Note: Descriptions are shown in the official language in which they were submitted.
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Increasing Fracture Complexity in Ultra-Low Permeable Subterranean Formation
Using Degradable Particulate
[0001] The inventions generally relate to the field of producing crude oil or
natural
gas from a well. More particularly, the inventions are directed to improved
methods and well
fluids for use in wells.
Oil & Gas Reservoirs
[0002] In the context of production from a well, oil and gas (in this context
referring
to crude oil and natural gas) are well understood to refer to hydrocarbons
naturally occurring
in certain subterranean formations. A hydrocarbon is a naturally occurring
organic compound
comprising hydrogen and carbon. A hydrocarbon molecule can range from being as
simple as
methane (CH4) to a large, highly complex molecule. Petroleum is a mixture of
many different
hydrocarbons.
[0003] A subterranean formation is a body of rock that has sufficiently
distinctive
characteristics and is sufficiently continuous for geologists to describe,
map, and name it. In
the context of formation evaluation, the term refers to the volume of rock
seen by a
measurement made through a wellbore, as in a log or a well test. These
measurements
indicate the physical properties of this volume of rock, such as the property
of permeability.
[0004] A subterranean formation containing oil or gas is sometimes referred to
as a
reservoir. A reservoir is a subsurface, porous, permeable, or naturally
fractured rock body in
which oil or gas is stored. Most reservoir rocks are limestones, dolomites,
sandstones, or a
combination of these. The four basic types of hydrocarbon reservoirs are oil,
volatile oil, gas
condensate, and dry gas.
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[00051 An oil reservoir generally contains three fluids¨gas, oil, and
water¨with
oil the dominant product. In the typical oil reservoir, these fluids become
vertically
segregated because of their different densities. Gas, the lightest, occupies
the upper part of
the reservoir rocks; water, the lower part; and oil, the intermediate section.
In addition to its
occurrence as a cap or in solution, gas may accumulate independently of the
oil; if so, the
reservoir is called a gas reservoir. Associated with the gas, in most
instances, are salt water
and some oil.
[0006] Volatile oil reservoirs are exceptional in that during early production
they
are mostly productive of light oil plus gas, but, as depletion occurs,
production can become
almost completely gas. Volatile oils are usually good candidates for pressure
maintenance,
which can result in increased reserves.
[0007] In a gas condensate reservoir, the hydrocarbons may exist as a gas,
but, when
brought to the surface, some of the heavier hydrocarbons condense and become a
liquid.
[0008] In the typical dry gas reservoir natural gas exists only as a gas and
production is only gas plus fresh water that condenses from the flow stream
reservoir. The
conventional natural gas reservoirs have a matrix permeability in the range of
about
500 milliDarcy (4.9346165 x 10-13 t112) to about 1 milliDarcy (9.869233 x 10-
16 m2).
[0009] A reservoir is in a shape that will trap hydrocarbons and that is
covered by a
relatively impermeable rock, known as cap rock. The cap rock forms a barrier
above
reservoir rock so that fluids cannot migrate beyond the reservoir. A cap rock
capable of
being a barrier to fluid migration on a geological time scale has a
permeability that is less
than about I microDarcy (9.869233 x 10-19 m2). Cap rock is commonly salt,
anhydrite, or
shale.
[ON 0] A conventional reservoir is a reservoir where the hydrocarbons flow to
the
wellbore in a manner in which the system can be characterized by flow through
permeable
media, where the permeability may or may not have been altered near the
wellbore, or flow
through permeable media to a permeable (conductive), bi-wing fracture placed
in the
formation. In addition, the hydrocarbons location in the reservoir are held in
place by an
upper, impermeable barrier and different reservoir fluids are located
vertically based on their
density where the movement of one of the reservoir fluid can apply a driving
force to another
reservoir fluid. A convention reservoir would typically have a matrix
permeability greater
than about 1 milliDarcy (equivalent to about 1,000 microDarcy, 9.869233 x 10-
16 m2).
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[0011] Tight gas, however, is natural gas that is difficult to access because
the
matrix permeability is relatively low. Generally, tight gas is in a
subterranean formation
having a matrix permeability in the range of about 1 milliDarcy (9.869233 x 10-
16 m2) to
about 0.01 milliDarcy (equivalent to about 10 microDarcy, 9.869233 x 10-18
m2).
Conventionally, to produce tight gas it is necessary to find a "sweet spot"
where a large
amount of gas is accessible, and sometimes to use various means to create a
reduced pressure
in the well to help draw the gas out of the formation.
[00121 In addition, shale can include relatively large amounts of organic
material
compared with other types of rock. Shale is a sedimentary rock derived from
mud. Shale
rock is conunonly finely laminated (bedded). Particles in shale are commonly
clay minerals
mixed with tiny grains of quartz eroded from pre-existing rocks. Shale is a
type of
sedimentary rock that contains clay and minerals such as quartz. Gas is very
difficult to
produce from shale, however, because the matrix permeability of the shale is
often less than
about 1 microDarcy (9.869233 x 10-19 m2).
[00131 A reservoir may be located under land or under the seabed off shore.
Oil and
gas reservoirs are typically located in the range of a few hundred feet
(shallow reservoirs) to a
few tens of thousands of feet (ultra-deep reservoirs) below the surface of the
land or seabed.
Producing Oil and Gas
[00141 To produce oil or gas from a reservoir, a wellbore is drilled into a
subterranean formation, which may be the reservoir or adjacent to the
reservoir. A well
includes at least one wellbore. The wellbore refers to the drilled hole,
including any cased or
uncased portions of the well. The borehole usually refers to the inside
wellbore wall, that is,
the rock face or wall that bounds the drilled hole. A wellbore can have
portions that are
vertical, horizontal, or anything in between, and it can have portions that
are straight, curved,
or branched. The wellhead is the surface termination of a wellbore, which
surface may be on
land or on a seabed. As used herein, "uphole," "downhole," and similar terms
are relative to
the direction of the wellhead, regardless of whether a wellbore portion is
vertical or
horizontal.
[00151 Broadly, a zone refers to an interval of rock along a wellbore that is
differentiated from surrounding rocks based on hydrocarbon content or other
features, such as
perforations or other fluid communication with the wellbore, faults, or
fractures. The near-
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wellbore region of a zone is usually considered to include the matrix of the
rock within a few
inches of the borehole. As used herein, the near-wellbore region of a zone is
considered to be
anywhere within about 12 inches (0.30 m) of the wellbore. The far-field region
of a zone is
usually considered the matrix of the rock that is beyond the near-wellbore
region.
[0016] Generally, well services include a wide variety of operations that may
be
performed in oil, gas, geothermal, or water wells, such as drilling,
cementing, completion,
and intervention. These well services are designed to facilitate or enhance
the production of
desirable fluids from or through a subterranean formation.
[0017] Drilling is the process of drilling the wellbore. After the hole is
drilled,
sections of steel pipe, referred to as casing, which are slightly smaller in
diameter than the
borehole, are placed in at least the uppermost portions of the wellbore. The
casing provides
structural integrity to the newly drilled borehole.
[0018] Cementing is a common well operation. For example, hydraulic cement
compositions can be used in cementing operations in which a string of pipe,
such as casing or
liner, is cemented in a wellbore. The cemented string of pipe isolates
different zones of the
wellbore from each other and from the surface. Hydraulic cement compositions
can be use in
primary cementing of the casing or in completion operations. Hydraulic cement
compositions can also be utilized in intervention operations, such as in
plugging highly
permeable zones or fractures in zones that may be producing too much water,
plugging
cracks or holes in pipe strings, and the like.
[0019] Completion is the process of making a well ready for production or
injection.
This principally involves preparing a zone of the wellbore to the required
specifications,
running in the production tubing and associated downhole equipment, as well as
perforating
and stimulating as required.
[0020] Intervention is any operation carried out on a well during or at the
end of its
productive life that alters the state of the well or well geometry, provides
well diagnostics, or
manages the production of the well. Workover can broadly refer to any kind of
well
intervention that involves invasive techniques, such as wireline, coiled
tubing, or snubbing.
More specifically, though, workover refers to the process of pulling and
replacing a
completion.
[0021] As used herein, a "well fluid" broadly refers to any fluid adapted to
be
introduced into a well for any well-servicing purpose. A well fluid can be,
for example, a
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drilling fluid, a cementing fluid, a treatment fluid, or a spacer fluid. If a
well fluid is to be
used in a relatively small volume, for example less than about 200 barrels, it
is sometimes
referred to in the art as a wash, dump, slug, or pill.
[00221 As used herein, "into a well" means introduced at least into and
through the
wellhead. According to various techniques known in the art, equipment, tools,
or well fluids
can be directed from the wellhead into any desired portion of the wellbore.
Additionally, a
well fluid can be directed from a portion of the wellbore into the rock matrix
of a zone.
Drilling and Drilling Fluids
[00231 The well is created by drilling a hole into the earth (or seabed) with
a drilling
rig that rotates a drill string with a drilling bit attached to the downward
end. Usually the
borehole is anywhere between about 5 inches (13 cm) to about 36 inches (91 cm)
in diameter.
The borehole usually is stepped down to a smaller diameter the deeper the
wellbore as upper
portions are cased or lined, which means that progressively smaller drilling
strings and bits
must be used to pass through the uphole casing or liner.
[00241 While drilling an oil or gas well, a drilling fluid is circulated
downhole
through a drillpipe to a drill bit at the downhole end, out through the drill
bit into the
wellbore, and then back uphole to the surface through the annular path between
the tubular
drillpipe and the borehole. The purpose of the drilling fluid is to maintain
hydrostatic
pressure in the wellbore, to lubricate the drill string, and to carry rock
cuttings out from the
wellbore.
[00251 The drilling fluid can be water-based or oil-based. Oil-based fluids
tend to
have better lubricating properties than water-based fluids, nevertheless,
other factors can
mitigate in favor of using a water-based drilling fluid.
[0026] In addition, the drilling fluid may be viscosified to help suspend and
carry
rock cuttings out from the wellbore. Rock cuttings can range in size from silt-
sized particles
to chunks measured in centimeters. Carrying capacity refers to the ability of
a circulating
drilling fluid to transport rock cuttings out of a wellbore. Other terms for
carrying capacity
include hole-cleaning capacity and cuttings lifting.
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Cementing and Hydraulic Cement Compositions
[00271 In performing cementing, a hydraulic cement composition is pumped as a
fluid (typically in the form of suspension or slurry) into a desired location
in the wellbore.
For example, in cementing a casing or liner, the hydraulic cement composition
is pumped
into the annular space between the exterior surfaces of a pipe string and the
borehole (that is,
the wall of the wellbore). The cement composition is allowed time to set in
the annular
space, thereby forming an annular sheath of hardened, substantially
impermeable cement.
The hardened cement supports and positions the pipe string in the wellbore and
bonds the
exterior surfaces of the pipe string to the walls of the wellbore.
[0028] Hydraulic cement is a material that when mixed with water hardens or
sets
over time because of a chemical reaction with the water. Because this is a
chemical reaction
with the water, hydraulic cement is capable of setting even under water. The
hydraulic
cement, water, and any other components are mixed to form a hydraulic cement
composition
in the initial state of a slurry, which should be a fluid for a sufficient
time before setting for
pumping the composition into the wellbore and for placement in a desired
downhole location
in the well.
Well Treatments and Treatment Fluids
[0029] Drilling, completion, and intervention operations can include various
types
of treatments that are commonly performed in a wellbore or subterranean
formation. For
example, a treatment for fluid-loss control can be used during any of
drilling, completion, and
intervention operations. During completion or intervention, stimulation is a
type of treatment
performed to enhance or restore the productivity of oil and gas from a well.
Stimulation
treatments fall into two main groups: hydraulic fracturing and matrix
treatments. Fracturing
treatments are performed above the fracture pressure of the subterranean
formation to create
or extend a highly permeable flow path between the formation and the wellbore.
Matrix
treatments are performed below the fracture pressure of the formation. Other
types of
completion or intervention treatments can include, for example, gravel
packing,
consolidation, and controlling excessive water production.
[0030] As used herein, the word "treatment" refers to any treatment for
changing a
condition of a wellbore or an adjacent subterranean formation. Examples of
treatments
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include fluid-loss control, isolation, stimulation, or conformance control;
however, the word
"treatment" does not necessarily imply any particular treatment purpose.
f00311 A treatment usually involves introducing a treatment fluid into a well.
As
used herein, a "treatment fluid" is a fluid used in a treatment. Unless the
context otherwise
requires, the word "treatment" in the term "treatment fluid" does not
necessarily imply any
particular treatment or action by the fluid. If a treatment fluid is to be
used in a relatively
small volume, for example less than about 200 barrels, it is sometimes
referred to in the art as
a slug or pill.
[0032] As used herein, a "treatment zone" refers to an interval of rock along
a
wellbore into which a treatment fluid is directed to flow from the wellbore.
Further, as used
herein, "into a treatment zone" means into and through the wellhead and,
additionally,
through the wellbore and into the treatment zone.
[0033] The following are some general descriptions of common well treatments
and
associated treatment fluids. Of course, other well treatments and treatment
fluids are known
in the art.
Well Treatment - Fluid-Loss Control
[0034] Fluid loss refers to the undesirable leakage of a fluid phase of a well
fluid
into the permeable matrix of a zone, which zone may or may not be a treatment
zone. Fluid-
loss control refers to treatments designed to reduce such undesirable leakage.
Providing
effective fluid-loss control for well fluids during certain stages of well
operations is usually
highly desirable.
[09351 The usual approach to fluid-loss control is to substantially reduce the
permeability of the matrix of the zone with a fluid-loss control material that
blocks the
permeability at or near the face of the rock matrix of the zone. For example,
the fluid-loss
control material may be a particulate that has a size selected to bridge and
plug the pore
throats of the matrix. All else being equal, the higher the concentration of
the particulate, the
faster bridging will occur. As the fluid phase carrying the fluid-loss control
material leaks
into the formation, the fluid-loss control material bridges the pore throats
of the matrix of the
formation and builds up on the surface of the borehole or fracture face or
penetrates only a
little into the matrix. The buildup of solid particulate or other fluid-loss
control material on
the walls of a wellbore or a fracture is referred to as a filter cake.
Depending on the nature of
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a fluid phase and the filter cake, such a filter cake may help block the
further loss of a fluid
phase (referred to as a filtrate) into the subterranean formation. A fluid-
loss control material
is specifically designed to lower the volume of a filtrate that passes through
a filter meditun.
10036) After application of a filter cake, however, it may be desirable to
restore
permeability into the formation. If the formation permeability of the desired
producing zone
is not restored, production levels from the formation can be significantly
lower. Any filter
cake or any solid or polymer filtration into the matrix of the zone resulting
from a fluid-loss
control treatment must be removed to restore the formation's permeability,
preferably to at
least its original level. This is often referred to as clean up.
100371 A variety of fluid-loss control materials have been used and evaluated
for
fluid-loss control and clean-up, including foams, oil-soluble resins, acid-
soluble solid
particulates, graded salt slurries, linear viscoelastic polymers, and heavy
metal-crosslinked
polymers. Their respective comparative effects are well documented.
[0038] Fluid-loss control materials are sometimes used in drilling fluids or
in
treatments that have been developed to control fluid loss. A fluid-loss
control pill is a
treatment fluid that is designed or used to provide some degree of fluid-loss
control. Through
a combination of viscosity, solids bridging, and cake buildup on the porous
rock, these pills
offentimes are able to substantially reduce the permeability of a zone of the
subterranean
formation to fluid loss. They also generally enhance filter-cake buildup on
the face of the
formation to inhibit fluid flow into the formation from the wellbore.
[0039] Fluid-loss control pills typically comprise an aqueous base fluid and a
high
concentration of a gelling agent polymer (usually crosslinked), and sometimes,
bridging
particles, like graded sand, graded salt particulate, or sized calcium
carbonate particulate. A
commonly used fluid-loss control pills contain high concentrations (100 to 150
lbs/1000 gal)
of derivatized hydroxyethylcellulose ("HEC"). HEC is generally accepted as a
gelling agent
affording minimal permeability damage during completion operations. Normally,
HEC
polymer solutions do not form rigid gels, but control fluid loss by a
viscosity-regulated or
filtration mechanism. Some other gelling agent polymers that have been used
include
xanthan, guar, guar derivatives, carboxymethylhydroxyethylcellulose ("CMHEC"),
and
starch. Viscoelastic surfactants can also be used.
100401 As an alternative to forming linear polymeric gels for fluid-loss
control,
crosslinked gels often are used. Crosslinking the gelling agent polymer
creates a gel structure
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that can support solids as well as provide fluid-loss control. Further,
crosslinked fluid-loss
control pills have demonstrated that they require relatively limited invasion
of the formation
face to be fully effective. To crosslink the gelling agent polymers, a
suitable crosslinking
agent that comprises polyvalent metal ions is used. Aluminum, titanium, and
zirconium are
common examples.
100411 A preferred crosslinkable gelling agent for fluid-loss control pills
are graft
copolymers of a hydroxyalkyl cellulose, guar, or hydroxypropyl guar that are
prepared by a
redox reaction with vinyl phosphonic acid. The gel is formed by hydrating the
graft
copolymer in an aqueous solution containing at least a trace amount of at
least one divalent
cation. The gel is crosslinked by the addition of a Lewis base or Bronsted-
Lowrey base so
that pH of the aqueous solution is adjusted from slightly acidic to slightly
basic. Preferably,
the chosen base is substantially free of polyvalent metal ions. The resulting
crosslinked gel
demonstrates shear-thinning and rehealing properties that provide relatively
easy pumping,
while the rehealed gel provides good fluid-loss control upon placement. This
gel can be
broken by reducing the pH of the fluid or by the use of oxidizers. Some fluid-
loss pills of this
type are described in U.S. Patent No. 5,304,620, assigned to Halliburton
Energy Services, the
relevant disclosure of which is incorporated herein by reference. Fluid-loss
control pills of
this type are commercially available under the trade name "K-MAX" from
Halliburton
Energy Services Inc. in Duncan, Oklahoma.
Well Treatment - Acidizing
[0042] A widely used stimulation technique is acidizing, in which a treatment
fluid
including an aqueous acid solution is introduced into the formation to
dissolve acid-soluble
materials. In this way, hydrocarbon fluids can more easily flow from the
formation into the
well. In addition, an acid treatment can facilitate the flow of injected
treatment fluids from
the well into the formation.
[0043] Acidizing techniques can be carried out as matrix acidizing procedures
or as
acid fracturing procedures.
