Note: Descriptions are shown in the official language in which they were submitted.
CA 02907615 2016-12-01
APPLICATION FOR PATENT
INVENTORS: JAMES B. CREWS;
CHUNLOU LI
TITLE: METHOD OF INCREASING FRACTURE NETWORK
COMPLEXITY AND CONDUCTIVITY
SPECIFICATION
Field of the Disclosure
[0001] Fracture network complexity within a subterranean formation may be
created
by pumping a low viscosity fluid into the formation followed by a low
viscosity fluid
containing independent small masses of viscous material. Stimulated rock
volume (SRV)
of the formation is increased with the complex fracture network created in the
formation.
Background of the Disclosure
[0002] Hydraulic fracturing is widely used to create high-conductivity
communication
with a large area of a subterranean formation, thereby allowing for an
increased rate of oil
and gas production. The stimulation process enhances the permeability of the
formation
in order that entrapped oil or gas may be produced.
[0003] During hydraulic fracturing of ultra-low permeability formations
(i.e. such as
less than 0.1 md), a fracturing fluid is pumped at high pressures and at high
rates into the
wellbore penetrating the subterranean formation. During the process, fractures
may be
created and enlarged that increase the amount of fracture surface area. The
efficiency of
the process is often measured by stimulated rock volume (SRV) of the
formation.
[0004] Once the fracture is initiated, subsequent stages of viscous fluid
containing
chemical agents, such as proppants, may be pumped into the created fracture.
The
fracture generally continues to grow during pumping and the proppants remain
in the
fracture in the form of a permeable "pack" that serves to "prop" the fracture
open. Once
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the treatment is completed, the fracture closes onto the proppants. The
fracturing fluid
ultimately causes an increase in the leak-off rate of the fluid through the
faces of fractures
which improves the ability of the proppant to pack within the fracture. The
proppants
maintain the fracture open, for the purpose of providing a highly conductive
pathway for
hydrocarbons and/or other formation fluids to flow into the wellbore.
[0005] Typically, the treatment design of a hydraulic fracturing operation
requires the
fracturing fluid to reach maximum viscosity as it enters the fracture. The
viscosity of the
fluid affects fracture length and width. The viscosity of most fracturing
fluids may be
attributable to the presence of a viscosifying agent, such as a viscoelastic
surfactant or a
viscosifying polymer. After the viscosity of the fluid has been reduced,
complete
removal of the polymer is often difficult, often times resulting in residual
polymer being
left on the face of the formation and within the proppant pack. This causes
clogging of
the pores of the formation and proppant pack. Hydrocarbons may therefore be
prevented
from flowing freely through and from the formation.
[0006] The use of non-polymeric treatment fluids, such as those containing
viscoelastic surfactants, has increased in recent years since such fluids
typically exhibit
the ability to transport proppant at lower viscosities than polymer-based
treatment fluids.
In addition, the amount of friction between the surfactant-based treatment
fluid and the
surfaces contacted by the fluid is often reduced. Further, since such fluids
do not contain
polymers, use of internal breakers degrade viscous VES-micelles into non-
viscous
spherical-micelles and the clean breaking fluid is typically not obstructed as
it passes
through the pore throats of the formation and proppant pack.
[0007] Slickwater fluids typically do not contain a viscoelastic surfactant
or
viscosifying polymer but do contain a sufficient amount of a friction reducing
agent to
minimize tubular friction pressures. Typically, the presence of the friction
reduction
agent in slickwater does not increase the viscosity of the fluid by more than
1 to 2
centipoise (cP). Slickwater fluids may be pumped down the wellbore as fast as
100
bbl/min. to fracture the low permeability formation. Without using slickwater
the top
speed of pumping is around 60 bbl/min.
[0008] Slickwater fracturing operations typically proceed by the continuous
injection
of slickwater into the wellbore. In some shale formations, an excessively long
primary
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fracture often results along the minimum stress orientation. Typically, two
wings of the
fracture extend away from the wellbore in opposing directions according to the
natural
stresses within the formation. Typically, pumping of additional fracturing
fluid into the
wellbore simply extends the planar fracture. In most instances, primary
fractures
dominate and secondary fractures are limited. Fracturing treatments which
create
predominately long planar fractures are characterized by a low surface area,
i.e., low
SRV. Production of hydrocarbons from the fracturing network created by such
treatments is limited by the low SRV.
[0009] Slickwater fracturing more commonly in shale formations create complex
fracture networks near the wellbore and are generally considered to be
inefficient in the
opening or creation of complex network of fractures farther away from the
wellbore.
Lately, slickwater fracturing operations have been seen to be successful in
producing
hydrocarbons from shale. However, the secondary fractures created by the
operation are
near to the wellbore where the surface area is increased. While SRV is
increased in
slickwater fracturing, production is high only initially and then drops
rapidly to a lower
sustained production since there is little access to hydrocarbons far field
from the
wellbore.
[00010] Like slickwater fracturing, conventional fracturing operations
typically render
an undesirably lengthy primary fracture. While a greater number of secondary
fractures
may be created farther from the wellbore using viscous fluids versus
slickwater, fluid
inefficiency, principally exhibited by a reduced number of secondary fractures
generated
near the wellbore, is common in conventional hydraulic fracturing operations.
[00011] Recently, attention has been directed to alternatives for increasing
the
productivity of hydrocarbons far field from the wellbore as well as near
wellbore.
Particular attention has been focused on increasing the productivity of low
permeability
formations. For instance, methods have been tailored to the stimulation of
discrete
intervals along the horizontal wellbore resulting in perforation clusters.
While the SRV
of the formation is increased by such methods, production areas between the
clusters are
often not affected by the operation. This decreases the efficiency of the
stimulation
operation. Methods of increasing the SRV by increasing the distribution of the
area
subjected to fracturing have therefore been sought.
