Note: Descriptions are shown in the official language in which they were submitted.
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SYSTEM AND METHOD OF TREATING A SUBTERRANEAN FORMATION
BACKGROUND
[0001] The list of diverting techniques used in wellbores includes, but
is not limited
to, mechanical isolation devices such as packers and well bore plugs, bridge
plugs,
ball sealers, slurried solids such as benzoic acid flakes and removable and/or
degradable particulates. For example, the hydraulic and acid fracturing of
horizontal
wells as well as multi-layered formations frequently require the use of
diversion
techniques to direct the fracturing fluid between different zones.
[0002] Treatment diversion with particulates may be based on the bridging
of
particles of the diverting material, e.g., behind casing, and forming a plug
by
accumulating additional particles at the formed bridge. Several problems are
related to
treatment diversion with particulate materials. One problem is that a
precisely timed
delivery of a relatively high concentration "pill" for diversion in a
relatively small
volume of treatment fluid for a very short period of time is difficult using
standard
surface pumping and mixing equipment, that is designed to supply typically low
concentrations solids or proppants delivered in large fluid volumes at
relatively high
flow rates and high pressures for extended periods of time to deliver the
proppant to
the far reaches of an extensive fracture network. For example, tons of
proppant may
be delivered at 0.12 ¨0.18 g/L, based on the volume of carrier fluid (1-1.5
ppa or
pounds of proppant added per gallon of carrier fluid) over a period of several
hours,
whereas the diversion slurry may require delivery, in less than a minute,
orders of
magnitude more solids, e.g., about 10 g/L.
[0003] Additionally, any interruption of the continuous injection of
treatment fluid
can result in proppant or other solids falling out of suspension and possibly
forming a
bridge in an undesired location, leading to a failure of the fracture
operation and
prematurely terminating the fracturing treatment. Therefore, care must be
taken in
making any changes to the treatment fluid so as to avoid an undesirable
interruption
of pumping of the treatment fluid in a continuous manner.
[0004] As another consideration, dilution of the diverting slurry with
other wellbore
fluid during pumping, e.g., via interface mixing, reduces the ability of the
diverting
slurry to form a bridge and/or plug and effect diversion to another downhole
flow
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feature. The necessity of using relatively large amounts and/or high
concentrations of
diverting materials to effect diversion imposes economic and logistic
constraints, as
well as difficulties with over-diversion to undesired downhole features and
removal of
excessive diverting material. The poor stability of some diverting agents
during either
pumping and/or the subsequent treatment stage can lead to poor diversion
efficiency.
[0005] It can be a challenge to achieve the relatively high content of a
diverting
agent within a diversion slurry of treatment fluid, that is generally used for
plugging
or diverting a downhole feature with solid diverting materials to form
temporary
bridges or plugs, such as a total amount of fibers and/or other shaped
particles of from
about 2.4 g/L (20 lbs/1000 gal) to about 180 g/L (1500 lbs/1000 gal. The
ability to
add a briefly high concentration of solid in a continuous manner for a short
period of
time with traditional low concentration solid feeders, which are limited in
their
feeding rates, as well as how quickly the feeding rate can be adjusted, is
difficult.
Because the treatment fluid, including both the fracturing fluid and the
diversion
slurry, is to be injected at a high rate, typically 132 L/s (50 bbl/min) or
more, and at a
high pressure, e.g., 6.9 MPa (1000 psi) to 140 MPa (20,000 psi) or more, the
rate of
addition of the diverting agent should be substantial enough to create a
stream of high
concentration solid material. Solid material may be in the form of
manufactured
shapes such as flakes, fibers and particles. The traditional methods of adding
solid
material cannot easily achieve a rapid injection of high concentrations of
diverting
agent so as to achieve a suitable stream, and when such methods are repeated
during
the treatment of the well, errors may be compounded.
SUMMARY
[0006] This summary is provided to introduce a selection of concepts that
are
further described below in the detailed description. This summary is not
intended to
identify key or essential features of the claimed subject matter, nor is it
intended to be
used as an aid in limiting the scope of the claimed subject matter. The
statements
made merely provide information relating to the present disclosure, and may
describe
some embodiments illustrating the subject matter of this application.
[0007] In aspects, methods for injecting a diverting composition may
include
transporting a diluted fluid stream to a high pressure flow line, transporting
a high-
loading stream to the high pressure flow line, combining the diluted fluid
stream and
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the high-loading stream to form a diverting composition, and introducing the
diverting
composition into the wellbore.
[0008] In further aspects, systems for injecting a diverting composition
are
envisaged. The systems may include at least one diluted fluid device that
transports a
diluted fluid stream to a high pressure flow line, and at least one high-
loading device
that transports a high-loading stream to the high pressure flow line. The
diluted fluid
stream and the high-loading stream may be combined to form a diverting
composition,
and the diverting composition may be introduced into the wellbore.
[0009] In further aspects, methods are disclosed. The methods may be for
pumping
a diverting composition. The methods may include pumping a diluted fluid
stream to
a high pressure flow line, pumping a high-loading stream to the high pressure
flow
line, combining the diluted fluid stream and the high-loading stream to form a
diverting composition, and introducing the diverting composition into the
wellbore.
The diluted fluid stream may include a first amount of degradable fibers, a
viscosifying agent and water. The high-loading stream may include a second
amount
of degradable fibers, particles, and water.
[0010] In yet further aspects, treatment methods may comprise introducing
a diluted
stream, comprising a non-bridging amount of carrier fibers in a low viscosity
carrier
fluid, into a high pressure flow line; adding proppant to the diluted stream
to form a
proppant-laden stream; injecting the proppant-laden stream from the high
pressure
flow line into a first fracture; introducing a high-loading stream, comprising
a
diverting agent, into the high pressure flow line to combine with the diluted
stream to
form a diversion slurry; delivering the diversion slurry from the high
pressure flow
line to the first fracture to divert fluid flow to a second fracture; and
injecting the
proppant-laden stream from the high pressure flow line into the second
fracture.
[0011] In still further aspects, treatment methods may comprise
introducing a
diluted stream, comprising a non-bridging amount of carrier fibers, from a
diluted
fluid device to a high pressure flow line; introducing a high-loading stream,
comprising a mix of bridging fibers and manufactured shape particles, from a
high-
loading fluid device to the high pressure flow line; combining the diluted
stream and
the high-loading stream to form a diversion slurry; and delivering the
diversion slurry
from the high pressure flow line to a downhole fluid flow feature to divert
fluid flow
from the downhole fluid flow feature to an alternate flow path.
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[0012] Yet further aspects comprise treatment methods comprising
injecting a
treatment fluid through a high pressure flow line into the subterranean
formation to
form a hydraulic fracture system, wherein the treatment fluid comprises: a low
viscosity carrier fluid having a viscosity less than 50 mPa-s at a shear rate
of 170 s-1
and a temperature of 25 C, proppant dispersed in the carrier fluid, and
carrier fiber
dispersed in the carrier fluid; maintaining a rate of the injection of the
treatment fluid
to avoid bridging in the wellbore; introducing a diluted stream, comprising a
non-
bridging amount of the carrier fibers and optionally free of the proppant, to
the high
pressure flow line; introducing a high-loading stream, comprising a mix of
bridging
fibers and manufactured shape particles, to the high pressure flow line;
combining the
diluted stream and the high-loading stream to form a diversion slurry;
delivering the
diversion slurry from the high pressure flow line to the hydraulic fracture
system to
divert fluid flow from one fracture to another.
[0013] Aspects pertain to systems for injecting a treatment fluid,
comprising at least
one diluted fluid device that transports a diluted stream to a high pressure
flow line; at
least one high-loading device that transports a high-loading stream to the
high
pressure flow line to combine with the diluted stream to form a diversion
slurry; and a
flow path for the diversion slurry to a downhole feature.
[0014] In any of the foregoing and following aspects of the disclosure,
the diluted
stream may comprise from 1.2 to 12 g/L of the carrier fibers based on the
total
volume of the diluted stream (from 10 to 100 ppt, pounds per thousand gallons
of
carrier fluid).
