time. A gel breaker may comprise any compound capable of
lowering the viscosity of a viscosified fluid. The term "break"
(and its derivatives) as used herein refers to a reduction in the
viscosity of the viscosified treatment fluid, e.g., by the breaking
or reversing of the crosslinks between polymer molecules or some
reduction of the size of the gelling agent polymers. No particular
mechanism is implied by the term
[0062] Suitable gel breaking agents for specific applications and
gelled fluids are known to one skilled in the arts. Nonlimiting
examples of suitable breakers include oxidizers, peroxides,
enzymes, acids, and the like. Some viscosified fluids also may
break with sufficient exposure of time and temperature.
[0063] Without being limited by a particular theory or mechanism of
action, it is nevertheless currently believed that using a dual
pumping scheme may extend the gel viscosity life by preventing
premature interaction between the gelled fracturing fluid and a
base fluid containing a gel breaker. Preventing such interaction
may be important in HTHP wells in which high temperatures may
increase the reaction rate at which the gel breaks. HTHP wells may
typically be deep wells resulting in an increased distance over
which the interaction between the gelled fluid and the base fluid
containing a gel breaker may occur. By keeping the two separate
until at or near the point of introduction into the formation, the
effectiveness of the fracturing fluid may be increased. In an
embodiment in which a gelled fracturing fluid and a base fluid
containing a gel breaker are kept separate during transport into
the well, the gel breaker may be an aggressive gel breaker. The use
of an aggressive gel beaker may allow for high pressure, high rate
fracturing with a reduced time to break the gel after fracturing
and return the fracturing fluids from the subterranean
formation.
[0064] In certain embodiments as shown in FIGS. 6D through 6F,
after one or more fractures have been created or enhanced in the
first zone of the subterranean formation 22, it may be desirable to
isolate the first zone from one or more additional zones. Such an
isolation may be performed by any means known to one of ordinary
skill in the art. In certain embodiments, such an isolation may be
performed by introducing a treatment fluid comprising a plurality
of proppant particulates into at least a portion of the region of
the well bore between the first zone and any additional zones. The
introduction of a plurality of proppant particulates may act to
form a proppant particulate bridge 68 across the casing,
effectively isolating the interval below the bridge 68 from the
interval above the bridge 68. Other suitable methods of performing
such an isolation may comprise the use of through tubing bridge
plugs, dump bailer set plugs (e.g., chemical plugs, proppant plugs,
etc.), ball sealers, or any other type of plugging device capable
of being set or passed through the tubing string to be placed in
the well bore. In another embodiment, a moveable bridge plug that
may be set and reset using a wireline, slickline, coiled tubing or
a combination thereof may be positioned in the well bore prior to
initially disposing the tubing string in the well bore. After an
interval has been fractured, the bridge plug may be repositioned
using a wireline, slickline, coiled tubing, or any combination
thereof passed through the tubing string.
[0065] As shown in FIGS. 6A through 6G, the steps described herein
may be repeated for multiple intervals in the subterranean
formation 22. For example, following the isolation of the first
zone from additional zone(s), one or more perforations 64 may be
created or enhanced in a second zone. Such perforations 64 may be
introduced, as described above, by the use of a hydrajetting tool
30, a perforating gun, or any other means of creating perforations.
After perforation of the second zone is completed, the tubing
string 16 and/or tool or apparatus used to create or enhance the
perforation(s) may then be moved to a third zone of the
subterranean formation. A fracturing fluid may then be pumped down
the annulus, optionally with the simultaneous introduction of a
base fluid through the tubing string, at a rate and pressure
sufficient to create or enhance one or more fractures in the second
zone of the subterranean formation. The second zone may then be
isolated from addition zone(s) as described above, and the methods
may then be repeated for a third zone, etc. Any number of zones may
be perforated and treated by repeating the process as many times as
necessary.
