Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
CA 02795417 2012-11-07
APPLICATION FOR PATENT
INVENTORS: HAROLD DEAN BRANNON; WILLIAM DALE WOOD;
RANDALL EDGEMAN; ALLAN RAY RICICARDS;
CHRISTOPHER JOHN STEPHENSON; DOUG WALSER AND
MARK MALONE
TITLE: METHOD OF TREATING SUBTERRANEAN FORMATIONS
USING MIXED DENSITY PROPPANTS OR SEQUENTIAL
PROPPANTI STAGES
SPECIFICATION
Field of the Invention
This invention relates to a method of trefiting subterranean formations and,
more
specifically, to hydraulic fracturing treatments for subterranean formations.
Use of the
method of the invention renders an increase in effective propped lengths by as
much as
100%. Thus, the inventive method increases well productivity, greatly enhances
reservoir drainage, and improves hydrocarbon recovery.
Background of the Invention
Hydraulic fracturing is a common stimulation technique used to enhance
production of fluids from subterranean formations. Hydraulic fracturing is
typically
employed to stimulate wells which produce from low permeability formations. In
such
wells, recovery efficiency is typically limited by the flow mechanisms
associated with a
low permeability formation.
During hydraulic fracturing, a viscosifled fracturing fluid is pumped at high
pressures and at high rates into a wellbore to initiate and propagate a
hydraulic fracture.
Once the natural reservoir pressures are exceeded, the fluid induces a
fracture in the
formation and transports the proppant into the fracture. The fluid used to
initiate and
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propagate the fracture is commonly known as the "pad". The pad may contain a
heavy
density fine particulate, such as fine mesh sand, for fluid loss control, or
larger grain sand
to abrade perforations or near-wellbore tortuosity. Once the fracture is
initiated,
subsequent stages of viscosified fracturing fluid containing chemical agents
such as
breakers, and containing proppants are pumped into the created fracture. The
fracture
generally continues to grow during pumping and the proppant remains in the
fracture in
the form of a permeable "pack" that serves to "prop" the fracture open. Once
the
treatment is completed, the fracture closes onto the proppants which maintain
the fracture
open, providing a highly conductive pathway for hydrocarbons and/or other
formation
fluids to flow into the wellbore. The fracturing fluid ultimately "leaks off'
into the
surrounding formation. The treatment design generally requires the fracturing
fluid to
reach maximum viscosity as it enters the fracture which affects the fracture
length and
width.
Fracturing fluids, including those containing breakers, typically exhibit poor
transport properties. High pumping rates are required in order to impart a
sufficient
velocity for placement of the proppant in the fracture. In such treatments,
the proppant
tends to settle, forming a 'proppant bank', as the linear slurry velocity
falls as a function
of the distance from the wellbore. This effect is further believed to result
in reduced
stimulation efficiency as the effective propped length is relatively short. In
addition,
much of the settled proppant is often below the productive interval.
The recovery of the fracturing fluid is accomplished by reducing the viscosity
of
the fluid to a low value such that it flows naturally from the formation under
the influence
of formation fluids and pressure. This viscosity reduction or conversion is
referred to as
"breaking". Historically, the application of breaking fluids as fracturing
fluids at elevated
temperatures, i.e., above about 120-130 F., has been a compromise between
maintaining
proppant transport and achieving the desired fracture conductivity, measured
in terms of
effective propped fracture length. Conventional oxidative breakers react
rapidly at
elevated temperatures, potentially leading to catastrophic loss of proppant
transport.
Encapsulated oxidative breakers have experienced limited utility at elevated
temperatures
due to a tendency to release prematurely or to have been rendered ineffective
through
payload self-degradation prior to release.
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Improvements in hydraulic fracturing techniques are required in order to
increase
the effective propped fracture length and thereby improve stimulation
efficiency and well
productivity.
Summary of the Invention
The invention relates to a method of hydraulically fracturing a hydrocarbon-
bearing subterranean formation by introducing into the formation one or more
proppant
stages wherein at least one of the proppant stages contains an ultra
lightweight (ULW)
proppant having a density less than or equal to 2.45 glee. The method results
in an
increase in the effective propped fracture length. The first proppant stage
may consist of
a mixture of proppants, at least one of which is an ULW proppant having a
density less
than or equal to 2.45 g/cc. Alternatively, sequential proppant stages may be
introduced
into the formation wherein at least one of the proppant stages contains a ULW
proppant.
The first proppant stage may be a pad fluid, containing a proppant, and pumped
at
a pressure sufficient to initiate a fracture. Alternatively, the first
proppant stage may be
pumped into a propagated fracture. As such, the first proppant stage of the
invention may
be introduced into the fracture subsequent to propagation of the fracture. An
optional
second proppant stage may be injected into the fracture after introduction of
the first
proppant stage. Successive proppant stages may be injected into the fracture
after
injection of the optional second proppant stage. The second proppant stage may
be
introduced into the formation immediately after the first proppant stage.
Thus, in the method of the invention, at least one of the following conditions
should prevail:
(i.) the first proppant stage contains a mixture of proppants ¨ for
example, a
first proppant and a second proppant - wherein at least one of the proppants
is a ULW;
preferably, the density differential between the ULW proppant and the second
proppant
in the proppant mixture is greater than or equal to 0.2 glee. For instance,
the first
proppant stage may contain a mixture of two proppants comprising a ULW
proppant and
a non-ULW proppant. In such proppant mixtures, the differential in the density
between
the two proppants is preferably greater than 0.2 glee. Alternatively, where
the invention
encompasses two or more proppant stages, all or some of the proppant stages
may
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contain a mixture of proppants, wherein within each proppant stage, at least
one of the
proppants is a ULW proppant. In each proppant stage, the density of the ULW
proppant
within the mixture is preferably greater than or equal to 0.2 g/cc the density
of a second
proppant within the mixture;
(ii.) the density
differential between the first proppant stage and the second
proppant stage is greater than or equal to 0.2 g/cc;
(iii.) the first proppant stage and the second proppant stage both contain ULW
proppants;
(iv.) the proppant of the first proppant stage and/or the second proppant
stage is
a ULW and the rate of injection of the second proppant stage into the fracture
is different
from the rate of injection of the first proppant stage; in a preferred mode,
the rate of
injection of the second proppant stage is less than the rate of injection of
the first
proppant stage; or
(v.) the proppant of the first proppant stage and/or the second proppant
stage
contains a ULW proppant and the particle size of the second proppant stage is
different
from the particle size of the first proppant stage; in a preferred mode, the
particle size of
the second proppant stage is preferably larger than the particle size of the
proppant of the
first proppant stage when the second proppant stage is directed more towards
the
wellbore. The particle size of the second proppant stage is preferably smaller
than the
particle size of the proppant of the first proppant stage when the second
proppant stage is
directed further into the fracture.