[0015] In any of the foregoing and following aspects of the disclosure,
the high-
loading stream may comprise a low viscosity carrier fluid; and the diverting
agent
may comprise from 1.2 to 12 g/L (from 10 to 100 ppt) of bridging fibers based
on the
total volume of the high-loading stream, and from 1.2 to 120 g/L (10 to 1000
ppt) of
manufactured shape particles based on the total volume of the high-loading
stream.
BRIEF DESCRIPTION OF THE DRAWINGS
[0016] Figure 1 shows a schematic representation of a treatment
configuration of
the related art.
[0017] Figure 2 shows a schematic representation of a treatment
configuration
according to one or more embodiments herein.
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[0018] Figure 3 shows a diagram of a treatment configuration according to
one or
more embodiments herein.
[0019] Figure 4 shows a graphical representation of pressure changes with
respect
to time according to one or more embodiments herein.
[0020] Figure 5A schematically illustrates a bridging test apparatus
according to
embodiments.
[0021] Figure 5B schematically illustrates an enlarged detail of the slot
design in
the apparatus of Figure 5A.
[0022] Figure 6 schematically graphs the proppant settling in a treatment
fluid with
various fibers.
[0023] Figure 7 schematically graphs the effect of fiber loading on
proppant settling
in a treatment fluid with crimped mid temperature fibers.
[0024] Figure 8 schematically graphs the effect of fiber loading on
proppant settling
in a treatment fluid with crimped low temperature fibers.
[0025] Figure 9 schematically graphs the effect of fiber diameter on
proppant
settling in a treatment fluid with crimped mid temperature fibers.
[0026] Figure 10 schematically graphs the effect of fiber diameter on
proppant
settling in a treatment fluid with crimped low temperature fibers.
[0027] Figure 11 schematically graphs the effect of fiber length on
proppant settling
in a treatment fluid with crimped mid temperature fibers.
[0028] Figure 12 schematically graphs the effect of fiber length on
proppant settling
in a treatment fluid with crimped low temperature fibers.
[0029] Figure 13 schematically graphs the effect of crimp level on
proppant settling
in a treatment fluid with crimped low temperature fibers.
[0030] Figure 14 schematically graphs the proppant settling in a
slickwater fluid
with various fibers.
DETAILED DESCRIPTION
[0031] In the following description, numerous details are set forth to
provide an
understanding of the present disclosure. However, it may be understood by
those
skilled in the art that the methods of the present disclosure may be practiced
without
these details and that numerous variations or modifications from the described
embodiments may be possible.
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[0032] At the outset, it should be noted that in the development of any
such actual
embodiment, numerous implementation¨specific decisions may be made to achieve
the developer's specific goals, such as compliance with system related and
business
related constraints, which will vary from one implementation to another.
Moreover, it
will be appreciated that such a development effort might be complex and time
consuming but would nevertheless be a routine undertaking for those of
ordinary skill
in the art having the benefit of this disclosure. In addition, the composition
used/disclosed herein can also comprise some components other than those
cited. In
the summary and this detailed description, each numerical value should be read
once
as modified by the term "about" (unless already expressly so modified), and
then read
again as not so modified unless otherwise indicated in context. Also, in the
summary
and this detailed description, it should be understood that a range listed or
described
as being useful, suitable, or the like, is intended to include support for any
conceivable sub-range within the range at least because every point within the
range,
including the end points, is to be considered as having been stated. For
example, "a
range of from 1 to 10" is to be read as indicating each possible number along
the
continuum between about 1 and about 10. Furthermore, one or more of the data
points in the present examples may be combined together, or may be combined
with
one of the data points in the specification to create a range, and thus
include each
possible value or number within this range. Thus, (1) even if numerous
specific data
points within the range are explicitly identified, (2) even if reference is
made to a few
specific data points within the range, or (3) even when no data points within
the range
are explicitly identified, it is to be understood (i) that the inventors
appreciate and
understand that any conceivable data point within the range is to be
considered to
have been specified, and (ii) that the inventors possessed knowledge of the
entire
range, each conceivable sub-range within the range, and each conceivable point
within the range. Furthermore, the subject matter of this application
illustratively
disclosed herein suitably may be practiced in the absence of any element(s)
that are
not specifically disclosed herein.
[0033] The following definitions are provided in order to aid those
skilled in the art
in understanding the detailed description.
[0034] The term "wellbore" is a drilled hole or borehole, including the
openhole or
uncased portion of the well that is drilled during a treatment of a
subterranean
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formation. The term "wellbore" does not include the wellhead, or any other
similar
apparatus positioned over the wellbore. The term "treatment" or "treating"
refers to
any subterranean operation that uses a fluid in conjunction with a desired
function
and/or for a desired purpose. The term "treatment" or "treating" does not
imply any
particular action by the fluid.
[0035] The term "injecting" describes the introduction of a new or
different element
into a first element. In the context of this application, injection of a
fluid, solid or
other compound may occur by any form of physical introduction, including but
not
limited to pumping.
[0036] The term "fracturing" refers to the process and methods of
breaking down a
geological formation and creating a fracture, i.e., the geological formation
around a
well bore, in order to increase production rates from a hydrocarbon reservoir.
The
fracturing methods otherwise use techniques known in the art.
[0037] The term "matrix acidizing" refers to a process where treatments
of acid or
other reactive chemicals are pumped into the formation at a pressure below
which a
fracture can be created. The matrix acidizing methods otherwise use techniques
known in the art.
[0038] In some embodiments herein, a treatment fluid comprises a carrier
fluid, and
may optionally further comprise fibers and/or fiber mixtures, proppant and/or
other
materials such as particles other than fiber or proppant, dispersed in the
carrier fluid.
As used herein, when not used in context relative to a higher viscosity fluid,
a "low
viscosity" fluid, e.g., a low viscosity carrier, refers to one having a
viscosity less than
50 mPa-s at a shear rate of 170 s-1 and a temperature of 25 C. The term
"particulate"
or "particle" refers to a solid 3-dimensional object with maximal dimension
less than
1 meter. Here, "dimension" of the object refers to the distance between two
arbitrary
parallel planes, each plane touching the surface of the object at least at one
point.
[0039] The carrier fluid may include water, fresh water, e.g.,
"slickwater," seawater,
connate water or produced water. The carrier fluid may also include hydratable
gels
(such as guars, polysaccharides, xanthan, hydroxy-ethyl-cellulose (HEC), guar,
copolymers of polyacrylamide and their derivatives, e.g., acrylamido-methyl-
propane
sulfonate polymer (AMPS), or other similar gels, or a viscoelastic surfactant
system,
e.g., a betaine, or the like), a cross-linked hydratable gel, a viscosified
acid (such as a
gel-based viscosified acid), an emulsified acid (such as an oil outer phase
emulsified
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acid), an energized fluid (such as an N2 or CO2 based foam), and an oil-based
fluid
including a gelled, foamed, or otherwise viscosified oil. The carrier fluid
may be a
brine, and/or may include a brine. The carrier fluid may include hydrochloric
acid,
hydrofluoric acid, ammonium bifluoride, formic acid, acetic acid, lactic acid,
glycolic
acid, maleic acid, tartaric acid, sulfamic acid, malic acid, citric acid,
methyl-sulfamic
acid, chloro-acetic acid, an amino-poly-carboxylic acid, 3-hydroxypropionic
acid, a
poly-amino-poly-carboxylic acid, and/or a salt of any acid. In embodiments,
the
carrier fluid includes a poly-amino-poly-carboxylic acid, such as a trisodium
hydroxyl-ethyl-ethylene-diamine triacetate, mono-ammonium salts of hydroxyl-
ethyl-
ethylene-diamine triacetate, and/or mono-sodium salts of hydroxyl-ethyl-
ethylene-
diamine tetra-acetate, or other similar compositions. When a polymer is
present in a
low viscosity carrier fluid, for example, in some embodiments it may be
present at a
concentration below 1.92 g/L (16 ppt), e.g. from 0.12 g/L (1 ppt) to 1.8 g/L
(15 ppt).
When a viscoelastic surfactant is used in a low viscosity carrier fluid, for
example, in
some embodiments it may be used at a concentration below 10 ml/L, e.g. 2.5m1/L
to
5m1/L.
