U.S. patent application number 13/687265 was filed with the patent office on 2014-05-29 for methods of enhancing the fracture conductivity of multiple interval fractures in subterranean formations propped with cement packs.
The applicant listed for this patent is Halliburton Energy Services, Inc.. Invention is credited to Jason E. Bryant, Loyd E. East, Timothy H. Hunter, Guillermo Antonio Izquierdo, Philip D. Nguyen, Michael W. Sanders, Leopoldo Sierra, Jimmie D. Weaver.
Application Number | 20140144634 13/687265 |
Document ID | / |
Family ID | 50772256 |
Filed Date | 2014-05-29 |
United States Patent
Application |
20140144634 |
Kind Code |
A1 |
Nguyen; Philip D. ; et
al. |
May 29, 2014 |
Methods of Enhancing the Fracture Conductivity of Multiple Interval
Fractures in Subterranean Formations Propped with Cement Packs
Abstract
Methods of treating a wellbore in a subterranean formation
having a top portion and a bottom portion, and a middle portion
therebetween. The method includes providing a jetting fluid;
providing a cement slurry; and providing a breakable gel fluid.
Then introducing the jetting fluid into the bottom portion of the
wellbore to create or enhance a bottom portion fracture;
introducing the jetting fluid into the top portion of the wellbore
to create or enhance a top portion fracture; introducing the cement
slurry into the top portion fracture; introducing the cement slurry
into the bottom portion fracture; and introducing the breakable gel
fluid into the wellbore so as to prevent the expandable
cementitious material from migrating out of the top portion
fracture and bottom portion fracture. The expandable cementitious
material is cured so as to form a cement pack, the breakable gel
fluid is broken and removed from the subterranean formation.
Inventors: |
Nguyen; Philip D.; (Houston,
TX) ; Weaver; Jimmie D.; (Duncan, OK) ;
Sanders; Michael W.; (Houston, TX) ; Bryant; Jason
E.; (Houston, TX) ; East; Loyd E.; (Houston,
TX) ; Izquierdo; Guillermo Antonio; (Villahermosa,
MX) ; Sierra; Leopoldo; (Houston, TX) ;
Hunter; Timothy H.; (Duncan, OK) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Halliburton Energy Services, Inc. |
Houston |
TX |
US |
|
|
Family ID: |
50772256 |
Appl. No.: |
13/687265 |
Filed: |
November 28, 2012 |
Current U.S.
Class: |
166/281 |
Current CPC
Class: |
E21B 43/261
20130101 |
Class at
Publication: |
166/281 |
International
Class: |
E21B 43/26 20060101
E21B043/26 |
Claims
1. A method comprising: providing a wellbore in a subterranean
formation having a top portion and a bottom portion, and a middle
portion therebetween; providing a jetting fluid comprising a base
fluid and a cutting particulate; providing a cement slurry
comprising an expandable cementitious material, wherein the
expandable cementitious material comprises an expandable agent
selected from the group consisting of calcium oxide; magnesium
oxide; any derivatives thereof; and any combinations thereof;
providing a breakable gel fluid; introducing the jetting fluid into
the bottom portion of the wellbore in the subterranean formation at
a pressure sufficient to create or enhance a bottom portion
fracture therein; introducing the jetting fluid into the top
portion of the wellbore in the subterranean formation at a pressure
sufficient to create or enhance a top portion fracture therein;
introducing the cement slurry into the top portion fracture;
introducing the cement slurry into the bottom portion fracture;
introducing the breakable gel fluid into the wellbore in the
subterranean formation so as to prevent the expandable cementitious
material from migrating out of the top portion fracture and the
bottom portion fracture in the subterranean formation; curing the
expandable cementitious material so as to form a cement pack,
wherein the curing of the expandable cementitious material expands
the expandable cementitious material such that at least one
microfracture is created within the top portion fracture and the
bottom portion fracture in the subterranean formation; breaking the
breakable gel fluid; and removing the broken breakable gel fluid
from the subterranean formation.
2. The method of claim 1 wherein the top portion fracture and the
bottom portion fracture in the subterranean formation are created
through a slot or a perforation in the subterranean formation.
3. The method of claim 1 wherein the wellbore in the subterranean
formation is a lateral wellbore.
4. The method of claim 1 wherein the jetting fluid, cement slurry,
and breakable gel fluid are introduced into the wellbore in the
subterranean formation using a hydrojetting tool.
5. The method of claim 1 wherein a nano-particle is introduced into
the wellbore in the subterranean formation after removing the
broken breakable gel fluid from the wellbore in the subterranean
formation.
6. The method of claim 1 further comprising acid-fracturizing the
top portion fracture and the bottom portion fracture after the
broken breakable gel fluid is removed.
7. (canceled)
8. A method comprising: providing a wellbore in a subterranean
formation having a top portion and a bottom portion, and a middle
portion therebetween; providing a jetting fluid comprising a base
fluid and a cutting particulate; providing a cement slurry
comprising an expandable cementitious material, wherein the
expandable cementitious material comprises an expandable agent
selected from the group consisting of calcium oxide; magnesium
oxide; any derivatives thereof; and any combinations thereof;
providing a breakable gel fluid; introducing the jetting fluid into
the bottom portion of the wellbore in the subterranean formation at
a pressure sufficient to create or enhance a bottom portion
fracture therein; introducing the jetting fluid into the middle
portion of the wellbore in the subterranean formation at a pressure
sufficient to create or enhance a middle portion fracture therein;
introducing the jetting fluid into the top portion of the wellbore
in the subterranean formation at a pressure sufficient to create or
enhance a top portion fracture therein; introducing the cement
slurry into the top portion fracture; introducing the cement slurry
into the middle portion fracture; introducing the cement slurry
into the bottom portion fracture; introducing the breakable gel
fluid into the wellbore in the subterranean formation so as to
prevent the expandable cementitious material from migrating out of
the top portion fracture and the bottom portion fracture in the
subterranean formation; curing the expandable cementitious material
so as to form a cement pack, wherein the curing of the expandable
cementitious material expands the expandable cementitious material
such that at least one microfracture is created within the top
portion fracture, the middle portion fracture, and the bottom
portion fracture in the subterranean formation; breaking the
breakable gel fluid; and removing the broken breakable gel fluid
from the subterranean formation.
9. The method of claim 8 wherein the top portion fracture, the
middle portion fracture, and the bottom portion fracture in the
subterranean formation are created through a slot or a perforation
in the subterranean formation.
10. The method of claim 8 wherein the wellbore in the subterranean
formation is a lateral wellbore.
11. The method of claim 8 wherein the jetting fluid, cement slurry,
and breakable gel fluid are introduced into the wellbore in the
subterranean formation using a hydrojetting tool.
12. The method of claim 8 wherein a nano-particle is introduced
into the wellbore in the subterranean formation after removing the
broken breakable gel fluid from the wellbore in the subterranean
formation.
13. The method of claim 8 further comprising acid-fracturizing the
top portion fracture and the bottom portion fracture after the
broken breakable gel fluid is removed.
14. (canceled)
15. A method comprising: providing a wellbore in a subterranean
formation having a top portion and a bottom portion, and a middle
portion therebetween; providing a jetting fluid comprising a base
fluid and a cutting particulate; providing a cement slurry
comprising an expandable cementitious material, wherein the
expandable cementitious material comprises an expandable agent
selected from the group consisting of calcium oxide; magnesium
oxide; any derivatives thereof; and any combinations thereof;
providing a breakable gel fluid; introducing the jetting fluid into
the bottom portion of the wellbore in the subterranean formation at
a pressure sufficient to create or enhance a bottom portion
fracture therein; introducing the jetting fluid into the middle
portion of the wellbore in the subterranean formation at a pressure
sufficient to create or enhance a middle portion fracture therein;
introducing the jetting fluid into the top portion of the wellbore
in the subterranean formation at a pressure sufficient to create or
enhance a top portion fracture therein; introducing the cement
slurry into at least one of the top portion fracture, the middle
fracture, and the bottom fracture; introducing the breakable gel
fluid into the wellbore in the subterranean formation so as to
prevent the expandable cementitious material from migrating out of
the top portion fracture and the bottom portion fracture in the
subterranean formation; curing the expandable cementitious material
so as to form a cement pack, wherein the curing of the expandable
cementitious material expands the expandable cementitious material
such that at least one microfracture is created within the top
portion fracture, the middle portion fracture, and the bottom
portion fracture in the subterranean formation; breaking the
breakable gel fluid; and removing the broken breakable gel fluid
from the subterranean formation.
