Note: Descriptions are shown in the official language in which they were submitted.
CA 02713734 2013-08-27
,
TITLE: METHOD OF TREATING SUBTERRANEAN FORMATIONS WITH
POROUS CERAMIC PARTICULATE MATERIALS
FIELD
This invention relates generally to methods and compositions useful for
subterranean formation treatments, such as hydraulic fracturing treatments and
sand control.
BACKGROUND OF THE INVENTION
Hydraulic fracturing is a common stimulation technique used to enhance
production of fluids from subterranean formations. In a typical hydraulic
fracturing treatment, fracturing treatment fluid containing a solid proppant
material is injected into the formation at a pressure sufficiently high enough
to
cause the formation or enlargement of fractures in the reservoir. During a
typical
fracturing treatment, proppant material is deposited in a fracture, where it
remains after the treatment is completed. After deposition, the proppant
material
serves to hold the fracture open, thereby enhancing the ability of fluids to
migrate from the formation to the well bore through the fracture. Because
fractured well productivity depends on the ability of a fracture to conduct
fluids
from a formation to a wellbore, fracture conductivity is an important
parameter in
determining the degree of success of a hydraulic fracturing treatment.
Hydraulic fracturing treatments commonly employ proppant materials that
are placed downhole with a gelled carrier fluid such as aqueous-based fluid
such as gelled brine. Gelling agents for proppant carrier fluids may provide a
source of proppant pack and/or formation damage, and settling of proppant may
interfere with proper placement downhole. Formation damage may also be
caused by gelled carrier fluids used to place particulates downhole for
purposes
such as for sand control, such as gravel packs, frac packs, and similar
1
CA 02713734 2012-07-24
1 1,
materials. Formulation of gelled carrier fluids usually requires equipment and
mixing steps designed for this purpose.
Hydraulic fracturing treatments may also employ proppant materials that
are placed downhole with non-aqueous-based fluids, such as liquid CO2 and
liquid CO2/N2 systems. Proppants commonly employed with such non-aqueous-
based fluids tend to settle in the system.
Many different materials have been used as proppants including sand,
glass beads, walnut hulls, and metal shot. Commonly used proppants today
include various sands, resin-coated sands, intermediate strength ceramics, and
sintered bauxite; each employed for their ability to cost effectively
withstand the
respective reservoir closure stress environment. As the relative strength of
the
various materials increases, so too have the respective particle densities,
ranging from 2.65 g/cc for sands to 3.4 g/cc for the sintered bauxite.
Unfortunately, increasing particle density leads directly to increasing degree
of
difficulty with proppant transport and a reduced propped fracture volume for
equal amounts of the respective proppant, reducing fracture conductivity.
Previous efforts undertaken to employ lower density materials as proppant have
generally resulted in failure due to insufficient strength to maintain
fracture
conductivity at even the lowest of closure stresses (6.9 MPa).
Recently, deformable particles have been developed. Such deformable
particles for sand flowback control are significantly lighter than
conventional
proppants, and exhibit high compressive strength. Such deformable materials
include polystyrene divinylbenzene (PSDVB) deformable beads. Such beads,
however, have not been entirely successful primarily due to limitations of the
base material. While PSDVB beads offered excellent deformability and
elasticity, they lacked the structural integrity to withstand high closure
stresses
and temperatures.
2
CA 02713734 2012-07-24
The first successful path to generate functional deformable particles was
the usage of modified ground walnut hulls. Walnut hulls in their natural state
have been used as proppants, fluid loss agents and lost circulation materials
for
many years with greater or lesser degrees of success in each respective task.
As a proppant, natural walnut hulls have very limited applicability, because
they
deform fairly readily upon application of closure stress. This deformation
drastically reduces conductivity and limits utility of the natural material to
relatively low-closure environments.
Walnut hull based ultra-lightweight (UCW) proppants may be
manufactured in a two- step process by using closely sized walnut particles
(i. e.
20/30 US mesh), and impregnating them with strong epoxy or other resins.
These impregnated walnut hull particles are then coated with phenolic or other
resins in a fashion similar to most resin coated proppants (RCP). Such walnut
hull based ULW proppants have a bulk density of 0. 85 grams/cc and withstand
up to 41.4 MPa closure stress at 79 C.
Generally speaking, the stronger a proppant, the greater the density. As
density increases, so too does the difficulty of placing that particle evenly
throughout the created fracture geometry. Excessive settling can often lead to
bridging of the proppant in the formation before the desired stimulation is
achieved. The lower particle density reduces the fluid velocity required to
maintain proppant transport within the fracture, which, in turn, provides for
a
greater amount of the created fracture area to be propped.
ULW proppants which allow for optimization of fracturing treatment with
improved fracture length and well productivity are therefore desired.
3
CA 02713734 2012-07-24
1 t,
,
SUMMARY OF THE INVENTION
The invention relates to methods for treating subterranean formations by
treating a well with a composition containing porous ceramic or organic
polymeric particulates. In particular, the compositions introduced into the
well
are particularly suitable in hydraulic fracturing of a well as well as sand
consolidation methods such as gravel packing and frac packing. The porous
particulate material may be a selectively configured porous particulate
material,
as defined herein. Alternatively, the porous particulate material may be a non-
selectively configured porous particulate material, as defined herein.
The porous particulate material may be selectively configured with a non-
porous penetrating material, coating layer or glazing layer. In a preferred
embodiment, the porous particulate material is a selectively configured porous
particulate material wherein either (a. ) the apparent density or apparent
specific
gravity of the selectively configured porous particulate material is less than
the
apparent density or apparent specific gravity of the porous particulate
material;
(b. ) the permeability of the selectively configured porous particulate
material is
less than the permeability of the porous particulate material; or (c. ) the
porosity
of the selectively configured porous particulate material is less than the
porosity
of the porous particulate material.
In a preferred embodiment, the penetrating material and/or coating layer
and/or glazing layer of the selectively configured porous particulate material
is
capable of trapping or encapsulating a fluid having an apparent specific
gravity
less than the apparent specific gravity of the carrier fluid. Further, the
coating
layer and/or penetrating material and/or glazing material may be a liquid
having
an apparent specific gravity less than the apparent specific gravity of the
matrix
of the porous particulate material.
4
CA 02713734 2012-07-24
The strength of the selectively configured porous particulate material is
typically greater than the strength of the porous particulate material per se.
Further, the selectively configured porous material exhibits crush resistance
under conditions as high as 69MPa psi closure stress, API RP 56 or API RP 60.
In a preferred mode, the porous particulate composition is a suspension
of porous particulates in a carrier fluid. The suspension preferably forms a
pack
of particulate material that is permeable to fluids produced from the wellbore
and
substantially prevents or reduces production of formation materials from the
formation into the wellbore.
Further, the porous particulate material may exhibit a porosity and
permeability such that a fluid may be drawn at least partially into the porous
matrix by capillary action. Preferably, the porous particulate material has a
porosity and permeability such that a penetrating material may be drawn at
least
partially into the porous matrix of the porous particulate material using a
vacuum
and/or may be forced at least partially into the porous matrix under pressure.
The selectively configured porous particulate material may consist of a
multitude of coated particulates bonded together. In such manner, the porous
material is a cluster of particulates coated with a coating or penetrating
layer or
glazing layer. Suitable coating layers or penetrating materials include liquid
and/or curable resins, plastics, cements, sealants, or binders such as a
phenol,
phenol formaldehyde, melamine formaldehyde, urethane, epoxy resin, nylon,
polyethylene, polystyrene or a combination thereof. In a preferred mode, the
coating layer or penetrating material is an ethyl carbamate-based resin.
In a preferred embodiment, the selectively configured porous particulate
materials are derived from lightweight and/or substantially neutrally buoyant
particles. The application of selected porous material particulates and
relatively
5
CA 02713734 2012-07-24
lightweight and/or substantially neutrally buoyant particulate material as a
fracture proppant particulate advantageously provides for substantially
improved
overall system performance in hydraulic fracturing applications, or in other
well
treating applications such as sand control.
The porous particulate material-containing compositions used in the
invention may further contain a carrier fluid. The carrier fluid may be a
completion or workover brine, salt water, fresh water, a liquid hydrocarbon,
or a
gas such as nitrogen or carbon dioxide.
The porous particulate material-containing compositions may further
contain a gelling agent, crosslinking agent, gel breaker, surfactant, foaming
agent, demulsifier, buffer, clay stabilizer, acid or a mixture thereof.
BRIEF DESCRIPTION OF THE DRAWINGS
In order to more fully understand the drawings referred to in the detailed
description of the present invention, a brief description of each drawing is
presented, in which:
FIG. 1 is a graph depicting bulk apparent density comparison of the data
of Example 1.
FIG. 2 is a graph depicting permeability versus closure stress data of
Example 2.
FIG. 3 is a graph depicting conductivity versus closure stress data of
Example 2.
FIG. 4 is a graph depicting conductivity versus closure stress data of
Example 2.
6
CA 02713734 2012-07-24
FIG. 5 is a graph depicting permeability versus closure stress data of
Example 2.
FIG. 6 is a graph depicting conductivity comparison data of Example 2.