[0040] The term "diluted stream (or fluid)" in one sense, in the context
of
concentration or loading of a material(s) or type(s) of material(s) relative
to another
stream, which other stream may be, but not necessarily, referred to as a "high-
loading
stream," where the loadings of the comparative streams may or may not be
specified,
refers to the one of the streams having the lower loading of the material
under
consideration. In another sense, where the context does not indicate that a
relative
loading is to be implied, the term "diluted stream" refers to a stream
comprising 4.8
g/L (40 lbs/1000 gal) or less of the material(s) or type(s) of material(s),
e.g., carrier
fibers, based on the total volume of the diluted stream (fluid plus solids
volume). In
some embodiments, the diluted stream may comprise or consist essentially of
fibers
that are proppant-suspending and/or non-bridging.
[0041] Similarly, the term "high-loading stream (or fluid)" in the
context of
concentration or loading of a material(s) or type(s) of material(s) relative
to another
stream, which other stream may be, but not necessarily, referred to as a
"diluted
stream," where the loadings of the comparative streams may or may not be
specified,
refers to the one of the streams having the higher loading of the material
under
consideration. In another sense, where the context does not indicate that a
relative
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loading is to be implied, the term "high-loading stream" refers to a stream
comprising
more than 4.8 g/L (40 lbs/1000 gal) of the material(s) or type(s) of
material(s), e.g., a
mix of fibers and other particles optionally including proppant, based on the
total
volume of the high-loading stream (fluid plus solids volume).
[0042] According to some embodiments of the present disclosure, different
types of
fibers may be used optionally at different loadings to provide different
functionalities,
which may not necessarily be mutually exclusive, to a particular treatment
fluid or
stream. For example, the term "carrier fibers" refers to fibers which are
suitable at an
appropriate loading for assisting in the transport of proppant into a
fracture, e.g.,
either during initiation, propagation or branching of the fiber, whereas the
term "non-
bridging fibers" refers to fibers which are suitable for use in a carrier
fluid at specified
conditions and loadings generally without forming a bridge in the flow path of
interest.
For example, carrier fibers may be bridging or non-bridging. "Bridging fibers"
refers
to fibers that do not have the non-bridging quality and/or non-bridging fibers
used a
bridge-inducing loading rates.
[0043] In some embodiments, the treatment fluid comprises from 1.2 to 12
g/L of
the carrier fibers based on the total volume of the carrier fluid (from 10 to
100 ppt,
pounds per thousand gallons of carrier fluid), e.g., equal to or less than 4.8
g/L of the
fibers based on the total volume of the carrier fluid (equal to or less than
40 ppt) or
from 1.2 or 2.4 to 4.8 g/L of the fibers based on the total volume of the
carrier fluid
(from 10 or 20 to 40 ppt).
[0044] In some embodiments, the carrier fibers, which may be proppant-
suspending
and/or non-bridging, are crimped staple fibers. In some embodiments, the
crimped
fibers comprise from 1 to 10 crimps/cm of length, a crimp angle from 45 to 160
degrees, an average extended length of fiber of from 4 to 15 mm, and/or a mean
diameter of from 8 to 40 microns, or 8 to 12, or 8 to 10, or a combination
thereof In
some embodiments, the carrier fibers comprise low crimping equal to or less
than 5
crimps/cm of fiber length, e.g., 1-5 crimps/cm.
[0045] Depending on the temperature that the treatment fluid will
encounter,
especially at downhole conditions, the carrier fibers may be chosen depending
on
their resistance or degradability at the envisaged temperature. In the present
disclosure,
the terms "low temperature fibers", "mid temperature fibers" and "high
temperature
fibers" may be used to indicate the temperatures at which the fibers may be
used for
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delayed degradation, e.g., by hydrolysis, at downhole conditions. Low
temperatures
are typically within the range of from about 60 C (140 F) to about 93 C (200
F); mid
temperatures typically from about 94 C (201 F) to about 149 C (300 F); and
high
temperatures typically about 149.5 C (301 F) and above, or from about 149.5 C
(301 F) to about 204 C (400 F).
[0046] In some embodiments, the carrier fibers comprise polyester. In
some
embodiments, the polyester undergoes hydrolysis at a low temperature of less
than
about 93 C as determined by slowly heating 10 g of the fibers in 1 L deionized
water
until the pH of the water is less than 3, and in some embodiments, the
polyester
undergoes hydrolysis at a moderate temperature of between about 93 C and 149 C
as
determined by slowly heating 10 g of the fibers in 1 L deionized water until
the pH of
the water is less than 3, and in some embodiments, the polyester undergoes
hydrolysis
at a high temperature greater than 149 C, e.g., between about 149.5 C and 204
C. In
some embodiments, the polyester is selected from the group consisting of
polylactic
acid, polyglycolic acid, copolymers of lactic and glycolic acid, and
combinations
thereof
[0047] In some embodiments, the proppant-suspending and/or non-bridging
carrier
fibers are selected from the group consisting of polylactic acid (PLA),
polyglycolic
acid (PGA), polyethylene terephthalate (PET), polyester, polyamide,
polycaprolactam
and polylactone, poly(butylene) succinate, polydioxanone, nylon, glass,
ceramics,
carbon (including carbon-based compounds), elements in metallic form, metal
alloys,
wool, basalt, acrylic, polyethylene, polypropylene, novoloid resin,
polyphenylene
sulfide, polyvinyl chloride, polyvinylidene chloride, polyurethane, polyvinyl
alcohol,
polybenzimidazole, polyhydroquinone-diimidazopyridine, poly(p-phenylene-2,6-
benzobisoxazole), rayon, cotton, cellulose and other natural fibers, rubber,
and
combinations thereof
[0048] In some embodiments, the treatment fluid, e.g., the diluted
stream, when
proppant is present as in the initiation, propagation or other fracture
creation operation,
comprises from 0.01 to 1 kg/L of the proppant based on the total volume of the
carrier
fluid in the treatment stream (from 0.1 to 8.3 ppa, pounds proppant added per
gallon
of carrier fluid), e.g., from 0.048 to 0.6 kg/L of the proppant based on the
total volume
of the carrier fluid in the dilute stream (0.4 to 5 ppa), or from 0.12 to 0.48
kg/L of the
proppant based on the total volume of the carrier fluid in the dilute stream
(from 1 to
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4 ppa), or from 0.12 to 0.18 kg/L of the proppant based on the total volume of
the
carrier fluid in the dilute stream (from 1 to 1.5 ppa). As used herein,
proppant loading
is specified in weight of proppant added per volume of dilute stream or other
treatment, e.g., kg/L (ppa = pounds of proppant added per gallon of carrier
fluid).
Other materials in the treatment fluid are generally expressed in terms of g/L
based on
the total volume of the treatment fluid (ppt = pounds of material per thousand
gallons
of treatment fluid). Exemplary proppants include ceramic proppant, sand,
bauxite,
glass beads, crushed nut shells, polymeric proppant, rod shaped proppant, and
mixtures thereof
[0049] In some embodiments, a suitable carrier fiber can be dispersed in
the carrier
in an amount effective to inhibit settling of proppant, where proppant is
present. This
settling inhibition may be evidenced, in some embodiments, for example, in a
static
proppant settling test at 25 C for 90 minutes. The proppant settling test in
some
embodiments involves placing the fluid in a container such as a graduated
cylinder
and recording the upper level of dispersed proppant in the fluid. The upper
level of
dispersed proppant is recorded at periodic time intervals while maintaining
settling
(quiescent) conditions. The proppant settling fraction is calculated as:
Proppant settling = [initial proppant level (t=0)] ¨ [upper proppant level at
time n]
[initial proppant level (t=0)] ¨ [final proppant level (t=00)]
[0050] The carrier fiber inhibits proppant settling if the proppant
settling fraction
for the fluid containing the proppant and carrier fiber has a lower proppant
settling
fraction than the same fluid without the carrier fiber and with the proppant
only. In
some embodiments of the diluted stream containing proppant, the proppant
settling
fraction of the diluted stream in the static proppant settling test after 90
minutes is less
than 50%, e.g., less than 40%.
[0051] In some embodiments, the carrier fiber is dispersed in the diluted
stream in
an amount insufficient to cause bridging, e.g., as determined in a small slot
test
comprising passing the treatment fluid comprising the carrier fluid and the
carrier
fiber without proppant at 25 C through a bridging apparatus such as that shown
in
Figs. 5A and 5B comprising a 1.0-1.8 mm slot that is 15-16 mm wide and 65 mm
long
at a flow rate equal to 15 cm/s, or at a flow rate equal to 10 cm/s.