16. The method of claim 15 wherein the top portion fracture, the
middle portion fracture, and the bottom portion fracture in the
subterranean formation are created through a slot or a perforation
in the subterranean formation.
17. The method of claim 15 wherein the wellbore in the subterranean
formation is a lateral wellbore.
18. The method of claim 15 wherein the jetting fluid, cement
slurry, and breakable gel fluid are introduced into the wellbore in
the subterranean formation using a hydrojetting tool.
19. The method of claim 15 wherein a nano-particle is introduced
into the wellbore in the subterranean formation after removing the
broken breakable gel fluid from the wellbore in the subterranean
formation.
20. The method of claim 15 further comprising acid-fracturizing the
top portion fracture and the bottom portion fracture after the
broken breakable gel fluid is removed.
Description
BACKGROUND
[0001] The present invention provides methods of enhancing fracture
conductivity within propped subterranean formations using a
cementitious material and methods of delivering and/or treating
such cementitious material.
[0002] Subterranean wells (e.g., hydrocarbon producing wells, water
producing wells, and injection wells) are often stimulated by
hydraulic fracturing treatments. In hydraulic fracturing
treatments, a viscous treatment fluid is pumped into a portion of a
subterranean formation at a rate and pressure such that the
subterranean formation breaks down and one or more fractures are
formed. While the treatment fluid used to initiate the fracture is
generally solids-free, typically, particulate solids, such as
graded sand, are suspended in a later portion of the treatment
fluid and then deposited into the fractures. These particulate
solids, or "proppants," serve to prop the fracture open (e.g., keep
the fracture from fully closing) after the hydraulic pressure is
removed. By keeping the fracture from fully closing, the proppants
aid in forming conductive paths through which produced fluids, such
as hydrocarbons, may flow.
[0003] The degree of success of a fracturing operation depends, at
least in part, upon fracture porosity and conductivity once the
fracturing operation is complete and production is begun.
Traditional fracturing operations place a large volume of proppant
suspended in an aqueous fluid into a fracture to form a "proppant
pack" in order to ensure that the fracture does not close
completely upon removing the hydraulic pressure. The ability of
proppants to maintain a fracture open depends upon the ability of
the proppants to withstand fracture closure and, therefore, is
typically proportional to the volume of proppants placed in the
fracture. The porosity of a proppant pack within a fracture is
related to the interconnected interstitial spaces between abutting
proppants. Thus, the fracture porosity is closely related to the
strength of the placed proppant and tight proppant packs are often
unable to produce highly conductive channels within a fracture,
while a reduced volume of proppant is unable to withstand fracture
closure. Moreover, hydraulic fracturing in soft rock formations,
such as carbonate formations, is often inadequate to create
conductive pathways because the proppant and carbonate formation
together are unable to withstand closure pressure.
[0004] The substantial volume of aqueous fluid introduced into a
formation during traditional fracturing treatments may also result
in dilution of later-placed treatment fluids, impairment of
produced fluid flow due to formation fluid retention, or damaged
formation portions causing reduced hydrocarbon permeability due to
fluid-induced swelling of the formation. Additionally, traditional
hydraulic fracturing treatments alone may create only shallow
fractures near the wellbore head, substantially impairing the
conductivity potential of a subterranean formation as a whole.
[0005] One way proposed to combat problems inherent in tight
proppant packs involves placing degradable particulates within the
proppant pack, which upon encountering a certain activating trigger
(e.g., temperature, pH, etc.) will degrade and leave behind
channels within the proppant pack. However, such degradable
particulates are often unpredictable and may lead to unconnected
and independent interstitial spaces within the proppant pack that
fail to enhance conductivity, but rather form pockets that trap
produced fluids. Additionally, the placement of the degradable
particulates may not be predictably uniform throughout the proppant
pack, again leaving only pockets that trap produced fluids rather
than contributing to an interconnected interstitial network for
fluids to flow.
[0006] In order to overcome some of the drawbacks of traditional
hydraulic fracturing, techniques have been developed to reduce the
amount of aqueous fluid required in a fracturing operation and/or
to replace or supplement traditional hydraulic fracturing with
techniques to extend fractures deep within a formation and prevent
complete fracture closure. These techniques may collectively be
referred to as enhanced oil recovery techniques. An example of one
such enhanced oil recovery technique is fracture-acidizing, in
which an acid (e.g., hydrochloric acid) is injected into a
formation above the formation fracture gradient in order to
fracture the formation and simultaneously etch channels in the face
of the fracture in a non-uniform pattern such that the channels
remain open after the pressure is removed and the fracture closes.
Fracture-acidizing is limited due to acid spending or leakoff,
resulting in fracture extension termination. Fracture-acidizing may
also be unable to overcome the drawbacks of fracturing soft rock
formations, failing to maintain conductive channels after fracture
closure.
[0007] Another example of an enhanced oil recovery technique is the
use of explosives or propellants to stimulate shockwaves in a
subterranean formation and generate fractures therein. While this
technique is effective at stimulating deep fractures within a
subterranean formation, handling of explosives or propellants poses
great threat to operators during well stimulation. Additionally,
the explosives or propellants may detonate at unplanned or
unpredictable intervals within the formation, interfering with the
conductivity potential of the well. Therefore, a method of safely
and predictably fracturing and generating highly conductive
channels within a propped fracture in a subterranean formation may
be of benefit to one of ordinary skill in the art.
SUMMARY OF THE INVENTION
[0008] The present invention provides methods of enhancing fracture
conductivity within propped subterranean formations using a
cementitious material and methods of delivering and/or treating
such cementitious material.
[0009] In one embodiment, the present invention provides a method
comprising: providing a wellbore in a subterranean formation having
a top portion and a bottom portion, and a middle portion
therebetween; providing a jetting fluid comprising a base fluid and
a cutting particulate; providing a cement slurry comprising an
expandable cementitious material; providing a breakable gel fluid;
introducing the jetting fluid into the bottom portion of the
wellbore in the subterranean formation at a pressure sufficient to
create or enhance a bottom portion fracture therein; introducing
the jetting fluid into the top portion of the wellbore in the
subterranean formation at a pressure sufficient to create or
enhance a top portion fracture therein; introducing the cement
slurry into the top portion fracture; introducing the cement slurry
into the bottom portion fracture; introducing the breakable gel
fluid into the wellbore in the subterranean formation so as to
prevent the expandable cementitious material from migrating out of
the top portion fracture and bottom portion fracture in the
subterranean formation; curing the expandable cementitious material
so as to form a cement pack, wherein the curing of the expandable
cementitious material expands the expandable cementitious material
such that at least one microfracture is created within top portion
fracture and the bottom portion fracture in the subterranean
formation; breaking the breakable gel fluid; and removing the
broken breakable gel fluid from the subterranean formation.
[0010] In other embodiments, the present invention provides a
method comprising: providing a wellbore in a subterranean formation
having a top portion and a bottom portion, and a middle portion
therebetween; providing a jetting fluid comprising a base fluid and
a cutting particulate; providing a cement slurry comprising an
expandable cementitious material; providing a breakable gel fluid;
introducing the jetting fluid into the bottom portion of the
wellbore in the subterranean formation at a pressure sufficient to
create or enhance a bottom portion fracture therein; introducing
the jetting fluid into the middle portion of the wellbore in the
subterranean formation at a pressure sufficient to create or
enhance a middle portion fracture therein; introducing the jetting
fluid into the top portion of the wellbore in the subterranean
formation at a pressure sufficient to create or enhance a top
portion fracture therein; introducing the cement slurry into the
top portion fracture; introducing the cement slurry into the middle
portion fracture; introducing the cement slurry into the bottom
portion fracture; introducing the breakable gel fluid into the
wellbore in the subterranean formation so as to prevent the
expandable cementitious material from migrating out of the top
portion fracture and bottom portion fracture in the subterranean
formation; curing the expandable cementitious material so as to
form a cement pack, wherein the curing of the expandable
cementitious material expands the expandable cementitious material
such that at least one microfracture is created within top portion
fracture, the middle portion fracture, and the bottom portion
fracture in the subterranean formation; breaking the breakable gel
fluid; and removing the broken breakable gel fluid from the
subterranean formation.