[0066] In an embodiment, a washing tool may be used at any point in
the method to clean out the well bore of any debris, including any
proppant bridges placed to isolate one interval from another. In
this embodiment, a washing tool may be used to circulate a fluid
through the tubing string and to the top of the well through the
annulus between the casing and the tubing string. In another
embodiment, a fluid may be circulated down the annulus between the
casing and tubing string and back to the top of the well through
the tubing.
[0067] An embodiment of the present invention may provide a method
of treating a well bore in a single trip, the method comprising
inserting a tubing string into a subterranean formation comprising
a well bore, wherein the tubing string has a locking device
disposed on an end; positioning a workover tool in a first zone of
the subterranean formation, wherein the workover tool engages the
locking device; creating or enhancing one or more perforations in a
first zone of a subterranean formation using the workover tool;
positioning the tubing string in a second zone of the subterranean
formation; introducing a fracturing fluid into the first zone of
the subterranean formation at a rate and pressure sufficient to
create or enhance one or more fractures in the subterranean
formation; isolating the first zone of the subterranean formation
from the second zone of the subterranean formation; and creating or
enhancing one or more perforations in the second zone of the
subterranean formation using the workover tool.
[0068] Another embodiment of the present invention may provide a
method of treating a well bore in a single trip, the method
comprising using a hydraulic workover unit to introduce a tubing
string into a subterranean formation comprising a well bore,
wherein the tubing string has a locking device disposed on an end;
introducing a logging tool into a well bore to position the end of
the tubing string; engaging a hydrajetting tool with the locking
device in a first zone of the subterranean formation; creating or
enhancing one or more perforations in the first zone of the
subterranean formation using the hydrajetting tool; positioning a
hydrajetting tool in a second zone of the subterranean formation;
pumping a fluid at a rate and pressure sufficient to create or
enhance one or more fractures in the subterranean formation; and
isolating the first zone from the second zone.
[0069] Still another embodiment of the present invention may
provide a downhole tool system comprising a profile nipple disposed
on a tubing string, where the profile nipple comprises a locking
receptacle; and a tool assembly, where the tool assembly has a
locking lug, wherein the locking lug engages the locking lug
receptacle, wherein the tool assembly may be passed through the
tubing string to engage the profile nipple.
[0070] To facilitate a better understanding of the present
invention, the following examples of the preferred embodiments are
given. In no way should the following examples be read to limit, or
define, the scope of the invention.
EXAMPLE 1
[0071] In order to demonstrate the methods disclosed herein, a set
of tests were conducted in Michigan in multiple shallow, low
pressure, substantially vertical wells. In these tests, a
hydrajetting tool was deployed from surface through a tubing
string. The end of the tubing was placed at a depth corresponding
to the target interval for perforating and fracturing. The end of
the tubing contained a seat (e.g., a profile nipple) to prevent the
hydra-jetting tool from passing completely through the end of
tubing while allowing the hydra-jetting tool to have the jets
exposed to the casing. The hydra-jetting tool was placed in the
tubing and allowed to pass through the tubing until it was disposed
in the end of tubing, where it engaged the seat. The hydra-jetting
tool was engaged to form perforations in the casing. Once the
perforations were formed, the fluid in the well was reverse
circulated (i.e., fluid was pumped down the annulus between the
casing and the tubing string to return to the surface through the
interior of the tubing string). The reverse circulation forced the
hydra-jetting tool to be lifted back to surface through the tubing
string where it was captured by a valve and short joint of
pipe.
[0072] The well bore was then fractured by pumping a fracturing
fluid through the tubing string and allowing it to pass through the
seat. A sand plug was then placed in the casing at the target
interval by passing a treatment fluid containing sand down the
tubing string and allowing the sand to settle in the well bore,
covering the perforations which were fractured. The tubing string
was then moved to the next target zone, which in this test was
above the first target zone, and the process was repeated.