[0044] In matrix acidizing, an acidizing fluid is injected from the well into
the
formation at a rate and pressure below the pressure sufficient to create a
fracture in the
formation. In sandstone formations, the acid primarily removes or dissolves
acid soluble
damage in the near wellbore region and is thus classically considered a damage
removal
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technique and not a stimulation technique. In carbonate formations, the goal
is to actually a
stimulation treatment where in the acid forms conducted channels called
wormholes in the
formation rock. Greater details, methodology, and exceptions can be found in
"Production
Enhancement with Acid Stimulation" 2nd edition by Leonard Kalfayan (PennWell
2008), SPE
129329, SPE 123869, SPE 121464, SPE 121803, SPE 121008, IPTC 10693, 66564-PA,
and
the references contained therein.
[00451 In acid fracturing, an acidizing fluid is pumped into a carbonate
formation at
a sufficient pressure to cause fracturing of the formation and creating
differential (non-
uniform) etching fracture conductivity. Greater details, methodology, and
exceptions can be
found in "Production Enhancement with Acid Stimulation" 2' edition by Leonard
Kalfayan
(PennWell 2008), SPE 129329, SPE 123869, SPE 121464, SPE 121803, SPE 121008,
IPTC
10693, 66564-PA, and the references contained therein.
Matrix Diversion
[00461 Matrix treatments in conventional reservoirs can utilize diversion.
True
matrix diversion does not apply, however, to ultra-low permeable formations.
[00471 For example, in subterranean treatments in conventional reservoirs, it
is
often desired to treat an interval of a subterranean formation having sections
of varying
permeability, reservoir pressures and/or varying degrees of formation damage,
and thus may
accept varying amounts of certain treatment fluids. For example, low reservoir
pressure in
certain areas of a subterranean formation or a rock matrix or a proppant pack
of high
permeability may permit that portion to accept larger amounts of certain
treatment fluids. It
may be difficult to obtain a uniform distribution of the treatment fluid
throughout the entire
interval. For instance, the treatment fluid may preferentially enter portions
of the interval
with low fluid flow resistance at the expense of portions of the interval with
higher fluid flow
resistance. In some instances, these intervals with variable flow resistance
may be water-
producing intervals. This is different from diversion between different zones.
See U.S.
application Serial No. 12/512,232, filed July 30, 2009, entitled "Methods of
Fluid Loss
Control and Fluid Diversion in Subterranean Formations," which is incorporated
by
reference.
[00481 In addition, relative permeability modifiers (RPMs) can be considered
another approach to matrix diversion.
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Well Treatment - Hydraulic Fracturing
[0049] Hydraulic fracturing, sometimes referred to as fracturing or fracing,
is a
common stimulation treatment. A treatment fluid adapted for this purpose is
sometimes
referred to as a fracturing fluid. The fracturing fluid is pumped at a
sufficiently high flow
rate and pressure into the wellbore and into the subterranean formation to
create or enhance a
fracture in the subterranean formation. Creating a fracture means making a new
fracture in
the formation. Enhancing a fracture means enlarging a pre-existing fracture in
the formation.
[0050j A frac pump is used for hydraulic fracturing. A frac pump is a high-
pressure, high-volume pump. Typically, a frac pump is a positive-displacement
reciprocating
pump. The structure of such a pump is resistant to the effects of pumping
abrasive fluids, and
the pump is constructed of materials that are resistant to the effects of
pumping corrosive
fluids. Abrasive fluids are suspensions of hard, solid particulates, such as
sand. Corrosive
fluids include, for example, acids. The fracturing fluid may be pumped down
into the
wellbore at high rates and pressures, for example, at a flow rate in excess of
50 barrels per
minute (2,100 U.S. gallons per minute, 8.0 m3) at a pressure in excess of
5,000 pounds per
square inch ("psi", 34,470 kPa). The pump rate and pressure of the fracturing
fluid may be
even higher, for example, flow rates in excess of 100 barrels per minute and
pressures in
excess of 10,000 psi (68,9501cPa) are common.
[0051] Fracturing a subterranean formation often uses hundreds of thousands of
gallons of fracturing fluid or more. Further, it is often desirable to
fracture more than one
treatment zone of a well. Thus, a high volume of fracturing fluids is often
used in fracturing
of a well, which means that a low-cost fracturing fluid is desirable. Because
of the ready
availability and relative low cost of water compared to other liquids, among
other
considerations, a fracturing fluid is usually water-based.
[0052] The creation or extension of a fracture in hydraulic fracturing occurs
suddenly. When this happens, the fracturing fluid suddenly has a fluid flow
path through the
fracture to flow more rapidly away from the wellbore, which may be detected as
a change in
pressure or fluid flow rate.
[0053] A newly-created or newly-extended fracture will tend to close together
after
the pumping of the fracturing fluid is stopped. To prevent the fracture from
closing, a
material is usually placed in the fracture to keep the fracture propped open
and to provide
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higher fluid conductivity than the matrix of the formation. A material used
for this purpose is
referred to as a proppant.
[0054] A proppant is in the form of a solid particulate, which can be
suspended in
the fracturing fluid, carried downhole, and deposited in the fracture to form
a proppant pack.
The proppant pack props the fracture in an open condition while allowing fluid
flow through
the permeability of the pack. The proppant pack in the fracture provides a
higher-
permeability flow path for the oil or gas to reach the wellbore compared to
the permeability
of the matrix of the surrounding subterranean formation. This higher-
permeability flow path
increases oil and gas production from the subterranean formation.
[0055] A particulate for use as a proppant is usually selected based on the
characteristics of size range, crush strength, and solid stability in the
types of fluids that are
encountered or used in wells. Preferably, a proppant should not melt,
dissolve, or otherwise
degrade from the solid state under the downhole conditions.
[0056] The proppant is selected to be an appropriate size to prop open the
fracture
and bridge the fracture width expected to be created by the fracturing
conditions and the
fracturing fluid. If the proppant is too large, it will not easily pass into a
fracture and will
screenout too early. If the proppant is too small, it will not provide the
fluid conductivity to
enhance production. See, for example, McGuire and Sikora, 1960. In the case of
fracturing
relatively permeable or even tight-gas reservoirs, a proppant pack should
provide higher
permeability than the matrix of the formation. In the case of fracturing ultra-
low permeable
formations, such as shale formations, a proppant pack should provide for
higher permeability
than the naturally occurring fractures or other micro-fractures of the
fracture complexity.
[0057] Appropriate sizes of particulate for use as a proppant are typically in
the
range from about 8 to about 100 U.S. Standard Mesh. A typical proppant is sand-
sized,
which geologically is defined as having a largest dimension ranging from about
0.06 millimeters up to about 2 millimeters (mm). (The next smaller particle
size class below
sand sized is silt, which is defined as having a largest dimension ranging
from less than about
0.06 nun down to about 0.004 nun.) As used herein, proppant does not mean or
refer to
suspended solids, silt, fines, or other types of insoluble solid particulate
smaller than about
0.06 mm (about 230 U.S. Standard Mesh). Further, it does not mean or refer to
particulates
larger than about 3 nun (about 7 U.S. Standard Mesh).
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(00581 The proppant is sufficiently strong, that is, has a sufficient
compressive or
crush resistance, to prop the fracture open without being deformed or crushed
by the closure
stress of the fracture in the subterranean formation. For example, for a
proppant material that
crushes under closure stress, a 20/40 mesh proppant preferably has an API
crush strength of
at least 4,000 psi (27,580 kPa) closure stress based on 10% crush fines
according to
procedure API RP-56. A 12/20 mesh proppant material preferably has an API
crush strength
of at least 4,000 psi (27,580 kPa) closure stress based on 16% crush fines
according to
procedure API RP-56. This performance is that of a medium crush-strength
proppant,
whereas a very high crush-strength proppant would have a crush-strength of
about 10,000 psi
(68,950 kPa). In comparison, for example, a 100-mesh proppant material for use
in an ultra-
low permeable formation such as shale preferably has an API crush strength of
at least
5,000 psi (34,470 kPa) closure stress based on 6% crush fines. The higher the
closing
pressure of the formation of the fracturing application, the higher the
strength of proppant is
needed. The closure stress depends on a number of factors known in the art,
including the
depth of the formation.
[0059] Further, a suitable proppant should be stable over time and not
dissolve in
fluids commonly encountered in a well environment. Preferably, a proppant
material is
selected that will not dissolve in water or crude oil.
100601 Suitable proppant materials include, but are not limited to, sand
(silica),
ground nut shells or fruit pits, sintered bauxite, glass, plastics, ceramic
materials, processed
wood, resin coated sand or ground nut shells or fruit pits or other
composites, and any
combination of the foregoing. Mixtures of different kinds or sizes of proppant
can be used as
well. In conventional reservoirs, if sand is used, it commonly has a median
size anywhere
within the range of about 20 to about 100 U.S. Standard Mesh. For a synthetic
proppant, it
commonly has a median size anywhere within the range of about 8 to about 100
U.S.
Standard Mesh.
[0061] The concentration of proppant in the treatment fluid depends on the
nature of
the subterranean formation. As the nature of subterranean formations differs
widely, the
concentration of proppant in the treatment fluid may be in the range of from
about
0.03 kilograms to about 12 kilograms of proppant per liter of liquid phase
(from about
0.1 lb/gal to about 25 lb/gal).
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Tip Screenout in Fracturing Permeable Formations
[0062] The conductivity of propped fractures depends on, among other things,
fracture width and fracture permeability. The permeability can be estimated
based on the size
of the proppant. The width of a fracture depends on the nature of the
formation and the
specific fracturing conditions.
100631 In relatively permeable formations, it is often desirable to maximize
the
length of the fractures created by hydraulic fracturing treatments, so that
the surface area of
the fractures, and therefore the area serviced by the well, may be maximized.
In certain frac-
packing treatments, particularly in weakly-consolidated highly-permeable sand
formations, it
may be more desirable to form short, wide fractures that feature high fracture
conductivities.
[0064] One way of creating such short, wide fractures is with a tip screenout.
In a
tip screenout, the growth of the fracture length is arrested when the proppant
concentration at
the tip of the fracture becomes highly concentrated, typically due to fluid
leak-off into the
surrounding formation. In a fracture tip screenout, the proppant bridges the
narrow gaps at
the tip of the fracture and are packed into the fracture, thus restricting
flow to the fracture tip,
which may terminate the extension of the fracture into the formation, among
other things,
because the hydraulic pressure of the stimulation fluid may not be transmitted
from the
wellbore to the fracture tip. The concentrated proppant slurry plugs the
fracture and prevents
additional lengthening of the fracture. Any additional pumping of the proppant
slurry beyond
this point causes the fracture to widen or balloon and packs the existing
fracture length with
additional proppant. This results in a relatively short, wide fracture having
both high fracture
conductivity and a high proppant concentration.
[0065] Being able to control the initiation of a fracture tip screenout may be
an
important aspect of a successful fracturing operation. Without control of the
fracture tip
screenout. a fracture may not be packed with proppant as needed, e.g., to have
the desired
fracture width near the wellbore.
[0066] Conventionally, to initiate a fracture tip screenout, the flow rate of
the
fracturing fluid is reduced while increasing proppant concentration therein,
with the
anticipation that this combination will cause a fracture tip screenout. Design
features
typically employed in situations in which a tip screenout is desired often
involve methods of
ensuring that fluid leak-off is high relative to the rate and amount of
proppant injection. This
can be achieved in a number of ways, including, but not limited to, using a
small amount of
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pad fluid to initiate the fracture, using little or no fluid loss additive,
using high proppant
concentrations earlier in the treatment, pumping more slowly during the
fracturing operation,
or some combination thereof. However, this methodology does not consistently
cause
fracture tip screenouts. While increasing the proppant concentration and
decreasing the flow
rate does increase the probability that a fracture tip screenout may occur,
this methodology
assumes that there is one fracture taking all of the fluid. But, where there
are competing
fractures, the initiation of a fracture tip screenout may be difficult to
control and/or predict
using conventional methodologies. Pressure transients collected by downhole
pressure
gauges during frac-packing treatments indicate that tip screenouts often do
not occur when
and where desired or intended. Instead, the fluid at the tip of the fracture
often remains
mobile, the fracture tip continues to grow throughout the treatment, and the
desired proppant
concentration in the fracture is not reached. Because of this, the desired
high fracture
conductivity may not be obtained.
[0067j For example, in deviated wellbores, where only a portion of the
perforations
communicate with the dominant fracture that is being extended (when using
conventional
technologies), fluid is lost (e.g., leaking oft) into other portions or
fractures in the well
besides the dominant fracture. Dependent upon the rate of fluid loss into the
formation, these
conventional methodologies may not successfully generate a tip screenout in
the fracture.
[0068] Furthermore, the conventional methods cannot predict when the screenout
occurs, and, therefore, while it is desirable for the proppant to bridge at
the tip of the fracture
and pack therein, the bridging of the proppant and thus the screenout may
occur anywhere in
the fracture. Oftentimes, this may happen near the wellbore, before the high
concentration
proppant reaches the fracture, causing an undesirable screenout inside the
well bore. If the
screenout does not occur at the tip, and the fracture is not gradually filled
with proppant
afterwards, the fracture may not be packed with proppant as desired.
[0069] One method of inducing and controlling tip screenout includes pumping
an
annulus fluid into an annulus, between the subterranean formation and a work
string disposed
within a wellbore penetrating the subterranean formation, at an annulus flow
rate; and
reducing the annulus flow rate below a fracture initiation flow point so that
the fracture tip
screenout is initiated in the one or more fractures in the subterranean
formation. U.S. Patent
No. 7,237,612, issued July 3, 2007, titled "Methods of Initiating a fracture
Tip Screenout"
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having for named inventors Jim B. Surjaatmadja, Billy W. McDaniel, Mark
Farabee, David
Adams, and Loyd East.
[0070] Another method of inducing and controlling tip screenout during a frac-
packing treatment comprising injecting a proppant slurry into a subterranean
formation,
wherein the proppant slurry comprises a proppant material, a fracturing fluid,
and degradable
particulates and wherein the degradable particulates physically interact with
themselves and
with the proppant material to aid in inducing tip screenout. U.S. Patent
7,413,017, issued
August 19, 2008, titled "Methods and Compositions for Inducing Tip-Screenouts
in Frac-
Packing Operations" having for named inventors Philip D. Nguyen and Anne M.
Culotta.
[0071] Tip screenout requires considerable fluid loss while at fracturing
rates. This
necessitates a high permeability formation and cannot occur in low
permeability formations
that have a matrix permeability less than 1,000 microDarcy (equivalent to 1
milliDarcy,
9.869233 x 10-16 m2), much less in ultra-low permeable formations that have a
matrix
permeability less than 1 microDarcy (equivalent to 0.001 milliDarcy, 9.869233
x 10-19 m2).
Well Treatment - Staged Fracturing and Zone Diversion
[0072] Multiple or staged fracturing involves fracturing two or more different
zones
of a wellbore in succession. Staged hydraulic fracturing operations are
commonly performed
from horizontal wellbores placed in shale gas reservoirs.
[0073] In the context of staged fracturing, diversion techniques are used to
divert a
fracturing fluid from one zone to a different zone. Diversion techniques fall
into two main
categories: mechanical diversion and chemical diversion. Mechanical diversion
includes the
use of mechanical devices, such as ball sealers or packers, to isolate one
zone from another
and divert a treatment fluid to the desired zone. Chemical diversion includes
the use of
chemicals to divert a treatment fluid from entering a zone in favor of
entering a different
zone.
[0074] In conventional methods of treating subterranean formations, once the
less
fluid flow-resistant zone of a subterranean formation has been treated, that
zone may be
sealed off using a variety of techniques to divert treatment fluids to a more
fluid flow-
resistant zone of the well. Such techniques may have involved, among other
things, the
injection of particulates, foams, emulsions, plugs, packers, or blocking
polymers (e.g.,
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crosslinked aqueous gels) into the interval so as to plug off high-
permeability portions of the
subterranean formation once they have been treated, thereby diverting
subsequently injected
fluids to more fluid flow-resistant portions of the subterranean formation.
[0075] For example, near wellbore diversion is a near-wellbore treatment that
causes a zone to greatly reduce or stop the taking of fluid so that the fluid
is then diverted to
enter another zone. This can be accomplished, for example, by plugging
wellbore
perforations or plugging a near-wellbore proppant pack. According to some
techniques
known in the art, diversion from one zone to another can be accomplished
without stopping
the pumping of one or more fracturing fluids into the well.
[0076] A fracturing stage includes pumping one or more fracturing fluids into
the
treatment zone at a rate and pressure above the fracture pressure of the
treatment zone.
Designing a fracturing stage usually includes determining a designed total
pumping time for
the stage or determining a designed total pumping volume of fracturing fluid
for the
fracturing stage. The tail end of a fracturing stage is the last portion of
pumping time into the
zone or the last portion of the volume of fracturing fluid pumped into the
zone. This is
usually about the last minute of total pumping time or about the last wellbore
volume of a
fracturing fluid to be pumped into the zone. The portion of pumping time or
fracturing fluid
volume that is pumped before the tail end of a fracturing stage reaches into a
far-field region
of the zone.
[00771 A person of skill in the art is able to plan each fracturing stage in
detail,
subject to unexpected or undesired early screenout or other problems that
might be
encountered in fracturing a well. A person of skill in the art is able to
determine the wellbore
volume between the wellhead and the zone. In addition, a person of skill in
the art is able to
determine the time within a few seconds in which a well fluid pumped into a
well should take
to reach a zone.
[0078] In addition to being designed in advance, the actual point at which a
fracturing fluid is diverted from a zone can be determined by a person of
skill in the art,
including based on observed changes in well pressures or flow rates.
Well Treatment - Gravel Packing
[0079] A solid particulate also can be used for gravel packing operations.
Gravel
packing is commonly used as a sand-control method to prevent production of
formation sand
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from a poorly consolidated subterranean formation. In gravel packing, a
mechanical screen is
placed in the wellbore and the surrounding annulus packed with a particulate
of a specific
size designed to prevent the passage of formation sand. The primary objective
is to stabilize
the formation while causing minimal impairment to well productivity.
[00801 The particulate used for this purpose is referred to as "gravel." In
the oil and
gas field, and as used herein, the term "gravel" is refers to relatively large
particles in the
sand size classification, that is, particles ranging in diameter from about
0.1 mm up to about
2 mm. Generally, a particulate having the properties, including chemical
stability, of a low-
strength proppant is used in gravel packing. An example of a commonly used
gravel packing
material is sand.
[00811 A sereenout is a condition encountered during some gravel-pack
operations
wherein the treatment area cannot accept further packing gravel (larger sand).
Under ideal
conditions, this should signify that the entire void area has been
successfully packed with the
gravel. However, if screenout occurs earlier than expected in the treatment,
it may indicate
an incomplete treatment and the presence of undesirable voids within the
treatment zone.
Increasing Viscosity of Fluid for Suspending Particulate
[00821 Various particulates can be employed in a fluid for use in a well or a
fluid
can be used to help remove particulates from a well.