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[00012] It should be understood that the above-described discussion is
provided for
illustrative purposes only and is not intended to limit the scope or subject
matter of the
appended claims or those of any related patent application or patent. Thus,
none of the
appended claims or claims of any related application or patent should be
limited by the
above discussion or construed to address, include or exclude each or any of
the above-
cited features or disadvantages merely because of the mention thereof herein.
[00013] Accordingly, there exists a need for improved compositions, systems,
apparatus and methods useful for increasing the productivity of hydrocarbons
far field
from the wellbore as well as near wellbore especially in low permeability
formations
equipped with having one or more of the attributes or capabilities described
or shown in,
or as may be apparent from, the other portions of this patent.
Summary of the Disclosure
[00014] In an embodiment of the disclosure, a method of fracturing a
hydrocarbon-
bearing subterranean formation is provided in which the first stage comprises:
(a) pumping a first fluid into the formation at a pressure sufficient to
create or
enlarge a primary fracture;
(b) pumping a second fluid into the formation, wherein the second fluid
comprises the first fluid and a viscous material;
(c) creating or enlarging at least one secondary fracture having a
directional
orientation distinct from the directional orientation of the primary fracture
by diverting
the flow of the second fluid; and
(d) forming a complex fracture network by creating multiple fractures in
the
formation originating from the at least one secondary fracture.
[00015] In another embodiment, a method of fracturing a hydrocarbon-bearing
subterranean formation is provided in which the first stage comprises:
(A) pumping a first fluid of low viscosity into the formation at a pressure
sufficient to create or enlarge a primary fracture; and
(B) forming a complex fracture network comprising
(a) at least one secondary fracture having a directional
orientation
distinct from the directional orientation of the primary fracture; and
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(b) a multiple of fractures originating from the at least one
secondary
fracture and having a directional orientation distinct from the direction
orientation
of the at least one secondary fracture
wherein the complex fracture network is formed by pumping a second fluid into
the
formation, wherein the second fluid comprises (i) the first fluid of low
viscosity and (ii) a
plurality of discrete bodies having a viscosity greater than the viscosity of
the first fluid.
[00016] In another embodiment of the disclosure, a method of hydraulically
fracturing
a hydrocarbon-bearing subterranean formation is provided in which a first
stage
comprises:
(a) pumping a first fluid of low viscosity into the formation at a pressure
sufficient to create or enlarge a primary fracture;
(b) pumping a second fluid into the formation, wherein the second fluid is
prepared by adding to the first fluid a plurality of discrete bodies having a
viscosity
greater than the viscosity of the first fluid;
(c) creating or enlarging at least one secondary fracture having a
directional
orientation distinct from the directional orientation of the primary fracture
by diverting
the flow of the second fluid; and
(d) forming a complex fracture network through the addition of a diverting
fluid into the formation and creating multiple fractures in the formation
originating from
the at least one secondary fracture wherein the diverting fluid is prepared by
adding to the
first fluid a plurality of discrete bodies having a viscosity greater than the
viscosity of the
first fluid and wherein the multiple fractures are created by the action of
the plurality of
discrete bodies of viscous material in the diverting fluid.
[00017] In still another embodiment of the disclosure, a method of fracturing
a
hydrocarbon-bearing subterranean formation is provided in order to create a
complex
fracture network, wherein in a first stage, a first fluid and a second fluid
are pumped into
the formation, wherein the at least one second fluid is comprised of a viscous
material
and the first fluid, wherein:
(a) a primary fracture is created or enlarged by pumping into the
formation
the first fluid;
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(b) at least one secondary fracture perpendicular and/or orthogonal to the
primary fracture is created by diverting the flow of the at least one second
fluid; and
(c) a complex fracture network comprising a series of fractures is created
by
continuously diverting the flow of the at least one second fluid through the
formation
and further wherein either:
(0 the
surface area ratio (Sr), defined by Scf/Spf wherein Scf is the
surface area of the complex fracture network and Spf is the surface area
over the primary fracture, is greater when the first fluid and second fluid
are pumped into the formation versus when only the first fluid is pumped
into the formation; or
(ii) the
conductivity ratio (Cr) defined by Ccf/Cpf, wherein Ccf is the
conductivity of the complex fracture network and Cpf is the conductivity
of the planar fracture divided by 1000 is greater when the first fluid and
the at least one second fluid are pumped into the formation versus when
only the first fluid is pumped into the formation.
[00018]
Accordingly, the present disclosure includes features and advantages which
are believed to enable it to advance methods of fracturing. Characteristics
and
advantages of the present disclosure described above and additional features
and benefits
will be readily apparent to those skilled in the art upon consideration of the
following
detailed description of various embodiments and referring to the accompanying
drawings.
Brief Description of the Drawings
[00019] The following figures are part of the present specification, included
to
demonstrate certain aspects of various embodiments of this disclosure and
referenced in
the detailed description herein:
[00020] FIGS. la, lb, lc and id are schematic illustrations of how discrete
bodies of
higher viscosity material described herein may vary;
[00021] FIGS. 2a, 2b and 2c are schematic illustrations of discrete bodies of
higher
viscosity material having different materials contained therein;
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[00022] FIGS. 3a and 3b are schematic illustrations of how discrete bodies of
higher
viscosity material as described herein may be sized and formulated to generate
viscosity
under wall shear conditions in narrow fractures; and
[00023] FIG. 4 is a schematic illustration of possible choke points in within
a complex
fracture network.