The effective propped length of the fracture after injection of any given
proppant
stage is preferably greater than the effective propped length of the proppant
stage
introduced into the fracture just prior to the injection of the any given
proppant stage.
In a preferred embodiment, the first proppant stage comprises a first proppant
and
a second proppant, wherein the first proppant is a relatively high-density
proppant, i.e.,
having a density greater than 2.45 gee, such as sand, ceramic, sintered
bauxite or resin
coated proppant, and the second proppant is a ULW proppant. A subsequent
second
proppant stage may include an ultra-lightweight proppant, exhibiting a
particle density
substantially lower than the density of the relatively high-density proppant.
For instance,
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the proppant of the subsequent proppant stage has a density less than or equal
to 2.45
glee, preferably ranging between from about 1.25 glee to about 1.75 g/cc.
Additional proppant stages may be introduced into the formation after
introduction of the second proppant stage. Such additional proppant stages
will be
referred to herein as the "ultimate proppant stage" and the "penultimate
proppant stage"
to refer to the latter and next to latter proppant stages, respectively. For
example, where
three proppant stages are employed and when referring to the third and second
proppant
stages, the third proppant stage may be referred to as the "ultimate proppant
stage" and
the second proppant stage as the "penultimate proppant stage." Where four
proppant
stages are employed and when referring to the fourth and third proppant
stages, the fourth
proppant stage may be referred to as the "ultimate proppant stage" and the
third proppant
stage may be referred to as the "penultimate proppant stage," etc. The
ultimate proppant
stage may be introduced into the formation immediately after the penultimate
proppant
stage. At least one of the following conditions preferably prevails:
(i.) the density
differential between the ultimate proppant stage and the
penultimate proppant stage is greater than or equal to 0.2 glee; for instance,
when
referring to the third and second proppant stages, the density differential
between the
third proppant stage and the second stage is greater than or equal to 0.2
g/cc;
(ii.) the rate of injection of the ultimate proppant stage into the
fracture is
different from the rate of injection of the penultimate proppant stage;
typically, the rate of
injection of the ultimate proppant stage into the fracture is lower than the
rate of injection
of the penultimate proppant stage into the fracture; or
(iii.) the particle size of the ultimate proppant stage is different from the
particle
size of the penultimate proppant stage; typically, the particle size of the
proppant of the
ultimate proppant stage into the fracture is dependent on whether the proppant
stage is
directed more towards the wellbore (generally larger) or further into the
fracture
(generally smaller).
In a preferred embodiment, the first proppant stage comprises a first proppant
and
a second proppant, wherein the first proppant is a relatively high-density
proppant, such
as sand, ceramic, sintered bauxite or resin coated proppant, and the second
proppant has a
density less than or equal to 2.45 g/cc.
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Alternatively, a fracture may be created in the formation by injecting a
banking
fluid containing a first proppant stage into the formation at a pressure
sufficient to allow
the formation of a proppant bank. A second proppant stage is then injected
into the
fracture. The proppant of either the first proppant stage or the second
proppant stage or
both may contain a ULW proppant. In a preferred embodiment, the density
differential
between the proppant of the first proppant stage (the banking fluid) and the
proppant of
the second proppant stage is at least 0.2 glee.
Alternatively, a fluid containing a relatively high-density proppant may be
used to
propagate the fracture, allowing it to form the bank. The subsequent second
proppant
stage may include an ultra-lightweight proppant, exhibiting a particle density
substantially lower than the density of the relatively high-density proppant.
For instance,
the proppant of the subsequent proppant stage may have a density ranging
between from
about 1.25 g/cc to about 1.75 g/cc.
The invention further has particular applicability in the use of a ULW
proppant in
a pad fluid to initiate a fracture in the formation. The second proppant stage
introduced
into the fracture may contain a ULW proppant or a proppant of higher density,
such as,
for example, sand, ceramic, bauxite, or resin coated proppant. The density
differential
between the first proppant stage, or pad fluid, and second proppant stage is
preferably at
least 0.2 g/cc.
The method of incorporating two or more proppant stages under the defined
conditions, or using two or more mixed proppants in a single proppant stage,
having a
ULW proppant provides significant benefits relative to treatments with
conventional
high-density proppants. In addition, the method provides significant benefits
as
compared to prior art methods. Such benefits include a reduction in costs and
the
potential for significantly improved effective propped fracture length.
Brief Description of the Drawings
FIG. 1 is a 2D depiction of a fracture, after closure of the fracture,
initiated with a
fluid pad not containing a ULW proppant, the fracture being successively
treated,., with a
second proppant stage.
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FIG. 2 is a 2D depiction of a fracture, after closure of the fracture,
initiated with a
fluid pad containing a ULW proppant, the fracture being successively treated
with a
second proppant stage.
Detailed Description of the Preferred Embodiments
The method of fracturing a hydrocarbon-bearing subterranean formation, as
defined by the invention, provides greater effective propped fracture length
than seen
with conventional fracturing techniques. Effective propped fracture lengths
may be
increased by as much as 100%. Such greater effective propped fracture length
translates
to improved stimulation efficiency, well productivity and reservoir drainage.
While not intending to be bound by any theory, it is believed that the
enhanced
effective length of the propped fracture is attributable to the reduced cross-
sectional flow
area existing above the settled bank. Where the first proppant stage is used
to propagate
the fracture, it is believed that the reduced cross-sectional flow area exists
above the
settled bank generated by this first proppant stage. Assuming constant pumping
rates at
the wellbore, the reduced cross-sectional area "artificially" increases the
velocity of the
second or successive proppant stages through that section of the fracture,
leading to
improved transport and deeper placement of the second or successive proppant
stages
into the fracture than would be achieved within the created fracture in the
absence of the
proppant bank.
In a preferred embodiment, the method of the invention consists of fracturing
by
introducing into the formation the use of multiple proppant stages wherein at
least one of
the proppant stages contains a ULW density proppant. Alternatively, the method
consists
of using a single proppant stage containing at least two proppants, wherein at
least one of
the proppant stages contains a ULW density proppant. As defined herein, a ULW
proppant is one which has a density less than or equal to 2.45 glee.