[00831 For example, during drilling, rock cuttings should be carried by the
drilling
fluid and flowed out of the wellbore. The rock cuttings typically have
specific gravity greater
than 2, which is much higher than that of many drilling fluids.
[00841 Similarly, a proppant used in fracturing may have a much different
density
than the fracturing fluid. For example, sand has a specific gravity of about
2.7, where water
has a specific gravity of 1.0 at Standard Laboratory conditions of temperature
and pressure.
A proppant having a different density than water will tend to separate from
water very
* rapidly.
[00851 As many well fluids are water-based, partly for the purpose of helping
to
suspend particulate of higher density, and for other reasons known in the art,
the density of
the fluid used in a well can be increased by included highly water-soluble
salts in the water,
such as potassium chloride. However, increasing the density of a well fluid
will rarely be
sufficient to match the density of the particulate.
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[0086] Increasing the viscosity of a well fluid can help prevent a particulate
having
a different specific gravity than an external phase of the fluid from quickly
separating out of
the external phase.
Emulsion for Increasing Viscosity
[0087] The internal-phase droplets of an emulsion disrupt streamlines and
require
more effort to get the same flow rate. Thus, an emulsion tends to have a
higher viscosity than
the external phase of the emulsion would otherwise have by itself. This
property of an
emulsion can be used to help suspend a particulate material in an emulsion.
This technique
for increasing the viscosity of a liquid can be used separately or in
combination with other
techniques for increasing the viscosity of a fluid.
[0088] As used herein, to "break" an emulsion means to cause the creaming and
coalescence of emulsified drops of the internal dispersed phase so that they
the internal phase
separates out of the external phase. Breaking an emulsion can be accomplished
mechanically
(for example, in settlers, cyclones, or centrifuges) or with chemical
additives to increase the
surface tension of the internal droplets.
Viscosity-Increasing Agent
100891 A viscosity-increasing agent is sometimes referred to in the art as a
thickener, gelling agent, or suspending agent. There are several kinds of
viscosity-increasing
agents and related techniques for increasing the viscosity of a fluid.
[0090] In general, because of the high volume of fracturing fluid typically
used in a
fracturing operation, it is desirable to efficiently increase the viscosity of
fracturing fluids to
the desired viscosity using as little viscosity-increasing agent as possible.
In addition,
relatively inexpensive materials are preferred. Being able to use only a small
concentration
of the viscosity-increasing agent requires a lesser amount of the viscosity-
increasing agent in
order to achieve the desired fluid viscosity in a large volume of fracturing
fluid.
Polymers for Increasing Viscosity
[0091] Certain kinds of polymers can be used to increase the viscosity of a
fluid. In
general, the purpose of using a polymer is to increase the ability of the
fluid to suspend and
carry a particulate material. Polymers for increasing the viscosity of a fluid
are preferably
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soluble in the external phase of a fluid. Polymers for increasing the
viscosity of a fluid can
be naturally occurring polymers such as polysaccharides, derivatives of
naturally occurring
polymers, or synthetic polymers.
Water-Soluble Polysaccharides or Derivatives for Increasing Viscosity
[0092] Fracturing fluids are usually water-based. Efficient and inexpensive
viscosity-increasing agents for water include certain classes of water-soluble
polymers.
[0093] Water-soluble polysaccharides are often used to the extent of at least
10 mg
per liter in water at 25 C. More preferably, the water-soluble polymer is
also used to the
extent of at least 10 mg per liter in an aqueous sodium chloride solution of
32 grams sodium
chloride per liter of water at 25 C. As will be appreciated by a person of
skill in the art, the
solubility or dispersability in water of a certain kind of polymeric material
may be dependent
on the salinity or pH of the water. Accordingly, the salinity or pH of the
water can be
modified to facilitate the solubility or dispersability of the water-soluble
polymer. In some
cases, the water-soluble polymer can be mixed with a surfactant to facilitate
its solubility in
the water or salt solution utilized.
[0094] The water-soluble polymer can have an average molecular weight in the
range of from about 50,000 to 20,000,000, most preferably from about 100,000
to about
3,000,000.
[0095] Typical water-soluble polymers used in well treatments are water-
soluble
polysaccharides and water-soluble synthetic polymers (e.g., polyacrylamide).
The most
common water-soluble polysaccharide employed in well treatments is guar and
its
derivatives.
[0096] A polysaccharide can be classified as being non-helical or helical (or
random
coil type) based on its solution structure in aqueous liquid media. Examples
of non-helical
polysaccharides include guar, guar derivatives, and cellulose derivatives.
Examples of helical
polysaccharides include xanthan, diutan, and scleroglucan, and derivatives of
any of these.
[0097] As used herein, a "polysaccharide" can broadly include a modified or
derivative polysaccharide. As used herein, "modified" or "derivative" means a
compound or
substance formed by a chemical process from a parent compound or substance,
wherein the
chemical skeleton of the parent exists in the derivative. The chemical process
preferably
includes at most a few chemical reaction steps, and more preferably only one
or two chemical
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reaction steps. As used herein, a "chemical reaction step" is a chemical
reaction between two
chemical reactant species to produce at least one chemically different species
from the
reactants (regardless of the number of transient chemical species that may be
formed during
the reaction). An example of a chemical step is a substitution reaction.
Substitution on a
polymeric material may be partial or complete.
[0098] A guar derivative can be selected from the group consisting of, for
example,
a carboxyalkyl derivative of guar, a hydroxyalkyl derivative of guar, and any
combination
thereof.
Preferably, the guar derivative is selected from the group consisting of
carboxymethylguar, carboxyrnethylhydroxyethylguar,
hydroxyethylguar,
carboxymethylhydroxypropylguar, ethyl-carboxymethylguar, and
hydroxypropylmethylguar.
[0099] A cellulose derivative can be selected from the group consisting of,
for
example, a carboxyalkyl derivative of cellulose, a hydroxyalkyl derivative of
cellulose, and
any combination thereof. Preferably, the cellulose derivative is selected from
the group
consisting of carboxymethylcellulo se,
carboxymethylhydroxyethyl cellulose,
hydroxyethylcellulose, methyl-cellulose, ethylcellulose,
ethylcarboxymethylcellulose, and
hydroxypropylmethyl cellulose.
Crosslinking of Polysaccharide to Increase Viscosity of a Fluid or Form a Gel
[0100] The viscosity of a fluid at a given concentration of viscosity-
increasing agent
can be greatly increased by crosslinking the viscosity-increasing agent. A
crosslinking agent,
sometimes referred to as a crosslinker, can be used for this purpose. One
example of a
crosslinking agent is the borate ion. If a polysaccharide is crosslinked to a
sufficient extent, it
can form a gel with water. Gel formation is based on a number of factors
including the
particular polymer and concentration thereof, the particular crosslinker and
concentration
thereof, the degree of crosslinking, temperature, and a variety of other
factors known to those
of ordinary skill in the art.
[0101] A base gel is a fluid that includes a viscosity-increasing agent, such
as guar,
but that excludes crosslinking agents. Typically, a base gel is a fluid that
is mixed with
another fluid containing a crosslinker, wherein the mixed fluid is adapted to
form a gel after
injection downhole at a desired time in a well treatment. A base gel can be
used, for
example, as the external phase of an emulsion.
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Breaker for Polysaccharide or Crosslinked Polysaccharide
[0102] Drilling or treatment fluids also commonly include a breaker for a
polysaccharide or crosslinked polysaccharide. In this context of viscosity
increase provided
by a use of a polysaccharide, the term break or breaker as used herein refers
to a reduction in
the viscosity of a fluid or gel by some breaking of the polymer backbones or
some breaking
or reversing of the crosslinks between polymer molecules. No particular
mechanism is
necessarily implied by the term. A breaker for this purpose can be, for
example, an acid, a
base, an oxidizer, an enzyme, a chelating agent for a metal crosslinker, an
azo compound, or
a combination of these. The acids, oxidizers, or enzymes can be in the form of
delayed-
release or encapsulated breakers.
[0103] Examples of such suitable breakers for treatment fluids of the present
invention include, but are not limited to, sodium chlorites, hypochlorites,
perborate,
persulfates, and peroxides (including organic peroxides). Other suitable
breakers include, but
are not limited to, suitable acids and peroxide breakers, delinkers, as well
as enzymes that
may be effective in breaking viscosified treatment fluids. The breaker may be
citric acid,
tetrasodium EDTA, ammonium persulfate, or cellulose enzymes. A breaker may be
included
in a treatment fluid of the present invention in an amount and form sufficient
to achieve the
desired viscosity reduction at a desired time. The breaker may be formulated
to provide a
delayed break, if desired. For example, a suitable breaker may be encapsulated
if desired.
Suitable encapsulation methods are known to those skilled in the art. One
suitable
encapsulation method involves coating the selected breaker in a porous
material that allows
for release of the breaker at a controlled rate. Another suitable
encapsulation method that
may be used involves coating the chosen breakers with a material that will
degrade when
downhole so as to release the breaker when desired. Resins that may be
suitable include, but
are not limited to, polymeric materials that will degrade when downhole.
[0104] A treatment fluid can optionally comprise an activator or a retarder
to,
among other things, optimize the break rate provided by a breaker. Any known
activator or
retarder that is compatible with the particular breaker used is suitable for
use in the present
invention. Examples of such suitable activators include, but are not limited
to, acid
generating materials, chelated iron, copper, cobalt, and reducing sugars.
Examples of
suitable retarders include sodium thiosulfate, methanol, and
diethylenetriamine.
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[0105] In the case of a crosslinked viscosity-increasing agent, for example,
one way to
diminish the viscosity is by breaking the crosslinks. For example, the borate
crosslinks in a
borate-crosslinked gel can be broken by lowering the pH of the fluid. At a pH
above 8, the
borate ion exists and is available to crosslink and cause gelling. At a lower
pH, the borate ion
reacts with proton and is not available for crosslinking, thus, an increase in
viscosity due to
borate crosslinking is reversible.
Viscastftittg Surfactants (i.e. Viscoelastic Surfactants)
[0106] It should be understood that merely increasing the viscosity of a fluid
may only
slow the settling or separation of distinct phases and does not necessarily
gel the fluid.
[0107] Certain viscosity-increasing agents can also help suspend a particulate
material
by increasing the elastic modulus of the fluid. The elastic modulus is the
measure of a
substance's tendency to be deformed non-permanently when a force is applied to
it. The
elastic modulus of a fluid, commonly referred to as G', is a mathematical
expression and
defined as the slope of a stress versus strain curve in the elastic
deformation region. G' is
expressed in units of pressure, for example, Pa (Pascals) or dynes/cm2. As a
point of
reference, the elastic modulus of water is negligible and considered to be
zero. An example of
a viscosity-increasing agent that also increases the elastic modulus of a
fluid is a viscoelastic
surfactant.
[0108] An example of a viscosity-increasing agent that is also capable of
increasing
the suspending capacity of a fluid is to use a viscoelastic surfactant. As
used herein, the term
"viscoelastic surfactant" refers to a surfactant that imparts or is capable of
imparting
viscoelastic behavior to a fluid due, at least in part, to the association of
surfactant molecules
to form viscosifying micelles. These viscoelastic surfactants may be cationic,
anionic, or
amphoteric in nature. The viscoelastic surfactants can comprise any number of
different
compounds, including methyl ester sulfonates (e.g., as described in U.S.
patent application
Serial Nos. 11/058,660, 11/058,475, 11/058,612, and 11/058,611, filed Feb. 15,
2005,
hydrolyzed keratin (e.g., as described in U.S. Patent No. 6,547,871,
sulfosuccinates, taurates,
amine oxides, ethoxylated amides, alkoxylated fatty acids, alkoxylated
alcohols (e.g., lauryl
alcohol ethoxylate, ethoxylated nonyl phenol), ethoxylated fatty amines some
of which are
described in U.S. Patent Nos.
4,061580,
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4,324,669, and 4,215,001, ethoxylated alkyl amines (e.g., cocoalkylamine
ethoxylate),
betaines, modified betaines, alkylamidobetaines (e.g., cocoamidopropyl
betaine), quaternary
ammonium compounds (e.g., trimethyltallowammonium chloride, trimethyl-
cocoammonium
chloride), derivatives thereof, and combinations thereof
[0109] Suitable viscoelastic surfactants may comprise mixtures of several
different
compounds, including but not limited to: mixtures of an ammonium salt of an
alkyl ether
sulfate, a cocoamidopropyl betaine surfactant, a cocoamidopropyl dimethylamine
oxide
surfactant, sodium chloride, and water; mixtures of an ammonium salt of an
alkyl ether
sulfate surfactant, a cocoamidopropyl hydroxysultaine surfactant, a
cocoamidopropyl
dimethylamine oxide surfactant, sodium chloride, and water; mixtures of an
ethoxylated
alcohol ether sulfate surfactant, an alkyl or alkene amidopropyl betaine
surfactant, and an
alkyl or alkene dimethylamine oxide surfactant; aqueous solutions of an alpha-
olefinic
sulfonate surfactant and a betaine surfactant; and combinations thereof
Examples of suitable
mixtures of an ethoxylated alcohol ether sulfate surfactant, an alkyl or
alkene amidopropyl
betaine surfactant, and an alkyl or alkene dimethylamine oxide surfactant are
described in
U.S. Patent No. 6,063,738. Examples of suitable aqueous solutions of an alpha-
olefinic
sulfonate surfactant and a betaine surfactant are described in U.S. Patent No.
5,879,699.
[0110] Examples of commercially-available viscoelastic surfactants suitable
for use in
the present invention can include, but are not limited to, Mirataine BET-0
3OTM (an
oleamidopropyl betaine surfactant available from Rhodia Inc., Cranbury, N.J.),
Aromox
APA-T (amine oxide surfactant available from Akzo Nobel Chemicals, Chicago,
HI.),
Ethoquad 0/12 PGTM (a fatty amine ethoxylate quat surfactant available from
Akzo Nobel
Chemicals, Chicago, Ill.), Ethomeen T/I2Tm (a fatty amine ethoxylate
surfactant available
from Akzo Nobel Chemicals, Chicago, Ill.), Ethomeen S/I2TM (a fatty amine
ethoxylate
surfactant available from Akzo Nobel Chemicals, Chicago, III), and Rewoteric
AM TEGTm (a
tallow dihydroxyethyl betaine amphoteric surfactant available from Degussa
Corp.,
Parsippany, N.J.). See, for example, U.S. Patent No. 7,727,935, issued June 1,
2010.
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Viscous Fluid Damage to Permeability
[0111] In the fracturing of conventional reservoirs having relatively high
permeability, viscous fluids used for carrying a proppant can damage the
permeability of the
proppant pack or the subterranean formation near the fracture. For example, a
fracturing
fluid may be or include a gel that is deposited in the fracture. The fluid may
include
surfactants that leave unbroken micelles in the fracture or change the
wettability of the
formation in the region of the fracture. The higher the viscosity of the
fracturing fluid, the
more likely it is to damage the permeability of a proppant pack or formation.
[0112] Breakers are utilized in many treatments to mitigate fluid damage in
the
fracture. However, breakers and other treatments are subject to variability of
results, they
add expense and complication to a fracture treatment, and in all cases still
leave at least some
fluid damage in the fracture.
[0113] In addition, the chemistry of fracturing gels, including the
crosslinking of
gels, creates complications when designing fracture treatments for a broad
range of
temperatures. After a fracture treatment, fracturing fluid that flows back to
the surface must
be disposed of, and the more fluid that is utilized in the treatment the
greater the disposal risk
and expense. Accordingly, in the fracturing of conventional reservoirs where
the matrix
permeability allows the fracturing fluid to enter the matrix of the formation
rock, it is often
desirable to minimize fluid loss into the formation.
Other Uses of Polymers in Well Fluids, For Example, As Friction Reducer
[0114] There are other uses for a polymers in a well fluid. For example, a
polymer
may be used as a friction reducer.
101151 During the drilling, completion and stimulation of subterranean wells,
well
fluids are often pumped through tubular structures (e.g., pipes, coiled
tubing, etc.). A
considerable amount of energy may be lost due to turbulence in the treatment
fluid. Because
of these energy losses, additional horsepower may be necessary to achieve the
desired
treatment. To reduce these energy losses, certain polymers (referred to herein
as "friction-
reducing polymers") have been included in these treatment fluids.
[01161 For example, one type of hydraulic fracturing treatment that may
utilize
friction-reducing polymers is commonly referred to as "high-rate water
fracturing" or "slick
water fracturing." As will be appreciated by those of ordinary skill in the
art, fracturing
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fluids used in these high-rate water-fracturing systems are generally not
gels. As such, in
high-rate water fracturing, fluid velocity rather than viscosity is relied on
for proppant
transport. Additionally, while fluids used in high-rate water fracturing may
contain a
friction-reducing polymer, the friction-reducing polymer is generally included
in the
fracturing fluid in an amount sufficient to provide the desired friction
reduction without gel
formation. Gel formation would cause an undesirable increase in fluid
viscosity that would
result in increased pumping horsepower requirements. More preferably, a
friction-reducing
polymer is used in an amount that is sufficient to provide the desired
friction reduction
without appreciably viscosifying the fluid and usually without a crosslinker.
As a result, the
fracturing fluids used in these high-rate water-fracturing operations
generally have a lower
viscosity than conventional fracturing fluids. Typically, a well fluid in
which a polymer is
used as a friction reducer has a viscosity in the range of about 0.7 cP
(0.0007 Pas) to about
about 10 cP (0.01 Pas). For the purposes of this disclosure, viscosities are
measured at room
temperature using a FANN Model 35 viscometer at 300 rpm with a 1/5 spring.
101171 An example of a stimulation operation that may utilize friction
reducing
polymers is hydraulic fracturing. Hydraulic fracturing is a process commonly
used to
increase the flow of desirable fluids, such as oil and gas, from a portion of
a subterranean
formation. In hydraulic fracturing, a fracturing fluid may be introduced into
the subterranean
formation at or above a pressure sufficient to create or enhance one or more
fractures in the
formation. Enhancing a fracture may include enlarging a pre-existing fracture
in the
formation. To reduce frictional energy losses within the fracturing fluid,
friction-reducing
polymers may be included in the fracturing fluid. One type of hydraulic
fracturing treatment
that may utilize friction-reducing polymers is commonly referred to as "high
rate water
fracturing" or "slick water fracturing." As will be appreciated by those of
ordinary skill in
the art, fracturing fluids used in these high rate water-fracturing systems
are generally not
gels. As such, in high rate water fracturing, velocity rather than the fluid
viscosity is relied
on for proppant transport. Additionally, while fluids used in high rate water
fracturing may
contain a friction-reducing polymer, the friction-reducing polymer is
generally included in
the fracturing fluid in an amount sufficient to provide the desired friction
reduction without
gel formation. Gel formation would cause an undesirable increase in fluid
viscosity that
would, in return, result in increased horsepower requirements.