FIG. 7 is a graph depicting permeability comparison data of Example 2.
FIG. 8 is a SEM photograph of a porous material particle of Example 3.
FIG. 9 is a SEM photograph of a porous material particle of Example 3.
FIG. 10 is a SEM photograph of a porous material particle of Example 3.
FIG. 11 is a SEM photograph of a porous material particle of Example 3.
FIG. 12 is a SEM photograph of a porous material particle of Example 3.
FIG. 13 is a SEM photograph of a porous material particle of Example 3.
FIG. 14 is a SEM photograph of a porous material particle of Example 3.
FIG. 15 is a SEM photograph of a porous material particle of Example 3.
FIG. 16 illustrates proppant distribution for a selected combination of well
treatment particulates according to one embodiment of the disclosed
compositions and methods described in Example 4.
FIG. 17 illustrates comparative proppant distribution data of Example 4
for Ottawa sand alone.
7
CA 02713734 2012-07-24
t 1t
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
As used herein, the following terms shall have the designated meanings:
"porous particulate material" shall refer to porous ceramic or porous
organic polymeric materials. Examples of types of materials suitable for use
as
porous material particulates include particulates having a porous matrix;
"selectively configured porous particulate material" shall refer to any
porous particulate material, natural or non-natural, which has been chemically
treated, such as treatment with a coating material; treatment with a
penetrating
material; or modified by glazing. The term shall include, but not be limited
to,
those porous particulate materials which have been altered to achieve desired
physical properties, such as particle characteristics, desired strength and/or
apparent density in order to fit particular downhole conditions for well
treating
such as hydraulic fracturing treatments and sand control treatments.
"non-selectively configured porous particulate material" shall refer to any
porous natural ceramic material, such as lightweight volcanic rocks, like
pumice,
as well as perlite and other porous "lavas" like porous (vesicular) Hawaiian
Basalt, porous Virginia Diabase, and Utah Rhyolite. Further, inorganic ceramic
materials, such as alumina, magnetic glass, titanium oxide, zirconium oxide,
and
silicon carbide may also be used. In addition, the term shall refer to a
synthetic
porous particulate material which has not been chemically treated and which
imparts desired physical properties, such as particle characteristics, desired
strength and/or apparent density in order to fit particular downhole
conditions for
well treating;
"relatively lightweight" shall refer to a porous particulate material that has
a apparent density (API RP 60) that is substantially less than a conventional
particulate material employed in hydraulic fracturing or sand control
operations,
such as sand having an apparent specific gravity (API RP 60) of 2.65 and
bauxite having an apparent specific gravity of 3.55. The apparent specific
gravity
of a relatively lightweight material is less than about 2.4.
8
CA 02713734 2012-07-24
"substantially neutrally buoyant" shall refer to a porous particulate
material that has an apparent density sufficiently close to the apparent
density of
a selected ungelled or weakly gelled carrier fluid, such as an ungelled or
weakly
gelled completion brine, other aqueous-based fluid, slick water, or other
suitable
fluid, which allows pumping and satisfactory placement of the
proppant/particulate using the selected ungelled or weakly gelled carrier
fluid.
A "weakly gelled carrier fluid" is a carrier fluid having a viscosifier or
friction reducer to achieve friction reduction when pumped down hole, for
example when pumped down tubing, work string, casing, coiled tubing, drill
pipe,
or similar location, wherein the polymer or viscosifier concentration from
about 0
pounds of polymer per thousand gallons of base fluid to about 10 pounds of
polymer per thousand gallons of base fluid, and/or the viscosity from about 1
to
about 10 centipoises.
An "ungelled carrier fluid" is a carrier fluid having no polymer or
viscosifier. The ungelled carrier fluid may contain a friction reducer known
in the
art.
The selectively configured porous particulate materials as well as non-
selectively configured porous particulate materials are particularly effective
in
hydraulic fracturing as well as sand control fluids such as water, salt brine,
slickwater such as slick water fracture treatments at relatively low
concentrations to achieve partial monolayer fractures, low concentration
polymer gel fluids (linear or crosslinked), foams (with gas) fluid, liquid gas
such
as liquid carbon dioxide fracture treatments for deeper proppant penetration,
treatments for water sensitive zones, and treatments for gas storage wells.
For instance, the selectively configured porous material particles or non-
selectively configured porous material particles may be mixed and pumped
during any desired portion/s of a well treatment such as hydraulic fracturing
treatment or sand control treatment and may be mixed in any desired
9
CA 02713734 2012-07-24
concentration with a carrier fluid. In this regard, any carrier fluid suitable
for
transporting the selectively configured porous particulate material or non-
selectively configured porous particulate material particles into a well
and/or
subterranean formation fracture in communication therewith may be employed
including, but not limited to, carrier fluids comprising salt water, fresh
water,
potassium chloride solution, a saturated sodium chloride solution, liquid
hydrocarbons, and/or nitrogen or other gases may be employed.
Suitable carrier fluids include or may be used in combination with fluids
have gelling agents, cross-linking agents, gel breakers, surfactants, foaming
agents, demulsifiers, buffers, clay stabilizers, acids, or mixtures thereof.
When used in hydraulic fracturing, the selectively configured porous
particulate material or non-selectively configured porous particulate material
particles may be injected into a subterranean formation in conjunction with a
hydraulic fracturing treatment or other treatment at pressures sufficiently
high
enough to cause the formation or enlargement of fractures. Such other
treatments may be near wellbore in nature (affecting near wellbore regions)
and
may be directed toward improving wellbore productivity and/or controlling the
production of fracture proppant or formation sand. Particular examples include
gravel packing and "frac-packs." Moreover, such particles may be employed
alone as a fracture proppant/sand control particulate, or in mixtures in
amounts
and with types of fracture proppant/sand control materials, such as
conventional
fracture or sand control particulate. Further information on hydraulic
fracturing
methods and materials for use therein may be found in United States Patent No.
6,059, 034 and in United States Patent No. 6,330,916.
When employed in well treatments, selected porous material particles
that have been selectively configured, such as glazed and/or treated with one
or
more selected coating and/or penetrating materials, may be introduced into a
wellbore at any concentration/s deemed suitable or effective for the downhole
CA 02713734 2012-07-24
, Ts.
..
conditions to be encountered. For example, a well treatment fluid may include
a
suspension of proppant or sand control particulate that is made up completely
of
relatively lightweight selected porous material particles that have been
selectively configured, such as glazed and/or treated with one or more
selected
coating and/or penetrating materials. Alternatively, it is possible that a
well
treatment fluid may include a suspension that contains a mixture of
conventional
fracture proppant or sand control particulates such as sand with relatively
lightweight selected porous material particles that have been selectively
configured such as glazed and/or treated with one or more selected coating
and/or penetrating materials.
In one exemplary embodiment, a gravel pack operation may be carried
out on a wellbore that penetrates a subterranean formation to prevent or
substantially reduce the production of formation particles into the wellbore
from
the formation during production of formation fluids. The subterranean
formation
may be completed so as to be in communication with the interior of the
wellbore
by any suitable method known in the art, for example by perforations in a
cased
wellbore, and/or by an open hole section. A screen assembly such as is known
in the art may be placed or otherwise disposed within the wellbore so that at
least a portion of the screen assembly is disposed adjacent the subterranean
formation. A slurry including the selectively configured porous particulate
material or non-selectively configured porous particulate material and a
carrier
fluid may then be introduced into the wellbore and placed adjacent the
subterranean formation by circulation or other suitable method so as to form a
fluid-permeable pack in an annular area between the exterior of the screen and
the interior of the wellbore that is capable of reducing or substantially
preventing
the passage of formation particles from the subterranean formation into the
wellbore during production of fluids from the formation, while at the same
time
allowing passage of formation fluids from the subterranean formation through
the screen into the wellbore. It is possible that the slurry may contain all
or only
11
CA 02713734 2012-07-24
a portion of selectively configured porous particulate material or the non-
selectively configured porous particulate material. In the latter case, the
balance
of the particulate material of the slurry may be another material, such as a
conventional gravel pack particulate.
As an alternative to use of a screen, the sand control method may use
the selectively configured porous particulate material or non-selectively
configured porous particulate material in accordance with any method in which
a
pack of particulate material is formed within a wellbore that it is permeable
to
fluids produced from a wellbore, such as oil, gas, or water, but that
substantially
prevents or reduces production of formation materials, such as formation sand,
from the formation into the wellbore. Such methods may or may not employ a
gravel pack screen, may be introduced into a wellbore at pressures below, at
or
above the fracturing pressure of the formation, such as frac pack, and/or may
be
employed in conjunction with resins such as sand consolidation resins if so
desired.
The porous particulate material shall include any naturally occurring or
manufactured or engineered porous ceramic particulate material that has an
inherent and/or induced porosity. A commercially available instrument,
ACCUPYC 1330 Automatic Gas Pycnometer (Micromeritics, Norcross, GA), that
uses Helium as an inert gas and the manufacturer's recommended procedure
can be used to determine the internal porosity of the particulates. The
internal
porosity is generally from about 10 to 75 volume percent. Such particulate
material may also have an inherent or induced permeability, i.e., individual
pore
spaces within the particle are interconnected so that fluids are capable of at
least partially moving through the porous matrix, such as penetrating the
porous
matrix of the particle, or may have inherent or induced non-permeability,
individual pore spaces within the particle are disconnected so that fluids are
substantially not capable of moving through the porous matrix, such as not
12
CA 02713734 2012-07-24
being capable of penetrating the porous matrix of the particle. The degree of
desired porosity interconnection may be selected and engineered into the non-
selectively configured porous particulate material.