Detailed Description of Embodiments
[00024] Characteristics and advantages of the present disclosure and
additional
features and benefits will be readily apparent to those skilled in the art
upon consideration
of the following detailed description of exemplary embodiments of the present
disclosure
and referring to the accompanying figures. It should be understood that the
description
herein and appended drawings, being of example embodiments, are not intended
to limit
the claims of this patent or any patent or patent application claiming
priority hereto. On
the contrary, the intention is to cover all modifications, equivalents and
alternatives
falling within the spirit and scope of the claims. Many changes may be made to
the
particular embodiments and details disclosed herein without departing from
such spirit
and scope.
[00025] In showing and describing embodiments in the appended figures, common
or
similar elements may be referenced with like or identical reference numerals
or are
apparent from the figures and/or the description herein. The figures are not
necessarily to
scale and certain features and certain views of the figures may be shown
exaggerated in
scale or in schematic in the interest of clarity and conciseness.
[00026] As used herein and throughout various portions (and headings) of this
patent
application, the terms "disclosure", "present disclosure" and variations
thereof are not
intended to mean every possible embodiment encompassed by this disclosure or
any
particular claim(s). Thus, the subject matter of each such reference should
not be
considered as necessary for, or part of, every embodiment hereof or of any
particular
claim(s) merely because of such reference.
[00027] Certain terms are used herein and in the appended claims to refer to
particular
elements and materials. As one skilled in the art will appreciate, different
persons may
refer to an element and material by different names. This document does not
intend to
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distinguish between elements or materials that differ in name. Also, the terms
"including" and "comprising" are used herein and in the appended claims in an
open-
ended fashion, and thus should be interpreted to mean "including, but not
limited to . . . ."
Further, reference herein and in the appended claims to elements and
components and
aspects in a singular tense does not necessarily limit the present disclosure
or appended
claims to only one such component, materials or aspect, but should be
interpreted
generally to mean one or more, as may be suitable and desirable in each
particular
instance.
[00028] The methods described herein may be used in the treatment of
conventional
rock formations such as carbonate formations (like limestone, chalk and
dolomite),
sandstone or siliceous substrate minerals, such as quartz, clay, shale, silt,
chert, zeolite, or
a combination thereof The methods have particular applicability in the
treatment of
unconventional hydrocarbon reservoir formations such as low permeability or
"tight"
formations, such as shale, tight sandstone and coal bed methane wells.
[00029] The methods described herein are especially effective with those
subterranean
reservoirs having a permeability less than or equal to 1.0 mD and most
especially those
subterranean reservoirs having a permeability less than or equal to 0.1 mD.
[00030] The disclosed method may consist of one or more stages. In one
embodiment,
a network of fractures may be created at near-wellbore and far-wellbore
locations in a
first stage.
[00031] The first stage comprises the pumping of a low viscosity fluid into
the
formation at a pressure which is sufficient to create or enlarge a primary
fracture. This
low viscosity fluid may be referred to as the "first fluid" of the first stage
of the fracturing
operation. The volume of first fluid pumped into the formation is selected in
order to
provide the desired length of the primary fracture. Thus, for instance, if the
primary
fracture is desired to be limited to 500 feet, the volume of low viscosity
fluid pumped
into the wellbore may be selected to provide the desired length of a 500 foot
primary
fracture.
[00032] The low viscosity fluid may be slickwater or a brine.
[00033] The low viscosity fluid may contain a friction reduction agent.
Suitable
friction reduction agents include polyacrylamides, polyacrylates, as well as
any of the
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viscoelastic surfactants described herein. When present, the amount of
friction reduction
agent in the first fluid is typically between from about 0.5 gallons per
thousand (gpt) to 2
gpt.
[00034] After the primary fracture is created (or a primary fracture within
the reservoir
is enlarged), one or more secondary fractures are created within the
formation. The
secondary fracture typically extends from the primary fracture and has a
directional
orientation which is distinct from the directional orientation of the primary
fracture.
[00035] The secondary fracture(s) are created by pumping into the formation a
second
fluid. The second fluid comprises the first fluid along with a viscous
material. The
viscosity of the second fluid is substantially the same as the viscosity of
the first fluid.
As such, the presence of the viscous material in the fluid does not
substantially affect the
viscosity of the second fluid. Thus, during fracturing, at the surface and
within the
wellbore the second fluid exhibits fluid properties like the low viscosity
(first) fluid.
[00036] Typically, a low loading of the viscous material is used in the second
fluid in
order that the viscosity of the second fluid and first fluid may be
substantially the same.
The low loading of the viscous material also minimizes residue and
conductivity damage.
Representative concentrations of the viscous material in the relatively low
viscosity (first)
fluid may range from about 0.1 vol% to about 20 vol%; alternatively range from
about
0.2% vol% to about 5 vol%; alternatively range from about 0.25 vol% to about 2
vol%.
Use of a viscous material in the low viscous fluid provides the second fluid
with the
initial properties of the low viscosity first fluid and higher viscosity
properties once it is
in select sections of the primary and secondary fractures.
[00037] In one non-limiting embodiment, the viscous material consists of
discontinuous masses or discrete bodies. Such discrete bodies may be prepared
by the
use of an extruder or die having a sizing cutter adapted to divide the viscous
material into
discrete bodies of a predetermined size such as that set forth in the U.S.
patent application
entitled "Method to Generate Diversion and Distribution For Unconventional
Fracturing
in Shale" by inventor James B. Crews, filed on an even date of the present
application,
and assigned U.S. patent application serial no. 14/225,526 filed on March 26,
2014.
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[00038] The size of the viscous material will typically vary depending on the
width
characteristic of the hydraulic fractures created within lower permeability
reservoirs. For
instance, the viscous material may have an average particle size from about
500 nm to
about 50 cm, in one non-limiting embodiment 500 nm to about 30 mm,
alternatively from
about 1 gm to about 4 mm, and in another non-limiting embodiment about 10 gm
to
about 1 mm.