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[0052] In some embodiments the carrier fiber is dispersed in the diluted
stream
comprising proppant in both an amount effective to inhibit settling of the
proppant
and in an amount insufficient to cause bridging, wherein settling and bridging
are
determined by comparing proppant accumulation in a narrow fracture flow test
comprising pumping the treatment fluid at 25 C through a 2 mm slot measuring 3
m
long by 0.5 m high for 60 seconds at a flow velocity of 65 cm/s, or at a flow
velocity
of 20 cm/s, relative to a reference fluid containing the carrier fluid and
proppant only
without the carrier fiber. In the narrow fracture flow test, the slot may be
formed of
flow cells with transparent windows to observe proppant settling at the bottom
of the
cells. Proppant settling is inhibited if testing of the fluid with the
proppant and carrier
fiber results in measurably less proppant settling than the same fluid and
proppant
mixture without the carrier fiber at the same other testing conditions.
Bridging is
likewise observed in the narrow fracture flow test as regions exhibiting a
reduction of
fluid flow also resulting in proppant accumulation in the flow cells.
[0053] In some embodiments the treatment fluid comprising the diluted
stream may
include a fluid loss control agent, e.g., fine solids less than 10 microns, or
ultrafine
solids less than 1 micron, or 30 nm to 1 micron. According to some
embodiments, the
fine solids are fluid loss control agents such as 7-alumina, colloidal silica,
CaCO3,
Si02, bentonite etc.; and may comprise particulates with different shapes such
as glass
fibers, flocs, flakes, films; and any combination thereof or the like.
Colloidal silica,
for example, may function as an ultrafine solid loss control agent, depending
on the
size of the micropores in the formation, as well as a gellant and/or thickener
in any
associated liquid or foam phase.
[0054] . In some embodiments, e.g., where the diluted stream is used to
carry
proppant or otherwise in fracture creation with or without proppant, the
carrier fluid
comprises brine, e.g., sodium chloride, potassium bromide, ammonium chloride,
potassium choride, tetramethyl ammonium chloride and the like, including
combinations thereof In some embodiments the diluted stream may comprise oil,
including synthetic oils, e.g., in an oil based or invert emulsion fluid.
[0055] In some embodiments, e.g., where the diluted stream is used to
carry
proppant or otherwise in fracture creation with or without proppant, the
carrier fluid
comprises a friction reducer, e.g., a water soluble polymer. The diluted
stream may
additionally or alternatively include, without limitation, clay stabilizers,
biocides,
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crosslinkers, breakers, corrosion inhibitors, temperature stabilizers,
surfactants, and/or
proppant flowback control additives. The diluted stream may further include a
product formed from degradation, hydrolysis, hydration, chemical reaction, or
other
process that occur during preparation or operation.
[0056] In some embodiments, a method to treat a subterranean formation
penetrated
by a wellbore, comprises injecting the treatment fluid described herein, e.g.,
the
diluted stream into the subterranean formation to form a hydraulic fracture
system,
and maintaining a rate of the injection to avoid bridging in the wellbore,
such as, for
example, as determined in a bridging testing apparatus without proppant.
[0057] In some embodiments, the method may comprise injecting a pre-pad,
pad,
tail or flush stage or a combination thereof, which may be, for example, the
diluted
stream described herein. In some embodiments, the treatment fluid used in
other
aspects of the method comprises the diluted stream described herein,
optionally
including proppant and/or other additives described herein, in any
combination.
[0058] The diluted stream may be prepared using blenders, mixers and the
like as
shown in Figs. 1-3 discussed in more detail below, using standard treatment
fluid
preparation equipment and well circulation and/or injection equipment. In some
embodiments, a method is provided to inhibit proppant settling in a treatment
fluid
circulated in a wellbore, wherein the diluted stream comprises the proppant
dispersed
in a low viscosity carrier fluid. The method comprises dispersing carrier
fiber in the
carrier fluid in an amount effective to inhibit settling of the proppant, such
as, for
example, as determined in the small slot test, and maintaining a rate of the
circulation
to avoid bridging in the wellbore, such as, for example, as determined in a
bridging
testing apparatus without proppant and/or in the narrow fracture flow test. In
some
embodiments, the treatment fluid further comprises a friction reducer.
[0059] According to some embodiments, the proppant stage(s) may be
injected into
a fracture system using any one of the available proppant placement
techniques,
including heterogeneous proppant placement techniques, wherein the low
viscosity
treatment fluid herein is used in place of or in addition to any proppant-
containing
treatment fluid, such as, for example, those disclosed in US 3,850,247; US
5,330,005;
US 7,044,220; US 7,275,596; US 7,281,581; US 7,325,608; US 7,380,601; US
7,581,590; US 7,833,950; US 8 061 424; US 8,066,068; US 8,167,043; US
8,230,925;
US 8 372 787; US 2008/0236832; US 2010/0263870; US 2010/0288495; US
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2011/0240293; US 2012/0067581; US 2013/0134088; EP 1556458; WO
2007/086771; SPE 68854: Field Test of a Novel Low Viscosity Fracturing Fluid
in
the Lost Hills Fields, California; and SPE 91434: A Mechanical Methodology of
Improved Proppant Transport in Low-Viscosity Fluids: Application of a Fiber-
Assisted Transport Technique in East Texas; each of which is hereby
incorporated
herein by reference in its entirety.
[0060] The term "diverting (or diversion) agent" refers to a chemical or
solid agent
used alone or with another diverting agent(s) used in well treatments, e.g.,
stimulation
treatments, to at least temporarily selectively control the rate of flow of a
treatment
fluid, e.g., reduce or stop the flow rate, into a downhole feature being
treated, and
may (and usually will), but not necessarily, initiate, maintain or increase
the rate of
flow of the same or a different treatment fluid to another downhole feature.
Diverting
agents, also known as chemical or solid diverters, function by creating a
temporary
blocking effect, e.g., either a bridge or a plug, that may optionally be
cleaned up
following the treatment, i.e., for diversion or for temporal zonal isolation
as disclosed
in U.S. Patent Application Publication No. 2012/0285692 to Potapenko et al.,
which
is hereby incorporated by reference in its entirety. A "diverting (or
diversion)
composition" refers to a composition comprising a diverting agent plus a
carrier fluid;
and the term "diversion slurry" refers to a diverting agent flowably dispersed
in a
fluid such as a gas, liquid, foam or energized fluid. A "downhole feature"
refers to
any feature without limitation through which fluid may flow or pass,
including, but
not limited to, a formation matrix, screen or other porous media, or surface
thereof,
fracture, formation void, vug, wormhole, fluid loss zone, chamber,
perforation, valve,
opening, or a line, tubing pipe or similar flow conduit, such as casing,
tubing
(including coiled tubing), drill pipe, and including any annulus or space
between any
of such structures, and any combinations thereof, or the like.
[0061] The diversion composition may be made of blends of particles or
blends of
particles and flakes, as examples. For example, the diversion composition may
comprise a non-bridging fiber, either alone at a bridging concentration or in
combination with another specific bridging fiber and/or particulates. The size
of the
largest particles or flakes in the blends according to embodiments may be
slightly
smaller than the diameter of the perforation holes in the zone or other
downhole
feature to isolate or divert.
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[0062] According to embodiments, the size of the particles or flakes in
the blends
may be larger than an average width of the void intended to be closed or
temporally
isolated. The average width of the void may be the smallest width of the void
after
the perforation hole or another entry in such void, at 10 cm, at 20 cm, at 30
cm, at 50
cm or at 500 cm (when going into the formation from the wellbore). The void
may be
a perforation tunnel, hydraulic fracture or wormhole. In some embodiments, the
ratio
between particles and flakes in the blends may reduce permeability of the
formed
plugs.
[0063] In some embodiments, the diverting agent includes removable
diverting
materials which may be degradable material and/or dissolvable material. A
degradable material refers to a material that will at least partially degrade
(for
example, by cleavage of a chemical bond) within a desired period of time such
that no
additional intervention is used to remove the plug. For example, at least 30%
of the
removable material may degrade, such as at least 50%, or at least 75%. In some
embodiments, 100% of the removable material may degrade. The degradation of
the
removable material may be triggered by a temperature change, and/or by
chemical
reaction between the removable material and another reactant. Degradation may
include dissolution of the removable material.