Furthermore such porous particles may be selected to have a size and
shape in accordance with typical fracturing proppant particle specifications
(i.e.,
having a uniform shape and size distribution), although such uniformity of
shape
and size is not necessary.
The apparent specific gravity of the porous particulate material is
generally less than or equal to 2.4, 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.
In a selectively configured porous particulate material, the particles may
be selected based on porosity and/or permeability characteristics so that they
have desired lightweight characteristics, such as when suspended in a selected
carrier fluid for a well treatment. As before, the inherent and/or induced
porosity
of a porous material particle may be selected so as to help provide the
desired
balance between apparent density and strength. Optional materials may be
employed along with a glazing, penetrating and/or coating material to control
penetration, such as enhancing or impairing penetration. For example, in one
embodiment an cationic clay stabilizer, such as CLAY MASTERT-m 50 from BJ
Services, may be first applied to the exterior surface of a porous ceramic
material to inhibit penetration by coating/penetrating material, such as epoxy
or
resin described elsewhere herein.
In a preferred embodiment, the porous particulate material is a relatively
lightweight or substantially neutral buoyant particulate material. Such
materials
may be employed in a manner that eliminates the need for gellation of carrier
fluid, thus eliminating a source of potential proppant pack and/or formation
13
CA 02713734 2012-07-24
damage. Furthermore, a relatively lightweight particulate material may be
easier
to place within a targeted zone due to lessened settling constraints, and a
reduced mass of such relatively lightweight particulate material is generally
required to fill an equivalent volume than is required with conventional sand
control particulates, used, for example, for gravel packing purposes.
Relatively lightweight and/or substantially neutrally buoyant fracture
proppant/particulate material used in hydraulic fracturing/sand control
treatment,
such as porous ceramic particles having untreated bulk apparent density of
1.16
and untreated porosity of about 59.3%, may be employed.
In one embodiment, the disclosed porous material particulates may be
employed as relatively lightweight particulate/proppant material that may be
introduced or pumped into a well as neutrally buoyant particles in, for
example,
a saturated sodium chloride solution carrier fluid or a carrier fluid that is
any
other completion or workover brine known in the art, thus eliminating the need
for damaging polymer or fluid loss material. In one embodiment, such a
material
may be employed as proppant/sand control particulate material at temperatures
up to about 371 C, and closure stresses up to about 55.2MPa. However, these
ranges of temperature and closure stress are exemplary only, it being
understood that the disclosed materials may be employed as proppant/sand
control materials at temperatures greater than about 371 C and/or at closure
stresses greater than about 8000 psi. In any event, it will be understood with
benefit of this disclosure that porous particulate material and/or
In those embodiments where the disclosed porous material particulates
are employed as relatively lightweight and/or substantially neutrally buoyant
particulate/proppant materials, they may be employed with carrier fluids that
are
gelled, non-gelled, or that have a reduced or lighter gelling requirement as
14
CA 02713734 2012-07-24
compared to carrier fluids employed with conventional fracture treatment/sand
control methods. In one embodiment employing one or more of the disclosed
substantially neutrally buoyant particulate materials and a brine carrier
fluid,
mixing equipment need only include such equipment that is capable of (a)
mixing the brine (dissolving soluble salts), and (b) homogeneously dispersing
in
the substantially neutrally buoyant particulate material. In one embodiment, a
substantially neutrally buoyant particulate/proppant material may be
advantageously pre-suspended and stored in a storage fluid, such as brine of
near or substantially equal density, and then pumped or placed downhole as is,
or diluted on the fly.
Examples of non-natural porous particulate materials for use in the
invention include, but are not limited to, porous ceramic particles such as
those
particles available from Carbo Ceramics Inc. as "EconopropTm", and those fired
kaolinitic described in United States Patent No. 5,188,175. As described in
this
reference such particles may include solid spherical pellets or particles from
raw
materials (such as kaolin clay) having an alumina content of between about 25%
and 40% and a silica content of between about 50% and 65%. A starch binder
may be employed. Such particles may be characterized as having a ratio of
silicon dioxide to alumina content of from about 1.39 to about 2.41, and a
apparent specific gravity of between about 2.20 and about 2.60 or between
about 2.20 and about 2.70.
It will also be understood that porous ceramic particles may be selectively
manufactured from raw materials such as those described in United States
Patent No. 5,188,175; United States Patent No. 4,427,068; and United States
Patent No. 4,522,731, such as by inclusion of selected process steps in the
initial material manufacturing process to result in a material that possesses
desired characteristics of porosity, permeability, apparent density or
apparent
specific gravity, combinations thereof. For example, such raw materials may be
fired at relatively low temperature of about 1235 F or about 1300 F (or about
700 C) to achieve a desired crystalline structure and a more highly porous and
CA 02713734 2012-07-24
lighter structure. In one exemplary embodiment of such particles, as described
elsewhere herein, about 20/40 mesh size porous material fired kaolinitic
particles from Carbo Ceramics Inc. may be selected for use in the disclosed
method. These particles have the following internal characteristics: bulk
apparent density about 1.16, internal porosity about 59.3%. These particles
may
be treated with a variety of penetrating/coating materials in an amount of
from
about 0.5 to about 10% by total weight of particle. Such coated particles may
be
manufactured and/or supplied, for example, by Fritz Industries of Mesquite,
Texas.
In one exemplary case, size of such a material may be selected to range
from about 200 mesh to about 8 mesh.
In such a case, the particles may be selected based on porosity and/or
permeability characteristics so that they have desired lightweight
characteristics,
such as when suspended in a selected carrier fluid for a well treatment. As
before, the inherent and/or induced porosity of a porous material particle may
be
selected so as to help provide the desired balance between apparent density
and strength. Optional materials may be employed along with a glazing,
penetrating and/or coating material to control penetration such as enhance or
impair penetration. For example, in one embodiment an cationic clay
stabilizer,
such as CLAY MASTERTm 50 from BJ Services, may be first applied to the
exterior surface of a porous ceramic material to inhibit penetration by
coating/penetrating material, such as epoxy or resin described elsewhere
herein.
In a selectively configured porous particulate material, the porous
particulate material is chemically treated in order to impart desired physical
properties, such as porosity, permeability, apparent density or apparent
specific
gravity, or combinations thereof to the particulate materials. Such desired
physical properties are distinct from the physical properties of the porous
particulate materials prior to treatment.
16
CA 02713734 2012-07-24
The desired physical properties may further be present in non-selectively
configured porous particulate materials. Non-selectively configured porous
particulate materials shall include naturally occurring porous ceramic
materials
as well as non-natural (synthetic) materials manufactured in a manner that
renders such desired characteristics.
The non-selectively configured particulate material is selected based on
desired physical properties, such as porosity, permeability, apparent density,
particle size, chemical resistance or combinations thereof.
The selectively configured porous particulate material as well as non-
selectively configured porous particulate material exhibit crush resistance
under
conditions as high as 69MPa closure stress, API RP 56 or API RP 60, generally
between from about 1.7 MPa to about 55.2 MPa closure stress, in combination
with a apparent specific gravity less than or equal to 2.4, to meet the
pumping
and/or downhole formation conditions of a particular application, such as
hydraulic fracturing treatment, sand control treatment.
Such desired physical properties may be imparted to a portion or portions
of the porous particulate material of the selectively configured porous
particulate
material or non-selectively configured porous particulate material, such as on
the particle surface of the material particulate, at or in the particle
surface of the
particulate material, in an area near the particle surface of a particulate
material,
in the interior particle matrix of a particulate material or a portion
thereof,
combinations thereof, etc.
Advantageously, in one embodiment the low apparent specific gravity of
the porous particulate material of the selectively configured porous
particulate
material or non-selectively configured porous particulate material may be
taken
advantage of to result in a larger fracture or frac pack width for the same
loading, such as pound per square foot of proppant, to give much larger total
volume and increased width for the same mass. Alternatively, this
characteristic
17
CA 02713734 2012-07-24
allows for smaller loading of proppant material to be pumped while still
achieving
an equivalent width.
In a preferred embodiment, selective configuration, such as by using
glaze-forming, coating and/or penetrating materials, such as those materials
described elsewhere herein, may be selectively employed to modify or
customize the apparent specific gravity of a selected porous particulate
material.
Modification of particulate apparent specific gravity, to have a greater or
lesser
apparent specific gravity, may be advantageously employed, for example, to
provide proppant or sand control particulates of customized apparent specific
gravity for use as a substantially neutrally buoyant particulate with a
variety of
different weight or apparent specific gravity carrier fluids.