[00039] During pumping, the viscous material effectively retains its size and
shape
within the second fluid and appears as discrete tiny masses with near zero
shear rate
viscosity in the low viscosity fluid. The tiny high viscosity material in the
second fluid,
in one non-limiting embodiment, is thus highly elastic and deformable and
resists fluid-
shear-induced fragmentation during pumping. Depending on the size of the
viscous
material, the second fluid may behave like the first fluid as it flows into
and through the
initial portion of the primary fracture. Once the second fluid is within a
section of the
primary fracture which has a width similar to or smaller than the viscous
material, such as
the primary fracture width 500' from the wellbore, the second fluid will
change its flow
properties (i.e. during viscous material interaction with the fracture walls)
and be diverted
from the primary fracture. Initiation and extension of one or more secondary
fractures
can then occur off of the primary fracture, preferably initially far-field.
Changes to any
of the size, shape, viscosity, or other parameters of the viscous material as
well as a
change in the pumping rate of the second fluid may allow flow of the second
fluid into
secondary fractures. Then, like within the primary fracture, when the high
viscosity
masses encounter fracture widths similar to or less than the size of the
viscous material,
due to the parameters of the viscous material and interaction with the
fracture walls the
flow properties of the second fluid will change and flow may be diverted from
one or
more of the secondary fractures.
[00040] Pumping of the second fluid into the formation may be suspended for a
sufficient time to allow the fluid to be diverted away from the primary
fracture.
[00041] By controlling the viscosity and shear sensitivity of the viscous
material,
frictional interaction of the viscous material with the walls of narrow
fractures may cause
the second fluid to transition from a low viscosity fluid flow (brine or
slickwater) to a
combination of low viscosity fluid flow (brine or slickwater) and discrete
viscous
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material having fracture wall interaction properties flow (i.e. dual-fluid;
brine fluid
having little interaction with fracture walls and discrete viscous fluid
masses with viscous
interaction with fracture walls). Once the second fluid interacts with narrow
hydraulic
fractures the flow induces performance properties and processes such as a)
path of least
resistance flow deviation; b) lodging of viscous material in the fracture that
reduces but
does not totally eliminate treatment fluid flow; (c) total fluid diversion;
(d) in situ wall-
shear induced fluid viscosity generation (i.e. less elastic and more
deformable discrete
viscous masses that shear thins in viscosity into a somewhat flowable,
discrete fluid mass
in the narrow fracture and thereby becoming flattened, like a pancake, and
take up greater
area in the narrow fracture); and (e) distribution of delayed released
treatment additives
can be engineered (once viscous masses internally break in viscosity). Most of
these
processes (i.e., partial diversion, path of least resistance flow alteration,
complete flow
diversion, etc.) will induce increased hydraulic fluid pressure (i.e. within
the fracture
where interactions are occurring). The increase in fluid pressure in the
fracture may: a)
reduce flow of the second fluid in the fracture; b) increase fracture width
(build-up of
fluid pressure in fracture does not divert fluid instantly but may open
fracture wider), c)
alter fracture extension (as fracture width builds fracture length can grow),
and d)
eventually the build-up of pressure in the fracture will overcome the
anisotropy rock
stress to initiate and propagate new fracture(s). Fracture network complexity
therefore
results.
[00042] Successive generated fractures may be created as an inherent
characteristic of
use of the second fluid as diverting fluid. Such additional fractures may then
be created
which originate from the secondary fracture(s). For instance, a tertiary
fracture may be
created by pumping the second fluid at a pressure which is sufficient for the
fluid to be
diverted away from the secondary fracture. A quaternary fracture may be
created by
pumping the second fluid at a pressure which is sufficient for the fluid to be
diverted
away from the tertiary fracture, and so on. Changes to the size, shape,
viscosity and the
like of the discrete tiny masses, and the type of interaction they exhibit
with the walls of
the fracture, play an important function in ability to induce diversion of the
second fluid
and the number of diversions within successive fractures. The tertiary,
quaternary,
quintary fractures and so on all originate from the creation of the secondary
fractures.
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Each of the fractures originating from secondary fractures typically has a
directional
orientation distinct from the direction orientation of the fracture from which
it extends.
Thus, a tertiary fracture originating from a secondary fracture typically has
a directional
orientation distinct from the direction orientation of the secondary fracture;
the
quaternary fracture stemming from the tertiary fracture (originating from the
secondary
fracture) typically has a directional orientation distinct from the tertiary
fracture; the
quintary fracture stemming from the quaternary fracture (originating from the
secondary
fracture) has a directional orientation distinct from the quaternary fracture
and so on.
[00043] Such additional fractures will be referred to herein as the
"successive fracture"
and the "penultimate fracture" to refer to the latter and next to latter
fractures,
respectively, wherein the fracture created from a successive stage has a
directional
orientation distinct from that of the fracture created from a penultimate
stage. For
example, where a tertiary fracture is created which extends from a secondary
fracture, the
tertiary fracture may be referred to as the "successive fracture" and the
second fracture
(extending from the primary fracture) as the "penultimate fracture." Where a
quaternary
fracture is created, the quaternary fracture stage may be referred to as the
"successive
fracture" and the tertiary fracture may be referred to as the "penultimate
fracture," etc.
Where a fracturing operation consists of the creation of multiple fractures,
the fracture
created from the pumping of a second fluid shall be referred to as a
"secondary fracture".