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[0118] Suitable friction reducing polymers should reduce energy losses due to
turbulence within the treatment fluid. Those of ordinary skill in the art will
appreciate that
the friction reducing polymer(s) included in the treatment fluid should have a
molecular
weight sufficient to provide a desired level of friction reduction. In
general, polymers having
higher molecular weights may be needed to provide a desirable level of
friction reduction.
By way of example, the average molecular weight of suitable friction reducing
polymers may
be at least about 2,500,000, as determined using intrinsic viscosities. The
average molecular
weight of suitable friction reducing polymers may be in the range of from
about 7,500,000 to
about 20,000,000. Those of ordinary skill in the art will recognize that
friction-reducing
polymers having molecular weights outside the listed range may still provide
some degree of
friction reduction. Typically, friction-reducing polymers are linear and
flexible, for example,
having a persistence length <10 nm.
[0119] A wide variety of friction reducing polymers may be suitable for use
with
the present invention. The friction-reducing polymer may be a synthetic
polymer.
Additionally, for example, the friction-reducing polymer may be an anionic
polymer or a
cationic polymer.
[0120] By way of example, suitable synthetic polymers may comprise any of a
variety of monomeric units, including acrylamide, acrylic acid, 2-acrylamido-2-
methylpropane sulfonic acid, N,N-dimethylacrylamide, vinyl sulfonic acid, N-
vinyl
acetamide, N-vinyl fortnatnide, itaconic acid, methacrylic acid, acrylic acid
esters,
methacrylic acid esters, quaternized aminoalkyl acrylate, such as a copolymer
of acrylamide
and dimethylaminoethyl acrylate quatemized with benzyl chloride, and mixtures
thereof.
[0121] Examples of suitable friction reducing polymers are described in U.S.
Patent
No. 6,784,141, U.S. patent application Serial No. 11/156,356, U.S. patent
application Ser.
No. 11300,614, and U.S. patent application Serial No. 11300,615, the
disclosure of which is
incorporated herein by reference. Combinations of suitable friction reducing
polymers may
also be suitable for use.
[0122] One example of a suitable anionic friction-reducing polymer is a
polymer
comprising acrylamide and acrylic acid. The acrylarnide and acrylic acid may
be present in
the polymer in any suitable concentration. An example of a suitable anionic
friction reducing
polymer may comprise acrylamide in an amount in the range of from about 5% to
about 95%
and acrylic acid in an amount in the range of from about 5% to about 95%.
Another example
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of a suitable anionic friction-reducing polymer may comprise acrylamide in an
amount in the
range of from about 60% to about 90% by weight and acrylic acid in an amount
in the range
of from about 10% to about 40% by weight. Another example of a suitable
anionic friction-
reducing polymer may comprise acrylamide in an amount in the range of from
about 80% to
about 90% by weight and acrylic acid in an amount in the range of from about
10% to about
20% by weight. Yet another example of a suitable anionic friction-reducing
polymer may
comprise acrylamide in an amount of about 85% by weight and acrylic acid in an
amount of
about 15% by weight. As previously mentioned, one or more additional monomers
may be
included in the anionic friction reducing polymer comprising acrylamide and
acrylic acid. By
way of example, the additional monomer(s) may be present in the anionic
friction-reducing
polymer in an amount up to about 20% by weight of the polymer.
[0123] Suitable friction-reducing polymers may be in an acid form or in a salt
form.
As will be appreciated, a variety of salts may be prepared, for example, by
neutralizing the
acid form of the acrylic acid monomer or the 2-acrylamido-2-methylpropane
sulfonic acid
monomer. In addition, the acid form of the polymer may be neutralized by ions
present in the
treatment fluid. As used herein, the term "polymer" is intended to refer to
the acid form of the
friction-reducing polymer, as well as its various salts.
[0124] As will be appreciated, the friction-reducing polymers suitable for use
in the
present technique may be prepared by any suitable technique. For example, the
anionic
friction-reducing polymer comprising acrylamide and acrylic acid may be
prepared through
polymerization of acrylamide and acrylic acid or through hydrolysis of
polyacrylamide (e.g.,
partially hydrolyzed polyacrylamide). See, for example, U.S. Patent Nos.
7,846,878 and
7,806,185.
Spacer Fluids
[0125] A spacer fluid is a fluid used to physically separate one special-
purpose fluid
from another. Special-purpose fluids are typically prone to contamination, so
a spacer fluid
compatible with each is used between the two. A spacer fluid is used when
changing well
fluids used in a well. For example, a spacer fluid is used to change from a
drilling fluid during
drilling a well to a cement slurry during cementing operations in the well. In
case of an oil-
based drilling fluid, it should be kept separate from a water-based cementing
fluid. In
changing to the latter operation, a chemically treated water-based spacer
fluid is usually used
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to separate the drilling fluid from the cement slurry. Another example is
using a spacer fluid
to separate two different treatment fluids.
Well Fluid Additives
101261 A well fluid can contain additives that are commonly used in oil field
applications, as known to those skilled in the art. These include, but are not
necessarily
limited to, inorganic water-soluble salts, breaker aids, surfactants, oxygen
scavengers,
alcohols, scale inhibitors, corrosion inhibitors, fluid-loss additives,
oxidizers, water control
agents (such as relative permeability modifiers), consolidating agents,
proppant flowback
control agents, conductivity enhancing agents, and bactericides.
Variations in Well Fluids over Time
101271 Unless the specific context otherwise requires, a "well fluid" refers
to the
specific properties and composition of a fluid at the time the fluid is being
introduced into a
well. ln addition, it should be understood that, during the course of a well
operation such as
drilling, cementing, completion, or intervention, or during a specific
treatment such as fluid-
loss control, hydraulic fracturing, or a matrix treatment, the specific
properties and
composition of a type of well fluid can be varied or several different types
of well fluids can
be used. For example, the compositions can be varied to adjust viscosity or
elasticity of the
well fluids to accommodate changes in the concentrations of proppant to be
carried down to
the subterranean formation from initial packing of the fracture to tail-end
packing. It can also
be desirable to accommodate expected changes in temperatures encountered by
the well
fluids during the course of the treatment. By way of another example, it can
be desirable to
accommodate the longer duration that the first treatment fluid may need to
maintain viscosity
before breaking compared to the shorter duration that a later-introduced
treatment fluid may
need to maintain viscosity before breaking. Changes in concentration of the
proppant,
viscosity-increasing agent, or other additives in the various treatment fluids
of a treatment
operation can be made in stepped changes of concentrations or ramped changes
of
concentrations.
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Continuum Mechanics and Rheology
(0128] One of the purposes of identifying the physical state of a substance
and
measuring viscosity or other physical characteristics of a fluid is to
establish whether it is
pumpable. In the context of oil and gas production, the pumpability of a fluid
is with
particular reference to the ranges of physical conditions that may be
encountered at a
wellhead and with the types and sizes of pumps available to be used for
pumping fluids into a
well. Another purpose is to determine what the physical state of the substance
and its
physical properties will be during pumping through a wellbore and under other
downhole
conditions in the well, including over time and changing temperatures,
pressures, and shear
rates. For example, in some applications, a well fluid forms or becomes a
higher viscosity
fluid or gel under downhole conditions that later is "broken" back to a lower
viscosity fluid.
[0129] Continuum mechanics is a branch of mechanics that deals with the
analysis
of the kinematics and the mechanical behavior of materials modeled as a
continuous mass on
a large scale rather than as distinct particles. Fluid mechanics is a branch
of continuum
mechanics that studies the physics of continuous materials that take the shape
of their
container. Rheology is the study of the flow of matter: primarily in the
liquid state, but also
as "soft solids" or solids under conditions in which they respond with plastic
flow rather than
deforming elastically in response to an applied force. It applies to
substances that have a
complex structure, such as fluid suspensions, gels, etc. The flow of such
substances cannot
be fully characterized by a single value of viscosity, which varies with
temperature, pressure,
and other factors. For example, ketchup can have its viscosity reduced by
shaking (or other
forms of mechanical agitation) but water cannot.
Physical States (Phases)
(0130j The common physical states of matter include solid (fixed shape and
volume), liquid (fixed volume and shaped by a container), and gas (dispersing
in a container).
Distinctions among these physical states are based on differences in
intermolecular
attractions. Solid is the state in which intermolecular attractions keep the
molecules in fixed
spatial relationships. Liquid is the state in which intermolecular attractions
keep molecules in
proximity (low tendency to disperse), but do not keep the molecules in fixed
relationships.
Gas is that state in which the molecules are comparatively separated and
intermolecular
attractions have relatively little effect on their respective motions (high
tendency to disperse).
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101311 In addition, as used herein, a solid includes a plastic material, that
is, a
material that has plasticity. Plasticity describes the deformation of a
material undergoing
non-reversible changes of shape in response to applied forces.
101321 As used herein, "phase" is used in the same sense as physical state,
regardless of geometric extent of the phase or size of a particle.
101331 The physical state of a substance is based on thermodynamics.
Thermodynamics is the science of energy conversion involving heat, mechanical
work, and
other forms of energy. It studies and interrelates variables, such as
temperature, volume,
pressure, and friction, which describe physical, thermodynamic systems.
101341 As used herein, if not otherwise specifically stated, the physical
state (phase)
or other physical properties of a material are determined at a temperature of
77 F (25 C)
and a pressure of 1 atmosphere (Standard Laboratory Conditions, 101.325 kPa)
and no
applied deformation force or shear (that is, not other such force than that of
natural gravity).
Particles
101351 As used herein, a "particle" refers a body having a finite mass and
sufficient
cohesion such that it can be considered as an entity but having relatively
small dimensions.
As used herein, a particle can be of any size ranging from molecular scale
particles to
macroscopic particles, depending on context. A particle can be in any physical
state. For
example, a particle of a substance in a solid state cart be as small as a few
molecules on the
scale of nanometers up to a large particle on the scale of a few millimeters,
such as large
grains of sand. Similarly, a particle of a substance in a liquid state can be
as small as a few
molecules on the scale of nanometers or a large drop on the scale of a few
millimeters. A
particle of a substance in a gas state is a single atom or molecule that is
separated from other
atoms or molecules such that intermolecular attractions have relatively little
effect on their
respective motions.
Particulate
101361 As used herein, "particulate" or "particulate material" refers to
matter in the
physical form of distinct particles. A particulate is a grouping of particles
based on common
characteristics, including chemical composition and particle size range,
particle size
distribution, or median particle size. As used herein, a particulate is a
grouping of particles
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having similar chemical composition and particle size ranges anywhere in the
range of about
1 micrometer (e.g., microscopic clay or silt particles) to about 3 millimeters
(e.g., large grains
of sand).
[0137] A particulate will have a particle size distribution ("PSD"). As used
herein,
"the size" of a particulate can be determined by methods known to persons
skilled in the art.
Solid Particulate
[0138] A particulate can be of solid or liquid particles. As used herein,
however,
unless the context otherwise requires, particulate refers to a solid
particulate. Of course, a
solid particulate is a particulate of particles that are in the solid physical
state, that is, the
constituent atoms, ions, or molecules are sufficiently restricted in their
relative movement to
result in a fixed shape for each of the particles.
[0139] One way to measure the approximate particle size distribution of a
solid
particulate is with graded screens. A solid particulate material will pass
through some
specific mesh (that is, have a maximum size; larger pieces will not fit
through this mesh) but
will be retained by some specific tighter mesh (that is, a minimum size;
pieces smaller than
this will pass through the mesh). This type of description establishes a range
of particle sizes.
A "+" before the mesh size indicates the particles are retained by the sieve,
while a "2 before
the mesh size indicates the particles pass through the sieve. For example, -
70/+140 means
that 90% or more of the particles will have mesh sizes between the two values.
[0140] Particulate materials are sometimes described by a single mesh size,
for
example, 100 U.S. Standard mesh. If not otherwise stated, a reference to a
single particle size
means about the mid-point of the industry accepted mesh size range for the
particulate.
[0141] Particulate smaller than about 400 U.S. Standard Mesh is usually
measured
or separated according to other methods because small forces such as
electrostatic forces can
interfere with separating tiny particulate sizes using a wire mesh.
Udden-Wentworth Scale for Particulate Sediments
[0142] The most commonly-used grade scale for classifying the diameters of
sediments in geology is the Udden-Wentworth scale. According to this scale, a
solid
particulate having particles smaller than 2 mm in diameter is classified as
sand, silt, or clay.
Sand is a detrital grain between 2 mm (equivalent to 2,000 micrometers) and
0.0625 nun
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(equivalent to 62.5 micrometers) in diameter. (Sand is also a term sometimes
used to refer to
quartz grains or for sandstone.) Silt refers to particulate between 74
micrometers (equivalent
to about -200 U.S. Standard mesh) and about 2 micrometers. Clay is a
particulate smaller
than 0.0039 mm (equivalent to 3.9 pm).
Dispersions
10143) A substance can have more than one phase. A dispersion is a system in
which particles of a substance of one state are dispersed in another substance
of a different
composition or physical state. In addition, phases can be nested. If a
substance has more
than one phase, the most external phase is referred to as the continuous phase
of the
substance as a whole, regardless of the number of different internal phases or
nested phases.
10144] A dispersion can be classified a number of different ways, including
based
on the size of the dispersed particles, the uniformity or lack of uniformity
of the dispersion,
whether or not precipitation occurs, and the presence of Brownian motion. For
example, a
dispersion can be considered to be homogeneous or heterogeneous based on being
a solution
or not, and if not a solution, based on the size of the dispersed particles
(which can refer to
droplet size in the case of a dispersed liquid phase).
Classification of Dispersions: Homogeneous and Heterogeneous
[0145) A dispersion is considered to be homogeneous if the dispersed particles
are
dissolved in solution or the particles are less than about 1 nanometer in
size.
[0146] A solution is a special type of homogeneous mixture. Solvation is the
process of attraction and association of molecules of a solvent with molecules
or ions of a
solute. A solution is homogeneous because the ratio of solute to solvent is
the same
throughout the solution and because solute will never settle out of solution,
even under
powerful centrifugation. This is due to intermolecular attraction between the
solvent and the
solute. An aqueous solution, for example, saltwater, is a homogenous solution
in which
water is the solvent and salt is the solute.
[0147] Even if not dissolved, a dispersion is considered to be homogeneous if
the
dispersed particles are less than about 11 nanometer in size.
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[0148] A dispersion is considered to be heterogeneous if the dispersed
particles are
not dissolved or are greater than about 1 nanometer in size. (For reference,
the diameter of a
molecule of toluene is about 1 nm).
[0149] Heterogeneous dispersions can have gas, liquid, or solid as an external
phase. An example of a suspension of solid particulate dispersed in a gas
phase would be an
aerosol, such as smoke. In case the dispersed-phase particles are liquid in an
external phase
that is another liquid, this kind of heterogeneous dispersion is more
particularly referred to as
an emulsion. Suspensions and emulsions are commonly used as well fluids.
Classification of Heterogeneous Dispersions: Colloids and Suspensions
[0150] Heterogeneous dispersions can be further classified based on the
dispersed
particle size.
101511 A heterogeneous dispersion is a "colloid" where the dispersed particles
range
up to about 1 micrometer (1,000 nanometers) in size. Typically, the dispersed
particles of a
colloid have a diameter of between about 5 to about 200 nanometers. Such
particles are
normally invisible to an optical microscope, though their presence can be
confirmed with the
use of an ultramicroscope or an electron microscope. In the cases where the
external phase of
a dispersion is a liquid, for a colloidal fluid the dispersed particles are so
small that they do
not settle.
[01521 A heterogeneous dispersion is a "suspension" where the dispersed
particles
are larger than about 1 micrometer. Such particles can be seen with a
microscope, or if larger
than about 100 micrometers (0.1 mm), with the unaided human eye. Unlike
colloids,
however, the dispersed particles of a suspension in a liquid external phase
may eventually
separate on standing, e.g., settle in cases where the particles have a higher
density than the
liquid phase. Suspensions having a liquid external phase are essentially
unstable from a
thermodynamic point of view; however, they can be kinetically stable over a
long period
depending on temperature and other conditions.
Gel and Deformation
[0153] The substance of a gel is a colloidal dispersion. A gel is formed by a
network of interconnected molecules, such as of a crosslinked polymer or of
micelles, which
at the molecular level are attracted to molecules in liquid form. The network
gives a gel
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phase its structure (apparent yield point) and contributes to stickiness
(tack). By weight, the
substance of gels is mostly liquid, yet they behave like solids due to the
three-dimensional
network with the liquid. At the molecular level, a gel is a dispersion in
which the network of
molecules is continuous and the liquid is discontinuous.
[01541 A gel is a semi-solid, jelly-like state or phase that can have
properties
ranging from soft and weak to hard and tough. Shearing stresses below a
certain finite value
fail to produce permanent deformation. The minimum shear stress which will
produce
permanent deformation is known as the shear or gel strength of the gel.
[01551 A gel is considered to be a single phase because the intermolecular
attractions between the molecules of the network and the molecules of the
liquid contribute to
its semi-solid, jelly-like properties.
Fluid and Apparent Viscosity
[01561 The substance of a fluid can be a single chemical substance or a
dispersion.
In general, a fluid is an amorphous substance that is or has a continuous
phase of particles
that are smaller than about I micrometer that tends to flow and to conform to
the outline of its
container.
[01571 Examples of fluids are gases and liquids. A gas (in the sense of a
physical
state) refers to an amorphous substance that has a high tendency to disperse
(at the molecular
level) and a relatively high compressibility. A liquid refers to an amorphous
substance that
has little tendency to disperse (at the molecular level) and relatively high
incompressibility.
The tendency to disperse is related to Intermolecular Forces (also known as
van der Waal's
Forces). (A continuous mass of a particulate, e.g., a powder or sand, can tend
to flow as a
fluid depending on many factors such as particle size distribution, particle
shape distribution,
the proportion and nature of any wetting liquid or other surface coating on
the particles, and
many other variables; nevertheless, as used herein, a fluid does not refer to
a continuous mass
of particulate. The sizes of the solid particles of a mass of a particulate
are too large to be
appreciably affected by the range of Intermolecular Forces.)
[0158] Viscosity is the resistance of a fluid to flow. In everyday terms,
viscosity is
"thickness" or "internal friction." Thus, pure water is "thin," having a
relatively low
viscosity whereas honey is "thick," having a relatively higher viscosity. Put
simply, the less
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viscous the fluid is, the greater its ease of movement (fluidity). More
precisely, viscosity is
defined as the ratio of shear stress to shear rate.
[0159] A Newtonian fluid (named after Isaac Newton) is a fluid for which
stress
versus strain rate curve is linear and passes through the origin. The constant
of
proportionality is known as the viscosity. Examples of Newtonian fluids
include water and
most gases. Newton's law of viscosity is an approximation that holds for some
substances
but not others.