[0064] Removable materials for use as the diverting agent may be in any
suitable
shape: for example, powder, particulates, beads, chips, or fibers. When the
removable
material is in the shape of fibers, the fibers may have a length of from about
2 to
about 25 mm, such as from about 3mm to about 20mm. In some embodiments, the
fibers may have a linear mass density of about 0.111 dtex to about 22.2 dtex
(about
0.1 to about 20 denier), such as about 0.167 to about 6.67 dtex (about 0.15 to
about 6
denier). Suitable fibers may degrade under downhole conditions, which may
include
temperatures as high as about 180 C (about 350 F) or more and pressures as
high as
about 137.9 MPa (about 20,000 psi) or more, in a duration that is suitable for
the
selected operation, from a minimum duration of about 0.5, about 1, about 2 or
about 3
hours up to a maximum of about 24, about 12, about 10, about 8 or about 6
hours, or a
range from any minimum duration to any maximum duration.
[0065] The removable materials may be sensitive to the environment, so
dilution
and precipitation properties should be taken into account when selecting the
appropriate removable material. The removable material used as a sealer may
survive
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in the formation or wellbore for a sufficiently long duration (for example,
about 3 to
about 6 hours). The duration should be long enough for wireline services to
perforate
the next pay sand, subsequent fracturing treatment(s) to be completed, and the
fracture
to close on the proppant before it completely settles, providing an improved
fracture
conductivity.
[0066] Further suitable removable materials and methods of use thereof
include
those described in U.S. Patent Application Publication Nos. 2006/0113077,
2008/0093073, and 2012/0181034, the disclosures of which are incorporated by
reference herein in their entireties. Such materials include inorganic fibers,
for
example of limestone or glass, but are more commonly polymers or co-polymers
of
esters, amides, or other similar materials. They may be partially hydrolyzed
at non-
backbone locations. Any such materials that are removable (due in-part because
the
materials may, for example, degrade and/or dissolve) at the appropriate time
under the
encountered conditions may also be employed in the methods of the present
disclosure. For example, polyols containing three or more hydroxyl groups may
be
used. Suitable polyols include polymeric polyols that solubilizable upon
heating,
desalination or a combination thereof, and contain hydroxyl-substituted carbon
atoms
in a polymer chain spaced from adjacent hydroxyl-substituted carbon atoms by
at
least one carbon atom in the polymer chain. The polyols may be free of
adjacent
hydroxyl substituents. In some embodiments, the polyols have a weight average
molecular weight from about 5000 to about 500,000 Daltons or more, such as
from
about 10,000 to about 200,000 Daltons.
[0067] Further examples of removable materials include
polyhdroxyalkanoates,
polyamides, polycaprolactones, polyhydroxybutyrates,
polyethyleneterephthalates,
polyvinyl alcohols, polyethylene oxide (polyethylene glycol), polyvinyl
acetate,
partially hydrolyzed polyvinyl acetate, and copolymers of these materials.
Polymers
or co-polymers of esters, for example, include substituted and unsubstituted
lactide,
glycolide, polylactic acid, and polyglycolic acid. For example, suitable
removable
materials for use as diverting agents include polylactide acid;
polycaprolactone;
polyhydroxybutyrate; polyhydroxyvalerate; polyethylene; polyhydroxyalkanoates,
such as poly[R-3-hydroxybutyrate], poly[R-3-hydroxybutyrate-co-3-
hydroxyvalerate],
poly[R-3-hydroxybutyrate-co-4-hydroxyvalerate], and the like; starch-based
polymers; polylactic acid and copolyesters; polyglycolic acid and copolymers;
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aliphatic-aromatic polyesters, such as poly(e-caprolactone), polyethylene
terephthalate, polybutylene terephthalate, and the like; polyvinylpyrrolidone;
polysaccharides; polyvinylimidazole; polymethacrylic acid; polyvinylamine;
polyvinylpyridine; and proteins, such as gelatin, wheat and maize gluten,
cottonseed
flour, whey proteins, myofibrillar proteins, caseins, and the like. Polymers
or co-
polymers of amides, for example, may include polyacrylamides.
[0068] Removable materials, such as, for example, degradable and/or
dissolvable
materials, may be used in the diverting agent at high concentrations (such as
from
about 201bs/1000gal to about 10001bs/1000gal, or from about 401bs/1000gal to
about
7501bs/1000gal) in order to form temporary plugs or bridges. The removable
material
may also be used at concentrations at least 4.8 g/L (40 lbs/1,000 gal), at
least 6 g/L
(50 lbs/1,000 gal), or at least 7.2 g/L (60 lbs/1,000 gal). The maximum
concentrations of these materials that can be used may depend on the surface
addition
and blending equipment available.
[0069] Suitable removable diverting agents also include dissolvable
materials and
meltable materials (both of which may also be capable of degradation). A
meltable
material is a material that will transition from a solid phase to a liquid
phase upon
exposure to an adequate stimulus, which is generally temperature. A
dissolvable
material (as opposed to a degradable material, which, for example, may be a
material
that can (under some conditions) be broken in smaller parts by a chemical
process that
results in the cleavage of chemical bonds, such as hydrolysis) is a material
that will
transition from a solid phase to a liquid phase upon exposure to an
appropriate solvent
or solvent system (that is, it is soluble in one or more solvent). The solvent
may be
the carrier fluid used for fracturing the well, or the produced fluid
(hydrocarbons) or
another fluid used during the treatment of the well. In some embodiments,
dissolution
and degradation processes may both be involved in the removal of the diverting
agent.
[0070] Such removable materials, for example dissolvable, meltable and/or
degradable materials, may be in any shape: for example, powder, particulates,
beads,
chips, or fibers. When such material is in the shape of fibers, the fibers may
have a
length of about 2 to about 25 mm, such as from about 3mm to about 20mm. The
fibers may have any suitable denier value, such as a denier of about 0.1 to
about 20, or
about 0.15 to about 6.
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[0071] Examples of suitable removable fiber materials include polylactic
acid
(PLA) and polyglycolide (PGA) fibers, glass fibers, polyethylene terephthalate
(PET)
fibers, and the like.
[0072] In some embodiments, the diverting agent content may include pre-
processed fiber flocks, which represent solids entrapped inside a fiber
network.
[0073] The high-loading stream may have a higher loading of materials
than the
diluted stream, and thus the diversion slurry will have a loading proportional
to the
amounts of materials and flow rates from each stream being combined. In the
diversion slurry, for example, the loading of any one or total amount of any
or all of
the carrier fibers, bridging fibers, proppant and other particulates, where
each is
present, in some embodiments may be in the range of from about 2.4 g/L (20
lbs/1000
gal) to about 120 g/L (1000 lbs/1000 gal), or from about 4.8 g/L (40 lbs/1000
gal) to
about 90 g/L (750 lbs/1000 gal), e.g., concentrations at least 4.8 g/L (40
lbs/1000 gal),
at least 6 g/L (50 lbs/1000 gal), or at least 7.2 g/L (60 lbs/1000 gal).
[0074] As shown in Figure 1, a system for pumping a fluid may include a
pumping
system 200 for pumping a fluid from a surface 118 of a well 120 to a wellbore
122
during an oilfield operation. The operation may be a hydraulic fracturing
operation,
and the fluid may be a fracturing fluid. The pumping system 200 includes a
plurality
of water tanks 221, which feed water to a gel maker 223. The gel maker 223
combines water from the water tanks 221 with a gelling agent so as to form a
gel.
The gel is then transported to a blender 225 where it is mixed with a proppant
from a
proppant feeder 227 to form a fracturing fluid.
[0075] The fracturing fluid is then pumped at a low pressure (such as
0.41-0.82
MPa (60-120 pounds per square inch (psi)) from the blender 225 to plunger
pumps
201 via the line 212. Each plunger pump 201 receives the fracturing fluid at a
low
pressure and discharges it into a common manifold 210 (sometimes called a
missile
trailer or missile) at a high pressure as shown by the discharge lines 214.