The formation may first be propagated by introducing into the formation a
proppant stage at a pressure sufficient to propagate the fracture. This
proppant stage,
which initiates the fracture, typically contains a conventional high-density
proppant,
though it may contain, in addition to or in lieu of the conventional high-
density proppant,
a ULW proppant.
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The "first proppant stage" of the invention may refer to either the proppant
stage
introduced into the formation to propagate the fracture or a proppant stage
introduced
into the formation after propagation has occurred. Thus, the term "first
proppant stage" is
not to be construed as encompassing only the first proppant stage introduced
to the
fracture or formation. It is meant only to refer to a proppant stage which
precedes a
"second proppant stage."
The "first proppant stage" may contain a mixture of proppants, at least one of
which is a ULW proppant. In a preferred mode, the first proppant stage
contains at least
two proppants. In a more preferred mode, the density differential of the two
proppants in
this mixture is greater than or equal to 0.2 g/cc. Where more than two
proppants are
present in the mixture, the density differential between at least two of the
proppants in the
mixture is greater than or equal to 0.2 g/cc. In another preferred mode, at
least two
proppants of the first proppant stage are ULW proppants. Depending on the
operator,
where the first proppant stage contains a mixture of such proppants, it may be
desirous to
introduce a second proppant stage into the formation after the introduction of
the first
proppant stage.
If the first proppant stage contains either a single proppant (either
conventional
high-density or ULW proppant) or a mixture of proppants, none of which are a
ULW
proppant, it is typically necessary to introduce a subsequent proppant stage
into the
formation. (As used herein, the term "conventional high-density proppant"
refers to a
proppant having a density greater than 2.45 g/cc.) This successive proppant
stage is
referred to herein as the "second proppant stage". It may be introduced into
the
formation immediately after the first proppant stage. Alternatively, at least
one additional
proppant stage may be introduced into the formation after the first proppant
stage but
before the second proppant stage.
Where a second proppant stage is employed, it is preferred that at least one
of the
following conditions should further prevail:
(i.) the first proppant stage and/or second proppant stage contains
a mixture of
proppants, at least one of which is a ULW proppant and, preferably wherein the
density
differential between at least two of the proppants in the mixture is greater
than or equal to
0.2 g/cc;
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(1) the first
proppant stage and/or the second proppant stage contains a ULW
proppant and the density differential between the first proppant stage and the
second
proppant stage is greater than or equal to 0.2 glee, preferably greater than
or equal to 0.50
glee, most preferably greater than or equal to 0.80 g/cc. Preferably, the
density of the
second proppant stage is less than the density of the first proppant stage.
For instance,
the density of the proppant of the first proppant stage may be around 2.65 and
the density
of the proppant of the second proppant stage may be 1.90;
(iii.) both the first proppant stage and the second proppant stage contain ULW
proppants;
(iv.) the proppant of the first proppant stage and/or the second proppant
stage
contain a ULW proppant and the rate of injection of the second proppant stage
into the
fracture is different from the rate of injection of the first proppant stage.
Typically, the
rate of injection of the second proppant stage is lower than the rate of
injection of the first
proppant stage. Typically the rate of injection of each of the proppant stages
is greater
than or equal to 5 barrels per minute. The rate of injection of any given
proppant stage
may be as high as 250 barrels/minute; or
(v.) the
proppant of the first proppant stage and/or second proppant stage
contain a ULW proppant and the particle size of the second proppant stage is
different
from the particle size of the first proppant stage; typically, the particle
size of the
proppant of the second proppant stage is greater than the particle size of the
proppant of
the first proppant stage, especially where the second proppant stage is
directed more
towards the wellbore and smaller than the particle size of the proppant of the
first
proppant stage especially where the second proppant stage is directed further
into the
fracture. Typically, the particle size of the proppant with the proppant
system used in the
invention is from about 8/12 US mesh to about 100 US mesh. Most typically, the
particle
size of the proppant with the proppant system used in the invention is from
about 12/20
US mesh to about 40/70 US mesh.
Successive proppant stages may be injected into the fracture after injection
of the
second proppant stage. Thus, the invention may consist of multiple proppant
introductions provided at least one of the following conditions prevail:
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(i.) the differential in density between the ultimate (successive) proppant
stage
and the penultimate proppant stage is greater than or equal to 0.2 g/cc;
(ii.) the rate of injection of the ultimate proppant stage into the
fracture is
different from the rate of injection of the penultimate proppant stage;
typically, the rate of
injection of the ultimate proppant stage into the fracture is lower than the
rate of injection
of the penultimate proppant stage into the fracture; or
(iii.) the particle size of the ultimate proppa.nt stage is different from the
particle
size of the penultimate proppant stage.
The limitation to the number of stages employed is principally based upon
practicality
from an operational perspective.
The effective propped length of the fracture after injection of the ultimate
proppant stage is preferably greater than the effective propped length of the
penultimate
proppant stage.
In a preferred embodiment, the first proppant stage comprises a mixture of a
first
proppant and a second proppant, wherein the first proppant is a conventional
high-density
proppant, such as sand, ceramic, sintered bauxite or resin coated proppant,
and the second
proppant is a ULW proppant having a density less than or equal to 2.45 Wee.
In another preferred embodiment, the process of the invention requires at
least
two proppant stages wherein the density differential between the first
proppant stage and
the second proppant stage is at least 0.2 g/cc. While the second proppant
stage in such
instances will require at least one ULW, the first proppant stage may contain
either a
conventional high-density proppant or a ULW.
Thus, for instance, the first proppant stage may be a banking fluid used to
cause
the initial propagation of the formation, allowing it to form a proppant bank.
The
banldng fluid may contain a conventional high-density proppant. A subsequent
second
proppant stage may include a ULW proppant, exhibiting a particle density
substantially
lower than the density of the conventional high-density proppant. For
instance, the
proppant of the subsequent proppant stage may have a density ranging between
from
about 1.25 g/cc to about 1.75 g/cc.
CA 02795417 2012-11-07
Proppant stages containing ULW proppants are less subject to settling than
conventional proppant stages and are more easily transported to provide
greater effective
propped fracture length.
In addition, the method of the invention offers a reduction in costs and the
potential for significantly improved effective propped fracture length.
As an example of the process of the invention, a hydrocarbon-bearing
subterranean formation may be hydraulically fractured by first introducing
into the
formation a first proppant stage. This first proppant stage may be a first
fracturing fluid
and may be introduced at a= pressure sufficient to initiate a fracture.