[0011] In still other embodiments, the present invention provides a
method comprising: providing a wellbore in a subterranean formation
having a top portion and a bottom portion, and a middle portion
therebetween; providing a jetting fluid comprising a base fluid and
a cutting particulate; providing a cement slurry comprising an
expandable cementitious material; providing a breakable gel fluid;
introducing the jetting fluid into the bottom portion of the
wellbore in the subterranean formation at a pressure sufficient to
create or enhance a bottom portion fracture therein; introducing
the jetting fluid into the middle portion of the wellbore in the
subterranean formation at a pressure sufficient to create or
enhance a middle portion fracture therein; introducing the jetting
fluid into the top portion of the wellbore in the subterranean
formation at a pressure sufficient to create or enhance a top
portion fracture therein; introducing the cement slurry into at
least one of the top portion fracture, the middle fracture, and the
bottom fracture; introducing the breakable gel fluid into the
wellbore in the subterranean formation so as to prevent the
expandable cementitious material from migrating out of the top
portion fracture and bottom portion fracture in the subterranean
formation; curing the expandable cementitious material so as to
form a cement pack, wherein the curing of the expandable
cementitious material expands the expandable cementitious material
such that at least one microfracture is created within top portion
fracture, the middle portion fracture, and the bottom portion
fracture in the subterranean formation; breaking the breakable gel
fluid; and removing the broken breakable gel fluid from the
subterranean formation.
[0012] The features and advantages of the present invention will be
readily apparent to those skilled in the art upon a reading of the
description of the preferred embodiments that follows.
BRIEF DESCRIPTION OF THE DRAWINGS
[0013] The following figures are included to illustrate certain
aspects of the present invention, and should not be viewed as
exclusive embodiments. The subject matter disclosed is capable of
considerable modifications, alterations, combinations, and
equivalents in form and function, as will occur to those skilled in
the art and having the benefit of this disclosure.
[0014] FIG. 1 is a cross-sectional view of a main wellbore
penetrating a subterranean formation having cement pillars located
in a fracture extending from the main wellbore.
[0015] FIG. 2 is a cross-sectional view of a main wellbore
penetrating a subterranean formation having multiple lateral
wellbores extending therefrom and having cement pillars located in
at least one fracture extending from a lateral wellbore.
DETAILED DESCRIPTION
[0016] The present invention provides methods of enhancing fracture
conductivity within propped subterranean formations using a
cementitious material and methods of delivering and/or treating
such cementitious material. The cementitious material of the
present invention may be introduced alone as a "cement pack" within
a fracture in a wellbore in a subterranean formation as a
cementitious slurry that largely fills the interior of a fracture
or a portion of the interior of a fracture (e.g., the cementitious
material is packed into the fracture without spacer fluid to form).
In other embodiments, the cementitious material of the present
invention may be introduced in the form of cementitious material
aggregates or cement pillars within a fracture in a subterranean
formation. As used herein, the term "cementitious material
aggregates" and related terms such as "cement pillars" refer to
coherent cluster of wetted, settable cementitious material that
remains a coherent body when placed into a carrier fluid and/or a
fracture. The cementitious material aggregate remains a coherent
body that does not generally become dispersed into smaller bodies
without application of shear.
[0017] The methods of the present invention may be used in any
wellbore in a subterranean formation. As used herein, the term
"wellbore" refers to main wellbores (both horizontal and vertical)
and lateral wellbores. As used herein, the term "lateral wellbore"
refers to a wellbore that extends or radiates from the main
wellbore in any direction. Lateral wellbores may be drilled to
bypass an unusable portion of a main wellbore or to access
particular portions of a subterranean formation without drilling a
second main wellbore. Lateral wellbores are often tight formations
that may require the use of a hydrojetting tool to treat the
lateral wellbore for stimulation operations.
[0018] Referring now to the drawings, FIGS. 1 and 2 depict
application of an embodiment of the present invention in a main
wellbore and a lateral wellbore, respectfully. FIG. 1 depicts main
wellbore 10 in subterranean formation 1. A packer depicted by upper
packer 4 and lower packer 8 are set in main wellbore 10 to form a
packer-to-wellbore bond with the main wellbore formation surface 3.
The upper packer 4, lower packer 8, and main wellbore 10 define
fracture treatment interval 11. Injection tubing 9 is set in the
main wellbore in order to facilitate introduction of treatment
fluids into fracture treatment interval 11. Using conventional
methods known in the art (e.g., a perforation gun or a hydrojetting
tool), a plurality of perforations 5 extend into through main
wellbore formation surface 3 and into subterranean formation 1.
Subterranean formation 1 is stimulated by conventional methods to
create fracture 6 (e.g., by hydraulic fracturing with a viscous
fluid) extending through perforations 5 in main wellbore 10 and
into subterranean formation 1. The cement slurry of the present
invention is placed within fracture 6 by any of the methods
disclosed herein so as to form cement pillars 7, thereby providing
a cement pillar propped fracture.
[0019] FIG. 2 depicts main wellbore 12 having multiple lateral
wellbores 13 in subterranean formation 14. The multiple lateral
wellbores 13 may be located at one or more of top portion 15 of
main wellbore 12, middle portion 16 of main wellbore 12, or bottom
portion 17 of main wellbore 12. Using the methods disclosed herein
(e.g., a hydrojetting tool), a plurality of perforations 21 extend
through lateral wellbore formation surface 24 and into subterranean
formation 14, and may be located at one or more of at top portion
18 of lateral wellbore 13, middle portion 19 of lateral wellbore
13, or bottom portion 20 of lateral wellbore 13. Subterranean
formation 14 is stimulated by the methods disclosed herein to
create fracture 22 through perforations 21 in lateral wellbore 13
and into subterranean formation 14. The cement slurry of the
present invention is placed within fracture 22 by any of the
methods disclosed herein so as to form cement pillars 23, thereby
providing a cement pillar propped fracture. As used herein, the
term "top portion" of a wellbore refers to the point of initiation
of the wellbore (e.g., the wellbore head exposed to open air or the
entrance of a lateral wellbore from the main wellbore), the term
"bottom portion" refers to the point of termination of the
wellbore, and the term "middle portion" refers to the length of the
wellbore therebetween.
[0020] In some embodiments, the present invention provides for a
method comprising providing a wellbore in a subterranean formation
having at least one fracture; providing an expandable cementitious
material; introducing the expandable cementitious material into the
at least one fracture; curing the expandable cementitious material,
wherein the curing of the expandable cementitious material expands
the expandable cementitious material such that at least one
microfracture is created within the at least one fracture in the
subterranean formation; and acid-fracturing the at least one
fracture in the subterranean formation. Acid-fracturing may operate
synergistically with the expandable cementitious material to
enhance the conductive channels created in the fracture to improve
the flow of produced fluids, both when the expandable cementitious
material is introduced as a cement pack or a cement pillar. The
acid-fracturing step of the present invention is performed after
the expandable cementitious material is cured within a fracture in
a subterranean formation by injecting an acid into the formation
above the formation fracture gradient. Acid-fracturing enhances
conductivity because after the expandable cementitious material
expands and creates microfractures within the fracture, the acid
from the acid-fracturing creates differential etching in the
fracture resulting in ridges of non-uniform acid dissolution that,
when the hydraulic pressure is removed, provides additional
conductive channels, some of which may also intersect the
microfractures. Acid-fracturing may also be used as a tail-in
treatment with the expandable cementitious material to maintain
near wellbore conductivity. Although it is preferred that
acid-fracturing be performed after an expandable cement pack or
cement pillar is placed in a fracture and cures, acid-fracturing
may also synergistically improve the conductivity of fractures
propped with non-expandable cement pillars comprised of
cementitious material. The cement pillars are capable of
withstanding the fracture closure pressures to allow the acid to
etch non-uniform channels within the fracture to enhance hydraulic
fracturing and flow conductivity.
[0021] In some embodiments, the present invention provides methods
of using a cement slurry comprising a cementitious material and a
breakable foamed carrier fluid, wherein the cementitious material
is capable of consolidating to form a plurality of cementitious
material aggregates and wherein the breakable foamed carrier fluid
is capable of coating and isolating the cementitious material
aggregates while being placed downhole. The cementitious material
may be introduced into the breakable foamed carrier fluid to form
the cement slurry by mixing. In preferred embodiments, the
cementitious material is introduced into the breakable foamed
carrier fluid in discrete blobs to form the cement slurry. The
cement slurry is introduced into at least one fracture within the
subterranean formation and, once placed, the cementitious material
aggregates cure to form cement pillars within the fracture. Also,
once placed into the fracture, the breakable foamed carrier fluid
is broken and then removed from the subterranean formation. In some
embodiments, it may be preferable that the breakable foamed carrier
fluid does not break until the cementitious material aggregates
have cured or substantially cured. In other embodiments, the curing
of the cementitious material aggregates may occur simultaneously
with the breaking of the foamed carrier fluid. In some embodiments,
the cementitious material may be an expandable cementitious
material. In still other embodiments, the cement pillar propped
fracture (either by cementitious material or expandable
cementitious material) may be acid fracturized after the curing of
the cementitious material aggregates.