[00044] In some cases, the second fluid and the diverting fluid used in the
creation or
enlargement of successive and penultimate fractures may be the same. The
fluids may
differ by varying the factors which are described herein. However, for
simplicity, the
fluid pumped into the formation to create such successive fractures and
penultimate
fractures shall only be referred to as the "second fluid" since the fluid will
be comprised of
the low viscosity (first) fluid and the viscous material. Certain
characteristics of the
viscous material may be optimized in order to create the multiple fractures
defining the
complex fracture network. In other words, the first stage of the disclosed
method
designed to render the complex fracture network may be monitored and tailored
such that
the fluid creating the fracture(s) is targeted to maximize the amount of fluid
used in order
to render the desired fracture.
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[00045] As an example, during the first stage, the viscous material within the
second
fluid may be varied, depending on the desired fracture length, width and level
of
conductivity, by 1) viscosity; 2) low shear rate elasticity; 3) size; 4)
shape; 5)
combination of sizes and/or shapes; 6) concentration to first fluid; 7)
composition and
density of the first fluid; and 8) inclusion of treatment materials within the
viscous
material (such as proppant, cleanup agent, clay control agent, breaker,
tracer, and the
like).
[00046] Thus, during the first stage where the complex fracture network is
created, more
than one viscous material may vary in viscosity, composition, density,
content, size,
shape, concentration in the brine, and the like, for providing more
versatility or wider
range of fracture interaction. In one non-limiting example, larger size,
higher
concentration and more viscous material may be used to produce a second fluid
for
improving treatment fluid diversion from the primary fracture, where a second
viscous
material could produce a second fluid better suited for fluid diversion within
narrow
secondary fractures, and a third viscous material could be used to produce a
second fluid
better suited (i.e. smaller in size, less elastic and more deformable, and
contain smaller
proppant) for creating a successive fracture(s).
[00047] Control of conditions to create the complex fracture network such as
varying
the size of the viscous material, the shape of the viscous material and/or the
concentration
of the viscous material within the second fluid may be effectuated by use of
an extruder
or dye on the fly. Such extruders and dies include those known in the art
including those
described in the patent application entitled "Method to Generate Diversion and
Distribution For Unconventional Fracturing in Shale" by James B. Crews, filed
on an
even date of the present application. Thus, the method disclosed herein may
provide for
a more efficient use of on-the-fly equipment and materials.
[00048] The multiple fractures created by diversion of the second fluid
through the
formation form a complex fracture network exhibiting an increase in SRV.
[00049] Further in a non-limiting embodiment, the surface area ratio (Sr),
defined by
Scf/Spf wherein Scf is the surface area of the complex fracture network and
Spf is the
surface area over the primary fracture, has been noted to be greater when the
first fluid
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and second fluid are pumped into the formation versus when only the first
fluid is
pumped into the formation.
[00050] The viscous material comprising the second fluid may be a hydratable
polymer such as, for example, one or more polysaccharides capable of forming
linear or
crosslinked gels. These include galactomannan gums, guars, derivatized guars,
cellulose
and cellulose derivatives, starch, starch derivatives, xanthan, derivatized
xanthan and
mixtures thereof.
[00051] Specific examples include, but are not limited to, guar gum, guar gum
derivative, locust bean gum, welan gum, karaya gum, xanthan gum, scleroglucan,
diutan,
cellulose and cellulose derivatives, etc. More typical polymers or gelling
agents include
guar gum, hydroxypropyl guar (HPG), carboxymethyl hydroxypropyl guar (CMHPG),
hydroxyethyl cellulose (HEC), carboxymethyl hydroxyethyl cellulose (CM NEC),
carboxymethyl cellulose (CMC), dialkyl carboxymethyl cellulose, etc. Other
examples
of polymers include, but are not limited to, polyacrylamides,
polyvinylacetates,
copolymers, terpolymers, phosphomannans, scleroglucans and dextrans.
[00052] The fluid containing the viscosifying polymer may further include a
crosslinking agent.
[00053] Any crosslinking agent suitable for crosslinking the hydratable
polymer may
be employed. Examples of suitable crosslinking agents include metal ions such
as
aluminum, antimony, zirconium and titanium-containing compounds, including
organotitanates. Examples of suitable crosslinkers may also be found in U.S.
Pat. No.
5,201,370; U.S. Pat. No. 5,514,309, U.S. Pat. No. 5,247,995, U.S. Pat. No.
5,562,160,
and U.S. Patent No. 6,110,875. Further examples of crosslinking agents are
borate-based
crosslinkers such as organo-borates, mono-borates, poly-borates, mineral
borates, etc.
Organic crosslinkers known to the art may also be utilized.
[00054] In an embodiment, the viscosifying agent is non-polymeric such as a
viscoelastic surfactant. The viscoelastic surfactant suitable for use as the
viscosifying
agent may be micellular, such as worm-like micelles, surfactant aggregations
or vesicles,
lamellar micelles, etc. Such micelles include those set forth in U.S. Patent
No.
6,491,099; 6,435,277; 6,410, 489; and 7,115,546.
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[00055] Suitable viscoelastic surfactants include cationic, amphoteric and
anionic
surfactants. Suitable cationic surfactants include those having only a single
cationic
group which may be of any charge state (e.g., the cationic group may have a
single
positive charge or two positive charges). The cationic group preferably is a
quaternary
ammonium moiety (such as a linear quaternary amine, a benzyl quaternary amine
or a
quaternary ammonium halide), a quaternary sulfonium moiety or a quaternary
phosphonium moiety or mixtures thereof. Preferably the quaternary group is
quaternary
ammonium halide or quaternary amine, most preferably, the cationic group is
quaternary
ammonium chloride or a quaternary ammonium bromide.
[00056] The amphoteric surfactant preferably contains a single cationic group.