Alternatively, this
first proppant stage may be introduced into the fracture after the fracture
has been
propagated. This initial (first) proppant stage may then be followed by
fracturing the
subterranean formation with a subsequent fracturing fluid, or second proppant
stage. The
number of successive proppant stages introduced into the fracture is
determined by the
preferences of the operator.
In a preferred embodiment of the invention, the fracturing fluid or "pad
fluid"
used to initiate the fracture may contain at least one ULW proppant. Fracture
conductivity is greatly improved by the incorporation of small amounts of a
ULW
proppant in the pad fluid. The effective propped length of a fracture pumped
with a
ULW proppant-containing pad stage is greater than the effective propped
fracture length
of a fracture pumped with a substantially similar pad fluid not containing a
ULW
proppant. By "substantially similar pad fluid" is principally meant a pad
fluid identical to
the ULW proppant-containing pad stage but not containing the ULW proppant.
Typically, the amount of ULW proppant in the pad fluid is between from about
0.12 to about 24, preferably between from about 0.6 to about 9.0, weight
percent based
on the total weight percent of the fracturing fluid. The proppant in the
second proppant
stage (following the pad stage) contains either a ULW proppant or a
conventional high
density proppant. The concentration of the ULW or conventional high density
proppant
in the second proppant stage is typically greater than or equal to the
concentration of
ULW proppant in the paid fluid. Preferably, the density differential between
the
proppant of the first proppant stage (pad fluid) and the second proppant stage
is at least
0.2 g/cc.
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The fracturing fluid may include any conventional fluid treatment such as
crosslinked organoborate gels, guar or cellulosic based slickwaters, brines,
linear gels and
foams. The fracturing fluid may further contain a fine particulate, such as
sand, for fluid
loss control, etc.
In a preferred embodiment, the initial (first) fracturing fluid may contain a
breaker. Further preferable, however, is the use of slick fluids, such as
those exhibiting
reduced water friction, as the initial stage which do not require a breaking
fluid. Other
proppant stages may optionally contain a breaker. The breaker can be any
conventionally
employed in the art to reduce the viscosity of the fracturing fluid including,
but not being
restricted to, thermostable polymers. Depending on the application, a breaker
of
predictable performance may be incorporated into the initial fracturing fluid
or any of the
proppant stages referred to herein for downhole activation.
A "spearhead" fluid may further precede the introduction of the fracturing or
pad
fluid to clean-up undesired products, such as ferrous sulfide and/or ferric
oxide. Such
fluids are typically introduced into the reservoir at fracturing rates and
pressures which
initiate the fracture in the formation and contain components known in the
art.
The initial fracturing fluid, as well as any of the proppant stages referred
to
herein, may also contain other conventional additives common to the well
service
industry such as surfactants, biocides, gelling agents, cross-linking agents,
curable resins,
hardening agents, solvents, foaming agents, demulsifiers, buffers, clay
stabilizers, acids,
or mixtures thereof. In the practice of the invention, the fracturing fluid
may be any
carrier fluid suitable for transporting a mixture of proppant into a formation
fracture in a
subterranean well. Such fluids include, but are not limited to, carrier fluids
comprising
salt water, fresh water, liquid hydrocarbons, and/or nitrogen or other gases.
The initial fracturing fluid of the invention is pumped at a rate sufficient
to initiate
and propagate a fracture in the formation and to place the proppant into the
fracture and
form a bank, During the actual pumping the pH may be adjusted by the addition
of a
buffer, followed by the addition of the enzyme breaker, crosslinking agent,
proppant or
additional proppant and other additives if required. After deposition, the
proppant
material serves to hold the fracture open, thereby enhancing the ability of
fluids to
migrate from the formation to the wellbore through the fracture.
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' .
Typically, viscous gels or foams are employed as the fracturing fluid in order
to provide
a medium that will adequately suspend and transport the solid proppant, as
well as to
impair loss of fracture fluid to the formation during treatment (commonly
referred to as
"filterability" or "fluid loss"). As such, viscosity of the fracturing fluid
may affect fracture
geometry because fluid loss affects the efficiency of a treatment. For
example, when the
rate of fluid loss to the formation equals or exceeds the rate of injection or
introduction
of fluid into a fracture, the fracture stops growing. Conversely, when the
rate of fluid loss
is less than the injection or introduction rate, taken together with other
factors, a fracture
continues to propagate. Excessive fluid loss thus results in fractures that
are smaller
and shorter than desired.
In one embodiment, the proppants disclosed herein may be introduced or pumped
into
a well as, for example, a saturated sodium chloride solution carrier fluid or
a carrier fluid
that is any other completion or workover brine having, for example, a specific
gravity of
from about 1 to about 1.5, alternatively from about 1.2 to about 1.5, further
alternatively
about 1.2, at temperatures up to about 150 F. and pressures up to about 1500
psi.
However, these ranges of temperature and closure stress are exemplary only, it
being
understood that the materials may be employed as proppant materials at
temperatures
greater than about 150 F and/or at closure stresses greater than about 1500
psi. It also
being understood that core and/or layer materials may be selected by those of
skill in
the art to meet and withstand anticipated downhole conditions of a given
application.
Preferably, the successive proppant stages (those proppant stages subsequent
to the
initial fracture proppant stage) include carrier systems that are gelled, non-
gelled, or that
have a reduced or lighter gelling requirement as compared to carrier fluids
employed
with conventional fracture treatment methods.
Conventional high-density proppants may be used in the first proppant stage,
especially
where the first proppant stage is used as the initial fracturing fluid, as
well as in
successive proppant stages (after the initial fracturing stage), may be any
conventional
proppant in the art. Such proppants include, for instance, quartz, glass,
aluminum
pellets, silica (sand) (such as Ottawa, Brady or Colorado Sands), synthetic
organic
particles such as nylon pellets, ceramics (including aluminosilicates such as
"CARBO
LITETm", "NAPLITETm" or "ECONOPROPTm"), sintered bauxite, and mixtures
thereof. In
addition, protective and/or hardening coatings, such as resins to modify or
customize
the density of a selected base proppant, e.g., ground walnut hulls, etc.,
resin-coated
13
CA 02795417 2013-05-13
sand (such as "ACME BORDEN PR 6000 TM" or "SANTROL TEMPERED HSTm"), resin-
coated ceramic particles and resin-coated sintered bauxite may be employed.