The selectively configured porous particulate material has an apparent
density from about 1.1 g/cm3 to about 2.6 g/cm3, a bulk apparent density from
about 1.03 g/cm3 to about 1.5 g/cm3, and an internal porosity from about 10 to
about 75 volume percent. In one example, bulk densities may be controlled to
be in the range of from about 1.1 g/cm3 to about 1.5 g/cm3, although greater
and
lesser values are also possible.
The selectively configured porous particulate material, as well as the non-
selectively configured particulate material, is generally between from about
200
mesh to about 8 mesh.
The selectively configured porous particulate material may comprise
porous particulate material selectively altered by treating with a coating or
penetrating material using any suitable wet or dry process. Methods for
coating
particulates, such as fracture proppant particles, with materials such as
resin are
known in the art, and such materials are available, for example, from
manufacturers listed herein. With regard to coating of the disclosed porous
18
CA 02713734 2012-07-24
=
particulate materials, coating operations may be performed using any suitable
methods known in the art.
As used herein, the term "penetration" shall further refer to partially or
completely impregnated with a penetrating material, by for example, vacuum
and/or pressure impregnation. For example, porous particulate material may be
immersed in a second material and then exposed to pressure and/or vacuum to
at least partially penetrate or impregnate the material.
Those of skill in the art will understand that one or more coating and/or
penetrating materials may be selected to treat a porous material particulate
to
meet particular criteria or requirements of given downhole application based
on
the information and examples disclosed herein, as well as knowledge in the
art.
In this regard, porous material particle characteristics, such as composition,
porosity and permeability characteristics of the particulate material, size,
and/or
coating or penetrating material characteristics, such as composition, amount,
thickness or degree of penetration, may be so selected. The coating or
penetrating material is typically non- porous.
The porosity and permeability characteristics of the porous particulate
material allows the penetrating material to be drawn at least partially into
the
porous matrix of the porous particulate material by capillary action, for
example,
in a manner similar to a sponge soaking up water. Alternatively, one or more
penetrating materials may be drawn at least partially into the porous matrix
of
the porous particulate material using a vacuum, and/or may be forced at least
partially into the porous matrix under pressure.
Examples of penetrating materials that may be selected for use include,
but are not limited to, liquid resins, plastics, cements, sealants, binders or
any
other material suitable for at least partially penetrating the porous matrix
of the
19
CA 02713734 2012-07-24
selected particle to provide desired characteristics of strength/crush
resistance,
apparent specific gravity, etc. It will be understood that selected
combinations of
any two or more such penetrating materials may also be employed, either in
mixture or in sequential penetrating applications.
Examples of resins that may be employed as penetrating and/or coating
materials include, but are not limited to, resins and/or plastics or any other
suitable cement, sealant or binder that once placed at least partially within
a
selected particle may be crosslinked and/or cured to form a rigid or
substantially
rigid material within the porous structure of the particle. Specific examples
of
plastics include, but are not limited to, nylon, polyethylene, styrene, etc.
and
combinations thereof. Suitable resins include phenol formaldehyde resins,
melamine formaldehyde resins, and urethane resins, low volatile urethane
resins, such as these and other types of resins available from Borden Chemical
Inc., Santrol, Hepworth of England, epoxy resins and mixtures thereof.
Specific examples of suitable resins include, but are not limited to, resins
from Borden Chemical and identified as 500-series and 700-series resins (e.
g.,
569C, 7940, etc.). Further specific examples of resins include, but are not
limited to, SIGMASETTm series low temperature curing urethane resins from
Borden Chemical, such as SIGMASETTm, SIGMASETTm LV, SIGMASETTm XL,
ALPHASETTm phenolic resin from Borden Chemical, OPTI-PROPTm phenolic
resin from Santrol, and POLAR PROPTM low temperature curing resin from
Santrol. Where desired, curing characteristics, such as curing time, may be
adjusted to fit particular treatment methods and/or final product
specifications
by, for example, adjusting relative amounts of resin components.
Still further examples of suitable resins and coating methods include, but
are not limited to, those found in European Patent Application EP 0 771 935 Al
;
and in U. S. Patents No. 4,869,960; 4,664,819; 4,518,039; 3,929,191;
3,659,651; and 5,422,183.
CA 02713734 2012-07-24
In one exemplary embodiment, a curable phenolic resin or other suitable
curable material may be selected and applied as a coating material so that
individual coated particles may be bonded together under downhole
temperature, after the resin flows and crosslinks/cures downhole, such as to
facilitate proppant pack/sand control particulate consolidation after
placement.
Alternatively, a cured phenolic type resin coat or other suitable cured
material may be selected to contribute additional strength to the particles
and/or
reduce in situ fines migration once placed in a subterranean formation. The
degree of penetration of the coating or penetrating fluid into the porous
particulate material may be limited by disconnected porosity, such as
substantially impermeable or isolated porosity, within the interior matrix of
the
particulate.
This may either limit the extent of uniform penetration of penetrating
material in a uniform manner toward the core, such as leaving a stratified
particle cross section having outside penetrating layer with unpenetrated
substantially spherical core, and/or may cause uneven penetration all the way
to
the core, such as bypassing "islands" of disconnected porosity but penetrating
all the way to the core. In any event, a penetrating and/or coating material
may
trap or encapsulate air (or other fluid having apparent specific gravity less
than
particle matrix and less than coating/penetrating material) within the
disconnected porosity in order to reduce apparent specific gravity by the
desired
amount. Such materials coat and/or penetrate the porous particulate without
invading the porosity to effectively encapsulate the air within the porosity
of the
particle. Encapsulation of the air provides preservation of the ultra-
lightweight
character of the particles once placed in the transport fluid. If the resin
coating or
transport fluids were to significantly penetrate the porosity of the particle,
the
density increases accordingly, and the particle no longer has the same
lightweight properties. The resin coat also adds strength and substantially
enhances the proppant pack permeability at elevated stress.
21
CA 02713734 2012-07-24
Coating layers may be applied as desired to contribute to particle
strength and/or reduce in situ fines migration once placed in a subterranean
formation. The coating significantly increases the strength and crush
resistance
of the ultra-lightweight ceramic particle. In the case of natural sands the
resin
coat protects the particle from crushing, helps resist embedment, and prevents
the liberation of fines.
The coating or penetrating fluid is typically selected to have an apparent
specific gravity less than the apparent specific gravity of the porous
particulate
material so that once penetrated at least partially into the pores of the
matrix it
results in a particle having a apparent specific gravity less than that of the
porous particulate material prior to coating or penetration, i. e., filling
the pore
spaces of a porous particulate material results in a solid or substantially
solid
particle having a much reduced apparent density.
For example, the selected porous particulate material may be treated with
a selected penetrating material in such a way that the resultant selectively
configured porous particulate material has a much reduced apparent density,
such as having a apparent density closer to or approaching the apparent
specific gravity of a carrier fluid so that it is neutrally buoyant or semi-
buoyant in
a fracturing fluid or sand control fluid.
Alternatively, a penetrating material may be selected so that it helps
structurally support the matrix of the porous particulate material (i. e.,
increases
the strength of the porous matrix) and increases the ability of the
particulate to
withstand the closure stresses of a hydraulic fractured formation, or other
downhole stresses.
For example, a penetrating material may be selected by balancing the
need for low apparent density versus the desire for strength, i.e., a more
dense
22
CA 02713734 2012-07-24
material may provide much greater strength. In this regard, the inherent
and/or
induced porosity of the porous particulate material may be selected so as to
help provide the desired balance between apparent density and strength. It
will
be understood that other variable, such as downhole temperature and/or fluid
conditions, may also impact the choice of penetrating materials.
The coating layer or penetrating material is generally present in the
selectively configured porous particulate material in an amount of from about
0.5% to about 10% by weight of total weight. The thickness of the coating
layer
of the selectively configured porous particulate material is generally between
from about 1 to about 5 microns. The extent of penetration of the penetrating
material of the selectively configured porous particulate material is from
less
than about 1% penetration by volume to less than about 25% penetration by
volume.
Especially preferred results are obtained when the porous particulate
material is a porous ceramic particle having an apparent density of 1.25 or
less
and untreated porosity is approximately 60%. Such materials may be treated
with a coating material that does not penetrate the porous matrix of the
porous
particulate material, or that only partially penetrates the porous matrix of
the
ceramic particulate material. Such treated ceramic materials may have an
apparent density from about 1.1 g/cm3 to about 1.8 g/cm3 (alternatively from
about 1.75 g/cm3 to about 2 g/cm3 and further alternatively about 1.9 g/cm3),
a
bulk apparent density from about 1.03 g/cm3 to about 1.5 g/cm3, and a treated
internal porosity from about 45% to about 55%. However, values outside these
exemplary ranges are also possible.
As an example, a porous ceramic treated with about 6% epoxy has been
seen to exhibit a bulk apparent density of about 1.29 and a porosity of about
50.6%, a porous ceramic treated with about 8% epoxy exhibits a bulk apparent
23
CA 02713734 2012-07-24
density of about 1.34 and a porosity of about 46.9%, a porous ceramic treated
with about 6% phenol formaldehyde resin exhibits a bulk apparent density of
about 1.32 and a porosity of about 51.8%, and a porous ceramic treated with
about 8% phenol formaldehyde resin exhibits a bulk apparent density of about
1.20 and a porosity of about 54.1%.