[0022] The fractures of the present invention may be created by any
hydraulic fracturing technique known in the art. In some
embodiments, hydraulic fracturing may be achieved by pumping a
fracturing fluid at or above the fracture gradient through
perforations extending from the wellbore into the formation. In
some cases the perforations extend through a cement sheath
separating the wellbore from the formation. Perforations may be
formed using generally circular-shaped charges in order to form the
perforations after detonation of the charge. Perforations may also
be formed using a hydrojetting tool with a generally
circular-shaped hydrojetting nozzle using a jetting fluid
comprising a base fluid and/or a cutting particulate.
[0023] Unlike traditional fracturing techniques, however, hydraulic
fracturing techniques for use in the methods of the present
invention may preferably be performed by pumping a fracturing fluid
at or above the fracture gradient through slots in a formation. As
used herein, the term "slots" refers to a shaped formation opening
in which the shape is a quadrilateral having two directions, where
one direction is longer than the other (e.g. a rectangle). In some
embodiments, the slots may be at least 3 times as long as wide. The
particular shape of the slots used in the present invention will
depend upon multiple factors including, for example, the type of
formation, the type of cementitious material used, and the size of
the fracture to be propped.
[0024] Slots may be formed using slot-shaped charges such that the
slot is created after detonation of the charge. Slots may also be
formed using a hydrojetting tool with a slot-shaped hydrojetting
nozzle. The slots may be made using the hydrojetting tool with a
jetting fluid comprising a base fluid alone or a base fluid and a
cutting particulate. Slots may also be created using a
non-slot-shaped hydrojetting tool by oscillating or reciprocating
the nozzle of the hydrojetting tool in a manner that carves out a
slot-shaped opening in the formation. Slots are particularly
beneficial for use in the present invention when cementitious
material aggregates are placed within the fracture. The slots help
the cementitious material aggregates or cement pillars to remain
substantially intact as they enter the fracture, which may increase
the conductivity of the fracture. Perforations, on the other hand,
may result in the mixing or breaking of cementitious material
aggregates as they encounter shear through small perforation
openings (or openings that do not comport with the size and shape
of the cementitious material aggregates) prior to being placed
within the fracture.
[0025] Suitable base fluids for use in any of the fluids of the
present invention requiring a base fluid (e.g., jetting fluid,
breakable gel fluid, breakable foamed carrier fluid, degradable gel
fluid) may include, but are not limited to, oil-based fluids,
aqueous-based fluids, aqueous-miscible fluids, water-in-oil
emulsions, or oil-in-water emulsions. Suitable oil-based fluids may
include alkanes, olefins, aromatic organic compounds, cyclic
alkanes, paraffins, diesel fluids, mineral oils, desulfurized
hydrogenated kerosenes, and any combination thereof. Suitable
aqueous-based fluids may include fresh water, saltwater (e.g.,
water containing one or more salts dissolved therein), brine (e.g.,
saturated salt water), seawater, and any combination thereof.
Suitable aqueous-miscible fluids may include, but not be limited
to, alcohols, e.g., methanol, ethanol, n-propanol, isopropanol,
n-butanol, sec-butanol, isobutanol, and t-butanol; glycerins;
glycols, e.g., polyglycols, propylene glycol, and ethylene glycol;
polyglycol amines; polyols; any derivative thereof; any in
combination with salts, e.g., sodium chloride, calcium chloride,
calcium bromide, zinc bromide, potassium carbonate, sodium formate,
potassium formate, cesium formate, sodium acetate, potassium
acetate, calcium acetate, ammonium acetate, ammonium chloride,
ammonium bromide, sodium nitrate, potassium nitrate, ammonium
nitrate, ammonium sulfate, calcium nitrate, sodium carbonate, and
potassium carbonate; any in combination with an aqueous-based
fluid; and any combination thereof. Suitable water-in-oil
emulsions, also known as invert emulsions, may have an oil-to-water
ratio from a lower limit of greater than about 50:50, 55:45, 60:40,
65:35, 70:30, 75:25, or 80:20 to an upper limit of less than about
100:0, 95:5, 90:10, 85:15, 80:20, 75:25, 70:30, or 65:35 by volume
in the base fluid, where the amount may range from any lower limit
to any upper limit and encompass any subset therebetween. Examples
of suitable invert emulsions include those disclosed in U.S. Pat.
No. 5,905,061 entitled "Invert Emulsion Fluids Suitable for
Drilling" filed on May 23, 1997, U.S. Pat. No. 5,977,031 entitled
"Ester Based Invert Emulsion Drilling Fluids and Muds Having
Negative Alkalinity" filed on Aug. 8, 1998, U.S. Pat. No. 6,828,279
entitled "Biodegradable Surfactant for Invert Emulsion Drilling
Fluid" filed on Aug. 10, 2001, U.S. Pat. No. 7,534,745 entitled
"Gelled Invert Emulsion Compositions Comprising Polyvalent Metal
Salts of an Organophosphonic Acid Ester or an Organophosphinic Acid
and Methods of Use and Manufacture" filed on May 5, 2004, U.S. Pat.
No. 7,645,723 entitled "Method of Drilling Using Invert Emulsion
Drilling Fluids" filed on Aug. 15, 2007, and U.S. Pat. No.
7,696,131 entitled "Diesel Oil-Based Invert Emulsion Drilling
Fluids and Methods of Drilling Boreholes" filed on Jul. 5, 2007,
each of which are incorporated herein by reference in their
entirety. It should be noted that for water-in-oil and oil-in-water
emulsions, any mixture of the above may be used including the water
being and/or comprising an aqueous-miscible fluid.
[0026] The cutting particulate suitable for use in the jetting
fluids of the present invention may be any proppant particulate
suitable for use in a subterranean operation that is capable of
withstanding the formation pressure so as to create a perforation
or slot therein. Suitable cutting particulates may include, but are
not limited to, sand, bauxite, ceramic materials, glass materials,
polymer materials, 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 cutting particulates of the
present invention may additionally be degradable particulates,
including any of those disclosed herein.
[0027] The cementitious material of the present invention may be
any cementitious material suitable use in a subterranean operation,
including hydraulic and non-hydraulic cementitious materials. In
preferred embodiments, the cementitious material is a hydraulic
cement. Hydraulic cements harden by the process of hydration due to
chemical reactions to produce insoluble hydrates (e.g., calcium
hydroxide) that occur independent of the cement's water content
(e.g., hydraulic cements can harden even under constantly damp
conditions). Thus, hydraulic cements are preferred because they are
capable of hardening regardless of the water content of a
particular subterranean formation. Suitable hydraulic cements
include, but are not limited to Portland cement; Portland cement
blends (e.g., Portland blast-furnace slag cement and/or expansive
cement); non-Portland hydraulic cement (e.g., super-sulfated
cement, calcium aluminate cement, and/or high magnesium-content
cement); and any combination thereof.
[0028] In some preferred embodiments, the cementitious material is
an expandable cementitious material. The expandable cementitious
material of the present invention may be any expandable
cementitious material known in the art. Suitable expandable
cementitious materials may include expandable agents such as, but
not limited to, calcium oxide; magnesium oxide; any derivatives
thereof; and any combinations thereof. Examples of suitable
expandable cementitious materials include, but are not limited to,
those disclosed in U.S. Pat. No. 4,046,583 entitled "Methods of
Producing Expansive and High Strength Cementitious Pastes, Mortars
and Concretes" and U.S. Pat. No. 4,797,159 entitled "Expandable
Cement Composition," each of which is incorporated herein by
reference in their entirety. Suitable examples of commercially
available expandable cementitious materials include, but are not
limited to, Dexpan.RTM. Non-Explosive Demolition Agent by
Dexpan.RTM. USA in Sunland Park, N. Mex.; Quikrete.RTM. Anchoring
Cement by Quikrete.RTM. Companies in Atlanta, Ga.; Rockite.RTM.