The
cationic group of the amphoteric surfactant is preferably the same as those
listed in the
paragraph above. The amphoteric surfactant may be one or more of glycinates,
amphoacetates, propionates, betaines, amine oxides, and mixtures thereof
Preferably,
the amphoteric surfactant is a glycinate, amine oxide or a betaine and, most
preferably,
the amphoteric surfactant is a linear glycinate, alkylaminopropyl amine oxide,
or a linear
betaine .
[00057] The cationic or amphoteric surfactant has a hydrophobic tail (which
may be
saturated or unsaturated). Preferably the tail has a carbon chain length from
about C12-
C18. Preferably, the hydrophobic tail is obtained from a natural oil from
plants, such as
one or more of coconut oil, soybean oil, rapeseed oil and palm oil. Exemplary
of
surfactants include N,N,N trimethyl- 1 -octadecammonium chloride: N,N,N
trimethyl- 1 -
hexadecammonium chloride; and N,N,N trimethyl-l-soyaammonium chloride, and
mixtures thereof
[00058] Exemplary of anionic surfactants are sulfonates, phosphonates,
ethoxysulfates
and mixtures thereof Preferably the anionic surfactant is a sulfonate. Most
preferably
the anionic surfactant is a sulfonate such as sodium xylene sulfonate and
sodium
naphthalene sulfonate.
[00059] In one embodiment, a mixture of surfactants are utilized to produce a
mixture
of (1) a first surfactant that is one or more cationic and/or amphoteric
surfactants set forth
above and (2) at least one anionic surfactant set forth above.
[00060] A mixture of any of the aforementioned viscous materials may also be
used.
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[00061] While the viscosity of the second fluid and first fluid may be
substantially the
same, the viscous material is at least 1,000 times more viscous than the first
fluid, and
typically is more than 100,000 times more viscous than the first fluid at 0.01
sec-1 shear
rate at 80 F (27 C). The ratio in viscosity (measured at 0.01 sec-1 and 80 F
((27 C)), Vr,
of the viscous material to the first fluid may be designed to achieve the
fracturing and
production purposes of the methods described herein. In one non-limiting
embodiment,
for example, Vr is 100 or greater, in one non-limiting embodiment 1000 or
greater,
alternatively is 10,000 or greater, and in a different non-limiting embodiment
is 100,000
or greater.
[00062] The integrity of the viscous material to retain its size and shape
during shear
when being pumped downhole may be dependent on the viscosity, size, shape,
density
and other properties of the viscous material. While the viscous material may
be of larger
sizes fluid diversion in fairly wide fracture widths; small sizes are
preferred within very
narrow fracture widths.
[00063] Shown in FIGS. la, lb, lc and id are schematic illustrations of the
discrete
bodies of viscous material which may vary one to the other. FIG. la shows that
discrete
bodies may have different average particle sizes. FIG. lb schematically
illustrates that
discrete bodies may have different viscosities, where the heavier the shading,
the greater
the viscosity. FIG. lc schematically illustrates how discrete bodies may be of
different
shapes, for instance a spherical shape shown at the top; to bent round rods or
pins shapes,
second; to straighter round rods or pins shapes, third; and long-aspect
rectangles (for
instance, a "french fry"-like shape), or discs of varying thickness (for
instance, flattened
spheres or egg-shapes) shapes, fourth. In some cases, some shapes may work
better than
others at holding their shape in different applications, or may function
better than others
for certain purposes, e.g. distributing proppants or enclosed additives. FIG.
1 d
schematically illustrates how different shapes may contain various other
materials. It will
be appreciated that these various characteristics may be combined with each
other so that
discrete bodies may be customized for a particular application.
[00064] The first fluid or second fluid may also contain other conventional
additives
common to the well service industry such as surfactants, biocides, gelling
agents, cross-
linking agents, curable resins, hardening agents, solvents, foaming agents,
demulsifiers,
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buffers, clay stabilizers, acids, or mixtures thereof Other additives may
include, but are
not necessarily limited to, piezoelectric particles, metal particles, metal
complexes, metal
salts, fines control agents, solid acids, solid high pH buffers, salts,
chelants, oxidizers,
plant and fish oils, mineral oils, shape memory polymers, fibers, glass
spheres,
encapsulations and combinations thereof
[00065] In an embodiment, illustrated in FIG. 2a, discrete bodies 10 may
include
spherical encapsulant 12 containing a treatment agent. FIG. 2b illustrates
discrete body
14 containing a dispersed or soluble treatment agent 16. The treatment agent
may
include, but not be limited to, biocides, tracers, proppants, self-assembling
nanocoating
agents for modifying fracture face properties, surfactants, scale inhibitors,
asphaltene
inhibitors, hydrogen sulfide scavengers, polymer breakers, VES breakers,
microemulsions to improve treatment fluid cleanup, other treatment fluid
cleanup agents,
fines migration control additives, fines migration control nanoparticles,
fracture imaging
materials (diagnostic agents that interact with signals and sensors), delayed
release
additives and combinations thereof. For instance, one type of nanocoating
agent may be
surface-modifying agents to introduce hydrophobicity and/or oleophobicity to
the
fracture surfaces. In a preferred though non-limiting embodiment, the second
fluid may
contain an internal viscosity breaker to enable the viscous material to break
at targeted
locations within the formation under downhole conditions. In an embodiment,
spherical
encapsulant 12 as well as treatment agent 16 may be blended into the viscous
material in
the device reservoir prior to being extruded through a conduit into discrete
bodies 10.
[00066] The second fluid may further contain proppant. FIG. 2c illustrates
discrete
body 18 containing dispersed proppant particles 20.