In this embodiment, a coating material or penetrating material may be
selected to be present in an amount of from about 0.5% to about 10% by weight
of total weight of individual particles. When present, thickness of a coating
material may be selected to be from about 1 to about 5 microns on the exterior
of a particle. When present, extent of penetration penetrating material into a
porous material particle may be selected to be from less than about 1%
penetration by volume to less than about 25% penetration by volume of the
particle. It will be understood that coating amounts, coating thickness, and
penetration amounts may be outside these exemplary ranges as well.
Further, the porous particulate material may be at least partially
selectively configured by glazing, such as, for example, surface glazing with
one
or more selected non-porous glaze materials. In such a case, the glaze, like
the
coating or penetrating material, may extend or penetrate at least partially
into
the porous matrix of the porous particulate material, depending on the glazing
method employed and/or the permeability (i.e., connectivity of internal
porosity)
characteristics of the selected porous particulate material, such as non-
connected porosity allowing substantially no penetration to occur. For
example,
a selected porous particulate material may be selectively configured, such as
glazed and/or coated with a non-porous material, in a manner so that the
porous
matrix of the resulting particle is at least partially or completely filled
with air or
some other gas, i.e., the interior of the resulting particle includes only
air/gas
and the structural material forming and surrounding the pores. Once again, the
inherent and/or induced porosity of a porous material particle may be selected
24
CA 02713734 2012-07-24
so as to help provide the desired balance between apparent density and
strength, and glazing and/or coating with no penetration (or extension of
configured area into the particle matrix) may be selected to result in a
particle
having all or substantially all porosity of the particle being unpenetrated
and
encapsulated to trap air or other relatively lightweight fluid so as to
achieve
minimum apparent specific gravity. In addition to sealing a particle, such as
to
seal air/gas within the porous matrix of the particle, such selective
configuration,
such as using glazing and/or coating materials, may be selected to provide
other
advantages.
In a preferred embodiment, the porous particulate material, such as the
above-described fired kaolinitic particles, is manufactured by using a glaze-
forming material to form a glaze to seal or otherwise alter the permeability
of the
particle surface, so that a given particle is less susceptible to invasion or
saturation by a well treatment fluid and thus capable of retaining relatively
lightweight or substantially neutrally buoyant characteristics relative to the
well
treatment fluid upon exposure to such fluid. Such glazing may be accomplished
using any suitable method for forming a glaze on the surface or in the near
surface of a particle, including by incorporating a glaze-forming material
into the
raw material "green paste" that is then formed such as molded into shape of
the
particle prior to firing. Those skilled in the art recognize that glazes may
be
made from a variety of methods, including the application of a smooth, glassy
coating such that a hard, nonporous surface is formed. Glazes may be formed
from powdered glass with oxides. The mixture of powders is suspended in water
and applied to the substrate. The glaze can be dried and then fixed onto the
substrate by firing or similar process known to those skilled in the art.
Additionally, the use of borates or similar additives may improve the glaze.
Examples of such glaze-forming materials include, but are not limited to,
materials such as magnesium oxide-based material, boric acid/boric oxide-
CA 02713734 2012-07-24
=
based material, etc. During firing, the glaze-forming material/s "bloom" to
the
surface of the particles and form a glaze. Alternatively, glazing may be
accomplished, for example, by applying a suitable glaze-forming material onto
the surface of the formed raw material or "green" particles prior to firing
such as
by spraying, dipping, and similar methods so that glazing occurs during
particle
firing. Further alternatively, a glaze-forming material may be applied to a
fired
ceramic particle, and then fired again in a separate glaze-forming step. In
one
embodiment, the glaze forms a relatively hard and relatively non-porous
surface
during firing of the particles.
Advantages of such a glazing treatment include maintaining the relatively
low apparent density of a relatively lightweight porous particle without the
necessity of further alteration, such as necessity of coating with a separate
polymer coating although optional coatings may be applied if so desired.
Furthermore, the resulting relatively smooth glazed surface of such a particle
also may serve to enhance the ease of multi phase fluid flow, such as flow of
water and gas and oil, through a particulate pack, such as through a proppant
pack in a fracture, resulting in increased fracture conductivity.
In an alternative embodiment, one or more types of the disclosed
selectively configured porous particulate material or non-selectively
configured
porous particulate material may be employed as particulates for well treating
purposes in combination with a variety of different types of well treating
fluids
(including liquid CO2-based systems and other liquefied-gas or foamed-gas
carrier fluids) and/or other types of particulates such as to achieve
synergistic
benefits, it being understood that benefits of the disclosed methods and
compositions may also be achieved when employing only one type of the
disclosed porous materials as a sole well treating particulate. Furthermore,
although exemplary embodiments are described herein with reference to porous
materials and to relatively lightweight porous materials, it will be
understood that
26
CA 02713734 2012-07-24
=
benefits of the disclosed methods and compositions may also be realized when
applied to materials that may be characterized as non-relatively lightweight
and/or non-porous in nature.
Elimination of the need to formulate a complex suspension gel may mean a
reduction in tubing friction pressures, particularly in coiled tubing and in
the
amount of on-location mixing equipment and/or mixing time requirements, as
well as reduced costs. Furthermore, when selectively configured, such as by
glazing and/or by treating with coating/penetrating material, to have
sufficient
strength and relative lightweight properties, the disclosed relatively
particles may
be employed to simplify hydraulic fracturing treatments or sand control
treatments performed through coil tubing, by greatly reducing fluid suspension
property requirements. Downhole, a much reduced propensity to settle (as
compared to conventional proppant or sand control particulates) may be
achieved, particularly in highly deviated or horizontal wellbore sections. In
this
regard, the disclosed particulate material may be advantageously employed in
any deviated well having an angle of deviation of between about 0 degree and
about 90 degrees with respect to the vertical. However, in one embodiment, the
disclosed particulate material may be advantageously employed in horizontal
wells, or in deviated wells having an angle with respect to the vertical of
between about 30 degrees and about 90 degrees, alternatively between about
75 degrees and about 90 degrees. Thus, use of the disclosed particulate
materials disclosed herein may be employed to achieve surprising and
unexpected improvements in fracturing and sand control methodology, including
reduction in proppant pack and/or formation damage, and enhancement of well
productivity.
It will be understood that the characteristics of glazing materials,
penetrating materials and/or coating materials given herein, such as
composition, amounts, types, are exemplary only. In this regard, such
27
CA 02713734 2012-07-24
=
characteristics may be selected with benefit of this disclosure by those of
skill in
the art to meet and withstand anticipated downhole conditions of a given
application using methods known in the art, such as those described herein.
In another disclosed embodiment, blends of two or more different types of
particles having different particulate characteristics, such as different
porosity,
permeability, apparent density or apparent specific gravity, settling velocity
in
carrier fluid, may be employed as well treatment particulates. Such blends may
contain at least one porous particulate material and at least one other
particulate
material that may or may not be a porous particulate material.
In addition, the selectively configured porous particulate material and
non-selectively configured porous particulate material may be used as two or
more multiple layers. In this regard, successive layers of such materials may
be
employed. For instance, multiple layers may consist of at least one
selectively
configured porous particulate material and at least one non- selectively
configured porous particulate material.
In one exemplary embodiment, a selected coating or penetrating material
may be a urethane, such as ethyl carbamate-based resin, applied in an amount
of about 4% by weight of the total weight of the selected porous material
particle. A selected coating material may be applied to achieve a coating
layer of
at least about 2 microns thick on the exterior of the selected porous material
particle.
Such blends may be further employed in any type of well treatment
application, including in any of the well treatment methods described
elsewhere
herein. In one exemplary embodiment, such blends may be employed to
optimize hydraulic fracture geometries to achieve enhanced well productivity,
such as to achieve increased propped fracture length in relatively "tight" gas
28
CA 02713734 2012-07-24
formations. Choice of different particulate materials and amounts thereof to
employ in such blends may be made based on one or more well treatment
considerations including, but not limited to, objective/s of well treatment,
such as
for sand control and/or for creation of propped fractures, well treatment
fluid
characteristics, such as apparent specific gravity and/or rheology of carrier
fluid,
well and formation conditions such as depth of formation, formation
porosity/permeability, formation closure stress, type of optimization desired
for
geometry of downhole-placed particulates such as optimized fracture pack
propped length, optimized sand control pack height, optimized fracture pack
and/or sand control pack conductivity and combinations thereof.
Such different types of particles may be selected, for example, to achieve
a blend of different specific gravities or densities relative to the selected
carrier
fluid. For example, a blend of three different particles may be selected for
use in
a water fracture treatment to form a blend of well treatment particulates
having
three different specific, gravities, such as apparent specific gravity of
first type of
particle from about 1 to less about 1.5; apparent specific gravity of second
type
of particle from greater than about 1.5 to about 2.0; and apparent specific
gravity
of third type of particle from about greater than about 2.0 to about 3.0; or
in one
specific embodiment the three types of particles having respective specific
gravities of about 2.65, about 1.7 and about 1.2, it being understood that the
preceding apparent specific gravity values are exemplary only and that other
specific gravities and ranges of specific gravities may be employed. In one
example, at least one of the types of selected well treatment particulates may
be
selected to be substantially neutrally buoyant in the selected carrier fluid.