Expansion Cement by Hartline Products Co., Inc. in Cleveland, Ohio;
and CRL Kwixset.RTM. Cement from Hartline Products Co., Inc. in
Cleveland, Ohio.
[0029] The expandable cementitious materials for use in the present
invention may expand as they cure, such that the area of the
expandable cementitious material occupied within the fracture is a
first amount and as the expandable cementitious material cures, the
area it occupied within the fracture increases to a second, larger
amount. In some embodiments, the expandable cementitious material
may expand up to 4 times the original size of the uncured
expandable cementitious material. By increasing the area occupied
by the expandable cementitious material, the expandable
cementitious material may overcome the in-situ stresses of the
formation to create microfractures within the fracture. These
microfractures may increase the conductivity of the fracture. The
type and composition of the expandable cementitious material may be
manipulated in order to control the magnitude of in-situ pressures
which it may overcome. By doing so, the amount and size of the
microfractures created may be controlled and/or predicted. The
expandable cementitious material may be intermixed with
cementitious material that is not expandable in order to achieve
the counter stress pressures for a particular formation. One of
ordinary skill in the art, with the benefit of this disclosure,
will recognize the type and amount of cementitious or expandable
cementitious material to include in a particular application.
[0030] The expandable cementitious materials of the present
invention may also be capable of acting as a barrier to prevent
direct fracture growth or extension in multiple-stage hydraulic
fracturing operations. In multiple-stage hydraulic fracturing
operations, multiple intervals of a subterranean formation may be
fractured at different time periods. The expandable cementitious
materials of the present invention may act to prevent already
existing fractures from growing during such multiple-stage
hydraulic fracturing operations. The methods of the present
invention may employ multiple-stage hydraulic fracturing (e.g.,
through use of a hydrojetting tool) beginning near the mouth of the
wellbore or near the deepest drilled portion of the wellbore and in
any order between such that the interval first fractured need not
be close to the interval fractured thereafter. Additionally,
because the expandable cementitious material is nonreactive with
subterranean formations, it is capable of producing a filtercake,
which controls leakoff into natural fractures and allows deeper
effective fracture lengths.
[0031] The synergistic combination of expandable cementitious
material and acid-fracturing disclosed by the present invention may
also overcome the difficulties associated with hydraulic fracturing
(including acid-fracturing) soft rock formations (e.g., carbonate
rock). Because the expandable cementitious material of the present
invention may be tightly packed into a fracture and be capable of
combating the in-situ formation closure stresses, while also
expanding and generating conductive channels.
[0032] In some embodiments, the cementitious material or expandable
cementitious material of the present invention may include a
pozzolanic material. Pozzolanic materials may aid in increasing the
density and strength of the cementitious material. As used herein,
the term "pozzolanic material" refers to a siliceous material that,
while not being cementitious, is capable of reacting with calcium
hydroxide, which may be produced during hydration of the
cementitious material. Because calcium hydroxide accounts for a
sizable portion of most hydrated hydraulic cements and because
calcium hydroxide does not contribute to the cement's properties,
the combination of cementitious and pozzolanic materials may
synergistically enhance the strength and quality of the cement. Any
pozzolanic material that is reactive with the cementitious or
expandable cementitious material may be used in the methods of the
present invention. Suitable pozzolanic materials include, but are
not limited to silica fume; metakaolin; fly ash; diatomaceous
earth; calcined or uncalcined diatomite; calcined fullers earth;
pozzolanic clays; calcined or uncalcined volcanic ash; bagasse ash;
pumice; pumicite; rice hull ash; natural and synthetic zeolites;
slag; vitreous calcium aluminosilicate; and any combinations
thereof. An example of a suitable commercially-available pozzolanic
material is POZMIX.RTM.-A available from Halliburton Energy
Services, Inc. of Houston, Tex. In some embodiments of the present
invention, the pozzolanic material may be present in an amount of
about 5% to about 60% w/w of the dry cementitious material. In
preferred embodiments, the pozzolanic material is present in an
amount of about 5% to about 30% w/w of the dry cementitious
material.
[0033] In some embodiments, the cementitious material or expandable
cementitious material of the present invention may further comprise
any cement additive capable of use in a subterranean operation.
Cement additives may be added to modify the characteristics of the
cementitious material. Such additives include, but are not limited
to, a cement accelerator; a cement retarder; a fluid-loss additive;
a cement dispersant; a cement extender; a weighting agent; a lost
circulation additive; and any combinations thereof. The cement
additives of the present invention may be in any form, including
powder form or liquid form.
[0034] The cementitious material or expandable cementitious
material may be held into place (e.g., prevented from escaping a
fracture) by the introduction of a breakable gel fluid into the
wellbore in the subterranean formation (e.g., by placing the
breakable gel fluid into the wellbore or into the near-wellbore
portion of the fracture itself). The breakable gel fluid pushes the
cementitious material toward the point of the fracture furthest
from the wellbore and prevents the cementitious material from
migrating out of the fracture and into the wellbore. Avoiding such
migration is generally important, as it may tend to prevent the
cementitious material from forming a cement pack capable of
withstanding fracture closure pressure, thereby hindering
conductivity of the fracture. Additionally, when the cementitious
material is an expandable cementitious material, migration out of
the fracture may prevent the expandable cementitious material from
creating microfractures within the fracture because the expandable
cementitious material is not in sufficient quantity to place
pressure on the fracture walls.
[0035] In some embodiments, the breakable gel fluid of the present
invention may additionally be introduced into a fracture in a
subterranean formation intermittently with the cementitious or
expandable cementitious material so as to alternate the breakable
gel fluid and the cementitious or expandable cementitious material
within the at least one fracture in the subterranean formation.
After placement curing the cementitious or expandable cementitious
material, the breakable gel fluid is broken and removed from the
subterranean formation so as to leave behind discrete spaces
between individual cement packs (e.g., cementitious or expandable
cementitious pillars).
[0036] The breakable gel fluid of the present invention may
comprise a base fluid, a gelling agent, a crosslinking agent, and a
gel breaker. The breakable gel fluid may additionally comprise a
particulate, such as sand. The base fluids suitable for use in the
present invention may be any base fluids that may be used in
subterranean operations. Suitable base fluids for use in
conjunction with the present invention may include, but not be
limited to,
[0037] The gelling agents suitable for use in the present invention
may comprise any substance (e.g. a polymeric material) capable of
increasing the viscosity of the breakable gel fluid. In certain
embodiments, the gelling agent may comprise one or more 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 gelling
agents, synthetic gelling agents, or a combination thereof. The
gelling agents also may be cationic gelling agents, anionic gelling
agents, or a combination thereof. Suitable gelling agents include,
but are not limited to, polysaccharides, biopolymers, and/or
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),
xanthan, scleroglucan, succinoglycan, diutan, and combinations
thereof. In certain embodiments, the gelling agents comprise an
organic carboxylated polymer, such as CMHPG.
[0038] Suitable synthetic polymers include, but are not limited to,
2,2'-azobis(2,4-dimethyl valeronitrile),
2,2'-azobis(2,4-dimethyl-4-methoxy valeronitrile), polymers and
copolymers of polyvinylpyrrolidone; acrylamide ethyltrimethyl
ammonium chloride, acrylamide, acrylamido-and methacrylamido-alkyl
trialkyl ammonium salts, acrylamidomethylpropane sulfonic acid,
acrylamidopropyl trimethyl ammonium chloride, acrylic acid,
dimethylaminoethyl methacrylamide, dimethylaminoethyl methacrylate,
dimethylaminopropyl methacrylamide,
dimethylaminopropylmethacrylamide, dimethyldiallylammonium
chloride, dimethylethyl acrylate, fumaramide, methacrylamide,
methacrylamidopropyl trimethyl ammonium chloride,
methacrylamidopropyldimethyl-n-dodecylammonium chloride,
methacrylamidopropyldimethyl-n-octylammonium chloride,
methacrylamidopropyltrimethylammonium chloride, methacryloylalkyl
trialkyl ammonium salts, methacryloylethyl trimethyl ammonium
chloride, methacrylylamidopropyldimethylcetylammonium chloride,
N-(3-sulfopropyl)-N-methacrylamidopropyl-N,N-dimethyl ammonium
betaine, N,N-dimethylacrylamide, N-methylacrylamide,
nonylphenoxypoly(ethyleneoxy)ethylmethacrylate, partially
hydrolyzed polyacrylamide, poly 2-amino-2-methyl propane sulfonic
acid, polyvinyl alcohol, sodium 2-acrylamido-2-methylpropane
sulfonate, quaternized dimethylaminoethylacrylate, quaternized
dimethylaminoethylmethacrylate, and derivatives and combinations
thereof. In certain embodiments, the gelling agent comprises an
acrylamide/2-(methacryloyloxy)ethyltrimethylammonium methyl sulfate
copolymer. In certain embodiments, the gelling agent may comprise
an acrylamide/2-(methacryloyloxy)ethyltrimethylammonium chloride
copolymer. In certain embodiments, the gelling agent may comprise a
derivatized cellulose that comprises 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 entire disclosures of
which are incorporated herein by reference.