[01601 Non-Newtonian fluids exhibit a more complicated relationship between
shear stress and velocity gradient (i.e., shear rate) than simple linearity.
Thus, there exist a
number of forms of non-Newtonian fluids. Shear thickening fluids have an
apparent
viscosity that increases with the rate of shear. Shear thinning fluids have a
viscosity that
decreases with the rate of shear. Thixotropic fluids become less viscous over
time when
shaken, agitated, or otherwise stressed. Rheopectic fluids become more viscous
over time
when shaken, agitated, or otherwise stressed. A Bingham plastic is a material
that behaves as
a solid at low stresses but flows as a viscous fluid at high stresses.
[0161] Most well fluids are non-Newtonian fluids. Accordingly. the apparent
viscosity of a fluid applies only under a particular set of conditions
including shear stress
versus shear rate, which must be specified or understood from the context. In
the oilfield and
as used herein, unless the context otherwise requires it is understood that a
reference to
viscosity is actually a reference to an apparent viscosity. Apparent viscosity
is commonly
expressed in units of centipoise ("cP").
[0162] Like other physical properties, the viscosity of a Newtonian fluid or
the
apparent viscosity of a non-Newtonian fluid is highly dependent on the
physical conditions,
primarily temperature and pressure. Accordingly, unless otherwise stated, the
viscosity or
apparent viscosity of a fluid is measured under Standard Laboratory
Conditions.
[0163] There are numerous ways of measuring and modeling viscous properties,
and new developments continue to be made. The methods depend on the type of
fluid for
which viscosity is being measured. A typical method for quality assurance or
quality control
(QA/QC) purposes uses a couette device, such as a Fann Model 50 viscometer,
that measures
viscosity as a function of time, temperature, and shear rate. The viscosity-
measuring
instrument can be calibrated using standard viscosity silicone oils or other
standard viscosity
fluids.
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[01641 Due to the geometry of most common viscosity-measuring devices,
however, solid particulate, such as proppant or gravel used in certain well
treatments, would
interfere with the measurement on some types of measuring devices. Therefore,
the viscosity
of a fluid containing such solid particulate is usually inferred and estimated
by measuring the
viscosity of a test fluid that is similar to the fracturing fluid without any
proppant included.
However, as suspended particles (which can be solid, gel, liquid, or bubbles
of gas) usually
affect the viscosity of a fluid, the actual viscosity of a suspension is
usually somewhat
different from that of the continuous phase.
[0165] Another example of a method of measuring the viscosity of certain
fluids
that have suspended proppant uses a Proppant Transport Measuring Device
("PTMD"),
which is disclosed in U.S. Patent No. 7,392,842, issued July 1, 2008 and in
SPE 115298.
The PTMD instrument is preferably calibrated against a more conventional
instrument, for
example, against a Fann Model 50 viscometer.
[01661 Other examples of methods of measuring the viscosity of a fluid
include:
(1) Tonmukayakul. N. Bryant, J.E. Talbot, M.S. and Morris, J.F., "Dynamic and
steady shear
properties of reversible cross-linked guar solution and their effects on
particle settling
behavior", The KWh International Congress on Rheology, Monterey, California, 3-
8 August,
2008. American Institute of Physic Conference Proceedings 1027 ISBN:978-0-7354-
0549-3;
(2) Tonmukayakul N. Bryant, J.E. and Morris, J.F., "Experimental investigation
of the
sedimentation behavior of concentrated suspension in non-Newtonian fluids
under simple
shear flows", 82nd Annual Meeting, The Society of Rheology, Santa Fe, New
Mexico,
October 24-28, 2010; (3) Tonmukayakul N. and Morris, J.F., "Sedimentation of
Particles in
Viscoelastic Fluids Under Imposed Shear Conditions," J. Rheol, 2011 (in
press);
(4) Tonmukayakul, N., Morris, J.E., Prud'hornme, R.E. "Method for estimating
proppant
transport and suspendability of viseoelastic liquids" US Application filed on
May 17, 2010,
US application Serial No. 12/722,493 and it was filed on March 11, 2010; and
(5) Tonmukayakul N. and Morris, J.F., "Spreading Front and Particles Alignment
in
Viscoelastic Fluids," Physical Review E, 2011 (in press).
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Foams
101671 A foam is fluid having a liquid external phase that includes a
dispersion of
undissolved gas bubbles that foam the liquid, usually with the aid of a
chemical (a foaming
agent) in the liquid phase to achieve stability.
101681 Any suitable gas may be used for foaming, including nitrogen, carbon
dioxide, air, or methane. A foamed treatment fluid may be desirable to, among
other things,
reduce the amount of fluid that is required in a water sensitive subterranean
formation, to
reduce fluid loss in the formation, and/or to provide enhanced proppant
suspension. The gas
may be present in the range of from about 5% to about 98% by volume of the
treatment fluid,
and more preferably in the range of from about 20% to about 80% by volume of
the treatment
fluid. The amount of gas to incorporate in the fluid may be affected by many
factors
including the viscosity of the fluid and the bottom hole temperatures and
pressures involved
in a particular application. One of ordinary skill in the art, with the
benefit of this disclosure,
will recognize how much gas, if any, to incorporate into a foamed treatment
fluid.
101691 Where it is desirable to foam the treatment fluids of the present
invention,
surfactants such as HY-CLEAN (HC-2) surface-active suspending agent or AQF-2
additive,
both commercially available from Halliburton Energy Services, Inc., of Duncan,
Oklahoma,
may be used. Additional examples of foaming agents that may be used to foam
and stabilize
the treatment fluids of this invention include, but are not limited to,
betaines, amine oxides,
methyl ester sulfonates, alkylamidobetaines such as cocoamidopropyl betaine,
alpha-olefin
sulfonate, trimethyltallowammonium chloride, C8 to C22 alkylethoxylate sulfate
and
trimethylcocoammonium chloride. Other suitable foaming agents and foam
stabilizing
agents may be included as well, which will be known to those skilled in the
art with the
benefit of this disclosure.
Emulsions
[01701 An emulsion is a fluid including a dispersion of immiscible liquid
particles
in an external liquid phase. In addition, the proportion of the external and
internal phases is
above the solubility of either in the other. A chemical (an emulsifier or
emulsifying agent)
can be included to reduce the interfacial tension between the two immiscible
liquids to help
with stability against coalescing of the internal liquid phase.
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[01711 An emulsion can be an oil-in-water (o/w) type or water-in-oil (w/o)
type. A
water-in-oil emulsion is sometimes referred to as an invert emulsion. In the
context of an
emulsion, the "water" phase refers to water or an aqueous solution and the
"oil" phase refers
to any non-polar organic liquid, such as petroleum, kerosene, or synthetic
oil.
[01721 It should be understood that multiple emulsions are possible, which are
sometimes referred to as nested emulsions. Multiple emulsions are complex
polydispersed
systems where both oil-in-water and water-in-oil emulsions exist
simultaneously in the fluid,
wherein the oil-in-water emulsion is stabilized by a lipophilic surfactant and
the water-in-oil
emulsion is stabilized by a hydrophilic surfactant. These include water-in-oil-
in-water
(w/o/w) and oil-in-water-in-oil (o/w/o) type multiple emulsions. Even more
complex
polydispersed systems are possible. Multiple emulsions can be formed, for
example, by
dispersing a water-in-oil emulsion in water or an aqueous solution, or by
dispersing an oil-in-
water emulsion in oil.
Classification of Fluids or Gels: Water-Based or Oil-Based
[01731 As used herein, "water-based" regarding a fluid or gel means that water
or an
aqueous solution is the dominant material by weight of the continuous phase of
the substance.
In contrast, "oil-based" means that oil is the dominant material by weight of
the continuous
phase of the substance as a whole.
_[01741 Methods of increasing the fracture complexity in a treatment zone of a
subterranean formation are provided. The subterranean formation is
characterized by having
a matrix permeability less than 1.0 microDarcy (9.869233 x 10-16 m2).
[0175] According to one aspect of the invention there is provided, a method
include
the step of pumping one or more fracturing fluids into a far-field region of a
treatment zone
of the subterranean formation at a rate and pressure above the fracture
pressure of the
treatment zone. A first fracturing fluid of the one or more fracturing fluids
comprises a first
solid particulate, wherein: (a) the first solid particulate comprises a first
particle size range
effective for bridging the pore throats of a proppant pack previously formed
or to be formed
in the far-field region of the treatment zone; (b) the first solid particulate
is in an insufficient
amount in the first fracturing fluid to increase the packed volume fraction of
any region of the
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proppant pack to greater than 73%; and (c) the first solid particulate
comprises a degradable
material.
[01761 The methods of the present invention may also include the step of
pumping
two or more fracturing fluids into the treatment zone at a rate and pressure
above the fracture
pressure of the treatment zone for a total pumping volume greater than 2
wellbore volumes,
wherein: (a) a first fracturing fluid of the two or more fracturing fluids is
pumped into the
treatment zone at least before the last 2 wellbore volumes of the total
pumping volume,
wherein the first fracturing fluid comprises a proppant, wherein the first
fracturing fluid does
not include a first solid particulate; and (b) a second fracturing fluid of
the two or more
fracturing fluids is pumped into the treatment zone after the first fracturing
fluid is pumped
into the treatment zone but at least before the last 2 wellbore volumes of the
total pumping
volume, wherein the second fracturing fluid comprises the first solid
particulate. The first
solid particulate comprises a first particle size range effective for bridging
the pore throats of
a proppant pack formed in the treatment zone by the proppant of the first
fracturing fluid, and
the first solid particulate is degradable.
[01771 In a remedial application, the methods of the present invention may
also
include the step of pumping one or more fracturing fluids into a far-field
region of the
treatment zone of the subterranean formation at a rate and pressure above the
fracture
pressure of the treatment zone. A first fracturing fluid of the one or more
fracturing fluids
comprises a first solid particulate, wherein: (a) the first solid particulate
comprises a first
particle size range effective for bridging the pore throats of a proppant pack
previously
formed in the far-field region of the treatment zone; and (b) the first solid
particulate
comprises a degradable material.
[01781 As will be appreciated by a person of skill in the art, the methods
according
to the invention can have application in various kinds operations involved in
the production
of oil and gas, including drilling, completion, and intervention.
[01791 The features and advantages of the present invention will be apparent
to
those skilled in the art. While numerous changes may be made by those skilled
in the art,
such changes are within the scope of the invention.
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BRIEF DESCRIPTION OF THE DRAWING
[01801 The accompanying drawing is incorporated into the specification to help
illustrate examples according to the presently most-preferred embodiment of
the invention.
[01811 Fig. 1 is a bar chart of the particle size distribution for an example
of a solid
particulate having particle sizes all less than 50 U.S. Mesh, which
particulate is suitable for
use in bridging the pore throats of a proppant pack formed of 100 U.S.
Standard Mesh size
proppant. More than 50% by weight of the particulate has a particle size
distribution of -
501+200 U.S. Mesh. This particulate includes a tail-end size range of the
particulate having
particles sizes less than 200 U.S. Standard mesh. The particulate size
distributions were
determined by graded screening.
[0182] Fig. 2 is a graph of the particle size distribution for the same
example
material of Fig. 1 but as measured with the MASTERSIZER instrument for
measuring
particle size distributions.
[0183] Fig. 3 is a graph of the permeability measurements of a laboratory
experiment illustrating the effectiveness of temporary reduction of the
permeability of a 100
U.S. Standard Mesh proppant pack with 5% wiw degradable particles having a
particle size
distributions as shown in Figs. 1 and 2.
101841 Fig. 4 is a graph of the general relationship between the weight
percent of
the degradable particles mixed with a 100 U.S. Standard Mesh proppant pack and
the packed
volume fraction when the mixed particles are packed.
General Definitions and Usages
[01851 As used herein, the words "comprise," "have," "include," and all
grammatical variations thereof are each intended to have an open, non-limiting
meaning that
does not exclude additional elements or steps.
10186] As used herein, if not otherwise specifically stated, the physical
state of a
substance (or mixture of substances) and other physical properties are
determined at a
temperature of 77 F (25 'V) and a pressure of 1 atmosphere (Standard
Laboratory
Conditions, 101.325 kPa) under no shear.
[0187] As used herein, if not otherwise specifically stated, a material is
considered
to be "soluble" in a liquid if at least 10 grams of the material can be
dissolved in one liter of
the liquid when tested at 77 F (25 C) and 1 atmosphere (101.325 kPa)
pressure for 2 hours
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and considered to be "insoluble" if less soluble than this. In addition, as
used herein, a
material is "dissolvable" if itself or its hydrated product or products is or
are "soluble." As
will be appreciated by a person of skill in the art, the solubility in water
of a certain material
may be dependent on the salinity, pH, or other additives in the water.
Accordingly, the
salinity, pH, additive selection of the water can be modified to facilitate
the solubility in
aqueous solution.
[0188] Unless otherwise specified, any ratio or percentage means by weight.
[0189] As used herein, the phrase "by weight of the water" means the weight of
the
water of the continuous phase of the fluid as a whole without the weight of
any proppant,
viscosity-increasing agent, dissolved salt, or other materials or additives
that may be present
in the water.
[0190] Unless otherwise specified, any doubt regarding whether units are in
U.S. or
Imperial units, where there is any difference U.S. units are intended herein.
For example,
"gal/Mgal" means U.S. gallons per thousand U.S. gallons.
[0191] The micrometer (1.im) may sometimes referred to herein as a micron.
[0192] As used herein, "first," "second," or "third" may be arbitrarily
assigned and
are merely intended to differentiate between two or more fluids, aqueous
solutions, etc., as
the case may be, that may be used according to the invention. Accordingly, it
is to be
understood that the mere use of the term "first" does not require that there
be any "second,"
and the mere use of the word "second" does not require that there by any
"third," etc.
Further, it is to be understood that the mere use of the term "first" does not
require that the
element or step be the very first in any sequence, merely that it is at least
one of the elements
or steps. Similarly, the mere use of the terms "first" and "second" does not
necessarily
require any sequence. Accordingly, the mere use of such terms does not exclude
intervening
elements or steps between the "first" and "second" elements or steps, etc.
[0193) Unless otherwise specified, as used herein, the apparent viscosity of a
fluid
(excluding any solid particulate) is measured with a Fann Model 50 type
viscometer at a
shear rate of 40 1/s and at 77 F (25 C) and a pressure of 1 atmosphere
(101.325 kPa). For
reference, the viscosity of pure water is about 1 cP (0.001 Pas). As used
herein, a material is
considered to be a pumpable fluid if it has an apparent viscosity less than
5,000 cP (5 Pas).
[0194] Unless otherwise specified, "about" regarding a number or measurement
means within 10% of the number or measurement.
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Ultra-Low Permeability Formations
[01951 In general, the present invention is directed to increasing fracture
complexity
in ultra-low permeable formations such as a shale reservoir (which is
sometimes referred to in
the art as a shale play). As used herein, an ultra-low permeable formation has
a matrix
permeability less than about 1 microDarcy (9.869233 x 1O-19 m2).
Fracture Complexity
E01961 Ultra-low permeable formations tend to have a naturally occurring
network
of multiple interconnected micro sized fractures. In addition, ultra-low
permeable formations
can be fractured to create or increase the complexity of such multiple
interconnected
fractures. The fracture complexity is sometimes referred to in the art as a
fracture network.
Fracturing Ultra-Low Permeable Formations
[01971 Ultra-low permeable formations are usually fractured with water-based
fluids having little viscosity and suspending relatively low concentrations of
proppant. The
size of the proppant is sized to be appropriate for the fracture complexity of
such a formation,
which is much smaller than used for fracturing higher permeability formations
such as
sandstone or even tight gas reservoirs. These kinds of fracturing treatments
are sometimes
referred to as water-frac or slic-frac. The overall purpose is to increase or
enhance the
fracture complexity of such a formation to allow the gas to be produced.
101981 Although the fractures of the fracture network are very small compared
to
fractures formed in higher permeability formations, they should still be
propped open.
According to the invention, it is desirable to temporarily plug the proppant
pack in the
fracture complexity to force additional fracturing fluid to increase the
fracture complexity.
After increasing the fracture complexity, it is desirable to re-open the
proppant pack to allow
the production of hydrocarbon from all the fracture complexity in the zone.
Matrix Permeability
[01991 As used herein, "matrix permeability" refers to the permeability of the
matrix of the formation regardless of the fractures or microfractures of any
major fractures or
fracture network. Methods of measuring matrix permeability are known in the
art. For
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example, one reference discloses: "Three laboratory methods were developed to
measure
matrix gas permeability (Km) of Devonian shale cores and drill cuttings at
native water
saturations. The first method uses pulse pressure testing of core plugs with
helium. The
second, new method uses pulse pressure testing of core chips or drill cuttings
with helium.
These methods gave comparable results on 23 companion shale samples from two
wells, with
Km = 0.2 to 19 x 104 md. The third, new method uses degassibility of core
plugs with
helium and methane, and yielded Km higher by a factor of 3 to 10. Most of the
core plugs
tested showed multiple microfractures that remain open at reservoir stress,
and these
dominate conventional flow tests. These microfractures are parallel to
bedding, are coring
induced, and are not present in the reservoir. Knowledge of Krn is important
in computer
simulation modeling of long-term Devonian shale gas production, and has been a
key to
understanding the nature of the natural fracture network present in the
reservoir." "Matrix
Permeability Measurement of Gas Productive Shales"; D.L. Luffel, ResTech
Houston; C.W.
Hopkins, S.A. Holditch & Assocs. Inc.; and P.D. Schettler Jr., Juniata
College; SPE 26633.
Stimulated Rock Volume
102001 Stimulated rock volume is a term used in the art regarding the
fracturing of
shale or other ultra-low permeability reservoirs. "Ultra-low permeability
shale reservoirs
require a large fracture network to maximize well performance. Microseismic
fracture
mapping has shown that large fracture networks can be generated in many shale
reservoirs.
In conventional reservoirs and tight gas sands, single-plane fracture half-
length and
conductivity are the key drivers for stimulation performance. In shale
reservoirs, where
complex network structures in multiple planes are created, the concept of a
single fracture
half-length and conductivity are insufficient to describe stimulation
performance. This is the
reason for the concept of using stimulated reservoir volume as a correlation
parameter for
well performance. The size of the created fracture network can be approximated
as the 3-D
volume (Stimulated Reservoir Volume or SRV) of the microseismic event cloud."
Title:
"What is Stimulated Rock Volume?" Authors: M.J. Mayerhofer, E.P. Loon, N.R.
Warpinski,
C.L. Cipolla, and D. Walser, Pinnacle Technologies, and C.M. Rightmire,
Forrest A. Garb
and Associates. Source: Society of Petroleum Engineers, "SPE Shale Gas
Production
Conference, 16-18 November 2008, Fort Worth, Texas, USA." SPE 119890.