Such different types of particles may be selected for use in any amount
suitable for achieving desired well treatment results and/or costs. However,
in
one embodiment multiple types of particles may be selected for use in a blend
of
well treatment particulates in amounts that are about equal in proportion on
the
29
CA 02713734 2012-07-24
't
basis of total weight of the blend. Thus, three different types of particles
may
each be employed in respective amounts of about 1/3 of the total blend such as
by total weight of the blend, four different types of particles may each be
employed in respective amounts of about 1/4 of the total blend such as by
total
weight or the blend. However, these relative amounts are exemplary only, it
being understood that any desired relative amount of each selected type of
well
particulate may be employed, such as for one exemplary embodiment of blend
having three different types of particles, such as selected from the different
types of particles described elsewhere herein, the amounts of each selected
type of particle may be present in the blend in an amount ranging from about
10% to about 40% such as by total weight of the blend to achieve 100% weight
of the total blend.
It will be understood with benefit of this disclosure that choice of different
particulate materials and amounts thereof to employ in such blends may be
made using any methodology suitable for evaluating such blends in view of one
or more desired well treatment considerations. In one embodiment, any method
known in the art suitable for modeling or predicting sand control pack or
fracture
pack geometry/conductivity may be employed, such as illustrated and described
in relation to Example 4 herein.
Examples of different particle types which may be selected for use in
such blends include, but are not limited to, conventional sand particulates,
such
as Ottawa sand, relatively lightweight well treatment particulates, such as
ground or crushed nut shells at least partially surrounded by at least one
layer
component of protective or hardening coating, selectively configured porous
materials, such as any one or more of the selectively configured porous
materials described herein, such as deformable particles. Further examples of
particle types which may be selected for use in such blends include any of
those
particles described in U.S. Patent No. 6,772,838; U.S. Patent No. 6,749,025;
CA 02713734 2012-07-24
. = .,
U.S. Patent No. 6,364,018; U.S. Patent No. 6,330,916; and U.S. Patent No.
6,059,034.
In one exemplary embodiment, selected blends of conventional sand
proppant, relatively lightweight particulates of ground or crushed nut shells
at
least partially surrounded by at least one layer component of protective or
hardening coating, and selectively configured porous materials such as
relatively lightweight porous material fired kaolinitic particles treated with
a
penetrating/coating materials described herein may be employed in a hydraulic
fracture treatment utilizing ungelled or weakly gelled carrier fluid. One
specific
example of such a blend is described in Example 4 herein. In such an
embodiment, these different types of particles may be employed in any relative
volume or weight amount or ratio suitable for achieving desired well treatment
results.
In one specific example, these different types of particles may be
employed in a well treatment particulate composition including about 1/3 by
weight of conventional sand proppant by total weight of well treatment
particulate, about 1/3 by weight of relatively lightweight particulate, such
as core
of ground or crushed nut shells at least partially surrounded by at least one
layer
component of protective or hardening coating) by total weight of well
treatment
particulate, and about 1/3 by weight of selectively configured relatively
lightweight porous material, such as fired kaolinitic particles treated with a
penetrating/coating materials described herein, by total weight of well
treatment
particulate. It will be understood that the foregoing relative amounts are
exemplary only and may be varied, for example, to achieve desired results
and/or to meet cost objectives of a given treatment. It will also be
understood
that the disclosed methods and compositions may also be practiced with such
blends using other types of relatively lightweight particulate materials as
described elsewhere herein, such as porous polymeric materials, such as
polyolefins, styrene-divinylbenzene based materials, polyalkylacrylate esters
and modified starches. Further, any of the disclosed porous materials may be
31
CA 02713734 2012-07-24
employed in "neat" or non-altered form in the disclosed blends where apparent
density and other characteristics of the particle are suitable to meet
requirements of the given well treating application.
In one respect, disclosed are well treating methods, such as hydraulic
fracturing and sand control, which may be employed to treat a well penetrating
a
subterranean formation, and include introducing into a well a selected porous
particulate material that is treated with a selected coating material,
selected
penetrating material, or combination thereof. Individual particles of the
particulate material optionally may have a shape with a maximum length-based
aspect ratio of equal to or less than about 5. In one embodiment porous
particulate materials may be any particulate material with suitable internal
porosity and/or permeability characteristics to achieve the desired finished
particle properties when combined with selected penetrating/coating materials
as described elsewhere herein.
Examples of suitable porous material particulates that may be selected
for use in aqueous based carrier fluids include, but are not limited to porous
ceramics, porous polymeric materials or any other porous material or
combinations thereof suitable for selection for combination of internal
porosity
and permeability to achieve desired properties, such as strength and/or
apparent specific gravity, for particular downhole conditions and/or well
treatment applications as described elsewhere herein. For example, porous
ceramic particles may be manufactured by firing at relatively low temperatures
to avoid loss of porosity due to crystallization and driving off of water.
Particular
examples include, but are not limited to, porous ceramic particles available
from
Carbo Ceramics Inc. of Irving, Texas composed of fired kaolinitic clay that is
fired at relatively low temperature of about 668 C or about 704 C (or about
700 C and that has trace amounts of components such as cristobalite, mullite
and opalite), polyolefin particles, and similar components.
32
CA 02713734 2012-07-24
In another disclosed embodiment, relatively lightweight particulates or
blends including such particulates as described elsewhere herein, such as
including selectively configured particulates and/or non-selectively
configured
particulates described elsewhere herein, may be advantageously employed as
well treatment particulates, such as fracture proppant particulate or sand
control
particulate, in liquefied gas and foamed gas carrier fluids.
Examples of types of such carrier fluids include, but are not limited to,
liquid CO2-based systems, liquid 002, CO2/N2, and foamed N2 in CO2 systems
that may be employed in hydraulic fracturing applications. In one specific
embodiment, porous ceramic well particulates having a bulk apparent density of
close to or about 1.0 g/cm3, in either selectively configured or non-
selectively
configured form, may be employed with such liquefied gas and/or foamed gas
carrier fluids, such as liquid CO2-based systems, liquid 002, CO2/N2, and
foamed N2 in CO2 systems.
In another specific embodiment, selectively configured particulates and/or
non-selectively configured particulates may be employed that may be
characterized as substantially neutrally buoyant in such liquefied gas and/or
foamed gas carrier fluids.
Liquid CO2 has a density close to about 1.02 g/cm3 under typical
fracturing conditions, and conventional proppants, such as sand, or non-
relatively lightweight ceramic proppants have a tendency to settle in liquid
CO2-
based systems. Furthermore, liquid CO2 has very little if any viscosity, and
therefore proppant transport in a liquid CO2-based system is provided by
turbulence and frictional forces, and fractures created by liquid CO2 are
typically
relatively narrow. Advantageously, using the disclosed methods and
compositions, proppant transport of relatively lightweight particulates is
easier
33
CA 02713734 2012-07-24
=
than is proppant transport of conventional sand proppants or non-relatively
lightweight ceramic proppants.
In one exemplary embodiment, relatively lightweight porous ceramic
particles may be employed in liquid CO2-based systems. Examples of types of
such relatively lightweight porous ceramic particles include, but are not
limited
to, those porous ceramic particles available from Carbo Ceramics for
controlled
release applications altered in the manufacturing process to have a bulk
apparent density close to about 1.0 g/cm3. Other suitable examples of
relatively
lightweight porous particles include, but are not limited to, those particles
having
a bulk apparent density of less than about 2.5 g/cm3, alternatively having a
bulk
apparent density of from about 1.0 to about 2.0 g/cm3, further alternatively
having a bulk apparent density of from about 1.2 g/cm3 to about 2.0 g/cm3.
One specific example of suitable relatively lightweight porous ceramic
particle for use in CO2-based systems of this embodiment is porous ceramic
material described elsewhere herein, either in selectively configured form, as
described herein in Example 1, or in non-selectively configured or non-altered
or
"neat" form.
In one exemplary embodiment, the practice of the disclosed methods and
compositions, relatively lightweight porous ceramic materials or blends
thereof
may be employed as fracture proppant materials in liquid CO2-based fracturing
systems using methodologies similar or the same to those employed with
conventional proppants in liquid CO2-based fracturing systems. In this regard,
liquid CO2-based fracturing job characteristics, such as proppant amounts,
proppant sizes, mixing and pumping methodologies, using relatively lightweight
porous ceramic materials may be the same as described for conventional
proppants in "The History and Success of Liquid CO2 and CO2/N2 Fracturing
System" by Gupta and Bobier, SPE 40016, March 1998. Further information on
34
CA 02713734 2012-07-24
<
liquid CO2-based fracturing job characteristics that may be employed with
relatively lightweight porous ceramic materials may be found in United States
Patent No. 4,374,545, United States Patent No. 5,558,160, United States Patent
No. 5,883,053, Canadian Patent No. 2,257,028 and Canadian Patent No.
2,255,413.