The
common manifold 210 then directs the fracturing fluid from the plunger pumps
201 to
the wellbore 122 via the line 215. A computerized control system 229 may be
employed to direct the entire pump system 200 for the duration of the
operation.
[0076] In such a system, each of the pumps 201 may be exposed to an
abrasive
proppant of the fracturing fluid. Accordingly, according to embodiments, a
split
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stream configuration may be designed to allow a fracturing fluid to be pumped
into
the wellbore.
[0077] In a split stream configuration, as disclosed in U.S. Patent No.
7,845,413 to
Shampine et al., which is hereby incorporated by reference in its entirety, a
pump
system can be operated whereby the fluid that is pumped from a well surface to
a
wellbore is split into a clean side containing primarily water as well as a
dirty side
containing solids in a fluid carrier. In a fracturing operation, the dirty
side may
contain a proppant in a fluid carrier, and the clean side would not be exposed
to
abrasive fluids.
[0078] In some embodiments, a split stream configuration is designed to
ultimately
transport a diverting composition, which may be a diverting slurry, into a
wellbore.
The diverting composition may be used at some time during a treatment
operation,
including a hydraulic fracturing or acid fracturing operation. The diverting
composition may be injected to partially or fully close a fracture in a
subterranean
formation so as to perform a diversion operation.
[0079] In embodiments, a method for injecting a diverting composition
into a
subterranean formation may include a split stream configuration. As can be
seen in
Figure 2, the diverting composition may be formed at a point prior to
injection in the
wellbore.
[0080] Figure 2 shows an injecting system 300 for injecting a diverting
fluid from a
surface 118 of a well 120 to a wellbore 122 during an oilfield operation. The
injection may occur by pumping or by another form of introduction. The
operation
may be for a diverting treatment to be performed at some point during a
fracturing or
other treatment. The injecting system 300 includes a plurality of water tanks
321,
which feed water downstream. The injecting system 300 also includes tank 323,
which feeds a viscosifying agent to a blender 325 where it may be mixed with
an
amount of proppant from proppant tank 327 and an amount of solid to form a
diluted
stream. In some embodiments, the solid may be in the form of manufactured
shapes,
which may include degradable fibers, particles, or a combination of the two.
[0081] The diluted stream is then pumped at a low pressure (such as 0.41-
0.82 MPa
(60-120 psi)) from the blender 325 to plunger pumps 301 via the diluted stream
line
DL. Each plunger pump 301 receives the diverting fluid at a low pressure and
discharges it into a common manifold 310.
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[0082] Additionally, an amount of water from the water tanks 321 may be
combined with a gelling agent supplied by tank 323 so as to form a gel. A
diverting
agent may be included with the gel at diverting agent truck 313 so as to form
a high-
loading stream. In some embodiments, the diverting agent may include an amount
of
manufactured shapes, which may be in the form of fibers, particles or flakes.
The
mixture of the manufactured shapes and the gel may occur by a process such as
batch
mixing. The resultant mixture formed as the high-loading stream may be in the
form
of a slurry.
[0083] The high-loading stream may pass through the high-loading stream
line HL
and reach the pumps 301' whereby the high-loading stream will be mixed and
then
pumped into the common manifold 310 which may include or be directly or
indirectly
connected to a high pressure flow line. The pumps 301' may be high-loading
pumps.
In the common manifold, the high-loading stream and the diluted stream may
then be
mixed to form a diverting composition. The common manifold 310 may then direct
the diverting composition from the plunger pumps 201 to the wellbore 122 via
the line
315. In embodiments, the high-loading stream and the diluted stream may be
combined outside of the common manifold 310, such as downstream of the
manifold,
which may be by connecting iron or by connecting the high-loading streams and
the
diluted stream at the wellhead.
[0084] A computerized control system 329 may be employed to direct the
entire
pump system 300 for the duration of the operation.
[0085] In embodiments, the pumps 301' may be high pressure pumps such as
positive displacement pumps, multi-stage centrifugal pumps or combinations
thereof
In some embodiments, the pumps 301' may be devices capable of injecting a
diverting
agent in the form of a ball. Thus, the pumps 301' may be ball injectors, as
described
in WO 2013/085410 to Lecerf et al., which is hereby incorporated by reference
in its
entirety. In embodiments where the pumps 301' are ball injectors, the high-
loading
stream will include a ball-type diverting agent. The pumps 301' may also be
suitable
for injected destructible containers or containers carrying a fluid and
intended to be
broken mechanically or otherwise at some point during or after injection into
a
wellbore.
[0086] The following description relates to the high-loading stream.
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[0087] In embodiments, the components of the high-loading stream other
than the
diverting agent are components of a carrier fluid. The carrier fluid may
include water,
fresh water, seawater, connate water or produced water. The carrier fluid may
also
include hydratable gels (such as guars, polysaccharides, xanthan, hydroxy-
ethyl-
cellulose, or other similar gels), a cross-linked hydratable gel, a
viscosified acid (such
as a gel-based viscosified acid), an emulsified acid (such as an oil outer
phase
emulsified acid), an energized fluid (such as an N2 or CO2 based foam), and an
oil-
based fluid including a gelled, foamed, or otherwise viscosified oil.
[0088] The carrier fluid may be a brine, and/or may include a brine. The
carrier
fluid may include hydrochloric acid, hydrofluoric acid, ammonium bifluoride,
formic
acid, acetic acid, lactic acid, glycolic acid, maleic acid, tartaric acid,
sulfamic acid,
malic acid, citric acid, methyl-sulfamic acid, chloro-acetic acid, an amino-
poly-
carboxylic acid, 3-hydroxypropionic acid, a poly-amino-poly-carboxylic acid,
and/or
a salt of any acid. In embodiments, the carrier fluid includes a poly-amino-
poly-
carboxylic acid, such as a trisodium hydroxyl-ethyl-ethylene-diamine
triacetate,
mono-ammonium salts of hydroxyl-ethyl-ethylene-diamine triacetate, and/or mono-
sodium salts of hydroxyl-ethyl-ethylene-diamine tetra-acetate, or other
similar
compositions.
[0089] The high-loading stream also contains a diverting agent which may
include
degradable fibers of manufactured shapes at high loading, generally more than
10Olb/1000gal.
[0090] In embodiments, the manufactured shapes which may be used may be
round
particles, such as, for example, particles having an aspect ratio less than
about 5, or
less than about 3. The particles may be of dimension which are optimized for
plugging or diverting, such as disclosed in Potapenko et al. Though some
particles
may be round in embodiments, the particles may not have to be round. The
particles
may include some round particles and some particles of other shapes, or may
include
no round particles at all. In embodiments where the particles include round
particles
and other shapes, the particles of other shapes may be cubes, tetrahedrons,
octahedrons, plate-like shapes (flakes), oval etc.
[0091] Also, the particles can include sand, different types of ceramics
used for
producing proppant, as well as aluminosilicates, such as muscovite mica. In
addition,
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the diverting agent may include mixtures of fibers, sand, particles, film and
other
similar components.
[0092] In embodiments where fibers are included in the high-loading
stream, the
fibers may be any of inorganic or organic fibrous materials and can be either
degradable or stable at bottomhole conditions. Embodiments may include fiber
materials such as PLA and PGA fibers, glass fibers, or PET fibers. In
embodiments,
pre-processed fiber flocks representing solids entrapped inside the fiber
network may
be included.
[0093] The diverting agent may include manufactured shapes that may be
made of a
swellable material. The swellable materials may be any materials that swell in
the
presence of hydrocarbons, water or mixtures of thereof. In embodiments, these
may
include elastomers, swellable resins, swellable polymers, or clays. The
materials may
be one or more of x-linked polyacrylamides and polyacrylic acid derivatives,
smectite
clay, bentonite, oil-swellable rubber, water-swellable elastomers and mixtures
of
thereof
[0094] The swellable materials can be in any form and size, including
grains,
spheres, fibers, shaped particulates, beads, and balls. The swellable
materials may also
be degradable or dissolvable in the presence of acids, hydroxides, amines or
other
reagents. Swelling time of the particles can be also controlled by slowly
dissolvable
coatings, additives in the base fluid or in the composition of the swellable
material as
well as by changing temperature.
[0095] In embodiments, the diverting agent including the fibers and
swellable
materials may be suspended in the carrier fluid.