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Desired Objectives of the Invention
[0201] Preferably, the degradable solid particulate is selected to be
effective for
reducing the permeability of the proppant pack in the fracture complexity of
the treatment
zone of an ultra-low permeable subterranean formation. The purpose is to cause
the proppant
pack to have a lower flow capacity than unplugged small fractures and lower
than a proppant
filled fracture, which causing an increase in fracture complexity rather than
extending
fracture planes during the fracturing stage. This favors increasing the
fracture complexity
beyond the near-wellbore region of the treatment zone. The creation of
increasing
complexity is preferably confirmed with microseismic techniques as known and
being
currently further developed in the art. The penetration is desired to extend
deeper into the
zone than in the near well-bore region.
[02021 As used herein, the far-field region of a zone is considered the matrix
of rock
that is at least 5 feet (1.52 m) from the wellbore. More preferably, the
methods according to
the invention penetrate into the matrix of rock at least 10 feet (3.05 m) from
the wellbore;
over 50 feet (15.24 m) from the wellbore is preferred.
[0203] The purpose of this invention is not diversion of fracturing fluids
between
treatment zones. In addition, the purpose of this invention is not to use the
degradable
particulate to bridge or obstruct pore throats in smaller fractures that may
be perpendicular to
the one or more dominant fractures being formed in the formation. Moreover,
the purpose of
this invention is not low damage of the formation. Rather, a purpose of the
present
inventions is to select a particulate to bridge pore throats of a proppant
pack in an ultra-low
permeable formation, and, thereby, increase fracture complexity in the ultra-
low permeable
formation. It is not to enhance large, dominant fractures but to increase
fracture complexity
of small or micro fractures from which point the hydrocarbons may flow to the
well bore and
then to the surface, where they may be produced.
[0204] A method of increasing the fracture complexity in a treatment zone of a
subterranean formation is provided. The subterranean formation is
characterized by having a
matrix permeability less than 1.0 microDarcy (9.869233 x 1(I'9 m2). The method
includes
the step of pumping one or more fracturing fluids into a far-field region of a
treatment zone
of the subterranean formation at a rate and pressure above the fracture
pressure of the
treatment zone. A first fracturing fluid of the one or more fracturing fluids
includes a first
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solid particulate, wherein: (a) the first solid particulate includes a
particle size distribution for
bridging the pore throats of a proppant pack previously formed or to be formed
in the
treatment zone; and (b) the first solid particulate comprises a degradable
material.
[02051 Preferably, the first solid particulate is in an insufficient amount in
the first
fracturing fluid to increase the packed volume fraction of any region of the
proppant pack to
greater than 73%.
102061 Preferably, the first solid particulate is in at least a sufficient
amount in the
first fracturing fluid to reduce the permeability of at least a region of the
proppant pack at
least 50%.
102071 More preferably, the entirety of each of the particles of the first
solid
particulate is made of one or more degradable materials.
Step of Identifying a Subterranean Formation
[02081 The methods preferably include the step of identifying a subterranean
formation characterized by having a matrix permeability less than 1.0
microDarcy (9.869233
x 10-19 m2). More particularly, the step of identifying includes identifying a
subterranean
formation additionally characterized by having a matrix permeability greater
than
0.001 microDarcy (equivalent to 1 nanoDarey, 9.869233 x 10-22 1112).
[02091 Preferably, the step of identifying includes identifying a subterranean
formation characterized by having a hydrocarbon content that is sufficient for
economic
recovery. More preferably, the step of identifying includes identifying a
subterranean
formation additionally characterized by having a hydrocarbon content greater
than 2% by
volume gas filled porosity.
[02101 Preferably, the step of identifying includes identifying a subterranean
formation additionally characterized as being shale.
Step of Designing a Fracturing Stage
[02111 The methods preferably include the step of designing or determining a
fracturing stage for a treatment zone of the subterranean formation, prior to
performing the
fracturing stage.
[02121 The step of designing can include the steps of: (i) determining the
total
designed pumping volume of the one or more fracturing fluids to be pumped into
the
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treatment zone at a rate and pressure above the fracture pressure of the
treatment zone;
(ii) determining the size of a proppant of a proppant pack previously formed
or to be formed
in fractures in the treatment zone at any time before the last 2 wellbore
volumes of the total
designed pumping volume of the fracturing stage; (iii) determining the size of
a first solid
particulate for bridging the pore throats of the proppant pack, wherein the
first solid
particulate comprises a degradable material. More preferably, the entire
particulate is made
of one or more degradable materials.
[0213] The step of designing or determining can include the steps of:
(i) determining the total designed pumping time for the pumping of one or more
fracturing
fluids into the treatment zone at a rate and pressure above the fracture
pressure of the
treatment zone; (ii) determining the size of a proppant of a proppant pack
previously formed
or to be formed in fractures in the treatment zone at any time before the last
10 minutes of the
total designed pumping time of the fracturing stage; (iii) determining the
size of a first solid
particulate for bridging the pore throats of the proppant pack, wherein the
first solid
particulate comprises a degradable material. It should be understood that the
pumping time is
based on a pumping rate that is at least 20% of the pumping rate before
diversion to another
fracturing stage or, in the case of the final fracturing stage of a multi-
stage fracturing job, the
pumping rate before the end of the final fracturing stage. In the unusual case
of a fracturing
job having only a single treatment zone, fracturing of the single treatment
zone fracturing
would be considered the final fracturing stage. More preferably, the entire
particulate is
made of one or more degradable materials.
[0214) Preferably, the step of designing or determining can additionally
include one
or more of the steps of: (1) selecting a fracturing fluid, including its
composition and
theological characteristics; (2) selecting the pH of the fracturing fluid, if
water-based; (3) the
design temperature; and (4) the loading of any proppant in the fracturing
fluid. As used
herein the term "design temperature" refers to an estimate or measurement of
the actual
temperature at the down hole environment at the time of the treatment. That
is, design
temperature takes into account not only the bottom hole static temperature
("BHST"), but
also the effect of the temperature of the treatment fluid on the BHST during
treatment.
Because treatment fluids may be considerably cooler than BHST, the difference
between the
two temperatures can be quite large. Ultimately, if left undisturbed, a
subterranean formation
will return to the BHST.
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[0215] In a method according to the inventions that includes the step of
planning or
determining the fracturing stage, the methods then include a step of
performing the fracturing
stage according to the planned or determined fracturing stage. For example,
for example, the
fracturing stage can include, after or during the time the proppant pack is
formed or to be
formed in the treatment zone but at least before the last 2 wellbore volumes
of the total
pumping volume, pumping a first fracturing fluid comprising the first solid
particulate into
the treatment zone at a rate and pressure above the fracture pressure of the
treatment zone.
Or, for example, the fracturing stage can include, after or during the time
the proppant pack is
formed or to be formed in the treatment zone but at least before the last 10
minutes of the
total pumping time, pumping a first fracturing fluid comprising the first
solid particulate into
the treatment zone at a rate and pressure above the fracture pressure of the
treatment zone.
Step of Performing a Fracturing Stage
[0216] In general, a fracturing stage according to the invention preferably
includes
pumping the one or more fracturing fluids into the treatment zone at a rate
and pressure above
the fracture pressure of the treatment zone for a total pumping time longer
than 30 minutes.
A fracturing fluid including the first solid particulate should be included as
part of the one or
more fracturing fluids before the tail end of the fracturing stage. It should
be understood that
the objective of the fracturing fluid with the first solid particulate and the
extended pumping
time is to increase the facture complexity far field in a zone and to increase
the stimulated
fracture volume. Accordingly, the duration of fracturing of a treatment zone
can be much
longer than 30 minutes or the total pumping volume of the one or more
fracturing fluids can
be much higher than conventionally used in conventional reservoirs.
Fracturing, Fluids
[02171 Preferably, the fracturing fluids for use in fracturing ultra-low
permeability
formations according to the methods of the invention are water-based. One of
the reasons for
this is the large volumes required, and water is relatively low cost compared
to oil-based
fluids. Other reasons can include concern for damaging the reservoir and
environmental
concerns.
[0218] A fracturing stage can include the step of pumping one or more
fracturing
fluids into a far-field region of a treatment zone. The first fracturing fluid
is the only
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fracturing fluid used in a fracturing stage. More than one fracturing fluid
may be used in the
same fracturing stage.
Slick Water Fracturing for Ultra-Low Permeability Formation
[0219] According to the invention, a friction-reducing polymer can be included
in
the treatment fluids, for example, in an amount equal to or less than 0.2% by
weight of the
water present in the treatment fluid. Preferably, any friction-reducing
polymers are included
in a concentration sufficient to reduce friction without gel formation upon
mixing. By way of
example, the treatment fluid comprising the friction-reducing polymer would
not exhibit an
apparent yield point. While the addition of a friction-reducing polymer may
minimally
increase the viscosity of the treatment fluids, the polymers are not included
in the treatment
fluids of the present invention in an amount sufficient to substantially
increase the viscosity.
For example, if proppant is included in the treatments fluid, velocity rather
than fluid
viscosity generally may be relied on for proppant transport. The friction-
reducing polymer
can be present in an amount in the range of from about 0.01% to about 0.15% by
weight of
the treatment fluid. The friction-reducing polymer can be present in an amount
in the range
of from about 0.025% to about 0.1% by weight of the treatment fluid.
[0220] Generally, the treatment fluids for use in the invention are not
relying on
viscosity for proppant transport. Where particulates (e.g., proppant, first
solid particulate,
etc.) are included in the fracturing fluids, the fluids rely on at least
velocity to transport the
particulates to the desired location in the formation. The treatment fluids
may have a
viscosity up to about 10 centipoise ("cP", 10 Pas). The treatment fluids may
have a viscosity
in the range of from about 0.7 cP (0.0007 Pas) to about 10 cP (0.01 Pas). The
first fracturing
fluid may have a viscosity in the range of about 0.7 cP to about 10 cP (0.01
Pas). All of the
one or more fracturing fluids may have a viscosity in the range of about 0.7
cP (0.0007 Pas)
to about 10 cP (0.01 Pas). For the purposes of this disclosure, viscosities
are measured at
room temperature using a FANN Model 35 viscometer at 300 rpm with a 1/5
spring.
10221] The ultra-low matrix permeability of a shale formation does not allow
for
fracturing fluid damage to the formation or fracturing fluid leak off into the
matrix of the
formation. In addition, the small proppant sizes used in fracturing to
increase the fracture
complexity of a subterranean formation having ultra-low matrix permeability
require less
viscosity to be carried by the fracturing fluid. In addition, a higher
viscosity fluid would not
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be able to appreciably penetrate the permeability of a proppant pack formed
with such
smaller proppant.
Proppant Pack Formed or to Be Formed (E.g., Remedial or Primary Treatment)
102221 A proppant pack can have been formed in the treatment zone before the
fracturing stage of the method. A proppant pack can be formed during the
fracturing stage.
If the proppant pack is formed before the fracturing stage, this means that
the treatment zone
was previously fractured and a proppant pack was previously placed in the
fracture
complexity. Accordingly, the methods according to the invention can be adapted
for
remedial or primary fracturing of a treatment zone.
Proppant Pack Formed or to Be Formed (E.g.. Stepwise within a Fracturing
Stage)
[02231 In addition, it is contemplated that a proppant pack can be formed
during the
fracturing stage, either before the introduction of the first solid
particulate or simultaneously
with the introduction of the first solid particulate. For example, one of the
earlier fracturing
fluids used in a fracturing stage can include a proppant for forming a
proppant pack in the
fracture complexity, and one of the later fracturing fluids used in the
fracturing stage can
include a first solid particulate for increasing the fracture complexity as
additional fracturing
fluid is pumped into the formation.
Proppant
10224] In embodiments that include a fracturing fluid with proppant, the one
or
more of the fracturing fluids used in the method preferably include in the
range of about 1%
to about 20% by weight of the proppant. Accordingly, the proppant is in the
fracturing fluid
at less than about 4 pounds per gallon (1.8 kg per 3.8 x 10-3 m3). More
preferably, one or
more of the fracturing fluids includes in the range of about 5% to about 10%
by weight of the
proppant.
102251 For an ultra-low permeable formation, the proppant of a proppant pack
formed or to be formed in the fracture complexity preferably has a particulate
size range that
has an upper end equal to or less than 50 U.S. Standard Mesh. More preferably,
the proppant
has a graded size range anywhere between -501+200 U.S. Standard Mesh. Most
preferably,
the proppant has a graded particle size range anywhere between -701+140 U.S.
Standard
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Mesh. Typically, the proppant of a proppant pack formed or to be formed in the
fracture
complexity of an ultra-low permeable formation has a median particle size of
about 100 U.S.
Standard Mesh.
Bridging of Pore Throats of a Proppant Pack
10226) In the context of a pack of particulate, such as a proppant pack, a
certain
particulate will have a predictable permeability and pore-throat sizes under a
certain packing
stress and other conditions. For example, all else being equal, a pack of
ideal spheres of
uniform size will have a predictable geometric arrangement and pore throat
sizes. For such a
pack spheres, a first bridging particulate having ideal spheres of uniform
size in a range that
is about 1/6th to about 1/13th of the size of the spheres in the pack will be
able to bridge the
pore throats and substantially reduce the permeability of the pack. The first
bridging
particulate will itself have a predictable permeability and pore-throat sizes,
but these will be
much smaller than that of the pack. A second bridging particulate having a
size distribution
in the range that is about 1/6th to about 1/I3th of the size of the first
bridging particulate would
be expected to be able to bridge the pore throats and substantially reduce the
permeability of
the first bridging particulate. The complexity increases with increasing the
particle size
distribution of each of the particulates, with changes in the shape of each of
the particulates,
and with variations in the shape distribution of each of the particulates, but
these basic size
proportions are useful rules of thumb.
First Solid Particulate
[02271 The first particle size range has an upper end that is greater than or
equal to
about 1/I 3' of the median particle size of the proppant (which would be
equivalent to about
12 pm for a 100 U.S. Standard Mesh proppant). In addition, the first particle
size range has a
lower end that is less than or equal to about 1/6th of the median size of the
proppant (which
would be equivalent to about 25 gm or about 500 mesh for a 100 U.S. Standard
Mesh
proppant). A tail end of smaller or larger particles than the particle sizes
of the first solid
particulate does not interfere and can be useful according to the invention.
10228] As a practical matter, for use with a 100 mesh median size proppant,
the first
solid particulate includes a first solid particle size range smaller than
about 33 latn, which is
equivalent to about 400 U.S. Standard mesh.
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[02291 As discussed above, the first solid particulate preferably is not in
the shape
of a fiber. Preferably, the particulate has aspect ratios less than 5:1. More
preferably, the
first solid particulate is substantially globular in shape.
[02301 It is to be understood that the proppant would be adequately suspended
in a
fracturing fluid that is similar to the first fracturing fluid but without the
first solid particulate
for the similar fracturing fluid to transport the proppant into the treatment
zone. In other
words, the solid particulate is not needed to help suspend the proppant in the
fracturing fluid
during transport into the treatment zone.
10231i Preferably, the first solid particulate is in the first fracturing
fluid in at least a
sufficient amount to reduce the permeability of at least a region of the
proppant pack by at
least 50%. More preferably, the first solid particulate is in the first
fracturing fluid in at least
a sufficient amount to reduce the permeability of at least a region of the
proppant pack at
least 90% in less than 10 minutes under the conditions of pumping the first
fracturing fluid
into the treatment zone. Furthermore, one skilled in the art would recognize
that determining
the size distribution of small particles (below about 200 mesh) is time
consuming. Therefore,
this empirical approach may be utilized to determine if a give particulate
containing 200
mesh and below particles has the desired performance without actually
measuring the size
distribution of the sub-200 mesh particles is a valuable method of determine
the suitability of
a given particulate.
[02321 The first solid particulate remains insoluble and does not otherwise
appreciably degrade for at least 2 hours under the conditions of the treatment
zone.
Preferably, the first solid particulate degrades under the temperature and
pressure conditions
of the treatment zone at least 50% by weight within 30 days. One skilled in
the art would
recognize that certain particulates, such as insoluble scale inhibitors, may
be tailored to have
longer dissolution rates to provide a secondary benefit such as long-term
scale inhibition in
excess of 30 days.
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Second Smaller Solid Particulate or Tail End of First Solid Particulate
[02331 The method optionally includes the step of: determining the size of a
second
solid particle size range for bridging the pore throats of the first solid
particulate. Preferably,
first fracturing fluid additionally comprises the second solid particle size
range.
[02341 The first solid particulate can include a second particle sizerange
effective
for bridging the pore throats of the first solid particulate. The first
fracturing fluid
additionally comprises a second solid particulate, wherein the second solid
particulate has a
second particle size range effective for bridging the pore throats of the
first solid particulate.
[0235] Preferably, the second solid particle size range is in the first
fracturing fluid
in at least a sufficient amount to reduce the permeability of at least a
region of a pack of the
first solid particulate at least 50%. More preferably, the second solid
particle size range is in
the first fracturing fluid in at least a sufficient amount to reduce the
permeability of at least a
region of a pack of the first solid particulate at least 90% in less than 10
minutes under the
conditions of pumping the first fracturing fluid into the treatment zone.
Theoretical Discussion
[0236] An ideal pack of spheres will have pore throats that are about 1/6th
the
diameter of the packed spheres. Such an idealized pack of spheres can
represent a pack of
proppant particles. The pore volume of a tightly packed proppant bed is about
35% of the
total pack volume. This can also be referred to as having a packed volume
fraction ("PVF")
of about 0.65.
[0237] A first solid particulate having a diameter of about 1/6th the pore
throat will
substantially plug the pore throat. A first solid particulate with a diameter
of 1/6th the
proppant particles would have a volume of about 0.46% of the proppant particle
(the ratio is
r3/R3 where r the radius of the first solid particulate and R the radius of
the proppant, the
ratio resulting from the ratio of volumes of spheres where the volume of a
sphere is 4 Pi r313).
If one of these particles is needed for each pore throat and there is on
average one pore throat
per proppant particle, then only a very small fraction of the void volume of a
particle pack is
needed to be filled with the first solid particulate to get substantial
plugging of the pore
throats of the proppant pack.
[0238] Even if a second particulate of smaller particles are used or needed to
bridge
on the pore throats of the bridged first solid particulate, the second
particulate still need not
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significantly fill the pore volume. Based on the idealized ratios involved,
there will be three
of particles of the second particulate needed per first solid particulate.
This would add
another 0.0064% additional volume to the void space. With the proppant and
plugging
particulates, the packed volume fraction, in such an idealized case, would be
about 0.655.