In one disclosed exemplary embodiment, relatively lightweight porous
ceramic particles employed as fracture proppant particulate in a liquid CO2-
based system may be used in "neat" or non-altered form and may have a
apparent specific gravity of from about 1.17 to about 2.0 In another disclosed
exemplary embodiment, using relatively lightweight porous ceramic particles as
fracture proppant particulate in a liquid CO2-based system allows the
concentration of proppant in such a system to be advantageously extended to
about 1200 Kg/cubic meter. Other advantages of using the disclosed relatively
lightweight porous ceramic particles in liquid CO2-based fracturing systems
include, but are not limited to, reduced proppant settling in surface mixing
equipment prior to pumping downhole and improved proppant transport
downhole and into the formation. It will be understood that although described
above for embodiments employing relatively lightweight porous ceramic
particles, the disclosed methods and compositions may also be practiced with
liquid CO2-based systems using other relatively lightweight porous material
particulate materials and blends thereof described elsewhere herein, such as
porous polymeric materials such as polyolefins. Any of such materials may be
employed in "neat" or non-altered form with liquid CO2-based systems where
apparent density and other characteristics of the particle are suitable to
meet
requirements of the given well treating application, or may alternatively be
employed in selectively configured form as described elsewhere herein.
The following examples will illustrate the practice of the present invention
in a preferred embodiment. Other embodiments within the scope of the claims
herein will be apparent to one skilled in the art from consideration of the
CA 02713734 2012-07-24
specification and practice of the invention as disclosed herein. It is
intended that
the specification, together with the example, be considered exemplary only,
with
the scope and spirit of the invention being indicated by the claims which
follow.
EXAMPLES
The following examples are illustrative and should not be construed as
limiting the scope of the invention or claims thereof.
Example 1:
To obtain the data for this example, the following procedure was followed:
Measured mass of 25 ml of sample on a graduate cylinder. Cylinder was tapped
several times on the countertop and the volume adjusted to an even 25 ml prior
to weighing. Mass/volume = bulk density.
The data of this example is shown in Table 1:
Table 1
Bulk Densities
Sand 1.721
CarboLite 1.747
Porous Ceramic-Neat 1.191
Porous Ceramic-2/2 1.238
Porous Ceramic-6% 1.293
Porous Ceramic-8% P-A 1.224
Porous Ceramic-8% P-B 1.198
Porous Ceramic-10% P 1.32
FIG. 1 illustrates comparisons of the bulk densities of various
proppants/sand control materials to samples of a selected porous ceramic
material (from Carbo Ceramics, Inc.).
In the examples, "Carbolite" is a commercial proppant available from
Carbo Ceramics, Inc. "Neat" is untreated porous ceramic material from Carbo
36
CA 02713734 2012-07-24
'
Ceramics, Inc., "2/2" 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 bis-phenol A) and with 2% by
weight of particle phenol formaldehyde resin outer coating material, "6%" is
porous ceramic material from Carbo Ceramics, Inc. treated with 6% by weight of
particle coating/penetrating material (epoxy is reaction product of
epichlorhidian
and bis-phenol A), "8% P-A" is porous ceramic material from Carbo Ceramics,
inc. treated with 8% by weight of particle phenol formaldehyde resin (Sample
A),"8% P-B" is porous ceramic material from Carbo Ceramics, Inc. treated with
8% by weight of particle phenol formaldehyde resin (Sample B), and "10`)/0 P"
is
porous ceramic material from Carbo Ceramics, Inc. treated with 10% by weight
of particle phenol formaldehyde resin.
Data is presented for both the untreated porous material particle, and for
the porous material particle treated with various types and concentrations of
selected penetrating materials. As may be seen, the bulk apparent density of
the
resulting particles varies with varying degree of infiltration or penetration
of the
penetrating material into the porous ceramic particle. The samples designated
as 2/2 and 8% P-B may be characterized from SEM thin section analysis as
having limited penetration towards the core of the particle, apparent
effective
encapsulation of the air in the particle core porosity, yet substantial
enhancement of the particle strength as illustrated by the conductivity tests.
Figs. 2 and 5 illustrate the permeability versus closure stress for coated
and uncoated ceramic ULW particulates. As shown, resin coating and
impregnation of the ULW particle imparts significant strength across the
closure
range and in particular, enhances the low to mid- range performance of the
material. The data represents equal pack widths for all of the proppants with
adjustments made for each respective density. Both the coated and uncoated
37
CA 02713734 2012-07-24
ceramics ULW were tested at 1.4 pounds per square foot (33.2 kg/m2). Each of
these tests had nearly identical width measurements for ease of comparison.
Example 2:
The porous particulate material employed was from "Carbo Ceramics"
having a size of about 20/40 mesh. The particulate material was treated with
various penetrating/coating materials corresponding to the same epoxy or
phenol formaldehyde materials used above. The treated particulate material was
tested alone, with no other particulate material blended in.
Comparison materials include Jordan Sand, "Econoprop" proppant from
Carbo Ceramics, "Econoflex" (coated Econoprop proppant), Hickory sand
(Brady Sand), "PR6000" `)/0 coated Ottawa sand from BORDEN, and "Carbolite"
proppant from Carbo Ceramics.
Conductivity tests were performed according to API RP 61 (1st Revision,
October 1, 1989) using an API conductivity cell with Ohio sandstone wafer side
inserts. Each particulate material sample was loaded into the cell and closure
stress applied to the particulate material using a "DAKE" hydraulic press
having
a "ROSEMOUNT" differential transducer (#3051C) and controlled by a
"CAMILE" controller. Also employed in the testing was a "CONSTAMETRIC
3200"constant rate pump which was used to flow deionized water through each
particulate sample.
Table 2 shows the proppant pack Permeability and Conductivity data
generated for this example.
Insert table 2 (entire page - in the landscape layout)
38
_
-.
. '
TABLE 2
Porous Ceramic Worksheet
PC PC-4% PC-6% PC-8% PC-2% PC-6% PC-8% PC-10% 20/40 20/40
20/40 20/40 20/40 20/40
neat Epoxy Epoxy Epoxy &2% resin resin
resin Jordan Econoprop Econoflex Hickory PR 6000 Carbolite
Epoxy_
_
_
Bulk dens 1.198 1.292 _ 1.34 1.238 _ 1.293 1.224
_ 1.32 1.6 _ 1.6 1.5 1.6 1.54 1.6
Acid 5.7% 1.20%
1.90% 0.30% 0.50% 0.30% 1.70%
Solubility _
Porosity _50.2 46.9 51.8 54.1
-
Crush
2000 3.65 .1
0.4 0.1
3000 .3,
1.8 0.2
4000 7.52 4.54 1.6
0.1 9.8 0.4
5000 2.6
13.6 0.7
6000 16.88 16.36
0.1 1.9
7000 21
7500 4.7
3.1 1.5
8000 20.87
0.2 4.5 c)
10000 13.3
0.5 10.7 12.1 D=1
Permeability PC PC-4% PC-6% PC-8% PC-2% PC-6% PC-8% PC-10% 20/40 20/40
20/40 20/40 20/40 20/40 o
r.)
neat Epoxy Epoxy Epoxy &2% resin resin
resin tordan Econoprop Econoflex Hickory PR 6000
Carbolite -.4
Eeox
CID
(AI
3000 110 331 226 304 318 376 994 384
170 319 274 144 241 466
4000 70 237 130 190 230 192 786 260 113
295 262 64 208 433 n.)
o
5000 97 110 131 185 151 671 181 80
257 255 42 168 376
n.)
6000 64 89 142 110 546 101 47
220 248 21 127 319 of
7000 48 55 78 361 32 178
225 12 94 252 ....3
1
8000 28 44 46 175 18 135
202 4 61 186 n.)
al.
Conductivity PC PC-4% PC-6% PC-8% PC-2% PC-6% PC-8% PC-10% 20/40 20/40
20/40 20/40 20/40 20/40
41 Epoxy Epoxy Epoxy &2% resin resin
resin Jordan Econoprop Econotlex Hickory PR 6000
Carbolite
neat Epoxy
2000 2726 8436 4693 5965 5484 4658 13522 5760 2116 3423
2586 2020 2550 4755
3000 1915 5152 3194 4283 4053 3177 10275 4116 1564 3132
2382 1276 2201 4383
4000 1103 1868 1695 2600 2621 1695 7028 2472 1013 2842
2178 532 1852 4011
5000 949 1356 1616 1983 1221 5406 1729 709 2442
2036 344 1468 3445
6000247 1042 1345 74-7 3783 986 405 2042
1895 157 1085 2879
7000 526 604 522 2455 279 1621
1650 94 790 2255
8000 M 296 463 296 1127 154 1201
1405 31 495 1637
CA 02713734 2012-07-24
'
Data is presented graphically in FIGS. 2-6.
Conductivity is a function of the width times the permeability.
Advantageously, as disclosed herein in one embodiment, a selected porous
material particulate may be treated with a selected coating and/or penetrating
material to produce a relatively lightweight particulate sample that at the
same
lb/sq ft loading as a conventional sand will occupy a greater width. Even if
the
pack permeability is the same, the conductivity, and thus the proppant pack
producability, will be higher. Thus, as represented by the conductivity data,
the
benefit of the combination of increased width and the improved permeability
may be achieved. Further, as disclosed herein in one embodiment, a selected
porous material particulate may be treated with a selected coating and/or
penetrating material so that particle strength is maintained to as high a
confining
(or closure) stress as possible, which is reflected more directly by the
permeability data. Thus a certain amount of fracture conductivity at a given
stress/temp condition may be maintained without increasing the cost, and/or by
offsetting any cost increase with improved value. Even in the event of
increased
particulate material cost, substantially less particulate material may be
employed
to achieve a substantially equivalent conductivity due to the lesser mass/unit
volume.