[0096] In embodiments, the swellable materials may swell in the plug so
that a
decrease in the plug conductivity results, which will thereby reduce the rate
of fluid
penetration in the isolated zone. Control of the plug permeability may be
performed
by replacement of the fluid that surrounds the plug with the fluid that causes
shrinkage of the swelled particles. In embodiments where polyacrylamide
particles
are used as swellable component and initial swelling happens in a water-based
fluid,
then shrinkage of the swelled particles may be caused by exposure to organic
solvents
or brines with high salinity. Hydrocarbons can be also used to case shrinkage
of
swelled bentonite grains.
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[0097] Other swellable particles can be modified proppants comprising a
proppant
particle and a hydrogel coating. The hydrogel coating is applied to a surface
of the
proppant particle and localizes on the surface to produce the modified
proppant.
[0098] In some embodiments, the diverting agent may include polylactide
resin
particles. The polylactide resin can be molded into different shapes and
sizes.
[0099] The following relates to the diluted stream.
[0100] The diluted stream may include a carrier fluid. The carrier fluid
may be the
same, or may differ from the carrier fluid in the high-loading stream. In
embodiments, the diluted stream may include a fluid with a lower viscosity
than the
fluid in the high-loading stream, which can be obtained by using the same
gelling
agent as in the high-loading stream, but in lesser quantity.
[0101] The diluted stream may contain manufactured shapes, or may not
carry any
manufactured shape. In embodiments where manufactured shapes are included,
such
shapes may be the same ones as in the high-loading stream. In such
embodiments, the
shapes may be included at a lower loading (e.g., a lower concentration) than
the
shapes in the high-loading stream. Further, the manufactured shapes in the
diluted
stream may be a shape of a smaller dimension than those in the high-loading
stream.
[0102] In embodiments, the high-loading stream may contain large
degradable
particles of a diameter of 4 mesh to 10 mesh or larger. The diluted stream may
contain comparatively smaller degradable particles, such as those of diameter
10 mesh
to 100 mesh or smaller. In embodiments, the particle size and distribution of
particles
will be optimized when the high-loading and diluted streams converge.
[0103] In embodiments, the diluted stream may contain a material of a
shape
different than in the high-loading stream. The diluted stream may contain
fiber
shapes while the high-loading stream may contain particulate shapes, or vice
versa.
In embodiments, the high-loading stream may contain a variety of shapes, while
the
diluted stream contains less variety of shape. In some embodiments, the high-
loading
stream may contain both fibers and particles, while the diluted stream
contains fibers.
The diluted stream would still contain a lower loading of manufactured shapes
than
the high-loading stream, when expressed in weight of shaped particles by
volume of
the stream.
[0104] In embodiments, the high-loading stream and the diluted stream are
injected
into the common manifold at particular rates. The high-loading stream may be
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injected at about 1 to about 20 bbl/min, or about 5 to about 10 bbl/min, or
about 7
bbl/min. The diluted stream may be injected at about 1 to about 100 bbl/min,
or about
25 to about 100 bbl/min, or about 25 to about 65 bbl/min, or about 43 bbl/min.
The
total injection rate at the manifold and subsequently into the wellbore will
thus be
about 2 to about 120 bbl/min, or about 30 to about 100 bbl/min, or about 30 to
about
75 bbl/min, or about 50 bbl/min.
[0105] Then, to complete the operation, a cleaning operation may be
performed.
This can include pumping an amount of fiber to clean the lines, then stopping
pumping fiber, and then, once the last fraction of proppant has passed the
perforations,
slowing down the injection rate when squeezing particles through the
perforations.
[0106] The following example describes a treatment utilizing a diverting
composition and method according to one or more embodiments.
[0107] A horizontal well is being fractured in sections, with sections
delimited by
bridge plugs. Each section is 91.4 m (300ft) long and has 6 0.305 m (1 ft)
perforation
clusters, separated by 15.2 m (50 ft). Each perforation cluster contains six
perforations.
The section is being treated with two stages of 36,300 kg (80,000) lbs of
proppant,
and each stage is separated by injecting a diverting agent which is a mixture
of
manufactured shapes. The shapes include particles and beads of various size
and
fibers.
[0108] A diverting agent (also referred to as a plugging or diverting
pill) in this
example includes 22.7 kg (50 lbs) of particles and includes 3.8 kg (8.4 lbs)
of fibers in
795 L (5 bbl) of 3 g/L (25 ppt) linear gel. This corresponds to 11.3 g/L (238
ppt) of
particles and 0.48 g/L (40 ppt) of bridging fiber. The high-loading stream is
injected
into the line connecting the manifold to the wellhead (i.e., downstream of the
manifold, identified as line 315 in Figure 2) at about 1100 ¨ 1300 L/min
(about 7-8
bbl/min) while the diluted stream is injected at about 6700-6800 L/min (42-43
bbl/min) to bring the total injection rate to 7950 L/min (50 bbl/min). The
diversion
slurry derived as a result of the combination of the high-loading stream and
the
diluted stream has a volume of 1500 L (36 bbl), a particle loading of 4 g/L
(33.3 ppt),
and a total fiber (carrier and bridging) loading of 6 g/L (50 ppt).
[0109] The high-loading stream is prepared in a mixing tub of a cement
mixing /
blender float. Thirty minutes before the last fraction of proppant enters the
wellbore,
diverting material is added in the batch mixer. Specifically, the mixing tub
is filled
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with 795 L (5 bbl) of water gelled with 11.3 kg (25 lbs) of linear gel. Into
this 3.8 kg
(8.4 lbs) of fiber are mixed. Then, 22.7 kg (50 lbs) of a particulate blend
are added to
achieve a desired concentration, and the stream is then mixed.
[0110] To pump the diverting agent in the high-loading stream, once the
last
fraction of proppant has passed the pump, the proppant is cut and 3180 L (20
bbl) of
crosslinked fluid is injected. Then, the crosslinker is cut and 3180 L (20
bbl) of linear
gel is injected.
[0111] To prepare the diluted stream, at a pod blender (which is disposed
at a low
pressure side of the diluted stream), a dry additive feeder may be set to 22.7
kg (50
lbs) of fiber /3785 L (1000 gal) of a 0.24 g/L (20 ppt) linear gel. The rate
of the
diluted stream is set to 6700-6800 L/min (42-43 bbl/min) so that the total
rate of
diversion slurry (the high-loading stream and the diluted stream) equals 7950
L/min
(50 bbl/min).
[0112] As can be seen in Figure 3, the diluted stream is pumped at a rate
of 6800
L/min (43 bbl/min), whereas the high-loading stream, mixed in a batch mixed,
is
pumped at a rate of 1100 L/min (7 bbl/min). The total pumping rate is 7900 L
(50
bbl/min) once the streams are combined to form the diverting composition or
slurry.
[0113] To mix the high-loading stream with the diluted stream, the high-
loading
stream is pumped as fast as possible on a dedicated pump, or may be supplied
to one
of the pumps that is otherwise used for the diluted stream, while maintaining
rate of
other fracturing pumps.
[0114] After the mixing of the high-loading stream with the diluting
stream, a
cleaning operation including pumping at least 795 L (5 bbl)or at least 1590 L
(10nnl)
from linear gel to clean the lines that were used to pump the high-loading
stream is
performed. Then, the fiber pumping through the high-loading stream lines is
stopped,
and once the last fraction of proppant has passed the perforations, the
injection rate is
slowed to 3180 L/min (20 bbl/min) when squeezing particles through the
perforations.
[0115] As shown in Figure 4, the diverting composition or slurry
according to the
embodiments described herein allows for an observed pressure when the
diverting
composition hits the perforation ranges to be from 3.1 to 21.4 MPa (450 to
3100 psi).
At stage #10, when the pressure increase reaches an amplitude of 24.1 MPa
(3500 psi),
the pressure went down sharply and stabilized at a pressure gain of 15 MPa
(2180 psi).
This shows that the pressure increased by 24.1 MPa (3500 psi), when the
diverter hit
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the perforations. The pressure went down sharply later on, but still remained
very
high. Overall, the gain in treatment pressure shows that perforation clusters
were
plugged effectively using the diverting composition.