Preferred high-density proppants are sand, ceramic, sintered bauxite and resin
coated
proppant. Such proppants typically exhibit a high density, for instance
greater than 2.65
g/cc. Typically, sand or synthetic fracture proppants are used. Such proppants
are
normally used in concentrations between about 1 to 18 pounds per gallon of
fracturing
fluid composition, but higher or lower concentrations can be used as required.
The ULW proppant is defined as having a density less than or equal to 2.45
g/cc.
Generally, the density of the ULW proppant is less than or equal to 2.25, more
preferably less than or equal to 2.0, even more preferably less than or equal
to 1.75,
most preferably less than or equal to 1.25 g/cc. Such proppants are less
subject to
settling and can be more easily transported to provide greater effective
propped fracture
length. Greater effective propped fracture length translates to improved
stimulation
efficiency, well productivity and, reservoir drainage.
In a preferred embodiment, the second proppant stage contains a proppant
having a
density less than the density of the proppant in the first proppant stage. In
a preferred
embodiment, successive third proppant stages contain a proppant having a
density less
than the density of the proppant of the second proppant stage. Preferably, the
density
differential between the proppant of the third proppant stage and the proppant
of the
second stage is greater than or equal to 0.2 g/cc. Thus, in a preferred
embodiment of
the invention, two or more proppants are pumped in successive stages; each
successive stage utilizing a proppant of lower density.
Such ULW proppants may be represented by relatively lightweight or
substantially
neutrally buoyant materials. One of the benefits of using such materials is
that the
requirements for the mixing equipment are minimized. For instance, when the
carrier
fluid is a brine, the only requirements on the mixing equipment is that it be
capable of
(a) mixing the brine (dissolving soluble salts), and (b) homogeneously
dispersing in the
substantially neutrally buoyant particulate material.
14
CA 02795417 2012-11-07
By "relatively lightweight" it is meant that the Material has a density that
is
substantially less than a conventional proppant employed in hydraulic
fracturing
operations, e.g., sand or having a density similar to these materials. By
"substantially
neutrally buoyant", it is meant that a material having a density sufficiently
close to the
density of an ungelled or weakly gelled carrier fluid (e.g., ungelled or
weakly gelled
completion brine, other aqueous-based fluid, or other suitable fluid) to allow
pumping
and satisfactory placement of the proppant using the selected carrier fluid.
For example,
urethane resin-coated ground walnut hulls having a specific gravity of from
about 1.25 to
about 1.35 grams/cubic centimeter may be employed as a substantially neutrally
buoyant
proppant in completion brine having a density of about 1.2. It will be
understood that
these values are -exemplary only. As used herein, a "weakly gelled" carrier
fluid is a
carrier fluid having minimum sufficient polymer, viscosifier or friction
reducer to achieve
friction reduction when pumped down hole (e.g., when pumped down tubing, work
string, casing, coiled tubing, drill pipe, etc.), and/or may be characterized
as having a
polymer or viscosifier concentration of from greater than 0 pounds of polymer
per
thousand gallons of base fluid to about 10 pounds of polymer per thousand
gallons of
base fluid, and/or as having a viscosity of from about 1 to about 10
centipoises. An
ungelled carrier fluid may be characterized as containing about 0 pounds per
thousand
gallons of polymer per thousand gallons of base fluid. Such relatively
lightweight and/or
substantially neutrally buoyant materials are disclosed in U.S. Patent No.
6,364,018.
Exemplary of such relatively lightweight and/or
substantially neutrally buoyant fracture proppant material is a ground or
crushed walnut
shell material that is coated with a resin to substantially protect and water
proof the shell.
Such a material may have a specific gravity of from about 1.25 to about 1.35,
and a bulk
density of about 0.67.
Examples of types of materials suitable for use as relatively lightweight
and/or
substantially neutrally buoyant proppant materials include, but are not
limited to, ground
or crushed shells of nuts such as walnut, pecan, almond, ivory nut, brazil
nut, etc.; ground
or crushed seed shells (including fruit pits) of seeds of fruits such as plum,
peach, cherry,
apricot, etc.; ground or crushed seed shells of other plants such as maize
(e.g. corn cobs
or corn kernels), etc., crushed fruit pits or processed wood materials such as
those derived
CA 02795417 2012-11-07
from woods such as oak, hickory, walnut, poplar, mahogany, etc. including such
woods
that have been processed by grinding, chipping, or other form of
particleization.
Those of skill in the art will understand that selection of suitable proppant
will
depend, in part, on the density of the carrier fluid and on whether it is
desired that the
selected proppant particle be relatively lightweight or substantially
neutrally buoyant in
the selected carrier fluid, and/or whether or not it is desired that the
carrier fluid be non-
gelled or non-viscosifled.
The ULW proppants employed in the invention, including the relatively
lightweight and/or substantially non-buoyant proppants, may be chipped,
ground,
crushed, or otherwise processed to produce particulate material having any
particle size
or particle shape suitable for use in the methods disclosed herein. Typically,
the particle
sizes of the proppants employed in the invention range from about 4 mesh to
about 100
mesh, alternatively from about 8 mesh to about 60 mesh, alternatively from
about 12
mesh to about 50 mesh, altematively from about 16 mesh to about 40 mesh, and
alternatively about 20 to 40 mesh. In one exemplary case, the proppant may
ground
walnut shells having a particle size of about 12/20 US mesh size in the first
proppant
stage and 20/40 US mesh size in the second proppant stage.
In a preferred mode, the second proppant stage is introduced into the
formation
immediately after the first proppant stage and the third proppant stages is
introduced into
the formation immediately after the second proppant stage without any
intervening
proppant stages.
Further, in a preferred mode, where the injection rate of a successive
proppant
stage is identical to the injection rate of the proppant stage introduced into
the fracture
immediately before the successive proppant stage or where the density of the
proppant of
the successive proppant stage is identical or less than the density of the
proppant of the
proppant stage introduced into the fracture immediately before the successive
proppant
stage, the particle size of the proppant of the successive proppant stage is
different from
the particle size of the proppant of the proppant stage introduced into the
fracture
immediately before the successive proppant stage.
16
CA 02795417 2012-11-07
Fracture proppant sizes may be any size suitable for use in a fracturing
treatment
of a subterranean formation. It is believed that the optimal size of the
proppant material
may be dependent, among other things, on the size of the fracture, on in situ
closure
stress. As an example of the variance of the particle size in the invention,
the particle
size of the proppant of the first (initial) proppant stage may be 40 mesh
while the particle
size of the proppant of the second proppant size may be 30 mesh.