[00067] The viscous materials disclosed herein are effective in promoting
distribution
of proppants in complex fracture networks. Particularly by wedging or
elongating and/or
flattening within the complex fractures to lodge the proppant particles in
place, such as
small unconventional proppants designed to create transitional nanodarcy to
microdarcy
to millidarcy conductivity in the narrow secondary, tertiary, quaternary, and
the like
complex fractures that typically remain unpropped due to the size and use of
only
conventional proppants like 20/40 and 30/70 mesh sand and ceramic proppants.
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[00068] In an embodiment, the proppant having an apparent specific gravity
(ASG)
less than or equal to 2.25, more preferably less than or equal to 2.0, even
more preferably
less than or equal to 1.75, most preferably less than or equal to 1.25 and
often less than or
equal to 1.05.
[00069] The proppant may further be a resin coated ceramic proppant or a
synthetic
organic particle such as nylon pellets, ceramics. Suitable proppants further
include those
set forth in U.S. Patent Publication No. 2007/0209795 and U.S. Patent
Publication No.
2007/0209794. The proppant may further be a plastic or a plastic composite
such as a
thermoplastic or thermoplastic composite or a resin or an aggregate containing
a binder.
Other suitable relatively lightweight proppants are those particulates
disclosed in U.S.
Patent Nos. 6,364,018, 6,330,916 and 6,059,034. These may be exemplified by
ground
or crushed shells of nuts (pecan, almond, ivory nut, brazil nut, macadamia
nut, etc);
ground or crushed seed shells (including fruit pits) of seeds of fruits such
as plum, peach,
cherry, apricot, etc.; ground or crushed seed shells of other plants such as
maize (e.g.
corn cobs or corn kernels), etc.; processed wood materials such as those
derived from
woods such as oak, hickory, walnut, poplar, mahogany, etc. including such
woods that
have been processed by grinding, chipping, or other form of particalization.
Preferred are
ground or crushed walnut shell materials coated with a resin to substantially
protect and
water proof the shell. Such materials may have an ASG of from about 1.25 to
about 1.35.
Further, lightweight particulate may be a selectively configured porous
particulate, as set
forth, illustrated and defined in U.S. Patent No. 7,426,961.
[00070] The proppants for use in the second fluid most preferably have an ASG
between from about 0.9 to about 1.8, and most preferably from about 1.0 to
about 1.2.
The smaller size will depend on the complex fracture widths for the particular
lithology
that is hydraulically fracture treated. In some cases, such proppants will be
less than 1
mm but larger than 10 microns in size.
[00071] Conventional proppants, such as sand, quartz, ceramics, silica, glass
and
bauxite, may be used and are more typically used for wider complex fractures
and planar
fracture to provide millidarcy to macrodarcy fracture conductivities.
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[00072] Conductivity of the primary fracture may be enhanced by pumping into
the
formation a second stage. The viscosity of the second stage fluid(s) is
generally greater
than the viscosity of first fluid or second fluid. Typically, the viscosity of
the second
stage fluid(s) is greater than 10 cps at 80 F at 100 sec-1. In some
circumstances, the fluid
of the second stage may be the same as the first fluid of the first stage.
[00073] The second stage fluid(s) may contain any of the viscosifying polymers
or
viscoelastic surfactants referenced in the paragraphs above. Thus, the second
stage
fluid(s) may contain of the aforementioned linear polymers, crosslinked
polymers,
viscoelastic surfactants, as well as combinations thereof
[00074] Further, the second stage fluid(s) may contain a proppant. Suitable
proppant
may include any of the proppants referenced in the paragraphs above include
conventional heavier proppants such as sand, bauxite, glass, etc. as well as
lightweight
proppants having an ASG less than 2.45.
[00075] In some embodiments, selection of proppant is designed in order to
form a
partial monolayer of proppant within created or enlarged fracture(s).
[00076] Fracture conductivity may be enhanced with any created or enlarged
fracture(s) by varying the size of the proppant within the first fluid or
second fluid; the
apparent specific gravity of the proppant within the first fluid or second
fluid; or the
shape of the proppant within the first fluid or second fluid.
[00077] Depending on the formation being treated, all or part of the second
stage fluid
may be pumped into the formation prior to pumping of the first fluid, prior or
after
pumping of the first fluid but prior to pumping of the second fluid of the
first stage.
[00078] The method of the disclosure further helps in the creation of a
transition of
propped fracture conductivity from the fracture tip to the wellbore, starting
with
nanodarcy permeabilities at the fracture tips, to microdarcy permeabilities in
the
complex, secondary fractures to millidarcy to darcy permeabilities near the
primary
fracture, then to darcy to macrodarcy permeabilities within the primary
propped fracture.
Such transitional fracture conductivity and the control of conductivity within
the complex
fracture network may be attributable to the presence of the viscous material
in the
pumped fluid coupled with proppant placement and distribution within the
fractures.
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[00079] In non-limiting embodiment, the conductivity ratio (Cr) defined by
Ccf/Cpf,
wherein Ccf is the conductivity of the complex fracture network and Cpf is the
conductivity of the planar fracture divided by 1000, has been noted to be is
greater when
the first fluid and the at least one second fluid are pumped into the
formation versus when
only the first fluid is pumped into the formation.
[00080] Referring to FIG. 3a viscous material 20 within second fluid 18 is
shown
entering fracture 22. As the width of the fracture 22 narrows viscous material
20
interacts with the fracture walls. Viscous material 20 is illustrated as
masses of discrete
bodies. FIG. 3b illustrates examples of specific type of discrete bodies 20a
that may
more easily deform in the narrow fracture region of fracture 22. The
deformation of
bodies 20a are by interaction with the walls of fracture 22, where the shear
force
relatively thins the viscosity of bodies 20a. The more they shear thin and
deform the
more fluid-like bodies 20a become. Depending on their initial viscosity and
fracture
wall-induced shear thinning properties, bodies 20a become discrete viscous
fluid bodies
26 that occupy greater fracture surface area within the narrow region of
fracture 22, as
represented by viscous deformed masses 26. Viscous deformed masses 26
represent the
adaptive properties of high viscosity bodies 20a, where they can be
transformed or
modified in situ into discrete viscous fracturing fluid masses.