[0039] 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 as
gelling agents.
[0040] The gelling agent may be present in the breakable gel fluids
useful in the methods of the present invention in an amount
sufficient to provide the desired viscosity. In some embodiments,
the gelling agents (i.e., the polymeric material) may be present in
an amount in the range of from about 0.1% to about 10% by weight of
the breakable gel fluid. In certain embodiments, the gelling agents
may be present in an amount in the range of from about 0.15% to
about 2.5% by weight of the breakable gel fluid.
[0041] In those embodiments of the present invention where it is
desirable to crosslink the gelling agent, the breakable gel fluid
may comprise one or more crosslinking agents. The crosslinking
agents may comprise a borate ion, a metal ion, or similar component
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, magnesium ions, zirconium IV
ions, titanium IV ions, aluminum ions, antimony ions, chromium
ions, iron ions, copper ions, magnesium 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, ferric chloride, boric acid,
disodium octaborate tetrahydrate, sodium diborate, pentaborates,
ulexite, colemanite, magnesium oxide, zirconium lactate, zirconium
triethanol amine, zirconium lactate triethanolamine, zirconium
carbonate, zirconium acetylacetonate, zirconium malate, 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.
[0042] Suitable crosslinking agents of the present invention may
also comprise at least one degradable group and at least two
unsaturated terminal groups. The at least one degradable group may
include, but is not limited to, an ester; a phosphate ester; an
amide; an acetal; a ketal; an orthoester; a carbonate; an anhydride
a silyl ether; an alkene oxide; an ether; an imine; an ether ester;
an ester amide; an ester urethane; a carbonate urethane; an amino
acid; any derivatives thereof; and any combinations thereof. The at
least two unsaturated terminal groups may include, but are not
limited to, an unsubstituted ethylenically unsaturated group; a
substituted ethylenically unsaturated group; a vinyl group; an
allyl group; an acryl group; an unsaturated ester; an acrylate; a
methacrylate; a butyl acrylate; an amide; an acrylamide; an ether;
a vinyl ether; any derivatives thereof; and any combinations
thereof.
[0043] 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 interaction with some other
substance. In some embodiments, the activation of the crosslinking
agent may be delayed by encapsulation with a coating (e.g., a
porous coating through which the crosslinking agent 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 conditions in the subterranean formation being
treated, the safety handling requirements, the pH of the breakable
gel fluid, temperature, and/or the desired delay for the
crosslinking agent to crosslink the gelling agent molecules.
[0044] When included, suitable crosslinking agents may be present
in the breakable gel fluids useful in the methods of the present
invention in an amount sufficient to provide the desired degree of
crosslinking between molecules of the gelling agent. In certain
embodiments, the crosslinking agent may be present in the breakable
gel fluids of the present invention in an amount in the range of
from about 0.005% to about 1% by weight of the breakable gel fluid.
In certain embodiments, the crosslinking agent may be present in
the breakable gel fluids of the present invention in an amount in
the range of from about 0.05% to about 1% by weight of breakable
gel 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 breakable gel 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 breakable gel
fluid.
[0045] The breakable gel fluids useful in the methods of the
present invention also may include internal gel breakers such as
enzyme, oxidizing, acid buffer, or delayed gel breakers. The gel
breakers may cause the breakable gel fluids of the present
invention to revert to thin fluids that can be produced back to the
surface. In some embodiments, the gel breaker 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
interaction with some other substance. In some embodiments, the gel
breaker may be delayed by encapsulation with a coating (e.g. a
porous coatings through which the breaker may diffuse slowly, or a
degradable coating that degrades downhole) that delays the release
of the gel breaker. In other embodiments the gel breaker may be a
degradable material (e.g. polylactic acid or polygylcolic acid)
that releases an acid or alcohol in the present of an aqueous
liquid. In certain embodiments, the gel breaker used may be present
in the breakable gel fluid in an amount in the range of from about
0.0001% to about 200% by weight of the gelling agent. One of
ordinary skill in the art, with the benefit of this disclosure,
will recognize the type and amount of a gel breaker to include in
the breakable gel fluids of the present invention based on, among
other factors, the desired amount of delay time before the gel
breaks, the type of gelling agents used, the temperature conditions
of a particular application, the desired rate and degree of
viscosity reduction, and/or the pH of the breakable gel fluid
fluid.
[0046] In some embodiments, the cementitious or expandable
cementitious material may additionally comprise a consolidating
agent. The consolidating agent may aid in maintaining the cement
slurry composition as it flows in the subterranean formation.
Suitable consolidating agents may include, but are not limited to,
sand, fibers, non-aqueous tackifying agents, aqueous tackifying
agents, emulsified tackifying agents, silyl-modified polyamide
compounds, resins, crosslinkable aqueous polymer compositions,
polymerizable organic monomer compositions, consolidating agent
emulsions, zeta-potential modifying aggregating compositions,
silicon-based resins, and binders. Combinations and/or derivatives
of these also may be suitable. In some embodiments, a consolidating
agent is present in the present invention in an amount in the range
from about 0.1% to about 20% by weight of the cementitious
material. In preferred embodiments, a consolidating agent is
present in the present invention in an amount in the range from
about 1% to about 5% by weight of the cementitious material.
[0047] Nonlimiting examples of suitable non-aqueous tackifying
agents may be found in U.S. Pat. Nos. 7,392,847, 7,350,579,
5,853,048; 5,839,510; and 5,833,000, the entire disclosures of
which are herein incorporated by reference. Nonlimiting examples of
suitable aqueous tackifying agents may be found in U.S. Pat. Nos.
8,076,271, 7,131,491, 5,249,627 and 4,670,501, the entire
disclosures of which are herein incorporated by reference.
Nonlimiting examples of suitable crosslinkable aqueous polymer
compositions may be found in U.S. Patent Application Publication
No. 2010/0160187 (pending) and U.S. Pat. No. 8,136,595 the entire
disclosures of which are herein incorporated by reference.
Nonlimiting examples of suitable silyl-modified polyamide compounds
may be found in U.S. Pat. No. 6,439,309 entitled the entire
disclosure of which is herein incorporated by reference.
Nonlimiting examples of suitable resins may be found in U.S. Pat.
Nos. 7,673,686; 7,153,575; 6,677,426; 6,582,819; 6,311,773; and
4,585,064 as well as U.S. Patent Application Publication No.
2008/0006405 (abandoned) and U.S. Pat. No. 8,261,833, the entire
disclosures of which are herein incorporated by reference.
Nonlimiting examples of suitable polymerizable organic monomer
compositions may be found in U.S. Pat. No. 7,819,192, the entire
disclosure of which is herein incorporated by reference.
Nonlimiting examples of suitable consolidating agent emulsions may
be found in U.S. Patent Application Publication No. 2007/0289781
(pending) the entire disclosure of which is herein incorporated by
reference. Nonlimiting examples of suitable zeta-potential
modifying aggregating compositions may be found in U.S. Pat. Nos.
7,956,017 and 7,392,847, the entire disclosures of which are herein
incorporated by reference. Nonlimiting examples of suitable
silicon-based resins may be found in Application Publication Nos.
2011/0098394 (pending), 2010/0179281 (pending), and U.S. Pat. Nos.
8,168,739 and 8,261,833, the entire disclosures of which are herein
incorporated by reference. Nonlimiting examples of suitable binders
may be found in U.S. Pat. Nos. 8,003,579; 7,825,074; and 6,287,639,
as well as U.S. Patent Application Publication No. 2011/0039737,
the entire disclosures of which are herein incorporated by
reference. It is within the ability of one skilled in the art, with
the benefit of this disclosure, to determine the type and amount of
consolidating agent to include in the methods of the present
invention to achieve the desired results.