EXAMPLE 2
[0073] In order to demonstrate the methods disclosed herein,
another set of tests were conducted in Michigan in multiple
shallow, low pressure, substantially vertical wells. These tests
were substantially similar to those tests described in Example 1
with the exception that a retrievable bridge plug was used between
target zones rather than the placement of one or more sand
plugs.
[0074] In these tests, a hydra-jetting tool was deployed from
surface through a tubing string. The end of the tubing was placed
at a depth corresponding to the target interval for perforating and
fracturing. The end of the tubing contained a seat (e.g., a profile
nipple) to prevent the hydra-jetting tool from passing completely
through the end of tubing while allowing the hydra-jetting tool to
have the jets exposed to the casing. The hydra-jetting tool was
placed in the tubing and allowed to pass through the tubing until
it was disposed in the end of tubing, where it engaged the seat.
The hydra-jetting tool was engaged to form perforations in the
casing. Once the perforations were formed, the fluid in the well
was reverse circulated (i.e., fluid was pumped down the annulus
between the casing and the tubing string to return to the surface
through the interior of the tubing string). The reverse circulation
forced the hydra-jetting tool to be lifted back to surface through
the tubing string where it was captured by a valve and short joint
of pipe.
[0075] The well bore was then fractured by pumping a fracturing
fluid through the tubing string and allowing it to pass through the
seat. A retrievable bridge plug was then placed in the casing at
the target interval by passing the retrievable bridge plus through
the tubing string and setting the bridge plug in the well bore
above the target zone, isolating the perforations which were
fractured. The tubing string was then moved to the next target
zone, which in this test was above the first target zone, and the
process was repeated.
[0076] Therefore, the present invention is well adapted to attain
the ends and advantages mentioned as well as those that are
inherent therein. The particular embodiments disclosed above are
illustrative only, as the present invention may be modified and
practiced in different but equivalent manners apparent to those
skilled in the art having the benefit of the teachings herein.
Furthermore, no limitations are intended to the details of
construction or design herein shown, other than as described in the
claims below. It is therefore evident that the particular
illustrative embodiments disclosed above may be altered or modified
and all such variations are considered within the scope and spirit
of the present invention. All numbers and ranges disclosed above
may vary by some amount. Whenever a numerical range with a lower
limit and an upper limit is disclosed, any number and any included
range falling within the range is specifically disclosed. In
particular, every range of values (of the form, "from about a to
about b," or, equivalently, "from approximately a to b," or,
equivalently, "from approximately a-b") disclosed herein is to be
understood to set forth every number and range encompassed within
the broader range of values. Moreover, the indefinite articles "a"
or "an," as used in the claims, are defined herein to mean one or
more than one of the element that it introduces. Also, the terms in
the claims have their plain, ordinary meaning unless otherwise
explicitly and clearly defined by the patentee. Therefore, the
present invention is well-adapted to carry out the objects and
attain the ends and advantages mentioned as well as those which are
inherent therein. While the invention has been depicted and
described by reference to exemplary embodiments of the invention,
such a reference does not imply a limitation on the invention, and
no such limitation is to be inferred. The invention is capable of
considerable modification, alternation, and equivalents in form and
function, as will occur to those ordinarily skilled in the
pertinent arts and having the benefit of this disclosure. The
depicted and described embodiments of the invention are exemplary
only, and are not exhaustive of the scope of the invention. In
particular, every range of values (of the form, "from about a to
about b," or, equivalently, "from approximately a to b," or,
equivalently, "from approximately a-b") disclosed herein is to be
understood as referring to the power set (the set of all subsets)
of the respective range of values, and set forth every range
encompassed within the broader range of values. Consequently, the
invention is intended to be limited only by the spirit and scope of
the appended claims, giving full cognizance to equivalents in all
respects. Moreover, the indefinite articles "a" and "an", as used
in the claims, are defined herein to mean to one or more than one
of the element that it introduces. The terms in the claims have
their plain, ordinary meaning unless otherwise explicitly and
clearly defined by the patentee.
* * * * *