It is possible further that the particle size of the proppant between
successive
fractures may differ due to the coatings on the proppants. For instance, a
proppant of a
second proppant stage may be selected from at least one of ground or crushed
nut shells,
ground or crushed seed shells, ground or crushed fruit pits, processed wood,
or a mixture
thereof. A proppant of a first proppant stage may additionally include at
least a portion
of the individual particles of the particulate material above as core
component which is at
least partially surrounded by at least one layer component of the second
proppant, the
first proppant including a protective or hardening coating. Under such
circumstances, if
the core of the first proppant is identical to the core of the second
proppant, the first
proppant would have a greater particle size.
The potential for significantly improved effective propped fracture length is
evidenced by use of the method of the invention. This may be due to the
reduced cross-
sectional flow area existing above the settled bank generated by the first
proppant
pumped. Assuming constant pumping rates at the wellbore, the reduced cross-
sectional
area 'artificially increases the successive reduced density proppant slurry
velocities th
rough that section of the fracture, leading to improved transport and deeper
placement of
those slurry stages into the fracture than would be achieved within the
created fracture in
the absence of the proppant bank.
Under some circumstances deformable particles having a size substantially
equivalent or larger than a selected fracture proppant size may be employed.
Such
deformable particles are discussed above. For example, a deformable
particulate material
having a larger size than the fracture proppant material may be desirable at a
closure
stress of about 1000 psi or less, while a deformable particulate material
equal in size to
the fracture proppant material may be desirable at a closure stress of about
5000 psi or
greater. However, it will be understood with benefit of this disclosure that
these are just
17
CA 02795417 2012-11-07
optional guidelines. In one embodiment, a deformable particle is selected to
be at least as
big as the smallest size of fracture proppant being used, and may be
equivalent to the
largest fracture proppant grain sizes. In either case, all things being equal,
it is believed
that larger fracture proppant and deformable particulate material is generally
advantageous, but not necessary. Although deformable particulate material
smaller than
the fractured proppant may be employed, in some cases it may tend to become
wedged or
lodged in the fracture pack interstitial spaces. In one embodiment, deformable
particles
used in the disclosed method may have a beaded shape and a size of from about
4 mesh
to about 100 mesh, alternatively from about 8 mesh to about 60 mesh,
alternatively from
about 12 mesh to about 50 mesh, alternatively from about 16 mesh to about 40
mesh, and
alternatively about 20/40 mesh. Thus, in one embodiment, deformable particles
may
range in size from about 1 or 2 mm to about 01 mm; alternatively their size
will be from
about 0.2 mm to about 0.8 mm, alternatively from about 0.4 mm to about 0.6 mm,
and
alternatively about 0.6 mm. However, sizes greater than about 2 mm and less
than about
0.1 turn are possible as well.
Deformable particles may be mixed and pumped with fracture proppant material
throughout or during any portion of a hydraulic fracturing treatment in the
practice of the
disclosed method. However, in one embodiment when deformable particulate
material is
mixed with only a portion of a fracture proppant material pumped into a
formation, it
may be mixed with proppant during the latter stages of the treatment in order
to dispose
the deformable particulate material in the fracture pack at or near the point
where the
wellbore penetrates a subterranean formation.
Deformable particles having any density suitable for fracturing a subterranean
formation may be employed in the practice of the disclosed method. In one
embodiment
specific gravity of deformable particulate material may range from about 0.3
to about 12,
alternatively from about 0.4 to about 12, and further alternatively from about
0.5 to about
12. In another embodiment, the specific gravity of a deformable particulate
material is
from about 0.3 to about 3.5, alternatively from 0.4 to about 3.5,
alternatively from about
0.5 to about 3.5, alternatively from about 0.6 to about 3.5, and even
alternatively from
about 0.8 to about 3.5. Alternatively a deformable particulate material having
a specific
gravity of from about 1.0 to about 1.8 is employed, and alternatively a
deformable
18
CA 02795417 2012-11-07
particle having a specific gravity of about 1.0 to about 1.1 is employed. In
another
specific embodiment, a particular divinylbenzene crosslinked polystyrene
particle may
have a bulk density of from about 0.4 to about 0.65, and alternatively of
about 0.6. In
another specific exemplary embodiment, a particular divinylbenzene crosslinked
polystyrene particle may have a specific gravity of about 1.055. However,
other specific
gravities are possible. Advantageously, in one embodiment when deformable
particles
having a density less than that of a selected fracture proppant material are
employed,
reduced treating pressures and concentration levels of potentially formation-
damaging
gelled or viscous fluids may be employed. This may allow higher treating rates
and/or
result in higher formation productivity.
Lastly, in a preferred mode, the second or ultimate proppant stage is injected
into
the fracture at a rate different from the injection rate of the first or
penultimate proppant
stage. Preferably, the rate of injection of the ultimate proppant stage is
less than the rate
of injection of the penultimate proppant stage. Typically, the rate of
injection of a
proppant stage into the formation or fracture in accordance with the invention
is from
about 5 barrels per minute to as high as 270 barrels per minute. Generally,
the rate of
injection is no greater than about 150 barrels per minute.
Additionally, the same arguments for this approach would apply when using more
viscous fluids such as linear or crosslinked fluids, particularly when
considering
applications in more rigorous downhole environments (i.e., higher
temperatures).
Further, subsequent to creating the fracture, it may be advantageous to
reverse the
process and fracture back to the wellbore filling the wellbore. This can be
achieved in
sequential steps such that at least one of the following conditions prevails
after each
successive stage:
(1) the density of the
successive (ultimate) stage being injected into the
wellbore is generally less than the density of the stage introduced to the
wellbore just
prior (penultimate) to the successive stage;
(2) the rate of
injection of the ultimate stage being injected into the fracture is
less than the rate of injection of the penultimate stage; or
(3) the particle size of
the proppant of the ultimate stage being injected into
the fracture is different than the particle size of the proppant of the
penultimate stage.
19
CA 02795417 2012-11-07
The following examples will illustrate the practice of the present invention
in its
preferred embodiments. Other embodiments within the scope of the claims herein
will be
apparent to one skilled in the art from consideration of the specification and
practice of
the invention as disclosed herein. It is intended that the specification,
together with the
examples, be considered exemplary only, with the scope and spirit of the
invention being
indicated by the claims that follow.
Examples
Example 1 (Comparative). This Example demonstrates the settling rates for
Ottawa sand
and Walnut Hull ULW.