[0048] In some embodiments of the present invention, degradable
particulates are included with the cementitious or expandable
cementitious material. One purpose of including degradable
particulates is to enhance the permeability of the conductivity of
the fracture. In some embodiments, the degradable particles used
are oil-degradable materials, which degrade by produced fluids. In
other embodiments, the degradable particulates may be degraded by
materials purposely placed in the formation by injection or mixing
the degradable particle with delayed reaction degradation agents,
or other suitable means to induce degradation. In embodiments in
which degradable particulates are used, the degradable particulates
are preferably substantially uniformly distributed throughout the
cementitious material. Over time, the degradable material will
degrade, in situ, causing the degradable material to substantially
be removed from the cured cementitious material and to leave behind
voids. These voids may enhance the conductivity of the
fracture.
[0049] Suitable degradable particulates include oil-degradable
polymers. Oil-degradable polymers that may be used in accordance
with the present invention may be either natural or synthetic
polymers. Some particular examples include, but are not limited to,
polyacrylics; polyamides; and polyolefins such as polyethylene,
polypropylene, polyisobutylene, and polystyrene. Other suitable
oil-degradable polymers include those that have a melting point
which is such that the polymer will melt or dissolve at the
temperature of the subterranean formation in which it is placed,
such as a wax material.
[0050] In addition to oil-degradable polymers, other degradable
particulates that may be used in conjunction with the present
invention include, but are not limited to, degradable polymers;
dehydrated salts; and/or mixtures of the two. As for degradable
polymers, a polymer is considered to be "degradable" herein if the
degradation is due to, in situ, a chemical and/or radical process
such as hydrolysis, or oxidation. The degradability of a polymer
depends at least in part on its backbone structure. For instance,
the presence of hydrolyzable and/or oxidizable linkages in the
backbone often yields a material that will degrade as described
herein. The rates at which such polymers degrade are dependent on,
at least, the type of repetitive unit, composition, sequence,
length, molecular geometry, molecular weight, morphology (e.g.,
crystallinity, size of spherulites, and orientation),
hydrophilicity, hydrophobicity, surface area, and additives. Also,
the environment to which the polymer is subjected may affect how it
degrades (e.g., formation temperature, presence of moisture,
oxygen, microorganisms, enzymes, pH, and the like).
[0051] Suitable examples of degradable polymers that may be used in
accordance with the present invention include polysaccharides such
as dextran or cellulose; chitins; chitosans; proteins; aliphatic
polyesters; poly(lactides); poly(glycolides);
poly(.epsilon.-caprolactones); poly(hydroxybutyrates);
poly(anhydrides); aliphatic or aromatic polycarbonates;
poly(orthoesters); poly(amino acids); poly(ethylene oxides); and
polyphosphazenes. Of these suitable polymers, aliphatic polyesters
and polyanhydrides may be preferred. Polyanhydride hydrolysis
proceeds, in situ, via free carboxylic acid chain-ends to yield
carboxylic acids as final degradation products. The degradation
time can be varied over a broad range by changes in the polymer
backbone. Examples of suitable polyanhydrides include poly(adipic
anhydride), poly(suberic anhydride), poly(sebacic anhydride), and
poly(dodecanedioic anhydride). Other suitable examples include, but
are not limited to, poly(maleic anhydride) and poly(benzoic
anhydride).
[0052] Dehydrated salts may be used in accordance with the present
invention as a degradable particulates. A dehydrated salt is
suitable for use in the present invention if it will degrade over
time as it hydrates. For example, a particulate solid anhydrous
borate material that degrades over time may be suitable. Specific
examples of particulate solid anhydrous borate materials that may
be used include, but are not limited to, anhydrous sodium
tetraborate (also known as anhydrous borax) and anhydrous boric
acid. These anhydrous borate materials are only slightly soluble in
water. However, with time and heat in a subterranean environment,
the anhydrous borate materials react with the surrounding aqueous
fluid and are hydrated. The resulting hydrated borate materials are
highly soluble in water as compared to anhydrous borate materials
and as a result degrade in the aqueous fluid. In some instances,
the total time required for the anhydrous borate materials to
degrade in an aqueous fluid is in the range of from about 8 hours
to about 72 hours depending upon the temperature of the
subterranean zone in which they are placed. Other examples include
organic or inorganic salts like acetate trihydrate.
[0053] Blends of certain degradable materials may also be suitable
as degradable particulates. One example of a suitable blend of
materials is a mixture of poly(lactic acid) and sodium borate where
the mixing of an acid and base could result in a neutral solution
where this is desirable. Another example would include a blend of
poly(lactic acid) and boric oxide. Other materials that undergo an
irreversible degradation may also be suitable, if the products of
the degradation do not undesirably interfere with either the
conductivity of the proppant matrix or with the production of any
of the fluids from the subterranean formation.
[0054] In some embodiments of the present invention, the degradable
particulates are present in the range from about 1% to about 90% by
weight of the combined total of cementitious material and
degradable particulates. In other embodiments, the degradable
particulates are present in the range from about 20% to about 70%
by weight of the combined total of cementitious material and
degradable particulates. In still other embodiments, the degradable
particulars are present in the range from about 25% to about 50% by
weight of the combined total of cementitious material and
degradable particulates. One of ordinary skill in the art with the
benefit of this disclosure will recognize an optimum concentration
of degradable particulates that provides desirable values in terms
of enhanced conductivity or permeability without undermining the
stability of the propped fracture itself.
[0055] In some embodiments, the present invention provides a method
comprising providing a wellbore in a subterranean formation having
at least one fracture; providing a cement slurry comprising a
cementitious or expandable cementitious material and a breakable
foamed carrier fluid, wherein the cementitious or expandable
cementitious material is capable of consolidating to form a
plurality of cementitious or expandable cementitious material
aggregates and wherein the breakable foamed carrier fluid is
capable of coating and isolating the cementitious or expandable
cementitious material aggregates; introducing the cement slurry
into the at least one fracture in the subterranean formation;
curing the cementitious or expandable cementitious material
aggregates so as to form a cement pillar within the fracture in the
subterranean formation; degrading the breakable foamed carrier
fluid; and removing the degraded breakable foamed carrier fluid
from the subterranean formation. In some embodiments, the fracture
may be acid-fracturized after placement and curing of the cement
pillars into the fracture.
[0056] As used herein, the term "foam" refers to a two-phase
composition having a continuous liquid phase and a discontinuous
gas phase. The breakable foamed carrier fluid of the present
invention is capable of surrounding cementitious material
aggregates and preventing or reducing their dispersal when being
placed in a fracture, particularly in high shear areas. By
preventing dispersal of the cementitious material aggregates,
discrete cementitious material aggregates may be placed into a
fracture and cured therein to form a cement pillar, which aid in
propping the fracture and enhancing conductivity of the
fracture.
[0057] The breakable foamed carrier fluid of the present invention
may be a foamed version of any fluid suitable for use as a base
fluid or substantially particulate-free pad fluid of the present
invention (e.g., a foamed aqueous-based fluid, a foamed oil-based
fluid, a foamed water-in-oil emulsion, or a foamed oil-in-water
emulsion). The breakable foamed carrier fluid of the present
invention is preferably substantially particulate-free. The
breakable foamed carrier fluid of the present invention may
comprise a nano-particle, a foaming agent, a foam breaker, and/or a
gas generating agent.
[0058] Nano-particles may be included in the breakable foamed
carrier fluid in order to enhance the stability and toughness of
the generated foam. In preferred embodiments, a nano-particle is
included in the breakable foamed carrier fluid to enhance its
ability to surround and protect the cementitious or expandable
cementitious material aggregates being placed into a fracture.
Suitable nano-particles may include, but are not limited to, fumed
silica; a phyllosilicate; and any combination thereof. In some
embodiments, the nano-particulates are present in the present
invention in the range from about 0.1% to about 10% by volume of
the breakable foamed carrier fluid. In preferred embodiments, the
nano-particulates are present in the present invention in the range
from about 1% to about 5% by volume of the breakable foamed carrier
fluid.