This is consistent with the behavior of natural core where the presence of 2%
"fines" (smaller
particles that can plug pore throats in a conventional formation) is known to
be enough to
cause serious damage to the permeability of the conventional formation if they
are mobilized.
The term "fines" refers to particles that are small enough to become mobile if
the right flow
conditions are created. Even with this loading of fines, there is still a
packed volume fraction
=
of only about 0.67.
[02391 For example, the method of increasing the fracture complexity of a
subterranean formation can include the steps of: (i) pumping a first
fracturing fluid of two or
more fracturing fluids into the treatment zone at a rate and pressure above
the fracture
pressure of the treatment zone; (ii) pumping a second fracturing fluid of the
two or more
fracturing fluids is pumped into the treatment zone after the first fracturing
fluid is pumped
into the treatment zone wherein the second fracturing fluid comprises a first
solid particulate,
wherein the first solid particulate has a size for bridging the pore throats
of any proppant pack
formed in the treatment zone by the proppant of the first fracturing fluid,
and wherein the first
solid particulate is degradable. It should be appreciated that these steps
could be repeated or
alternated in the same fracturing zone.
[02401 When this is performed there will be regions within the proppant pack
that
have the solid degradable particulate and regions that do not have any. The
packed volume
fraction of the regions containing the solid degradable particulate will be
below 0.73;
furthermore, the regions of the proppant pack without the solid degradable
particulate will be
well below 0.73 and will approach or be at the native packed volume fraction
for the given
proppant. In most, if not all instances, the packed volume fraction of the
proppant pack as a
whole will not appreciably change from its native value. This would also be
the case for
instances where the particulate is run throughout the proppant stage. The
native packed
volume fraction for a perfect sphere of one size is on the order of 0.64 to
0.68 depending
upon the method used to determine the value (Torquato, S.; Truskett, T. M.;
Debenedetti, P.
G. Is Random Close Packing of Spheres Well Defined? Phys. Rev. Lett. 2000, 84,
2064 as
referenced in Ind. Eng. Chem. Res. 2002, 41, 1122-1128).
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102411 Conceptually, the difference between the methods according to this
invention and diversion is that diversion occurs at or near the wellbore
region. This is best
illustrated by taking the hypothetical situation where a zone contains a
single perforation. If
one performs a near-wellbore diversion, that single perforation would stop
taking fluid and
since there is not a second perforation to take the fluid, the stage would be
complete.
According to this invention, one would be able to continue pumping through the
single
perforation a fluid according to the method of the invention.
Example of First Solid Particulate for Use with a Proppant Pack of 100 U.S.
Mesh Proppant
102421 An example of a particulate having a suitable particle size
distribution for
use as the first solid particulate is a particulate formed of a scale
inhibitor as described herein.
[02431 Fig. 1 is a bar chart of the particle size distribution for the example
of a solid
particulate having particle sizes all less than 50 U.S. Mesh, which
particulate is suitable for
use in bridging the pore throats of a proppant pack formed of 100 U.S.
Standard Mesh size
proppant. More than 50% by weight of the particulate has a particle size
distribution of -
50/4200 U.S. Mesh. This particulate includes a tail-end size range of the
particulate having
particles sizes less than 200 U.S. Standard mesh. The particulate size
distributions were
determined by graded screening.
[0244] The particulate size distribution of this example material was also
measured
using a MASTERSIZER 2000 particulate analyzer with a 2000S sampler and
MASTERSIZER Software v 5.60. This instrument uses laser light scattering to
compute
the size of particles with sizes ranging from 0.02 gm to 2000 gm. The amount
of scattered
light as well as the angle of scattering can be used to determine the size of
a particle that is
dispersed in either air or liquid. The system is capable of examining solid
particulate,
emulsions, and suspensions. The instrument settings were:
Sample RI: 1.5 (Actual RI unknown, but most organic materials are
¨1.5)
Absorption Value: 0.1
Dispersant: Air
Stir Speed: N/A
Sonication: N/A
Disperser Pressure: 2.0 bar (200 kPa)
Feed Rate: 13-18
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Measurement Time: 5 s
Calculation Model: General Purpose (Fine)
[02451 Fig. 2 is a graph of the particle size distribution as measured with
the
MASTERSIZER instrument. The upper end of the particle size range is about
630 micrometers and the median particle size is about 72.5 micrometers. This
measurement
is in volume percent, whereas the analysis shown in Fig. 1 is in weight
percent.
[0246] Fig. 3 is a graph of the permeability measurements of a laboratory
experiment illustrating the effectiveness of temporary reduction of the
permeability of a
100 U.S. Standard Mesh proppant pack with 5% w/w of the example degradable
particulate
having a particle size distribution as shown in Figs. 1 and 2. The laboratory
procedure was
as follows: Pack a flow cell with 100 U.S. Standard Mesh proppant. The cell
used had a
1 inch (0.0254 m) internal diameter and 6 inches (0.1524 m) in length with a
screen on the
bottom to retain the 100 mesh proppant. Flow water through the proppant pack
at constant
pressure to get a baseline flow rate. Repack cell with the 100 mesh proppant
mixed with 5%
by weight of the degradable particulate relative to the weight of the
proppant. In this
example, the degradable particulate is a chemical capable of inhibiting scale
as described
herein. Flow water through proppant pack at constant pressure and measure flow
rate with
time to determine the permeability. As illustrated in Fig. 3, the permeability
of a pack of
100 Mesh proppant with 5% w/w of the degradable particulate is temporarily
reduced
[0247] Fig. 4 is a graph of the general relationship between the weight
percent of
the degradable particles mixed with a 100 U.S. Standard Mesh proppant pack and
the packed
volume fraction when the mixed particles are packed. A proppant pack will
typically have a
packed volume fraction of about 0.65, with a small variation depending on how
tightly
packed. Adding the degradable particulate increases the packed volume fraction
relative to
the proppant pack alone. As illustrated in Fig. 3, a 5% wt/wt of the example
first solid
particulate is more than sufficient to increase the packed volume fraction to
about 0.7 and to
reduce the permeability of the proppant pack more than 90%. Any additional
proportion of
the first solid particulate to the proppant beyond that necessary to achieve
about a 90%
reduction in the proppant pack permeability would be wasted for the purposes
of the present
inventions.
f02481 Preferably, the first solid particulate does not increase the packed
volwne
fraction to more than 0.73. Preferably, the sum total of all solid particulate
included in the
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fracturing fluid does not increase the packed volume fraction of a proppant
pack formed or to
be formed in the formation to more than 0.73.
Degradable Solid Particulate
[02491 The first solid particulate for use in the methods according to the
invention is
selected to be degradable. Preferably, any second solid particulate is also
selected to be
degradable, although any second solid particulate is not required to be
degradable. As the
first solid particulate is degradable, when the first solid particulate
degrades any second
particulate should be small enough to pass through the pore throats of the
proppant pack. The
chemical composition of the second solid particulate can be the same or
different as the first
solid particulate.
f02501 As used herein, a degradable material is capable of undergoing an
irreversible degradation dovvnhole. The term "irreversible" as used herein
means that the
degradable material once degraded should not recrystallize or reconsolidate
while downhole
in the treatment zone, that is, the degradable material should degrade in situ
but should not
recrystallize or reconsolidate in situ.
[0251] The terms "degradable" or "degradation" refer to both the two
relatively
extreme cases of degradation that the degradable material may undergo, that
is,
heterogeneous (or bulk erosion) and homogeneous (or surface erosion), and any
stage of
degradation in between these two.
[0252] Preferably, the degradable material of the particulate degrades slowly
over
time as opposed to instantaneously.
[02531 The specific features of the degradable material of a first solid
particulate
may be modified so as to reduce the permeability of a proppant pack when
intact while easing
the removal of the degradable material when desirable. Whichever degradable
material is
utilized, the bridging agents may have any shape, including but not limited to
particles having
the physical shape of platelets, shavings, flakes, ribbons, rods, strips,
spheroids, toroids,
pellets, tablets, or any other physical shape. One of ordinary skill in the
art with the benefit
of this disclosure will recognize the specific degradable material and the
preferred size and
shape for a given application. Preferably, however, the particulate for use in
the methods
according to the invention is not fiber shaped. More preferably, the
particulate for use in the
present invention is globular or generally- spherical.
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102541 The bridging in the proppant pack formed by a solid particulate
comprising a
degradable material according to the present invention is preferably "self-
degrading." As
referred to herein, the term "self-degrading" means bridging may be removed
without the
need to circulate a separate "clean up" solution or "breaker" into the
treatment zone, wherein
such clean up solution or breaker having no purpose other than to degrade the
bridging in the
proppant pack. Though the bridging formed by the methods of the present
invention
constitute "self-degrading" bridging, an operator may nevertheless elect to
circulate a
separate clean up solution through the well bore and into the treatment zone
under certain
circumstances, such as when the operator desires to hasten the rate of
degradation of the
bridging in the proppant pack. The particulate of the present invention may be
sufficiently
acid-degradable as to be removed by such treatment.
102551 The degradation can be a result of, inter alia, a chemical or thermal
reaction
or a reaction induced by radiation. The degradable particulate is preferably
selected to
degrade by at least one mechanism selected from the group consisting of:
hydrolysis,
hydration followed by dissolution, dissolution, decomposition, or sublimation.
[02561 The choice of degradable material for use in the degradable particulate
can
depend, at least in part, on the conditions of the well, e.g., wellbore
temperature. For
instance, lactides can be suitable for lower temperature wells, including
those within the
range of about 60 F (15.6 C) to about 150 F (65.6 C), and polylactides can
be suitable for
well bore temperatures above this range. Dehydrated salts may also be suitable
for higher
temperature wells.
102571 In general, selection of a degradable particulate and fracturing fluid
depends
on a number of factors including: (1) the degradability of the material of the
particulate; (2)
the particle size of the particulate; (3) the pH of the fracturing fluid, if
water-based; (4) the
design temperature; and (5) the loading of degradable particulate in the
fracturing fluid. The
step of designing or determining a fracturing stage preferably includes
selecting a suitable
degradable particulate and fracturing fluid for the fracturing stage.
[02581 In choosing the appropriate degradable material, the degradation
products
that will result should also be considered. For example, the degradation
products should not
adversely affect other operations or components in the well. As an example of
this
consideration, a boric acid derivative may not be included as a degradable
material in the
fracturing fluids of the present invention where such fluids utilize xanthan
as the viscosifier,
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because boric acid and xanthan are generally incompatible. One of ordinary
skill in the art,
with the benefit of this disclosure, will be able to recognize when potential
components of the
fracturing fluids of the present invention would be incompatible or would
produce
degradation products that would adversely affect other operations or
components.
[0259] It is to be understood that a particulate can include mixtures of two
or more
different degradable compounds.
Degradable Polymers
[0260] As for degradable polymers, a polymer is considered to be "degradable"
herein if the degradation is due to, inter alia, chemical or radical process
such as hydrolysis,
oxidation, enzymatic degradation, or UV radiation. The degradability of a
polymer depends
at least in part on its backbone structure. For instance, the presence of
hydrolyzable or
oxidizable linkages in the backbone often yields a material that will degrade
as described
herein. The rates at which such polymers degrade are dependent on the type of
repetitive
unit, composition, sequence, length, molecular geometry, molecular weight,
morphology
(e.g., crystallinity, size of spherulites, and orientation), hydrophilicity,
hydrophobicity,
surface area, and additives. Also, the environment to which the polymer is
subjected may
affect how the polymer degrades, e.g., temperature, presence of moisture,
oxygen,
microorganisms, enzymes, pH, and the like.
[0261] Some examples of degradable polymers are disclosed in U.S. Patent
Publication No. 2010/0267591, having for named inventors Bradley L. Todd and
Trinidad
Munoz, which is incorporated herein by reference, discloses some suitable
chemical
compositions that can be sized for particulate materials for use in methods
according to the
present invention.
[0262] Suitable examples of degradable polymers that may be used in accordance
with the present invention include but are not limited to those described in
the publication of
Advances in Polymer Science, Vol. 157 entitled "Degradable Aliphatic
Polyesters" edited by
A.-C. Albertsson and the publication "Biopolymers" Vols. 1-10, especially Vol.
3b, Polyester
II: Properties and Chemical Synthesis and Vol. 4, Polyester III: Application
and Commercial
Products edited by Alexander Steinbuchel, Wiley-VCM.
[0263] Non-limiting examples of degradable materials that may be used in
conjunction with the present invention include, but are not limited to
aromatic polyesters and
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aliphatic polyesters. Such polyesters may be linear, graft, branched,
crosslinked, block,
dendritic, homopolymers, random, block, and star- and hyper-branched aliphatic
polyesters,
etc.
[0264] Some suitable polymers include poly(hydroxy alkanoate) (PHA);
poly(alpha-hydroxy) acids such as polylactic acid (PLA), polygylcolic acid
(PGA),
polylactide, and polyglycolide; poly(beta-hydroxy alkanoates) such as
poly(beta-hydroxy
butyrate) (PHB) and poly(beta-hydroxybutyrates-co-beta-hydroxyvelerate)
(PHBV);
poly(omega-hydroxy alkanoates) such as poly(beta-propiolactone) (PPL) and
poly(s-
caprolactone) (PCL); poly(alkylene dicarboxylates) such as poly(ethylene
succinate) (PES),
poly(butylene succinate) (PBS); and poly(butylene succinate-co-butylene
adipate);
polyanhydrides such as poly(adipic anhydride); poly(orthoesters);
polycarbonates such as
poly(trimethylene carbonate); and poly(dioxepan-2-one)}; aliphatic polyesters;
poly(lactides);
poly(glycolides); poly(s-caprolactones); poly(hydroxybutyrates);
poly(anhydrides); aliphatic
polycarbonates; poly(orthoesters); poly(amino acids); poly(ethylene oxides);
and
polyphosphazenes. Of these suitable polymers, aliphatic polyesters and
polyanhydrides are
preferred. Derivatives of the above materials may also be suitable, in
particular, derivatives
that have added functional groups that may help control degradation rates.
[0265] Aliphatic polyesters degrade chemically, inter alia, by hydrolytic
cleavage.
Hydrolysis can be catalyzed by acids, bases, enzymes, or metal salt catalyst
solutions.
Generally, during the hydrolysis, carboxylic end groups are formed during
chain scission, and
this may enhance the rate of further hydrolysis. This mechanism is known in
the art as
"autocatalysis," and is thought to make polyester matrices more bulk eroding.
Suitable
aliphatic polyesters have the general formula of repeating units shown below:
Formula
R
11
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where n is an integer above 75 and more preferably between 75 and 10,000 and R
is selected
from the group consisting of hydrogen, alkyl, aryl, alkylaryl, acetyl,
heteroatoms, and
mixtures thereof.
[0266] Of the suitable aliphatic polyesters, poly(lactide) is preferred.
Poly(lactide)
is synthesized either from lactic acid by a condensation reaction or more
commonly by ring-
opening polymerization of cyclic ;wide monomer. Since both lactic acid and
lactide can
achieve the same repeating unit, the general term poly(lactic acid) as used
herein refers to
formula I without any limitation as to how the polymer was made such as from
lactides, lactic
acid, or oligomers, and without reference to the degree of polymerization or
level of
plasticization.
102671 The lactide monomer exists generally in three different forms: two
stereoisomers L- and D-lactide and racemic D,L-lactide (meso-lactide). The
oligomers of
lactic acid and oligomers of lactide are defined by the formula:
Fottnula It
110"Thy 10,1i
0
where m is an integer 2 < m < 75. Preferably m is an integer and 2 < m < 10.
These limits
correspond to number average molecular weights below about 5,400 and below
about 720,
respectively. The chirality of the lactide units provides a means to adjust,
inter alia,
degradation rates, as well as physical and mechanical properties. Poly(L-
lactide), for
instance, is a semicrystalline polymer with a relatively slow hydrolysis rate.
This could be
desirable in applications of the present invention where a slower degradation
of the
degradable material is desired. Poly(D,L-lactide) may be a more amorphous
polymer with a
resultant faster hydrolysis rate. This may be suitable for other applications
where a more
rapid degradation may be appropriate. The stereoisomers of lactic acid may be
used
individually or combined to be used in accordance with the present invention.
Additionally,
they may be copolymerized with, for example, glycolide or other monomers like
c-
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caprolactone, I,5-dioxepan-2-one, triraethylene carbonate, or other suitable
monomers to
obtain polymers with different properties or degradation times. Additionally,
the lactic acid
stereoisomers can be modified to be used in the present invention by, inter
alia, blending,
copolymerizing or otherwise mixing the stereoisomers, blending, copolymerizing
or
otherwise mixing high and low molecular weight polylactides, or by blending,
copolymerizing or otherwise mixing a polylactide with another polyester or
polyesters. See
U.S. application Publication Nos. 2005/0205265 and 2006/0065397. One skilled
in the art
would recognize the utility of oligmers of other organic acids that are
polyesters.
[0268] For the purposes of forming a suitable solid particulate, the polymer
(or
oligomer) should have at least a sufficient degree of polymerization or level
of plasticization
to be a solid.
[0269] Polycondensation reactions, ring-opening polymerizations, free radical
polymerizations, anionic polymerizations, carbocationic polymerizations,
coordinative ring-
opening polymerization, and any other suitable process may prepare such
suitable polymers.
Degradable Anionic Compounds that Can Bind a Multi-Valent Metal
[0270] Certain anionic compounds that can bind a multi-valent metal are
degradable.
More preferably, the anionic compound is capable of binding with any one of
the following:
Calcium, magnesium, iron, lead, barium, strontium, titanium, zinc, and or
zirconium. One
skilled in the art would recognize that proper conditions (such as pH) may be
required for this
to take place.
[0271] Examples of anionic compounds that can bind with a muli-valent metal
include scale inhibiting chemicals and chelating chemicals. Examples of
suitable scale-
inhibiting and chelating chemicals are disclosed in U.S. application Serial
No. 12/512,232
filed on July 30, 2009, entitled "Methods of Fluid Loss Control and Fluid
Diversion in
Subterranean Formations".
[0272] In embodiments in which the particulate comprises an anionic compound,
the
first solid particulate may comprise a scale inhibitor. In general, suitable
scale inhibitors for
use in the present invention may be any scale inhibitor in particulate form
that is insoluble in
water. Suitable scale inhibitors generally include, but are not limited to,
bis(hexamethylene
tri am ine penta (methylene phosphonic acid));
diethylene triamine penta
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(methylene phosphonic acid); ethylene diamine tetra (methylene phosphonic
acid);
hexamethylenediamine tetra(methylene phosphonic acid); 1-hydroxy ethylidene-
1,1-
diphosphonic acid; 2- hydroxypho sphonocarboxyl ic acid; 2-pho sphonobutane- 1
,2,4-
tricarboxylic acid; phosphino carboxylic acid; diglycol amine phosphonate;
aminotris(methanephosphonic acid); methylene phosphonates; phosphonic acids;
aminoalkylene phosphonic acids; aminoalkyl phosphonic acids; polyphosphates,
salts thereof
(such as but not limited to: sodium, potassium, calcium, magnesium, ammonium);
and
combinations thereof. As an added benefit, these types of particulate have
scale-inhibiting
properties, wherein the particulate releases the scale inhibitor over time.