ULW 1.75 is porous ceramic material from Carbo Ceramics, Inc. treated with 2%
by weight of particle epoxy inner coating/penetrating material (epoxy is
reaction product
of epichlorohydrin and his-phenol A) and with 2% by weight of particle phenol
formaldehyde resin outer coating material. It can be characterized as a porous
ceramic
particle with the roundness and sphericity common to ceramic proppants. The
porosity
averages 50%, yielding a bulk density of 1.10 to 1.15g/cm3. Median-sized 20/40
particles of the ULW-1.75 and Ottawa sand were used. The 20/40 Ottawa sand has
an
average bulk density of 1.62 g/cm with a specific gravity of 2.65. The ULW-
1.75 has a
bulk density of 1.05 to 1.10.
Static particle settling evaluations were conducted in fresh water to
determine the
differences in settling rate between the conventional proppant and the ULW
particles.
Median sized 20/40 particles of each proppant were used for the evaluations.
Stokes Law
calculations giving the fall velocity in ft/minute are presented in Table 1
and were
calculated as:
V =1.15x103(c1,2 / pd)(Sp.Gr.prop ¨ Sp.Gr ..flõm )
where velocity is in ft/min., diameter d is the average particle diameter and,
is fluid
viscosity in cps.
20
CA 02795417 2012-11-07
TABLE I
Static Settling Rates for Proppants as Derived by Stoke's Law
20/40 Proppant Sp.Gr. Settling Velocity ft/minute
Ottawa sand 2.65 16.6
1,75 11.2
Large-scale slot flow tests were conducted to characterize the dynamic
settling
rates of the ultra-lightweight proppant. Proppant transport characteristics
were studied at
ambient temperature through a glass slot. The transparent slot is a 22-inch
high, 16-ft
long and 0.5-inch wide parallel plate device. One thousand gallons of test
fluid was
prepared and the fluid rheology was measured using a standard Fann 35
viscometer. Fluid
was then transferred to a 200-gallon capacity ribbon blender and pumped
through the test
loop to fill the transparent slot model. Once the slot was filled with the
test fluid,
proppant was added to the blender to prepare a slurry of the desired
concentration. The
slicicwater fluid used in the test exhibited an average viscosity of 5 to 7
cps throughout
the series of tests.
The shear rate in the slot is given by the equation:
[sec-I
1.925q{gpm]
=--
(14in.D2(Hift]
where q is the rate in gallons per minute, w is width in inches and H is
height in feet.
Fluid velocity through this slot model is given by:
v[ni / sec] ¨ 0.00815q[gPin]
(w[ind)(HEM)
The proppant transport behavior of each test slurry was observed through the
slot
at various flow rates. During these tests, the proppant distribution was
continually
recorded with video cameras as well as manually by observation. All bed height
measurements for this work were taken close to the discharge end of the slot
flow cell.
Ottawa sand slurried in slickwater was observed to begin settling upon
entrance to
the slot even at the maximum fluid pump rate. Within 12 minutes at 90 gpm (
378sec-1
shear rate), the bed height was 15 inches, 68% of the total height of the 22
in. slot.
21
CA 02795417 2012-11-07
Table 2 below shows the results in tabular form. Only at shear rates in excess
of 1000
sec-1 was the dynamic Ottawa Sand proppant fall rate mitigated in the
slicicwater test
fluid. As flow rates were lowered to 30 gpm, the Ottawa proppant bed reached
its
maximum bed height of 19.5 inches or 91.25% of the slot height. Above the
proppant
bed, the shear rate reached 1,414 sec-1, at which point additional settling
did not occur.
As the rate increased from 30 to 40 gpm (1,919 sec-1), the bed height was
actually
reduced.
...:,..,-......,,i,..4.7:::-.._i=.:....r,;.. . ,:..:supix2.,,µ.::.::.,,,
,A.:11,1,.,, .::.. ,Aa.t,q,:,,,,,A
'f,tukd 1k0 :1 .15.1`4PBOd 2,''' ' Va t*:,-: ,-,10004
..i6WIto.,' . ;01).itris,..õ,., ',:: = . ,Heigla 0i) ".Si,r4 il,.Q.,',6
0 90 0 378 378
-,. 1 90 0.25 383 443
12 90 1.25 381 1201
14 60 1.27 252 825
18 60 1.38 252 825
19 40 1.39 168 677
28 40 1.54 170 1076
30 30 1.58 116 858
42 30 1.67 171 1414
43 40 1.67 171 1919
45 40 1.52 169 1070
The ULW-1.75 test was initiated at 90 gpm. ULW-1.75 was observed to be
subject to some settling at 90 gpm, with the bed height growing to 4 inches.
The fluid
rate was lowered to 80 gpm and bed height grew to 6 inches. As the rates were
reduced
incrementally down to 30 gpm, the ULW-1.75 bed was observed to grow with
reduced
rate to 12 inches. The rate was lowered further to 5 gpm and the bed height
grew to 19
inches or 86% of the total slot height. As observed in previous tests, as the
rate is
increased incrementally, bed height decreases due to erosion and fluidization
of the bed.
The ULW-1.75 results are presented in Table 3.
Ti,rue.., . 'Flitid Rate Prop Bed Slot,Sheer
'Above bed,.
Minbte Gpm Height . . See-1 = sec-1 ' ,
0 90 0.0 378 378
7 90 0.33 378 463
8 80 0.38 337 423
11 80 0.54 337 ' 478
12 70 0.58 295 432
15 60 0.71 252 412
17 60 0.79 252 445
18 50 0.83 210 386
22
CA 02795417 2012-11-07
-Pii110461` shitcSitieot.-=bve bed?
20 50.4 0.92 212 425
22 39 0.96 164 345
23 30 1 126 278
28 31 1.29 130 443
29 20 1.33 81 299
33 8 1.44 34 159
34 5.1 1.46 21 106
35 20 1.54 84 534
37 20.5 1.58 86 640
38 40.4 1.52 170 1006
40 50.6 1.46 213 1048
45 60.2 1.33 253 933
Both of the tested materials settle progressively more as the velocity
decreases.
Due to the decreased density, the ULW is more easily placed back in flow as
the rate is
increased. The reduced density materials require less shear increase to
fluidize the
proppant bed. Ottawa sand was observed to require in excess of 1,500 sec-1 to
transport
the proppant in slicicwater and almost 2,000 sec-1 of shear to begin to
fluidize the
proppant bed. The ULW-1.75 transporting at shear rates of 500 sec-1 and fluid
shear
rates of 800 sec-1 were needed to fluidize the proppant bed.