[0116] In the following examples relating to non-bridging and/or proppant-
carrying
fibers, slickwater and low viscosity linear guar fluids were prepared from tap
water.
The slickwater contained 1 mL/L (1 gpt) of a concentrated friction reducer
solution.
Then, depending on the test, two types of linear guar fluids were prepared:
= In the model static settling test in cylinder used in example 1, a fluid
A was used, it
contained linear guar fluid containing 5.4 g/L (45 ppt) guar and 0.48 kg/L
(4ppa) of
12/18 mesh proppant were used, these proppant was obtained from CARBOPROP TM
from Carboceramics (Houston, Texas, USA);
= In the settling test in narrow slot used in example 2, a fluid B was
used, it contained a
linear gel containing 2.4 g/L (20 ppt) guar and 0.12 to 0.24 kg/L (2 ppa) of
40/70
mesh proppant were used, these proppant were BADGER TNI sand from Badger
Mining Corporation (Berlin, Wisconsin, USA).
[0117] The fibers used in the following examples were polylactic acid
fibers that
were obtained from Trevira GmbH (Germany). Both mid and low temperature
resistant fibers were used, the mid temperature fibers generally being useful
in
treatments with a formation temperature in the range of 94-149 C, and the low
temperature resistant fibers at 60-93 C, of those tested in these examples.
The fibers
were straight (uncrimped), or low crimp (4-5 crimps/cm) or high crimp (>5
crimps/cm, e.g., 8-15 crimps/cm). In the fibers evaluated in these examples,
the low
crimp fibers performed well in terms of bridging resistance and inhibiting
proppant
settling at lower fiber loadings. Fibers with diameters from 8 to 13 microns
and
lengths from 3 to 12 mm were evaluated, and of those tested in these examples,
the
fibers with a diameter of 8 ¨ 9.5 microns and a length of 6 mm performed well
in
terms of bridging resistance and inhibiting proppant settling at lower fiber
loadings.
The characteristics of the fibers used and other examples of suitable fibers
in some
embodiments are identified in Table 1.
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Table 1. Fibers used in experimental tests and other exemplary fibers.
Fiber Hydrolysis T Crimps/cm Diameter, Length,
ID Range microns mm
NF1 Mid 0 13 6
NF2 Low 0 12 6
CF1 Mid Low 10 4
CF2 Mid Low 10 6
CF3 Mid Low 10 8
CF4 Mid Low 10 12
CF5 Mid Low 12 4
CF6 Mid Low 12 6
CF7 Mid Low 12 8
CF8 Mid Low 12 12
CF9 Low Low 10 4
CF10 Low Low 10 6
CF11 Low Low 10 8
CF12 Low Low 10 12
CF13 Low High 10 4
CF14 Low High 10 6
CF15 Low High 10 8
CF16 Low High 10 12
CF17 Low Low 12 4
CF18 Low Low 12 6
CF19 Low Low 12 8
CF20 Low Low 12 12
CF21 Low High 12 4
CF22 Low High 12 6
CF23 Low High 12 8
CF24 Low High 12 12
[0118] Figures 6 to
13 are the results of test obtained with the proppant settling
cylinder test.
[0119] The model
proppant settling test involved placing the fluid in a graduated
cylinder and recording the upper level of dispersed proppant in the fluid. The
upper
level of dispersed proppant was recorded at periodic time intervals, e.g., 0,
10, 30, 60,
90 and 120 minutes while maintaining settling conditions. The proppant
settling
fraction was calculated as:
Proppant settling = [initial proppant level (t=0)1 ¨ [upper proppant level at
time n-I
[initial proppant level (t=0)] ¨ [final proppant level (t=co)]
[0120]
Concerning the bridging screen test apparatus used is seen in Figures 5A and
5B. The fluid being tested was pumped through the apparatus at a flow rate of
10 ¨
500 mL/min for a period of at least 1 minute (at the end of the time period
the total
volume of fluid pumped was 500 mL). Formation of a fiber plug in the slot (1-2
mm)
was indicated by a pressure rise. Bridging tests using the test apparatus of
Figures 5A
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and 5B were conducted without proppant unless otherwise noted. The fluid was
recorded as negative for bridge formation if no plug was formed.
[0121] A narrow fracture flow test apparatus was also employed for more
in depth
analysis. The narrow fracture flow test apparatus employed parallel glass
panes with
a length of 3 m, height of 0.5 m and width of 2 mm for visualization of the
fluid and
proppant at a flow rate up to 50 L/min. The narrow fracture flow tests were
run with
L-, T- and X-shape slot orientation.
[0122] Example 1: Proppant Settling. In this example, fluid A was used.
The
tests were made to compare one fiber with another, and estimate the behavior
of any
new fiber as a proppant settling inhibitor. The tests were made in a linear
gel since
settling test in a slickwater type of fluid may not be representative as the
settling may
occur immediately.
[0123] A fluid with 0.48 g/L of fibers NF1 ¨ NF2 and CF1 ¨ CF 24 with
0.48 kg/L
(4 ppa) proppant was prepared. The data which are shown in Figure 6 indicate
the
crimped fibers inhibited proppant settling better than the uncrimped fibers.
[0124] The qualitative results in Figures 7 and 8 indicate that the mid
temperature
fiber CF2 (10 microns/6 mm) and the low temperature fiber CF10 (10 microns/6
mm)
indicate the fiber loading was reduced by 25% using the crimped fibers in
place of the
uncrimped fibers NF1 and NF2, respectively. The results in Figures 9 and 10
indicate
that 10 micron diameter fibers inhibit inhibited proppant settling to a
greater extent
than the 12 micron fibers. The results in Figures 11 and 12 indicate that 6 mm
long
fibers provided more or equivalent proppant settling inhibition relative to 4,
8 and 12
mm fibers. The results in Figure 13 show that low crimp fibers provided better
inhibition of proppant settling than high crimp fibers. The data generally
show CF2
and CF10 (10 micron, 6 mm, low crimp) had the best settling inhibition
characteristics.
[0125] Due to the difficulty of applying static proppant settling test in
cylinder to
slickwater due to immediate settling, experiments on proppant settling in
narrow slot
in static conditions were not run on this test equipment, however, experiments
with
fluid B that has a lower viscosity were run to confirm the findings evidenced
from the
cylinder test with linear gel A. The results are available in Figure 14 and
confirm the
tendencies observed.
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[0126] Example 2: Fiber Bridging in Low Viscosity Guar Fluid. In this
example, the fluid B was prepared, it contained a linear guar fluid, 2.4 g/L
(20 ppt)
guar, at 4.8 g/L (40 ppt) of fibers NF1, CF10 and CF14 without proppant. The
bridge
screening test results are presented in Table 2.
Table 2: Screening Bridge Testing.
Flow rate, Linear Fiber NF1 Fiber Fiber
mL/min velocity, (uncrimped) CF10 CF14
cm/s (low (high
crimp) crimp)
0.57 Bridged Bridged Bridged
50 2.86 Bridged Bridged Bridged
75 4.29 Bridged Bridged Bridged
100 5.72 Bridged Bridged Bridged
150 8.59 Bridged No Bridged
Bridge
200 11.4 Bridged No No
Bridge Bridge
250 14.3 Bridged No No
Bridge Bridge
300 17.2 Bridged No No
Bridge Bridge
350 20.0 No Bridge No No
Bridge Bridge
[0127] The
foregoing data show that fibers can be used in fracturing treatments
using slickwater and linear gels having a low viscosity. With the appropriate
fiber
selection, bottom hole temperatures of 60-204 C (140-400 F) may be applicable.
The
fibers provide better proppant transport and reduced settling with reduced
water
requirements (higher proppant loading), reduced proppant requirements (better
proppant placement) and reduced power requirements (lower fluid viscosity and
less
pressure drop). The fibers may increase proppant transport in a low viscosity
fluid.
The fibers may be degradable after placement in the formation. The fibers can
be
used in hybrid treatments such as heterogeneous proppant placement and/or
pulsed
proppant and/or fiber pumping operation modes.
[0128] Although the preceding description has been described herein with
reference
to particular means, materials and embodiments, it is not intended to be
limited to the
particulars disclosed herein; rather, it extends to all functionally
equivalent structures,
methods and uses, such are within the scope of the appended claims.
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