[0273) In embodiments in which the particulate comprises a chelating agent,
the
chelating agent may be insoluble in water. The chelating agents useful in the
present
invention may be any suitable chelating agent in particulate form that is
insoluble in water.
Suitable chelating agents generally include, but are not limited to, the
acidic forms of the
following: ethylenediaminetetraacetic acid (EDTA), hydroxyethyl
ethylenediamine triacoic
acid (HEDTA), nitrilotriacetic acid (NTA), diethylene triamine pentaacetic
acid (DTPA),
glutarnic acid diacetic acid (GLDA), glucoheptonic acid (CSA), propylene
diamine
tetraacetic acid (PDTA), ethylenediaminedisuccinic acid (EDDS),
diethanolglycirte (DEG),
ethanoldiglycine (EDG), glucoheptonate, citric acid, malic acid, phosphates,
amines, citrates,
derivatives thereof, and combinations thereof. Other suitable chelating agents
may include
the acidic forms of chelating agents classified as polyphosphates (such as
sodium
tripolyphosphate and hexametaposphoric acid), aminocarboxylic acids (such as N-
dihydroxyethylglycine), aminopolycarboxylates, 1,3-diketones (such as
acetylacetone,
trifiuoroacetylacetone, and thenoyltrifiuoroacetone), hydroxycarboxylic acids
(such as
tartaric acid, glueortic acid and 5-sulfosalicylic acid), polyamines (such as
ethylenediamine,
dethylentriamine, treithylertetetramine, and triaminotriethylamine),
aminoalcohols (such as
triethanolamine, N-hydroxyethylethylenediamine), aromatic, heterocyclic bases
(such as
dipyridyl and o-phenanthroline), phenols (such as salicylaldehyde,
disulfopyrocatechol, and
chromotropic acid), aminophenols (such as oxine and 8-hydroxyquinoline),
oximes (such as
oxinesulfonic acid, dimethylglyoxime, and salicylaldoxime), Schiff bases (such
as
disaliclaldehyde 1,2-propylenediimine), tetrapyrroles (such as
tetraphenylporphine and
phthalocyanine), sulfur compounds (such as toluenedithiol, dimercaptopropanol,
thioglycolie
acid, potassium ethyl xanthate, sodium diethyldithiocarbamate, dithizotte,
diethyl
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dithiophosphoric acid, and thiourea), synthetic macrocyclic compounds (such as
dibenzo-
p81-crown-6, and hexarnthy1414]-4,l1 dieneN4(2.2.2-cryptate), polymers (such
as
polyethoeneimines, polymethacryloyl acetone, poly(p-vinylbenzyliminodiacetic
acid),
phosphonic acids (such as nitrilotrimethylenephosphonic acid,
ethylenediaminetetra(methylenephosphonic acid) and
hydroxyehtylidenediphosphonic acid),
derivatives thereof, and combinations thereof.
[02741 In general, particulates comprising a scale inhibitor or a chelating
agent
suitable for use in the present invention are insoluble in water, but are
substantially soluble
when contacted with a solubilizing agent. Therefore, once the fracturing
treatment operation
has been completed, a solubilizing agent is introduced into the well bore (or
may be already
present in the subterranean formation), whereby the particulate comprising a
scale inhibitor
or a chelating agent is dissolved. The solubilizing agent may have the effect
of causing the
particulate comprising a scale inhibitor or a chelating agent to form its free
acid, to dissolve,
to hydrolyze into solution, to form its salt, to change salts, etc. and
thereby become soluble.
After a chosen time, the fracturing fluid may be recovered through the well
bore that
penetrates the subterranean formation.
[02751 Suitable solubilizing agents include salts, including ammonium salts,
or
aqueous fluids containing a salt or having a different pH than the fracturing
fluid, such as
brine, formation fluids (e.g., produced formation water, returned load water,
etc.), acidic
fluids, and spent acid. The type of solubilizing agent used generally depends
upon the type of
particulate to be solubilized. For example, solubilizing agents comprising
acidic fluids may
be suitable for use with polymeric scale inhibitors. One of ordinary skill in
the art with the
benefit of this disclosure will be able to select an appropriate solubilizing
agent based on the
type of scale inhibitor or chelating agent used.
[02761 The fracturing fluid can optionally comprise an acid generating
compound.
Examples of acid generating compounds that may be suitable for use in the
present invention
include, but are not limited to, esters, aliphatic polyesters, ortho esters,
which may also be
known as ortho ethers, poly (ortho esters), which may also be known as
poly(ortho ethers),
poly(lactides), poly(glycolides), poly(g-
caprolactones), poly(hydroxybutyrates),
poly(anhydrides), or copolymers thereof. Derivatives and combinations also may
be suitable.
The term "copolymer" as used herein is not limited to the combination of two
polymers, but
includes any combination of polymers, e.g., terpolymers. Other suitable acid-
generating
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compounds include: esters including, but not limited to, ethylene glycol
monoformate,
ethylene glycol diformate, diethylene glycol diformate, glyceryl monoformate,
glyceryl
difonnate, glyceryl triformate, triethylene glycol diformate and formate
esters of
pentaerythritol. Other suitable materials may be disclosed in U.S. Patent Nos.
6,877,563 and
7,021,383.
[0277] Particulates comprising a scale inhibitor or a chelating agent suitable
for use in
the present invention may be at least partially coated or encapsulated with
slowly water
soluble or other similar encapsulating materials. Such materials are well
known to those
skilled in the art. Examples of water-soluble and other similar encapsulating
materials that
can be utilized include, but are not limited to, porous solid materials such
as precipitated
silica, elastomers, polyvinylidene chloride (PVDC), nylon, waxes,
polyurethanes, cross-linked
partially hydrolyzed acrylics, and the like.
[0278] Degradable anionic compounds that can bind a multi-valent metal
advantage
over other potential chemistries are their ability to provide a secondary
function such as scale
or iron control. This may also provide an economical advantage.
Solid Materials that Degrade by Sublimation
[0279] Suitable examples of degradable materials that can be used in
accordance with
the present invention include but are not limited to those that sublime under
the design
temperature or finally under the bottom hole static temperature ("BHST") of
the treatment
zone.
[0280] An example of a suitable solid is a solid azo organic compound having
an azo
component and a methylenic component and is characterized by having a melting
point of at
least 332.6 F (167 C), a degree of solubility in water at a temperature of
from about 200 F
(93.3 C) to about 425 F (218.3 C) and a pressure of 600 pounds per square
inch (p.s.i, 4140
kPa) of less than about 20 pounds (9.1 kg) of the compound in 1,000 gallons
(3.8 m3) of
water, a degree of solubility in kerosene at a temperature of from about 200
F (93.3 C) to
about 425 F (218.3 C) and a pressure of 600 p.s.i. (4140 kPa) of at least 2
pounds (0.91 kg)
of the compound in 1,000 gallons (3.8 m3) of kerosene, and a sublimation rate
at a
temperature of from about 250 F (121.1 C) to about 425 F (218.3 C) of from
about 1
percent by weight of the compound in 24 hours to about 100 percent by weight
of the
compound in 12 hours.
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[02811 Examples of suitable solid azo compounds having an azo component and a
methylenic component such as the compounds known as Hansa Yellow G and Fast
Yellow
4RLF. Hansa Yellow G can be made by coupling orthonitroparatoluidine and
acetoacetanilid.
Methods of its preparation are well known and are disclosed in U.S. Patent No.
2,410,219.
Fast Yellow 4RLF dye's preparation is well known and is disclosed in U.S.
Patent No.
2,410,219. Additional disclosure is provided in U.S. Patent No. 4,527,628.
U.S. Patent Nos.
2,410,219 and 4,527,628.
[0282] Solid materials that degrade by sublimation have a technical advantage
in that
no aqueous phase is needed for their degradation.
Degradab Dehydrated Compounds
[0283] Dehydrated compounds may be used in accordance with the present
invention
as a degradable material. As used herein, a dehydrated compound means a
compound that is
anhydrous or of a lower hydration state, but chemically reacts with water to
form one or more
hydrated states where the hydrated state is more soluble than the dehydrated
or lower
hydrated state.
[0284] A dehydrated compound is suitable for use in the present invention if
it will
degrade over time as it is hydrated. For example, a particulate solid
anhydrous borate material
that degrades over time can be suitable. Specific examples of particulate
solid anhydrous
borate materials that may be used include but are not limited to anhydrous
sodium tetraborate
(also known as anhydrous borax), and anhydrous boric acid. These anhydrous
borate
materials are only slightly soluble in water. However, with time and heat in a
subterranean
environment, the anhydrous borate materials react with the surrounding aqueous
fluid and are
hydrated. The resulting hydrated borate materials are substantially soluble in
water as
compared to anhydrous borate materials and as a result degrade in the aqueous
fluid. In some
instances, the total time required for the anhydrous, borate materials to
degrade in an aqueous
fluid is in the range of from about 8 hours to about 72 hours depending upon
the temperature
of the treatment zone in which they are placed.
[0285] Examples of suitable boron compounds are disclosed in U.S. patent
application
Serial No. 12/957,522, filed on December 1, 2010, entitled "Methods of
Providing Fluid Loss
Control or Diversion". A relatively insoluble borate material ("RIBM")
degrades or dissolves
in the presence of an aqueous fluid
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in contact therewith and, once removed, the ftee movement of fluids within the
formation is
again allowed.
102861 The R1BM's suitable for use in the present invention include, but are
not
limited to, solid, slowly soluble borate materials such as anhydrous sodium
tetraborate (also
known as anhydrous borax), sodium tetraborate monohydrate, and anhydrous boric
acid (also
known as boric oxide). Without being limited by theory, it is believed that
these borate
materials are only slightly soluble in water; however, with time and heat in
the subterranean
zone, the borate materials react with the surrounding aqueous fluid and are
hydrated. The
resulting hydrated borate materials are highly soluble in water as compared to
the anhydrous
borate materials and as a result can be dissolved in an aqueous fluid. The
total time required
for the anhydrous borate materials to degrade and dissolve in an aqueous fluid
is in the range
of from about eight hours to about seventy-two hours depending upon the
temperature of the
subterranean zone in which they are placed. One skilled in the art would
recognize that some
hydrates, such as sodium tetraborate monohydrate, are relatively insoluble
compared to their
counterparts that are hydrated to a greater degree.
102871 The RIBM degrades over time when in contact with an aqueous fluid and
converts to the hydrated form of borate material. The treatment fluid itself
may be aqueous,
or the RIBM may come into contact with water after it is placed into the
subterranean
formation. The RIBM dissolves in an aqueous fluid, thereby eliminating the
need for
contacting the subterranean zone with clean-up fluids to remove the material
and restore
permeability. Another advantage of the relatively insoluble borate material
particulates used
in the present invention is that the melting points of the materials are high,
i e., 1367 F
(741.7 C) for anhydrous sodium tetraborate and 840 F (448.9 C) for
anhydrous boric
oxide, and as a result, the materials do not readily soften and are suitable
for use in high
temperature subterranean zones.
102881 Selection of an RIBM and treatment fluid for a desired use depends on a
number of factors including (1) the solubility of the chosen RIBM, (2) the
particle size of the
R1BM, (3) the pH of the treatment fluid, (4) the design temperature, and (5)
the loading of
RIBM in the treatment fluid.
102891 The solubility of the RIBM can be affected by the pH of the treatment
fluid,
by the design temperature, and by the selection of the RIBM itself. By way of
example, for
pH levels of between about 8 and 12, higher pH increases solubility of an
anhydrous boric
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acid RIBM to whereas decreasing the pH increases the solubility of an
anhydrous borax
RIBM. The solubility of the RIBM may be controlled such that complete
dissolution of the
RIBM at design temperature takes more than two hours, and in some cases longer
than a
week. The solubility of the RIBM may be controlled such that 50% dissolution
of the RIBM
at design temperature takes at least two hours. The solubility of the RIBM may
be controlled
such that 50% dissolution of the RIBM at design temperature takes at least
twenty-four hours.
[0290] To allow for relatively slow solubility, the treatment fluids of the
present
invention are preferably pH neutral or below, at least initially.
Degradable Liquid Particulate in Fracturing Fluid to Reduce Flow through a
Proppant Pack
[0291] An insoluble liquid particulate that is degradable can be included in
the
fracturing fluid to help increase fracture complexity. The insoluble liquid
particulate can be
used to form an emulsion, whereby the apparent viscosity of the fracturing
fluid is increased.
This reduces the permeability of the proppant pack to the fracturing fluid,
which can be used
to help reduce the flow of fracturing fluid through the proppant pack, thereby
increasing
fracturing fluid. The methods of using an insoluble solid particulate can be
particularly
effective when combined with the method of using an insoluble liquid
particulate.
[0292] Suitable degradable liquids include acid generating compounds. Examples
of
acid generating compounds that depending on molecular weight and other
chemical
properties can be in a liquid state include esters; ortho ethers (that may be
referred to as ortho
esters); poly(ortho ethers). Aliphatic polyesters; lactides, poly(lactides);
glycolides;
poly(glycolides); lactones; poly(.epsilon.-caprolactones);
poly(hydroxybutyrates); anhydrides;
poly( anhydrides); and poly(amino acids) may also be suitable if dissolved in
an appropriate
solvent that does not negatively impact the subterranean formation in which
they be used
(e.g., they do not create an additional clean up hindrance). Such compounds
are described in
U.S. Patent No. 7,686,080.
[0293] Degradable dehydrated compounds have several advantageous properties.
First, they have minimal impact on the pH. Second, some also swell and this
may provide
additional control of fluid flow. Finally, they typically degrade faster than
degradable
polymers.
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Step of Allowing or Causing the Particulate to Degrade
[0294] After the step of introducing a fracturing fluid comprising the first
solid
particulate, the methods include a step of allowing or causing the first solid
particulate to
degrade. If a second particulate that is degradable is used, the methods
preferably include a
step of allowing or causing the second particulate to degrade. The first and
second
particulates can be the same or different, and can degrade at the same or
different rates. As
discussed above, this preferably occurs with time under the conditions in the
zone of the
subterranean fluid. It is contemplated, however, that a clean-up treatment
could be
introduced into the zone to help degrade the degradable material of the first
solid particulate.
Additional Step of Monitoring
[0295] Any of the methods according to the invention preferably further
include a
step of monitoring the wellhead pressure to help determine the actual end of
the fracturing
stage. The end of the fracturing stage is the end of pumping into the
treatment zone, which
can be due to screenout at or near the wellbore or other mechanical or
chemical diversion of
fluid to a different treatment zone.
[0296] The methods more preferably further include a step of monitoring the
pressure in the wellbore along the treatment zone.
[0297] The methods most preferably further include a step of determining
microseismic activity near the zone to confirm an increase in fracture
complexity in the
treatment zone.
[0298] Seismic data is used in many scientific fields to monitor underground
events
in subterranean rock formations. In order to investigate these underground
events, micro.
earthquakes, also known as microseisms, are detected and monitored. Like
earthquakes,
microseisms emit elastic waves--compressional ("p-waves") and shear ("s-
waves"), but they
occur at much higher frequencies than those of earthquakes and generally fall
within the
acoustic frequency range of 200 Hz to more than 2000 Hz. Standard microseismic
analysis
techniques locate the sources of the microseismic activity caused by fluid
injection or
hydraulic fracturing
[0299] Microseismic detection is often utilized in conjunction with hydraulic
fracturing or water flooding techniques to map created fractures. A hydraulic
fracture
induces an increase in the formation stress proportional to the net fracturing
pressure as well
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as an increase in pore pressure due to fracturing fluid leak off. Large
tensile stresses are
formed ahead of the crack tip, which creates large amounts of shear stress.
Both
mechanisms, pore pressure increase and formation stress increase, affect the
stability of
planes of weakness (such as natural fractures and bedding planes) surrounding
the hydraulic
fracture and cause them to undergo shear slippage. It is these shear slippages
that are
analogous to small earthquakes along faults.
[0300j Microseisms are detected with multiple receivers (transducers) deployed
on
a wireline array in one or more offset well bores. With the receivers deployed
in several
wells, the microseism locations can be triangulated as is done in earthquake
detection.
Triangulation is accomplished by determining the arrival times of the various
p- and s-waves,
and using formation velocities to find the best-fit location of the
microseisms. However,
multiple offset wells are not usually available. With only a single nearby
offset observation
well, a multi-level vertical array of receivers is used to locate the
microseisms. Data is then
transferred to the surface for subsequent processing to yield a map of the
hydraulic fracture
network geometry.
Additional Step of Repeating Method in another Treatment Zone
103011 The methods according to the invention have application in multi-stage
fracturing of a subterranean formation having ultra-low permeability.
Preferably, a method
according to the invention further includes repeating the steps for another
treatment zone of
the subterranean formation: (a) designing a fracturing stage for a treatment
zone of the
subterranean formation; and (b) performing the fracturing stage as designed.
Additional Step of Producing Hydrocarbon from Subterranean Formation
[0302] Preferably, the methods according to the invention further include the
step of
producing hydrocarbon from the subterranean formation.
10303j Therefore, the present invention is well adapted to attain the ends and
advantages mentioned as well as those that are inherent therein. The
particular embodiments
disclosed above are illustrative only, as the present invention may be
modified and practiced
in different but equivalent manners apparent to those skilled in the art
having the benefit of
the teachings herein. Furthermore, no limitations are intended to the details
of construction
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or design herein shown, other than as described in the claims below. It is,
therefore, evident
that the particular illustrative embodiments disclosed above may be altered or
modified and
all such variations are considered within the scope of the present invention.
While
compositions and methods are described in terms of "comprising," "containing,"
or
"including" various components or steps, the compositions and methods also can
"consist
essentially of or "consist of the various components and steps. Whenever a
numerical range
with a lower limit and an upper limit is disclosed, any number and any
included range falling
within the range is specifically disclosed. In particular, every range of
values (of the form,
"from about a to about b," or, equivalently, "from approximately a to b," or,
equivalently,
"from approximately a to b") disclosed herein is to be understood to set forth
every number
and range encompassed within the broader range of values. Also, the terms in
the claims have
their plain, ordinary meaning unless otherwise explicitly and clearly defined
by the patentee.
Moreover, the indefinite articles "a" or "an", as used in the claims, are
defined herein to mean
one or more than one of the element that it introduces. If there is any
conflict in the usages of
a word or term in this specification and one or more patent(s) or other
documents that may be
referred to, the definitions that are consistent with this specification
should be adopted.