Example 2. This Example illustrates use of the combination of both sand and
walnut hull
ULW proppants.
One hundred pounds of sand and 50 pounds of walnut hull ULW proppant were
blended together in a ribbon blender and circulated throughout the system. The
blend
displayed behavior almost identical to their individual tests, respectively.
The sand
settled even at very high flow rates, throughout the length of the slot as in
the earlier test.
Because sand built bed height continuously throughout the test, the ULW
proppant stayed suspended. Lateral velocity was increased by the sand bed, so
very little
ULW proppant was entrained in the sand bed. This is attributable to the fact
that the sand
bed height artificially increased lateral velocities in the slot to levels
that maintained the
ULW proppant in suspension for the most part. Most of the sand settled out in
the slot
before any ULW proppant began to settle. Rates had to be dropped down to below
10
gpm in order to initiate larger scale settling of the ULW material and by that
time, there
was little sand left to settle.
23
CA 02795417 2012-11-07
The process presents a suitable means to improve penetration of proppant into
a
productive horizon. Both proppants behave independently from each other, yet
the
settling of the heavier proppant improves the ability of the lighter proppant
to move
deeper in the fracture by partially occluding the open flow space. It is
reasonable to
assume that the behavior will extend to more than two proppants in a given
slurry and as
such may offer additional advantages in fracture placement and propagation.
This offers
advantages for slickwater fracturing operations as they are currently
conducted.
Example 3. This Example demonstrates the improvement in fracture conductivity
by use
of a ULW proppant as a component in a pad fluid.
A fracture was simulated using the Mfrac three-dimensional hydraulic
fracturing
simulator of Meyer & Associates, Inc. using a simple 3-layer isotropic
homogeneous 0.1
mD permeability gas reservoir model, 40 acre spacing. The fracture was
designed to be
placed into the zone at a theoretical depth of 9800 feet and the model was run
in full 3-D
mode. The fracturing fluid was a crosslinked organoborate. The pad fluid was
injected
into the model at a rate of 50 barrels per minute (bpm). The fracturing fluid
of
Example 3A contained no ULW proppant. In Example 3B, a very small amount (0.5
pounds per gallon) of LitePropTM 125 lightweight proppant, a product of BJ
Services
Company, was added to the fracturing fluid. The second and subsequent stages
employed sand as proppant wherein the sand concentration was approximately 8
ppg.
Since the Mfrac model does not make calculations for a partial monolayer, the
conductivity of the proppant was artificially increased at a concentration of
0.5 lbs/sq.
Table 4 shows the pump schedule utilized for Example 3A and Table 5 shows the
pump
schedule for Example 3B.
24
CA 02795417 2012-11-07
,
TABLE 4
Stage Slurry Rate Stage Liquid Stage Time Stage Type Fluid
Type Prop Type Prop Conc. Prop Damage
No. Volume
Factor
(-) (bpm) (U.S. gal) (min) _ (-) (-) (-)
(lbm/gal) (-)
1 50 20000 9.5238 Pad B095 0000 0 0
- 2 50 10000 5.1929 Prop 8095 0001 2 0
3 50 10000 5.6239 Prop B095 0001 4 0
4 50 10000 6.0548 Prop B095 0001 6 0
50 10000 6.4858 Prop B095 0001 8 0
. 6 50 9600 4.5714 Flush SG20 0000 0 0
Wellbore Fluid Type: 2% KC1
5 B095 - Spectra Frac ET 3500w! 4.0 gpt 8F-71, 2.0 gpt XLW-56 crosslinker,
products of 13J Services Company,
Fluid Type: 5020 - 2% KC1 guar slicicwater 20#
Proppant Type: 0000 - No Prop, Slug
Proppant Type: 0001 - 20/40 Jordan Sand
TAB LE 5
Stage Slurry Rate Stage Liquid Stage Time Stage Type Fluid
Type Prop Type Prop Conc. Prop Damage
No. Volume
Factor
(-) (bPtn) (U.S. gal) (mm) (-) (-) (-)
(lbm/gal) (-)
1 50 20000 9.9803 Pad B095 SG19 0.5 0
2 50 10000 5,1929 Prop B095 0001 2 0
3 50 10000 5.6239 Prop B095 0001 4 0
4 50 10000 6.0548 Prop B095 0001 6 0
5 50 10000 6.4858 Prop B095 0001 8 0
6 50 9600 4.5714 Flush S020 0000 0 0
Wellbore Fluid Type: 2% KC1
8095 - Spectra Frac HT 3500w! 4.0 gpt BF-7L, 2.0 gpt XLW-56 crosslinker,
products of BJ Services Company,
Fluid Type: SG20 - 2% KC1 guar slickwater 20#
Proppant Type: S019 - ULW 125 partial rnonolayer Proppant
Proppant Type: 0001 - 20/40 Jordan Sand
Proppant Type: 0000- No Prop, Slug
Fracture conductivity between the proppant-packed fracture and that of the
native
reservoir, mathematically defined as:
(proppant pack permeability x fracture width) /
(formation permeability x propped fracture half length)
is illustrated in the conductivity profiles of FIGs. 1 and 2 after closure of
the fracture.
FIG. 1 is a 2D depiction of the fracture of injection of the fracturing fluid
of Example 3A.
FIG. 2 contrasts injection of the fracturing fluid of Example 3B. In both
figures, the
"created fracture area," represented as 10, is the area of the reservoir
traversed by the
propagating fracturing fluid pad. The "propped fracture area", 20, is
contributory to well
stimulation, and represents the area of the reservoir "propped open" to
provide improved
fracture conductivity. The created but unpropped area 30, "heal" upon fracture
closure
and, thus, is not considered to be stimulated.
CA 02795417 2012-11-07
As set forth in FIGs. 1 and 2, the propped fracture length is increased from
approximately 320 ft to approximately 460 feet by the addition of the ULW
proppant and
all of the proppant ends in the pay zone, defined by the area within 40 and
50. The
Figures demonstrate greatly improved fracture conductivity by the
incorporation of a
ULW proppant into a previously non-proppant laden pad fluid. This results in
an
enhanced fracture length which leads to enhanced well productivity, producible
well
reserves and ultimate expected recovery. Use of the ULW proppants avoid
failure due to
settling and bridging of the particles.
The foregoing disclosure and description of the invention is illustrative and
explanatory thereof, and various changes in the size, shape, and materials, as
well as in
the details of illustrative construction and assembly, may be made without
departing from
the spirit of the invention.
26