Example 3:
Using the selected treated material of the Examples above, particles may
be produced that are capable for use, such as having sufficient crush
resistance
for use or do not crush, under conditions of 13.8 MPa closure stress or
greater,
alternatively 17.2 MPa closure stress or greater, alternatively 20.7 MPa
closure
stress or greater, alternatively up to at least about 41.4 MPa closure stress,
alternatively up to at least about 48.3 MPa closure stress, and alternatively
at
least about 55.2 MPa closure stress, i.e., almost as resistant to crush as
CA 02713734 2012-07-24
e
commercial ceramic proppants which are heavier (e.g., commercial ceramic
proppant (CarboLite) is about 40% heavier). In another embodiment, particles
may be produced that are capable for use (e. g., have sufficient crush
resistance
for use or do not crush) under conditions of from about 13.8 closure stress to
about 55.2 MPa closure stress, alternatively from about 17.2 MPa closure
stress
to about 55.2 MPa closure stress, alternatively from about 20.7 MPa closure
stress to about 55.2 MPa closure stress. However, it will be understood that
particles may produced that are capable of use at higher closure stresses than
55.2 MPa and lower closure stresses than about 13.8 MPa as well.
FIGS. 8-15 are cross-sectional and surface SEM photographs of various
treated and untreated samples of porous ceramic materials from CARBO
CERAMICS. Where indicated as "epoxy" or as "resin", the particular
coating/penetrating material is either the same epoxy or phenol formaldehyde
resin employed and identified in Example 1.
FIG. 8 shows particles treated with about 10% by weight of particle resin.
FIG. 9 shows particles treated first with 2% by weight epoxy and second with
2% by weight resin. FIG. 10 shows untreated particles. FIG. 11 shows particles
treated first with 2% by weight epoxy and second with 2% by weight resin. FIG.
12 shows surface of untreated particle. FIG. 13 shows untreated particles.
FIG.
14 shows particles treated with 8% by weight epoxy. FIG. 15 shows particles
treated with 6% by weight epoxy.
Example 4:
In this example, a selected blend of three different apparent specific
gravity well treatment particulates were evaluated for use in a water fracture
treatment of a "tight" gas well based on a Canyon Sand gas well. The three
different apparent specific gravity particulates were chosen to represent, for
example, a selected blend of the following different types of well treatment
particulates:
41
CA 02713734 2012-07-24
. =
20/40 mesh Ottawa sand having the following properties: apparent
specific gravity of 2.65; Vt = 17.5 ft/min @ Nre = +/-500 (Typical for water
fracs)
H.
20/40 mesh porous ceramic particles coated with 2% resin (described
elsewhere herein) having the following properties: apparent specific
gravity of 1.70; Vt = 9.5 ft/min @ Nre = +/-500 (Typical for water fracs)
HI. 20/40 mesh ground or crushed nut shells coated with protective or
hardening coating (e.g., "LiteProp" from BJ Services described in U. S.
Patent No. 6,364,018 and US Patent No. 6,749,025) having the following
properties: apparent specific gravity of 1.20; Vt = 3.9 ft/min @ Nre = +/-
500 (Typical for water fracs)
As may be seen from the data above, particulate III weighs about half as
much as Particulate I, but settles at a rate less than about 1/4 as fast.
A well treatment particulate including a selected blend of roughly equal
amounts of the above types of particulates (i.e., about 1/3 by weight of above
particulate I of the total weight of the blend, about 1/3 by weight of above
particulate II of the total weight of the blend, and about 1/3 by weight of
above
particulate HI of the total weight of the blend) was modeled for use in a
water
fracture treatment of a "tight" gas well using a hydraulic fracture simulation
program. FIG. 16 illustrates proppant distribution in the resulting simulated
hydraulic fracture created downhole.
For comparison purpose, a well treatment particulate including only
particulate I (Ottawa sand) was modeled for use in a water fracture treatment
of
the same "tight" gas well similarly modeled using the same pumping schedule
(but in this case using 135,000 pounds of Ottawa sand). FIG. 17 illustrates
proppant distribution in the resulting simulated hydraulic fracture created
downhole.
42
CA 02713734 2012-07-24
s4 fµ' *
As may be seen from a comparison of the resulting propped profiles of
FIGS. 16 and 17, the well treatment particulate including only particulate I
(Ottawa sand) resulted in a proppant distribution that propped the bottom half
of
the pay out to about 1000' (see FIG. 18), while the well treatment particulate
including a selected blend of roughly equal amounts of particulates I, II and
III
resulted in a synergistic proppant distribution that propped all of the pay
out to
almost 2000' (see FIG. 16), or approximately four times the propped fracture
surface area.
Example 5:
The proppant distributions of FIG. 16 and FIG. 17 were next input into a
reservoir production simulator ("M-Prod") and gas production separately
simulated for each proppant distribution. An assumption was made that the
effective conductivity of the proppant distribution of FIG. 16 (i.e., roughly
equal
amounts of particulates I, II and III) would have only 1/10th the effective
conductivity of the proppant distribution of FIG. 17 (i. e., particulate I
only).
The proppant distribution of FIG. 17 (i.e. , particulate I only) produced at
an initial potential of 707 MCFD with a cumulative production of 595 MMCF over
ten years, while the proppant distribution of FIG. 16 (i.e. , roughly equal
amounts
of particulates I, II and III) produced at an initial potential of 920 mcf/day
("MCFD") with a cumulative production of 1312 MMCF over ten years. Thus, the
proppant distribution of FIG. 16 (i.e., roughly equal amounts of particulates
I, II
and III) resulted in the production of twice the reserves from the same well
as
the proppant distribution of FIG. 17 (i.e., particulate I only), despite
having only
1/10th of assumed conductivity. This shows how the disclosed selected blend of
different types of well treatment particulates may be advantageously employed
to achieve increased production rates and reserves from relatively tight gas
formations by increasing propped fracture lengths, even with reduced effective
conductivities.
43
CA 02713734 2012-07-24
s =
.
Although this example illustrates the use of a selected blend of different
types and amounts of well treatment particulates in a tight gas well, it will
be
understood that blends of these and other types of well treatment blends may
be
selected and employed for other types of wells, including wells productive of
liquids as well as gas, and wells having relatively higher formation
permeability
values. Furthermore, it will be understood that benefits of the disclosed
method
may be realized using blends of other than three different types of well
treatment
particulates, for example, using two different types of well treatment
particulates
or more than three different types of well treatment particulates (e. g., as
many
as four, five, six, seven, eight, nine and more different types of well
treatment
particulates) having varying characteristics.
Example 6:
ULW-1.75 corresponds to 2/2 discussed above in Example 1 and 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 3 and were calculated as:
V = 1 . 15x103( d2prop ipfluid)( Sp. r-Jr. prop ¨ Sp.GR.fhild)
where velocity is in ft/min., diameter d is the average particle diameter
and, p is fluid viscosity in cps.
44
CA 02713734 2012-07-24
= , w= *
TABLE 3
Static Settling Rates For Proppants as Derived by Stoke's Law
20/40 Proppant SpGr
Settling Velocity ft/minute
Ottawa Sand 2.65 16.6
ULw-1.75 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 slickwater 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:
1.925 q [grin]
y = [sec = __________
(w [iii.12 CH [ f tl
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:
0,00815q[gpm]
vf m/sed =
(vii[in.}(H[f
CA 02713734 2012-07-24
== = 4 4 M.
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. Table 4 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 slickwater 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. .
TABLE 4
Time, minute Fluid rate Gpm Prop Bed Height (ft)
Slot Shear sec-1 Above bed, sec-1
0 90 0 378 378
90 7.62 383 443
12 90 38.1 381 1201
14 60 38.7 252 825
18 60 42.1 252 825
19 40 42.4 168 677
28 40 46.9 170 1076
30 30 48.2 116 858
42 30 50.9 171 1414
43 40 50.9 171 1919
45 40 46.3 169 1070
46
CA 02713734 2012-07-24
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 5.
TABLE 5
Time, minute Fluid Rate Gpm Prop Bed Height Slot Shear Sec-1
Above bed, 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
60 0.71 252 412
17 60 0.79 252 445
18 50 0.83 210 386
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 81 229
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
47
CA 02713734 2012-07-24
IP.
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 slickwater 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.
The data clearly show the advantage of lower density particles in relation
to dynamic sand fall rates. Heavier proppants require significant fluid
viscosity,
elevated fluid density, and/or high slurry velocity for effective proppant
transport.
While the invention may be adaptable to various modifications and
alternative forms, specific embodiments have been shown by way of example
and described herein. However, it should be understood that the claims should
not be limited by the preferred embodiment and examples, but should be given
the broadest interpretation consistent with the description as a whole
invention.
48