[0059] Suitable foaming agents for use in the present invention may
include, but are not limited to, an ethoxylated alcohol ether
sulfate; an alkyl amidopropyl betaine; an alkene amidopropyl
betaine surfactant; an alkyl amidopropyl dimethyl amine oxide; and
alkene amidopropyl dimethyl amine oxide; any derivatives thereof;
and any combinations thereof. In some embodiments, the foaming
agent is present in the breakable foamed carrier fluid of the
present invention in an amount of about 0.01% to about 10% by
volume of the breakable foamed carrier fluid. In preferred
embodiments, the foaming agent is present in the breakable foamed
carrier fluid of the present invention in an amount of about 0.1%
to about 2% by volume of the breakable foamed carrier fluid.
[0060] Foam breakers function to reduce or hinder already produced
foam or the future production of foam. Foam breakers are able to
rupture air bubbles and degrade foam. In doing so, foam breakers
are able to reduce the viscosity of foamed breakable foamed carrier
fluids in order to aid, for example, in producing (or removing)
fluids back to the surface of the subterranean formation. In
preferred embodiments of the present invention, the foam breaker
may be encapsulated with a coating (e.g., a porous coating through
which the foam breaker may diffuse slowly, or a degradable coating
that degrades downhole upon an activating condition, such as, for
example, pH or temperature). The coating encapsulating the foam
breaker may serve to minimize interference between the foam
breaking and the foaming agent such that the foaming agent is able
to produce foam and the foam is broken only upon certain
conditions, such as the duration or time the breakable foamed
carrier fluid has been downhole, temperature, pH, salinity, and the
like. For use in the present invention, suitable foam breakers
include any known oil-based foam breakers; water-based foam
breakers; silicone-based foam breakers; polymer-based foam
breakers; alkyl polyacrylate foam breakers; and any combinations
thereof. Suitable oil-based foam breakers may comprise an oil
carrier and a wax component. The oil carrier may include, but is
not limited to, mineral oil; vegetable oil; white oil; any other
oil insoluble in the breakable foamed carrier fluid; and any
combinations thereof. The wax may include, but is not limited to,
ethylene bis stearamide; paraffin wax; ester wax; fatty alcohol
wax; and any combination thereof. In addition, the oil-based foam
breakers of the present invention may include a hydrophobic silica.
Suitable water-based foam breakers for use in the breakable foamed
carrier fluid of the present invention may comprise a water carrier
and an oil component or a water carrier and a wax component. The
oil component may include, but is not limited to, white oil;
vegetable oil; and any combinations thereof. The wax component may
include, but is not limited to, a long chain fatty alcohol wax; a
fatty acid soap wax; an ester wax; and any combinations thereof.
Suitable silicone-based foam breakers may comprise a hydrophobic
silicone component dispersed in a silicone oil. The silicone-based
foam breaker may additionally comprise silicone glycols or other
modified silicones. Suitable polymer-based foam breakers may
comprise polyethylene glycol and polypropylene glycol copolymers
and may be delivered in an oil carrier, a water carrier, or an
emulsion base. Suitable alykyl polyacrylate foam breakers may
comprise an oil carrier and an alykyl polyacrylate. In some
embodiments, the foam breaker is present in the breakable foamed
carrier fluid of the present invention in an amount in the range
from about 0.1% to about 10% by volume of the breakable foamed
carrier fluid. In preferred embodiments, the foam breaker is
present in the breakable foamed carrier fluid of the present
invention in an amount in the range from about 0.5% to about 3% by
volume of the breakable foamed carrier fluid.
[0061] The breakable foamed carrier fluid of the present invention
may also comprise a gas generating agent. Gas generating agents may
aid the foaming agent in producing foam. Some gas generating agents
may be capable of forming a foam without the aid of a foaming
agent. Suitable gas generating agents for use in conjunction with
the present invention may include, but are not limited to,
nitrogen; carbon dioxide; air; methane; helium; argon; and any
combination thereof. One skilled in the art, with the benefit of
this disclosure, should understand the benefit of each gas. By way
of nonlimiting example, carbon dioxide foams may have deeper well
capability than nitrogen foams because carbon dioxide gas foams
have greater density than nitrogen gas foams so that the surface
pumping pressure required to reach a corresponding depth is lower
with carbon dioxide than with nitrogen. In some embodiments, the
foam quality of the breakable foamed carrier fluid may range from a
lower limit of about 5%, 10%, 25%, 40%, 50%, 60%, or 70% gas volume
to an upper limit of about 95%, 90%, 80%, 75%, 60%, or 50% gas
volume, and wherein the foam quality of the breakable foamed
carrier fluid may range from any lower limit to any upper limit and
encompass any subset therebetween. Most preferably, the breakable
foamed carrier fluid may have a foam quality from about 85% to
about 95%, or about 90% to about 95%.
[0062] Any of the fluids or cementitious materials of the present
invention may further comprise an additive including, but not
limited to, a salt; a weighting agent; an inert solid; a fluid loss
control agent; a dispersion aid; a corrosion inhibitor; a
viscosifying agent; a gelling agent; a surfactant; a particulate; a
proppant particulate; a gravel particulate; a lost circulation
material; a pH control additive; a breaker; a biocide; a
crosslinker; a stabilizer; a scale inhibitor; a friction reducer;
and any combinations thereof.
[0063] In some embodiments, the cementitious or expandable
cementitious material aggregates of the present invention are
introduced into a fracture alone or intermittently between a
substantially particulate-free pad fluid so as to create spaced
cementitious material portions flanked by the substantially
particulate-free pad fluid. After the cementitious or expandable
cementitious material aggregates cure, the substantially
particulate-free pad fluid may be returned to the surface such that
individual cement pillars remain in the fracture. Any suitable base
fluid may be used as a substantially particulate-free pad fluid of
the present invention, provided that the substantially
particulate-free pad fluid is substantially particulate-free. As
used herein, the term "substantially particulate-free fluid" refers
to a fluid having a particulate volume of no more than about 60% by
weight of the substantially particulate-free fluid.
[0064] In some embodiments, the present invention provides a method
comprising providing a wellbore or a lateral wellbore in a
subterranean formation having a top portion and a bottom portion,
and a middle portion therebetween; providing a jetting fluid
comprising a base fluid and a cutting particulate; providing a
cement slurry comprising an expandable cementitious material; and
providing a breakable gel fluid. The jetting fluid is then
introduced into the bottom portion of the wellbore in the
subterranean formation at a pressure sufficient to create or
enhance a bottom portion fracture therein and thereafter introduced
into the top portion of the wellbore in the subterranean formation
at a pressure sufficient to create or enhance a top portion
fracture therein. Next, the cement slurry is introduced first into
the top portion fracture and then into the bottom portion fracture.
The breakable gel fluid is introduced into the wellbore or lateral
wellbore so as to prevent the expandable cementitious material from
migrating out of the top portion fracture and bottom portion
fracture in the subterranean formation. The expandable cementitious
material is cured so as to form a cement pack, wherein the curing
of the expandable cementitious material expands the expandable
cementitious material such that at least one microfracture is
created within top portion fracture and the bottom portion fracture
in the subterranean formation and the breakable gel fluid is broken
and removed from the subterranean formation. In some embodiments,
the broken breakable gel fluid may be removed by circulating a base
fluid with or without the additives disclosed herein. In some
embodiments, the base fluid may be circulated using a hydrojetting
tool.
[0065] A hydrojetting tool may be used to create or enhance the top
and bottom fractures of the present invention and, when used, it
can be repositioned within the wellbore so as to sequentially
create fractures along the length of the wellbore. In some
embodiments, a hydrojetting tool is used to create a first fracture
at the bottom portion of the wellbore and is then repositioned
along the middle portion and up to the top portion of the wellbore
in order to create multiple fractures along the length of the
wellbore, ending with the top portion. In some embodiments, the
fractures are created through perforations or slots in the
subterranean formation. Any means of creating fractures in
subterranean formations known to those of ordinary skill in the art
may also be used with the methods of the present invention.
[0066] 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, combined,
or modified and all such variations are considered within the scope
and spirit of the present invention. The invention illustratively
disclosed herein suitably may be practiced in the absence of any
element that is not specifically disclosed herein and/or any
optional element disclosed herein. While compositions and methods
are described in terms of "comprising," "containing," or
"including" various components or steps, the compositions and
methods can also "consist essentially of" or "consist of" the
various components and steps. 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. Also, the terms in the claims have
their plain, ordinary meaning unless otherwise explicitly and
clearly defined by the patentee. 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. If there is any
conflict in the usages of a word or term in this specification and
one or more patent or other documents that may be incorporated
herein by reference, the definitions that are consistent with this
specification should be adopted.
* * * * *