[00081] The ability to transform viscous material 20a into viscous fluid
masses 26
promotes unique hydraulic pressure with the first fluid within the fracture
22, generating
a combined second fluid hydraulic pressure medium to slow and eventually
prevent
further fracture growth and the restrictive flow pressure will initiate a new
fracture and
create fluid diversion. Additionally, viscous fluid masses 26 can occupy
greater fracture
surface area the deeper masses 26 penetrate. When the masses of the discrete
bodies 20a
contain proppant and create greater fracture surface area masses 26 they will
thus create
channel-type conductivity, as illustrated in FIG. 3b.
[00082] As further schematically illustrated in FIG. 5b, viscous gel bodies
20a
generate viscosity only in very narrow fractures. Narrow fractures may be
defined as less
than 1 mm wide, and may range from about 1 gm (micrometer) up to 1 mm. The
typical
range where viscous gel bodies 20a generate viscosity and form high fracture
surface area
fluid masses 26 will be from 0.5 mm to 0.02 mm, in one non-limiting example.
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relatively wider fracture widths, discrete bodies 26 will retain their shapes
as shown in
the left side of FIG. 3b. However, for very narrow fracture widths, as at the
bottom of
fracture 22 in FIG. 3a, and the right side of FIG. 3b, discrete bodies 20a may
form wall-
shear deformed discrete fluid masses 26 and generate viscosity in second fluid
18 as well
as provide the diverting function. Thus, where bodies 20a are wedged in the
tip of
fracture 22, they will shear thin and optimize to the local fluid pressure
conditions for
limiting fracture growth and preferentially induce a new fracture off of
fracture 22.
[00083] Conductivity limited "choke points" may also be reduced by the viscous
material and proppant retained at restrictive flow locations in the complex
fracture
network during the treatment. The method thus provides greater versatility in
treatment
design, control and results than methods practiced previously.
[00084] FIG. 4 is a schematic illustration of possible choke points in a
complex
fracture network having a wellbore 30 from which extends a primary, propped
fracture
32, and a plurality of more complex, unpropped fractures 34. The extent of SRV
is
illustrated. The value Xpf is the half-length of primary fracture 32, which is
a bilength of
the total fracture since a biwing (not shown) extends from wellbore 30 on the
opposite
side. The value dr is the distance between unpropped fractures 34 and Lsf is
the length of
the secondary fractures extending from primary fracture 32. Potential
conductivity choke
points 36 are the locations in the fracture network having insufficient
fracture
conductivity. Such choke points restrict the rate of flow of hydrocarbons. The
incidence
and/or extent of conductivity choke points 36 may be reduced by viscous
material 20
which may contain proppant and which are retained at such restrictive flow
locations in
the complex fracture network. The ability to pinpoint placement of proppant by
selectively sized viscous material within the second fluid that become wedged
at such
locations will prevent or greatly reduce the lack of propped fracture
conductivity at these
locations.
[00085] Numerous advantages have been noted by used of the disclosed method to
create a complex fracture network. Such advantages may be attributable to the
fact that
(i) the viscosity of the second fluid of the first stage is more adept than
the conventional
fluids such as slickwater and viscous crosslinked polymer systems for creating
complex
fracture networks; (ii) the second fluid containing the viscous material
exhibits brine-like
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viscosity from the surface to the fractures; (iii) the ability to target
deeper and more
narrower fracture regions before the viscous material interacts with the
fracture walls;
(iv) the promotion by the second fluid of increased hydraulic pressure during
flow only
within narrow width fractures; (v) the promotion by the second fluid of
pressure-initiated
fractures; vi) the ability of the second fluid with the defined viscous
material to create
deeper fluid diversion and fracture complexity; and (vi) the ability to target
and engineer
placement treatment additives deeper within the complex fractures.
[00086] Embodiments of the present disclosure thus offer advantages over the
prior art
and are well adapted to carry out one or more of the objects of this
disclosure. However,
the present disclosure does not require each of the components and acts
described above
and are in no way limited to the above-described embodiments or methods of
operation.
Any one or more of the above components, features and processes may be
employed in
any suitable configuration without inclusion of other such components,
features and
processes. Moreover, the present disclosure includes additional features,
capabilities,
functions, methods, uses and applications that have not been specifically
addressed herein
but are, or will become, apparent from the description herein, the appended
drawings and
claims.
[00087] The methods that may be described above or claimed herein and any
other
methods which may fall within the scope of the appended claims can be
performed in any
desired suitable order and are not necessarily limited to any sequence
described herein or
as may be listed in the appended claims. Further, the methods of the present
disclosure
do not necessarily require use of the particular embodiments shown and
described herein,
but are equally applicable with any other suitable structure, form and
configuration of
components.
[00088] While exemplary embodiments of the disclosure have been shown and
described, many variations, modifications and/or changes of the system,
apparatus and
methods of the present disclosure, such as in the components, details of
construction and
operation, arrangement of parts and/or methods of use, are possible,
contemplated by the
patent applicant(s), within the scope of the appended claims, and may be made
and used
by one of ordinary skill in the art without departing from the spirit or
teachings of the
disclosure and scope of appended claims. Thus, all matter herein set forth or
shown in
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the accompanying drawings should be interpreted as illustrative, and the scope
of the
disclosure and the appended claims should not be limited to the embodiments
described
and shown herein.
23
